New Fortress Energy Inc. - Quarter Report: 2021 September (Form 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 September 30, 2021

☐	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 October 29, 2021, the registrant had 206,863,242 shares of Class A common stock outstanding.

TABLE OF CONTENTS

GLOSSARY OF TERMS		ii

CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS		iii

PART I FINANCIAL INFORMATION		1

Item 1.	Financial Statements.	1

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	39

Item 3.	Quantitative and Qualitative Disclosures About Market Risks.	63

Item 4.	Controls and Procedures.	64

PART II OTHER INFORMATION		65

Item 1.	Legal Proceedings.	65

Item 1A.	Risk Factors.	65

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	113

Item 3.	Defaults upon Senior Securities.	113

Item 4.	Mine Safety Disclosures.	113

Item 5.	Other Information.	113

Item 6.	Exhibits.	113

SIGNATURES		119

Table of Contents

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

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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

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PART I

FINANCIAL INFORMATION

Item 1.

Financial Statements.

New Fortress Energy Inc.

Condensed Consolidated Balance Sheets

As of September 30, 2021 and December 31, 2020

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

	September 30, 2021			December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	224,383		$	601,522
Restricted cash		72,338			12,814
Receivables, net of allowances of $130 and $98, respectively		161,008			76,544
Inventory		82,390			22,860
Prepaid expenses and other current assets, net		75,602			48,270
Total current assets		615,721			762,010

Restricted cash		37,879			15,000
Construction in progress		973,880			234,037
Property, plant and equipment, net		2,025,688			614,206
Equity method investments		1,227,991			-
Right-of-use assets		145,941			141,347
Intangible assets, net		166,964			46,102
Finance leases, net		603,662			7,044
Goodwill		740,132			-
Deferred tax assets, net		6,087			2,315
Other non-current assets, net		121,142			86,030
Total assets	$	6,665,087		$	1,908,091

Liabilities
Current liabilities
Current portion of long-term debt	$	249,752		$	-
Accounts payable		210,259			21,331
Accrued liabilities		159,304			90,352
Current lease liabilities		32,009			35,481
Due to affiliates		6,910			8,980
Other current liabilities		109,662			35,006
Total current liabilities		767,896			191,150

Long-term debt		3,597,659			1,239,561
Non-current lease liabilities		93,321			84,323
Deferred tax liabilities, net		284,176			2,330
Other long-term liabilities		37,885			15,641
Total liabilities		4,780,937			1,533,005

Commitments and contingencies (Note 20)

Stockholders’ equity
Class A common stock, $0.01 par value, 750.0 million shares authorized, 206.9 million issued and outstanding as of September 30, 2021; 174.6 million issued and outstanding as of December 31, 2020		2,069			1,746
Additional paid-in capital		1,912,643			594,534
Accumulated deficit		(283,256	)		(229,503	)
Accumulated other comprehensive income		24,625			182
Total stockholders’ equity attributable to NFE		1,656,081			366,959
Non-controlling interest		228,069			8,127
Total stockholders’ equity		1,884,150			375,086
Total liabilities and stockholders’ equity	$	6,665,087		$	1,908,091

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

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New Fortress Energy Inc.

Condensed Consolidated Statements of Operations and Comprehensive Loss

For the three and nine months ended September 30, 2021 and 2020

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Revenues
Operating revenue	$	188,389		$	83,863		$	382,421		$	223,542
Vessel charter revenue		78,656			-			143,217			-
Other revenue		37,611			52,995			148,541			82,412
Total revenues		304,656			136,858			674,179			305,954

Operating expenses
Cost of sales		135,432			71,665			333,533			209,780
Vessel operating expenses		15,301			-			30,701			-
Operations and maintenance		20,144			13,802			54,960			31,785
Selling, general and administrative		46,802			26,821			124,954			87,273
Transaction and integration costs		1,848			4,028			42,564			4,028
Contract termination charges and loss on mitigation sales		-			-			-			124,114
Depreciation and amortization		31,194			9,489			68,080			22,363
Total operating expenses		250,721			125,805			654,792			479,343
Operating income (loss)		53,935			11,053			19,387			(173,389	)
Interest expense		57,595			19,813			107,757			50,901
Other (income) expense, net		(5,400	)		2,569			(13,458	)		4,179
Loss on extinguishment of debt, net		-			23,505			-			33,062
Net income (loss) before income from equity method investments and income taxes		1,740			(34,834	)		(74,912	)		(261,531	)
(Loss) income from equity method investments		(15,983	)		-			22,958			-
Tax provision		3,526			1,836			7,058			1,949
Net loss		(17,769	)		(36,670	)		(59,012	)		(263,480	)
Net loss attributable to non-controlling interest		7,963			312			5,259			81,163
Net loss attributable to stockholders	$	(9,806	)	$	(36,358	)	$	(53,753	)	$	(182,317	)

Net income (loss) per share – basic and diluted	$	(0.05	)	$	(0.21	)	$	(0.27	)	$	(2.14	)

Weighted average number of shares outstanding – basic and diluted		207,497,013			170,074,532			195,626,564			85,009,385

Other comprehensive loss:
Net loss	$	(17,769	)	$	(36,670	)	$	(59,012	)	$	(263,480	)
Currency translation adjustment		76,996			(971	)		(23,697	)		(1,122	)
Comprehensive loss		(94,765	)		(35,699	)		(35,315	)		(262,358	)
Comprehensive loss (income) attributable to non-controlling interest		8,162			(926	)		6,005			80,156
Comprehensive loss attributable to stockholders	$	(86,603	)	$	(36,625	)	$	(29,310	)	$	(182,202	)

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

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New Fortress Energy Inc.

Condensed Consolidated Statements of Changes in Stockholders’ Equity

For the three and nine months ended September 30, 2021 and 2020

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

	Class A shares				Class B shares				Class A common stock					Additional paid-in			Accumulated			Accumulated other comprehensive			Non- controlling			Total 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
Net (loss) income		-		-		-		-		-			-		-			(6,044	)		-			4,310			(1,734	)
Other comprehensive income		-		-		-		-		-			-		-			-			101,363			327			101,690
Share-based compensation expense		-		-		-		-		-			-		1,613			-			-			-			1,613
Shares issued as consideration in business combinations		-		-		-		-		31,372,549			314		1,400,470			-			-			-			1,400,784
Issuance of shares for vested RSUs		-		-		-		-		8,930			-		-			-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		-		-		-		-		(3,329	)		-		(164	)		-			-			-			(164	)
Non-controlling interest acquired in business combinations		-		-		-		-		-			-		-			-			-			229,285			229,285
Dividends		-		-		-		-		-			-		(20,736	)		-			-			-			(20,736	)
Balance as of June 30, 2021		-	$	-		-	$	-		206,698,564		$	2,060	$	1,932,318		$	(273,450	)	$	101,422		$	239,569		$	2,001,919
Net loss		-		-		-		-		-			-		-			(9,806	)		-			(7,963	)		(17,769	)
Other comprehensive loss		-		-		-		-		-			-		-			-			(76,797	)		(199	)		(76,996	)
Share-based compensation expense		-		-		-		-		-			-		1,562			-			-			-			1,562
Adjustments related to business combinations		-		-		-		-		-			-		-			-			-			(319	)		(319	)
Issuance of shares for vested RSUs		-		-		-		-		193,193			9		(9	)		-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		-		-		-		-		(28,515	)		-		(478	)		-			-			-			(478	)
Dividends		-		-		-		-		-			-		(20,750	)		-			-			(3,019	)		(23,769	)
Balance as of September 30, 2021		-	$	-		-	$	-		206,863,242		$	2,069	$	1,912,643		$	(283,256	)	$	24,625		$	228,069		$	1,884,150

	Class A shares						Class B shares					Class A common stock					Additional paid-in			Accumulated			Accumulated other comprehensive			Non- controlling			Total 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 changes		-			-			-			-		-			-		-			(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
Net loss		-			-			-			-		-			-		-			(137,493	)		-			(29,094	)		(166,587	)
Other comprehensive income		-			-			-			-		-			-		-			-			435			85			520
Share-based compensation expense		-			1,922			-			-		-			-		-			-			-			-			1,922
Issuance of shares for vested RSUs		11,529			-			-			-		-			-		-			-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		(3,250	)		(40	)		-			-		-			-		-			-			-			-			(40	)
Exchange of NFI units		144,342,572			206,587			(144,342,572	)		-		-			-		-			-			-			(206,587	)		-
Balance as of June 30, 2020		168,587,346		$	335,503			-		$	-		-		$	-	$	-		$	(193,315	)	$	352		$	7,070		$	149,610
Conversion from LLC to Corporation		(168,587,346	)		(335,503	)		-			-		168,587,346			1,687		333,816			-			-			-			-
Net loss		-			-			-			-		-			-		-			(36,358	)		-			(312	)		(36,670	)
Other comprehensive income (loss)		-			-			-			-		-			-		-			-			(267	)		1,238			971
Share-based compensation expense		-			-			-			-		-			-		2,071			-			-			-			2,071
Issuance of shares for vested RSUs		-			-			-			-		157,148			-		-			-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		-			-			-			-		(6,071	)		-		(239	)		-			-			-			(239	)
Dividends		-			-			-			-		-			-		(17,006	)		-			-			-			(17,006	)
Balance as of September 30, 2020		-		$	-			-		$	-		168,738,423		$	1,687	$	318,642		$	(229,673	)	$	85		$	7,996		$	98,737

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

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New Fortress Energy Inc.

Condensed Consolidated Statements of Cash Flows

For the nine months ended September 30, 2021 and 2020

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

	Nine Months Ended September 30,
	2021			2020
Cash flows from operating activities
Net loss	$	(59,012	)	$	(263,480	)
Adjustments for:
Amortization of deferred financing costs and debt guarantee, net		9,503			9,949
Depreciation and amortization		68,971			23,025
(Earnings) losses of equity method investees		(22,958	)		-
Dividends received from equity method investees		14,259			-
Sales-type lease payments received in excess of interest income		1,458			-
Change in market value of derivatives		(4,955	)		-
Contract termination charges and loss on mitigation sales		-			71,510
Loss on extinguishment and financing expenses		-			37,090
Deferred taxes		(4,280	)		388
Change in value of Investment of equity securities		(7,265	)		2,376
Share-based compensation		4,945			6,501
Other		72			1,895
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in receivables		(75,633	)		(43,307	)
(Increase) Decrease in inventories		(56,172	)		26,691
Decrease (Increase) in other assets		25,500			(16,526	)
Decrease in right-of-use assets		3,149			31,910
(Decrease) Increase in accounts payable/accrued liabilities		(2,530)			23,982
(Decrease) in amounts due to affiliates		(2,070	)		(1,033	)
(Decrease) in lease liabilities		(2,510	)		(30,930	)
(Decrease) Increase in other liabilities		(30,159	)		4,249
Net cash (used in) operating activities		(139,687	)		(115,710	)

Cash flows from investing activities
Capital expenditures		(430,549	)		(115,841	)
Cash paid for business combinations, net of cash acquired		(1,586,042	)		-
Entities acquired in asset acquisitions, net of cash acquired		(8,817	)		-
Other investing activities		(5,750	)		137
Net cash (used in) provided by investing activities		(2,031,158	)		(115,704	)

Cash flows from financing activities
Proceeds from borrowings of debt		2,234,650			1,832,144
Payment of deferred financing costs		(35,846	)		(27,099	)
Repayment of debt		(229,887	)		(1,490,002	)
Payments related to tax withholdings for share-based compensation		(29,717	)		(6,356	)
Payment of dividends		(65,051	)		(16,871	)
Net cash provided by financing activities		1,874,149			291,816
Impact of changes in foreign exchange rates on cash and cash equivalents		1,960			-
Net (decrease) increase in cash, cash equivalents and restricted cash		(294,736	)		60,402
Cash, cash equivalents and restricted cash – beginning of period		629,336			93,035
Cash, cash equivalents and restricted cash – end of period	$	334,600		$	153,437

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	$	187,295		$	(4,682	)
Liabilities associated with consideration paid for entities acquired in asset acquisitions		9,959			-
Consideration paid in shares for business combinations		1,400,784			-

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

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Organization

New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, 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 has liquefaction, regasification and power generation operations in the United States, Jamaica and Brazil. Subsequent to the Mergers (defined below), the Company has marine operations with vessels operating under time charters and in the spot market globally.

On April 15, 2021, the Company completed the 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. The results of operations of Hygo and GMLP have been included in the Company’s condensed consolidated financial statements for the period subsequent to the Mergers.

As a result of the Mergers, the Company acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50% interest in a 1.5GW 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”).

The Company acquired the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. In addition to the Nanook, the Company acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (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 the Company’s existing facilities and international project pipeline. The majority of the FSRUs are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business.

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 accounting principles generally accepted in the United States of America (“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. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020.

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. Certain prior year amounts have been reclassified to conform to current year presentation.

A variable interest entity (“VIE”) is an entity that by design meets any of the following characteristics: (1) lacks sufficient equity to allow the entity to finance its activities without additional subordinated financial support; (2) as a group, equity investors do not have the ability to make significant decisions relating to the entity’s operations through voting rights, or do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of the entity; or (3) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. The primary beneficiary of a VIE is required to consolidate the assets and liabilities of the VIE. The primary beneficiary is the party that has both (1) the power to direct the economic activities of the VIE that most significantly impact the VIE’s economic performance; and (2) through its interest in the VIE, the obligation to absorb the losses or the right to receive the benefits from the VIE that could potentially be significant to the VIE.

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The sale and leaseback financings of certain vessels acquired in the Mergers were consummated with VIEs. As part of these financings, the asset was sold to a single asset entity of the lending bank and then leased back. While the Company does not hold an equity investment in these entities, these entities are VIEs, and the Company has a variable interest in the entities due to the guarantees and fixed price repurchase options that absorb the losses of the VIE that could potentially be significant to the entity. The Company has concluded that it has the power to direct the economic activities that most impact the economic performance as it controls the significant decisions relating to the assets and it has the obligation to absorb losses or the right to receive the residual returns from the leased asset. As NFE has no equity interest in these VIEs, all equity attributable to these VIEs is included in non-controlling interests in the condensed consolidated financial statements.

(b)	Revenue recognition

Terminals and Infrastructure

Within the Terminals and Infrastructure segment, 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 delivered in containers transported by truck to customer sites, but may also be delivered via vessel to an unloading point specified in a contract. Revenue from sales of LNG is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, 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, which may be accounted for as a finance or operating lease. For the Company’s operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated the lease component. The lease component of such operating leases is recognized as Operating revenue in the condensed consolidated statements of operations and comprehensive loss. The Company allocates consideration in agreements containing finance leases 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 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.

In addition to the revenue recognized from the finance lease 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.

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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. 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. 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.

Ships

Charter contracts for the use of the FSRUs and LNG carriers acquired as part of the Mergers are leases as the contracts convey the right to obtain substantially all of the economic benefits from the use of the asset and allow the customer to direct the use of that asset.

At inception, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. In making the classification assessment, the Company estimates the residual value of the underlying asset at the end of the lease term with reference to broker valuations. None of the vessel lease contracts contain residual value guarantees. Renewal periods and termination options are included in the lease term if the Company believes such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. The Company assesses leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease.

For charter contracts that are determined to be finance leases accounted for as sales-type leases, the profit from the sale of the vessel 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. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss.

Revenues include lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenues generated from charters contracts are recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Lease payments includes fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, the Company has elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based become probable or occur.

Repositioning fees are included in Vessel charter revenues and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee will be recognized evenly over the term of the charter.

Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss over the lease term.

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The Company’s LNG carriers may participate in an LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as the Cool Pool. The Cool Pool allows the pool participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as an agent, for the marketing and chartering of the participating vessels and paying certain voyage costs such as port call expenses and brokers’ commissions in relation to employment contracts, with each of the Pool Participants continuing to be fully responsible for fulfilling the performance obligations in the contract.

The Company is primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and the Company is the principal in such time charters. Revenue and expenses for charters of the Company’s vessels that participate in the Cool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the condensed consolidated statements of operations and comprehensive loss. The Company’s allocation of its share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss.

(c)	Business combinations

Business combinations are accounted for under the acquisition method. On acquisition, the identifiable assets acquired and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the purchase price over the fair values of the identifiable net assets acquired is recognized as goodwill. Acquisition related costs are expensed as incurred. The results of operations of acquired businesses are included in the Company’s condensed consolidated statements of operations and comprehensive loss from the date of acquisition.

If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values.

(d)	Equity method investments

The Company accounts for investments in entities over which the Company has significant influence, but do not meet the criteria for consolidation, under the equity method of accounting. Under the equity method of accounting, the Company’s investment is recorded at cost, or in the case of equity method investments acquired as part of the Mergers, at the acquisition date fair value of the investment. The carrying amount is adjusted for the Company’s share of the earnings or losses, and dividends received from the investee reduce the carrying amount of the investment. The Company allocates the difference between the fair value of investments acquired in the Mergers and the Company’s proportionate share of the carrying value of the underlying assets, or basis difference, across the assets and liabilities of the investee. The basis difference assigned to amortizable net assets is included in Income (loss) from equity method investments in the condensed consolidated statements of operations and comprehensive loss. When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee.

(e)	Lessor expense recognition

Vessel operating expenses, which are recognized when incurred, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and third-party management fees. Voyage expenses principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

Initial direct costs include costs directly related to the negotiation and consummation of the lease are deferred and recognized in Vessel operating expenses over the lease term.

(f)	Guarantees

Guarantees issued by the Company, excluding those that are guaranteeing the Company’s own performance, are recognized at fair value at the time that the guarantees are issued and recognized in Other current liabilities and Other non-current liabilities on the condensed consolidated balance sheets. The guarantee liability is amortized each period as a reduction to Selling, general and administrative expenses. If it becomes probable that the Company will have to perform under a guarantee, the Company will recognize an additional liability if the amount of the loss can be reasonably estimated.

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(g)	Derivatives

As part of the Mergers, the Company acquired derivative positions that were used to reduce market risks associated with interest rates and foreign exchange rates. All derivative instruments are initially recorded at fair value as either assets or liabilities on the condensed consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The Company has not designated any derivatives as cash flow or fair value hedges; however, certain instruments may be considered economic hedges.

(h)	Property, plant and equipment, net

Property, plant and equipment is recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Vessel refurbishment costs are capitalized and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs increase the capacity or improve the efficiency or safety of vessels and equipment. Expenditures for routine maintenance and repairs for assets in the Terminals and Infrastructure segment are charged to expense as incurred within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss; such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses.

Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul. Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years. For vessels, the Company utilizes the “built-in overhaul” method of accounting. The built-in overhaul method is based on the segregation of vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals to reflect the different useful lives of the components of the assets. The estimated cost of the drydocking component is depreciated until the date of the first drydocking following acquisition of the vessel, upon which the cost is capitalized, and the process is repeated. If drydocking occurs prior to the expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive loss.

The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:

	Useful life (Yrs)
Vessels	5-30
Terminal and power plant equipment	4-24
CHP facilities	4-20
Gas terminals	5-24
ISO containers and associated equipment	3-25
LNG liquefaction facilities	20-40
Gas pipelines	4-24
Leasehold improvements	2-20

The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.

Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the condensed consolidated statements of operations and comprehensive loss. When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal.

(i)	Transaction and integration costs

Transaction and integration costs are comprised of costs related to business combinations and include advisory, legal, accounting, valuation and other professional or consulting fees. This caption also includes gains or losses recognized in connection with business combinations, including the settlement of preexisting relationships between the Company and an acquired entity. Financing costs which are not deferred as part of the cost of the financing on the balance sheet are recognized within this caption including fees associated with debt modifications.

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Adoption of new and revised standards

(a)	New standards, amendments and interpretations issued but not effective for the 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 will adopt this guidance in the first quarter of 2022 and does not expect it to have a material impact on the Company’s financial position results of operations or cash flows.

(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 in the first quarter of 2021 did not have a material impact on the Company’s financial position, results of operations or cash flows.

Acquisitions

Hygo Merger

On April 15, 2021, the Company completed the acquisition of all of the outstanding common and preferred shares representing all voting interests of Hygo, a 50-50 joint venture between Golar LNG Limited (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd., a fund managed by Stonepeak Infrastructure Partners (“Stonepeak”), in exchange for 31,372,549 shares of NFE Class A common stock and $580,000 in cash. The acquisition of Hygo expands the Company’s footprint in South America with three gas-to-power projects in Brazil’s large and fast-growing market.

Based on the closing price of NFE’s common stock on April 15, 2021, the total value of consideration in the Hygo Merger was $1.98 billion, shown as follows:

Consideration			As of April 15, 2021
Cash consideration for Hygo Preferred Shares	$	180,000
Cash consideration for Hygo Common Shares		400,000
Total Cash Consideration			$	580,000
Merger consideration to be paid in shares of NFE Common Stock		1,400,784
Total Non-Cash Consideration				1,400,784
Total Consideration			$	1,980,784

The Company has determined it is the accounting acquirer of Hygo, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of Hygo based on their respective estimated fair values as of the closing date.

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The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment in determining the appropriate assumptions and estimates. The Company is in the process of finalizing the valuation of assets acquired, liabilities assumed and non-controlling interests of Hygo, and therefore the purchase price allocation should be considered preliminary. The preliminary purchase price allocation may be subject to further refinement as the evaluation of the underlying inputs and assumptions of third-party valuations and the assessment of acquisition-related income taxes are finalized. The goodwill balance may be adjusted pending the completion of the valuation of the assets acquired, liabilities assumed and non-controlling interests of Hygo as described above. The preliminary estimates may be subject to adjustments during the measurement period, not to exceed one year, based upon new information obtained about facts and circumstances that existed as of the acquisition date. Preliminary fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of Hygo as of the closing date were as follows:

Hygo	As of April 15, 2021
Assets Acquired
Cash and cash equivalents	$	26,641
Restricted cash		48,183
Accounts receivable		5,126
Inventory		1,022
Other current assets		8,095
Assets under development		128,625
Property, plant and equipment, net		385,389
Equity method investments		823,521
Finance leases, net		601,000
Deferred tax assets, net		1,065
Other non-current assets		52,996
Total assets acquired:	$	2,081,663
Liabilities Assumed
Current portion of long-term debt	$	38,712
Accounts payable		3,059
Accrued liabilities		39,149
Other current liabilities		13,495
Long-term debt		433,778
Deferred tax liabilities, net		254,949
Other non-current liabilities		21,520
Total liabilities assumed:		804,662
Non-controlling interest		36,115
Net assets acquired:		1,240,886
Goodwill	$	739,898

During the three months ended September 30, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of Hygo due to additional information utilized to determine fair value during the measurement period. The measurement period adjustment impacted the fair value of debt assumed, including associated impacts to non-controlling interests and deferred tax liabilities. The measurement period adjustment decreased goodwill by $7,039, and the Company recognized additional interest expense of $1,088 in the three months ended September 30, 2021.

The fair value of Hygo’s non-controlling interest (“NCI”) as of April 15, 2021 was $36,115, including the fair value of the net assets of VIEs that Hygo has consolidated. These VIEs are special purpose vehicles (“SPV”) for the sale and leaseback of certain vessels, and Hygo has no equity investment in these entities. The fair value of NCI was determined based on the valuation of the SPV’s external debt and the lease receivable asset associated with the sales leaseback transaction with Hygo’s subsidiary, using a discounted cash flow method.

The fair value of receivables acquired from Hygo is $8,009, which approximates the gross contractual amount; no material amounts are expected to be uncollectible.

Goodwill is calculated as the excess of the purchase price over the net assets acquired. Goodwill represents access to additional LNG and natural gas distribution systems and power markets, including a local workforce that will allow the Company to rapidly develop and deploy LNG to power solutions.

The Company’s results of operations for the nine months ended September 30, 2021 include Hygo’s result of operations from the date of acquisition, April 15, 2021, through September 30, 2021. Revenue and net income (loss) attributable to Hygo during the period was $42,136 and $9,324, respectively.

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GMLP Merger

On April 15, 2021, the Company completed the acquisition of all of the outstanding common units, representing all voting interests, of GMLP in exchange for $3.55 in cash per common unit and for each of the outstanding membership interest of GMLP’s general partner. In conjunction with the closing of the GMLP Merger, NFE simultaneously extinguished a portion of GMLP’s debt for total consideration of $1.15 billion.

With the acquisition of GMLP, the Company gains vessels to support the existing terminals and business development pipeline, as well as an interest in a floating natural gas facility (“FLNG”), which is expected to provide consistent cash flow streams under a long-term tolling arrangement. The interest in the FLNG facility also provides the Company access to intellectual property that will be used to develop future FLNG solutions.

The consideration paid by the Company in the GMLP Merger was as follows:

Consideration				As of April 15, 2021
GMLP Common Units ($3.55 per unit x 69,301,636 units)	$	246,021
GMLP General Partner Interest ($3.55 per unit x 1,436,391 units)		5,099
Partnership Phantom Units ($3.55 per unit x 58,960 units)		209
Cash Consideration				$	251,329
GMLP debt repaid in acquisition		899,792
Total Cash Consideration					1,151,121
Cash settlement of preexisting relationship		(3,978	)
Total Consideration				$	1,147,143

The Company has determined it is the accounting acquirer of GMLP, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of GMLP based on their respective estimated fair values as of the closing date.

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The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment in determining the appropriate assumptions and estimates. The Company is in the process of finalizing the valuation of assets acquired, liabilities assumed and non-controlling interests of GMLP, and therefore the purchase price allocation should be considered preliminary. The preliminary purchase price allocation may be subject to further refinement as the evaluation of the underlying inputs and assumptions of third-party valuations and the assessment of acquisition-related income taxes are finalized. The goodwill balance may be adjusted pending the completion of the valuation of the assets acquired, liabilities assumed and non-controlling interests of GMLP as described above. The preliminary estimates may be subject to adjustments during the measurement period, not to exceed one year, based upon new information obtained about facts and circumstances that existed as of the acquisition date. Preliminary fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of GMLP as of the closing date were as follows:

GMLP	As of April 15, 2021
Assets Acquired
Cash and cash equivalents	$	41,461
Restricted cash		24,816
Accounts receivable		3,195
Inventory		2,151
Other current assets		2,789
Equity method investments		355,500
Property, plant and equipment, net		1,063,215
Intangible assets, net		120,000
Deferred tax assets, net		963
Other non-current assets		4,400
Total assets acquired:	$	1,618,490
Liabilities Assumed
Current portion of long-term debt	$	158,073
Accounts payable		3,019
Accrued liabilities		17,226
Other current liabilities		73,774
Deferred tax liabilities, net		16,008
Other non-current liabilities		10,630
Total liabilities assumed:		278,730
Non-controlling interest		192,851
Net assets to be acquired:		1,146,909
Goodwill	$	234

During the three months ended September 30, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of GMLP due to additional information utilized to determine fair value during the measurement period. The measurement period adjustment impacted the fair value of debt assumed, including associated impacts to non-controlling interests. The measurement period adjustment decreased goodwill by $1,431, and the Company recognized an amortization of the discount on debt of $11,119 as an addition to interest expense for the period after the GMLP Merger.

The fair value of GMLP’s NCI as of April 15, 2021 was $192,851, which represents the fair value of other investors’ interest in the Mazo, GMLP’s preferred units which were not acquired by the Company and the fair value of net assets of an SPV formed for the purpose of a sale and leaseback of the Eskimo. The fair value of GMLP’s preferred units and the valuation of the SPV’s external debt and the lease receivable asset associated with the sale leaseback transaction have been estimated using a discounted cash flow method.

The fair value of receivables acquired from GMLP is $4,797, which approximates the gross contractual amount; no material amounts are expected to be uncollectible.

The Company acquired favorable and unfavorable leases for the use of GMLP’s vessels. The fair value of the favorable contracts is $120,000 and the fair value of the unfavorable contracts is $13,400. The total weighted average amortization period is approximately three years; the favorable contract asset has a weighted average amortization period of approximately three years and the unfavorable contract liability has a weighted average amortization period of approximately one year.

The Company and GMLP had an existing lease agreement prior to the GMLP Merger. As a result of the acquisition, the lease agreement and any associated receivable and payable balances are effectively settled. The lease agreement also included provisions that required a subsidiary of NFE to indemnify GMLP to the extent that GMLP incurred certain tax liabilities as a result of the lease. A loss of $3,978 related to settlement of this indemnification provision was recognized in Transaction and integration costs in the condensed consolidated statements of operations and comprehensive loss in the second quarter of 2021.

The Company’s results of operations for the nine months ended September 30, 2021 include GMLP’s result of operations from the date of acquisition, April 15, 2021, through September 30, 2021. Revenue and net income (loss) attributable to GMLP during this period was $123,261 and $82,310, respectively.

Acquisition costs associated with the Mergers of $58 and $33,530 for the three and nine months ended September 30, 2021 were included in Transaction and integration costs in the Company’s condensed consolidated statements of operations and comprehensive loss.

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Unaudited pro forma financial information

The following table summarizes the unaudited pro forma condensed financial information of the Company as if the Mergers had occurred on January 1, 2020.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Revenue	$	304,656		$	229,619		$	780,875		$	571,892
Net income (loss)		(8,994	)		(35,127	)		(75,963	)		(357,190	)
Net income (loss) attributable to stockholders		(12,822	)		(36,870	)		(95,954	)		(281,127	)

The unaudited pro forma financial information is based on historical results of operations as if the acquisitions had occurred on January 1, 2020, adjusted for transaction costs incurred, adjustments to depreciation expense associated with the recognition of the fair value of vessels acquired, additional amortization expense associated with the recognition of the fair value of favorable and unfavorable customer contracts for vessel charters, additional interest expense as a result of incurring new debt and extinguishing historical debt, elimination of a pre-existing lease relationship between the Company and GMLP, and a step-up of the equity method investments and a favorable power purchase agreement contract.

Pro forma net income (loss) for the nine months ended September 30, 2020 includes non-recurring expenses associated with the Mergers of $37,508; such non-recurring expenses have been removed from the pro forma financial information for the nine months ended September 30, 2021. Transaction costs incurred and the elimination of a pre-existing lease relationship between the Company and GMLP are considered to be non-recurring. The unaudited pro forma financial information does not give effect to any synergies, operating efficiencies or cost savings that may result from the Mergers.

GLNG management and services agreements

In connection with the closing of the Mergers, the Company entered into multiple agreements with Golar Management Limited, a subsidiary of GLNG (“Golar Management”), including omnibus agreements, transition services agreements, ship management agreements and other services agreements described as follows:

•

The Company and Golar Management entered into transition service agreements whereby Golar Management provides certain administrative and consulting services to facilitate the integration of GMLP and Hygo (the “Transition Services Agreements”). The Transition Services Agreements commenced on April 15, 2021 and will terminate on April 30, 2022 unless terminated earlier by either party. The Company pays Golar Management monthly payments of $250 and will reimburse Golar Management for all reasonable and documented out-of-pocket expenses or remittances of funds paid to a third party in connection with the provision of the Transition Services.

•

The Company’s vessel-owning subsidiaries entered into ship management agreements with Golar Management (the “Ship Management Agreements”), pursuant to which Golar Management provides certain technical, crew, insurance and commercial management services for the acquired vessels for a specified annual cost per vessel. The Ship Management Agreements commenced on April 15, 2021 will continue until terminated by either party by notice, in which event the relevant Ship Management Agreements will terminate upon the later of 12 months after April 15, 2021 or two months from the date on which such notice is received.

•

The Company also entered into certain agreements to facilitate the integration of the acquired businesses and their operations whereby GLNG or its subsidiaries will continue to provide certain guarantees and indemnities under charter arrangements or GMLP’s and Hygo’s sale leaseback agreements. NFE pays the relevant Charter Guarantor or Golar an annual guarantee fee of $250 per vessel.

•

The Company and Golar Management (Bermuda) Limited (“Golar Bermuda”) entered into a services agreement (the “Bermuda Services Agreement”) pursuant to which Golar Bermuda will act as GMLP’s and Hygo’s registered office in Bermuda and provide certain corporate secretarial, registrar and administration services (the “Bermuda Services Agreements”). The Bermuda Services Agreements commenced on April 15, 2021. Either party may terminate the Bermuda Services Agreements upon 30 days’ prior written notice. Golar Partners and Hygo pay Golar Bermuda an aggregate annual fee of $50 for the Bermuda services and will reimburse Golar Bermuda for all incidental documented costs and expenses reasonably incurred by Golar Bermuda and its designees in connection with the provision of the Bermuda services.

During the period subsequent to the completion of the Mergers, the Company incurred $3,387 and $6,487 for the three and nine months ended September 30, 2021, respectively, in management, services or guarantee fees under these agreements with GLNG, Golar Management or GLNG affiliated entities.

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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 1.37 GW 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 approximately $3,600. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $3,047 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the condensed consolidated balance sheets. 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. For the three and nine months ended September 30, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $62 and $9, respectively, which is presented in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss.

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 were included in the purchase consideration. The total purchase consideration of $5,776, which includes a deferred tax liability of $1,531 recognized as a result from the acquisition, was allocated to permits and authorizations acquired and was recorded within Intangible assets, net.

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 as of the acquisition date of $7,473 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the condensed consolidated balance sheets. 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. For the three and nine months ended September 30, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $843 and $427, respectively, which is presented in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss.

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 Intangible assets, net on the condensed consolidated balance sheets; the remaining purchase consideration was related to working capital acquired.

VIEs

Lessor VIEs

The Company assumed sale leaseback arrangements for four vessels as part of the Mergers. The counterparty to each of these sale leaseback arrangements is a VIE, and these lessor VIEs are SPVs wholly owned by financial institutions. While the Company does not own hold an equity investment in these entities, these lessor VIEs are consolidated in the condensed consolidated financial statements. As the Company has no equity attributable to these lessor VIEs, all equity attributable to these lessor VIEs is included in non- controlling interests in the condensed consolidated financial statements. Transactions between our wholly-owned subsidiaries and these VIEs are eliminated in consolidation, including sale leaseback transactions.

China Merchants Bank Lending (“CMBL”)

In November 2015, the Eskimo was sold to a subsidiary of CMBL, Sea 23 Leasing Co. Limited, and subsequently leased back under a bareboat charter for a term of ten years. The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the ten-year lease period.

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CCB Financial Leasing Corporation Limited (“CCBFL”)

In September 2018, the Nanook was sold to a subsidiary of CCBFL, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years. The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period.

Oriental Shipping Company (“COSCO”)

In December 2019, the Penguin was sold to a subsidiary of COSCO, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years. The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period.

AVIC International Leasing Company Limited (“AVIC”)

In March 2020, the Celsius was sold to a subsidiary of AVIC, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years. The Company has options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period.

While the Company does not hold an equity investment in the above SPVs, the Company has a variable interest in these SPVs. The Company is the primary beneficiary of these VIEs and, accordingly, these VIEs are consolidated into the Company’s financial results for the period after the Mergers. The effect of the bareboat charter arrangements is eliminated upon consolidation of the SPVs. The equity attributable to CMBL, CCBFL, COSCO and AVIC in their respective VIEs are included in non-controlling interests in the condensed consolidated financial statements. As of September 30, 2021, the Eskimo, Penguin and Celsius are recorded as Property, plant and equipment, net on the condensed consolidated balance sheet, and the Nanook was recognized in Finance leases, net on the condensed consolidated balance sheet.

The following table gives a summary of the sale and leaseback arrangements, including repurchase options and obligations as of September 30, 2021:

Vessel	End of lease term	Date of next repurchase option	Repurchase price at next repurchase option date		Repurchase obligation at end of lease term
Eskimo	$November 2025	$November 2021	$	189,100	$	128,250
Nanook	September 2030	December 2021		202,116		94,179
Penguin	December 2025	December 2021		92,761		63,040
Celsius	March 2027	March 2022		98,290		45,000

A summary of payment obligations under the bareboat charters with the lessor VIEs as of September 30, 2021, are shown below:

Vessel	Remaining 2021		2022		2023		2024		2025		_2026+
Eskimo	$	3,353	$	-	$	-	$	-	$	-	$	-
Nanook		5,477		21,561		20,964		20,390		19,768		85,754
Penguin		2,955		11,663		11,322		10,962		8,002		-
Celsius		3,976		15,574		15,023		14,484		13,922		12,753

The payment obligation table above includes variable rental payments due under the lease based on an assumed LIBOR plus margin but excludes the repurchase obligation at the end of lease term.

The assets and liabilities of these lessor VIEs that most significantly impact the condensed consolidated balance sheet as of September 30, 2021 are as follows:

	Eskimo		Nanook		Penguin		Celsius
Assets
Restricted cash	$	-	$	19,533	$	9,690	$	24,924
Liabilities
Long-term interest bearing debt - current portion	$	152,004	$	-	$	18,813	$	5,870
Long-term interest bearing debt - non-current portion		-		202,006		77,738		110,336

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As a result of the Mergers, the most significant impact of the lessor VIEs operations on the Company’s condensed consolidated statement of operations is an addition to interest expense of $15,263 and $8,628 for the three and nine months ended September 30, 2021, respectively. Upon assumption of the debt held by VIEs in conjunction with the Mergers, the Company recognized the liabilities assumed at fair value, and the amortization of the discount of $11,550 and $1,843 has been recognized as an addition to interest expense incurred of $3,713 and $6,785 for the three and nine months ended, respectively. The most significant impact of the lessor VIEs cash flows on the condensed consolidated statements of cash flows is net cash used in financing activities of $21,061 for the period subsequent to the completion of the Mergers.

Other VIEs

Hilli LLC

The Company acquired an interest of 50% of the common units of Hilli LLC (“Hilli Common Units”) as part of the acquisition of GMLP. Hilli LLC owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Company determined that Hilli LLC is a VIE, and the Company is not the primary beneficiary of Hilli LLC. Thus, Hilli LLC has not been consolidated into the financial statements and has been recognized as an equity method investment.

As of September 30, 2021 the maximum exposure as a result of the Company’s ownership in the Hilli LLC is the carrying value of the equity method investment of $363,543 and the outstanding portion of the Hilli Leaseback (defined below) which have been guaranteed by the Company.

Revenue recognition

Operating revenue 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. Other revenue includes revenue for development services as well as interest income from the Company’s finance leases and other revenue. The table below summarizes the balances in Other revenue:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Development services revenue	$	25,264	$	51,974	$	125,924	$	79,540
Interest income and other revenue		12,347		1,021		22,617		2,872
Total other revenue	$	37,611	$	52,995	$	148,541	$	82,412

Development services revenue recognized in the three and nine months ended September 30, 2021 included $25,264 and $114,654, respectively, for the customer’s use of natural gas as part of commissioning their assets.

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of September 30, 2021 and December 31, 2020, receivables related to revenue from contracts with customers totaled $126,783 and $76,431, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $130 and $98, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases which are accounted for outside the scope of ASC 606 and receivables associated with reimbursable costs.

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 September 30, 2021 and December 31, 2020 are detailed below:

	September 30, 2021		December 31, 2020
Contract assets, net - current	$	7,310	$	4,029
Contract assets, net - non-current		38,554		30,434
Total contract assets, net	$	45,864	$	34,463

Contract liabilities	$	2,371	$	8,399

Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	6,340	$	6,542

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Contract assets are presented net of expected credit losses of $530 and $376 as of September 30, 2021 and December 31, 2020, respectively. As of September 30, 2021 and December 31, 2020, contract assets was comprised of $45,513 and $6,821 of unbilled receivables, respectively, that represent unconditional rights to payment only subject to the passage of time.

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 September 30, 2021, the Company has capitalized $11,132, of which $604 of these costs is presented within Other current assets and $10,528 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.

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 represents 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	$	67,761
2022		474,995
2023		515,235
2024		511,719
2025		503,099
Thereafter		8,446,430
Total	$	10,519,239

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.

Lessor arrangements

The Company’s vessel charters of LNG carriers and FSRUs can take the form of operating or finance leases. Property, plant and equipment subject to vessel charters accounted for as operating leases is included within Vessels within Note 14 Property, plant and equipment, net. The following is the carrying amount of property, plant and equipment that is leased to customers under operating leases:

	September 30, 2021			December 31, 2020
Property, plant and equipment	$	1,274,293		$	18,394
Accumulated depreciation		(20,128	)		(932	)
Property, plant and equipment, net	$	1,254,165		$	17,462

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The components of lease income from vessel operating leases for the three and nine months ended September 30, 2021 were as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2021		September 30, 2021
Operating lease income	$	74,069	$	136,095
Variable lease income		3,096		4,466
Total operating lease income	$	77,165	$	140,561

The Company’s charter of the Nanook to CELSE and certain equipment leases provided in connection with the supply of natural gas or LNG are accounted for as finance leases.

The Company recognized interest income of $11,607 and $21,288 for the three months and nine months ended September 30, 2021, respectively, related to the finance lease of the Nanook included within Other revenue in the condensed consolidated statements of operations and comprehensive loss. The Company recognized revenue of $1,491 and $2,656 for the three months and nine months ended September 30, 2021, respectively, related to the operation and services agreement within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss.

As of September 30, 2021, there were outstanding balances due from CELSE of $6,183, of which $4,210 is recognized in Receivables, net and a loan to CELSE of $1,973 is recognized in Prepaid expenses and other current assets, net on the condensed consolidated balance sheets. CELSE is an affiliate due to the equity method investment held in CELSE’s parent, CELSEPAR, and as such, these transactions and balances are related party in nature.

The following table shows the expected future lease payments as of September 30, 2021, for the remainder of 2021 through 2025 and thereafter:

	Future cash receipts
	Financing Leases		Operating Leases
Remainder of 2021	$	12,478	$	64,827
2022		49,951		244,239
2023		50,616		144,375
2024		51,442		105,572
2025		51,876		25,961
Thereafter		1,104,102		-
Total minimum lease receivable	$	1,320,465	$	584,974
Unguaranteed residual value		107,000
Gross investment in sales-type lease	$	1,427,465
Less: Unearned interest income		818,758
Less: Current expected credit losses		1,546
Net investment in leased vessel	$	607,161

Current portion of net investment in leased asset	$	3,499
Non-current portion of net investment in leased asset		603,662

Leases, as 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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As of September 30, 2021 and December 31, 2020, right-of-use assets, current lease liabilities and non-current lease liabilities consisted of the following:

	September 30, 2021		December 31, 2020
Operating right-of-use-assets	$	126,424	$	141,347
Finance right-of-use-assets ⁽¹⁾		19,517		-
Total right-of-use assets	$	145,941	$	141,347

Current lease liabilities:
Operating lease liabilities	$	28,871	$	35,481
Finance lease liabilities		3,138		-
Total current lease liabilities	$	32,009	$	35,481
Non-current lease liabilities:
Operating lease liabilities	$	80,736	$	84,323
Finance lease liabilities		12,585		-
Total non-current lease liabilities	$	93,321	$	84,323

(1) Finance lease right-of-use assets are recorded net of accumulated amortization of $289 as of September 30, 2021.

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For the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Fixed lease cost	$	9,450	$	11,160	$	30,231	$	28,024
Variable lease cost		221		1,054		1,417		1,767
Short-term lease cost		523		473		2,752		1,088

Lease cost - Cost of sales	$	7,954	$	10,690	$	27,983	$	26,150
Lease cost - Operations and maintenance		486		619		1,592		1,447
Lease cost - Selling, general and administrative		1,754		1,378		4,825		3,282

For the three and nine months ended September 30, 2021, the Company has capitalized $5,297 and $8,809 of lease costs, respectively, 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 transport inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.

Beginning in the second quarter of 2021, leases for ISO tanks and a parcel of land that transfer the ownership in underlying assets to the Company at the end of the lease have commenced, and these leases are treated as finance leases. For the three and nine months ended September 30, 2021, the Company recognized interest expense related to finance leases of $152 and $202, respectively, which are included within Interest expense, net in the condensed consolidated statements of operations and comprehensive loss. For the three and nine months ended September 30, 2021, the Company recognized amortization of the right-of-use asset related to finance leases of $228 and $289, respectively, which are included within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive loss.

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 nine months ended September 30, 2021 and 2020:

	Nine Months Ended September 30,
	2021		2020
Operating cash outflows for operating lease liabilities	$	26,905	$	32,230
Financing cash outflows for finance lease liabilities		1,092		-
Right-of-use assets obtained in exchange for new operating lease liabilities		7,377		172,053
Right-of-use assets obtained in exchange for new finance lease liabilities		19,805		-

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The future payments due under operating and finance leases as of September 30, 2021 are as follows:

	Operating Leases		Financing Leases
Due remainder of 2021	$	9,788	$	1,218
2022		33,540		3,449
2023		26,868		3,519
2024		20,496		3,538
2025		12,085		3,538
Thereafter		61,417		2,883
Total Lease Payments	$	164,194	$	18,145
Less: effects of discounting		54,587		2,422
Present value of lease liabilities	$	109,607	$	15,723

Current lease liability	$	28,871	$	3,138
Non-current lease liability		80,736		12,585

As of September 30, 2021, the weighted-average remaining lease term for operating leases was 8.4 years and finance leases was 5.4 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 September 30, 2021 was 8.5%. The weighted average discount rate associated with finance leases as of September 30, 2021 was 5.1%.

The Company has entered into several leases for ISO tanks that have not commenced as of September 30, 2021 with noncancelable terms of 5 years and including fixed payments of approximately $6.3 million.

8.	Financial instruments

Interest rate and currency risk management

In connection with the Mergers, the Company has acquired financial instruments that GMLP and Hygo used to reduce the risk associated with fluctuations in interest rates and foreign exchange rates. Interest rate swaps are used to convert floating rate interest obligations to fixed rates, which from an economic perspective hedges the interest rate exposure. The Company also acquired a cross currency interest rate swap to manage interest rate exposure on the Debenture Loan and the foreign exchange rate exposure on the US dollar cash flows from the charter of the Nanook to CELSE that guarantees the repayments of the Brazilian Real-denominated Debenture Loan.

The Company does not hold or issue instruments for speculative or trading purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties.

The following table summarizes the terms of interest rate and cross currency interest rate swaps as of September 30, 2021:

Instrument	Notional Amount		Maturity Dates	Fixed Interest Rate	Forward Foreign Exchange Rate
Interest rate swap: Receiving floating, pay fixed	$	372,750,000	March 31, 2026	_2.86%	N/A
Cross currency interest rate swap - Debenture Loan, due 2024	BRL 230,100,142		September 2024	_5.90%	_5.424

The mark-to-market gain or loss on our interest rate and foreign currency swaps that are not designated as hedges for accounting purposes for the period are reported in the condensed consolidated statements of operations and comprehensive loss in Other (income) expense, net.

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.

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•	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, including those that are measured at fair value, as of September 30, 2021 and December 31, 2020:

_	Fair Value Hierarchy	September 30, 2021 Carrying Value		September 30, 2021 Fair Value		December 31, 2020 Carrying Value		December 31, 2020 Fair Value		Valuation Technique
Non-Derivatives:
Cash and cash equivalents	Level 1	$	224,383	$	224,383	$	601,522	$	601,522	Market approach
Restricted cash	Level 1		110,217		110,217		27,814		27,814	Market approach
Investment in equity securities	Level 1		12,421		12,421		256		256	Market approach
Investment in equity securities	Level 3		1,849		1,849		1,000		1,000	Market approach
Long-term debt⁽¹⁾	Level 2		3,888,894		3,685,935		1,250,000		1,327,488	Market approach
Derivatives:
Derivative liability⁽²⁾⁽³⁾	Level 3		31,803		31,803		10,716		10,716	Income approach
Equity agreement⁽³⁾⁽⁴⁾	Level 3		18,893		18,893		22,768		22,768	Income approach
Interest rate swap liability⁽⁵⁾⁽⁶⁾	Level 2		28,046		28,046		-		-	Income approach

⁽¹⁾Long-term debt is recorded at amortized cost on the condensed consolidated balance sheets, and is presented in the above table gross of deferred financing costs of $41,483 and $10,439 as of September 30, 2021 and December 31, 2020, respectively.

⁽²⁾Consideration due to the sellers in assets acquisitions when certain contingent events occur. The liability associated with the derivative liabilities is recorded within Other long-term liabilities on the condensed consolidated balance sheets.

⁽³⁾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.

⁽⁴⁾To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received for the facility in development in Shannon, Ireland. The liability associated with the equity agreement is recorded within Other current liabilities on the condensed consolidated balance sheets.

⁽⁵⁾Interest rate swap liability and cross currency interest rate swap liability is presented within Other current liabilities on the condensed consolidated balance sheets.

⁽⁶⁾The fair value of certain derivative instruments, including interest rate swaps, is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties.

The Company believes the carrying amounts of cash and cash equivalents, accounts receivable, finance lease receivables and accounts payable approximated their fair value as of September 30, 2021 and December 31, 2020.

As part of the Hygo Merger, the Company assumed liabilities for payments due to sellers in asset acquisitions completed prior to the Hygo Merger, and these liabilities are reflected as derivative liabilities. Activity during the nine months ended September 30, 2021 also included the recognition of additional derivative liabilities from transactions accounted for as asset acquisitions of $10,520 (Note 4). During the three and nine months ended September 30, 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 table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, the derivative liability and equity agreement, as well as the cross currency interest rate swap and the interest rate swap. These adjustments have been recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021			2020
Derivative liability/Equity agreement - Fair value adjustment - Loss (Gain)	$	155	$	2,892	$	(558	)	$	2,598
Interest rate swap - Fair value adjustment - Loss (gain)		227		-		(119	)		-
Cross currency interest rate swap - Fair value adjustment - Loss (gain)		4,051		-		(1,962	)		-

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Under the Company’s interest rate swap, the Company is required to provide cash collateral, and as of September 30, 2021, $12,500 of cash collateral is presented as restricted cash on the condensed consolidated balance sheets.

Restricted cash

As of September 30, 2021 and December 31, 2020, restricted cash consisted of the following:

	September 30, 2021		December 31, 2020
Cash held by lessor VIEs	$	54,147	$	-
Collateral for interest rate swaps		12,500		-
Collateral for performance under customer agreements		15,000		15,000
Collateral for LNG purchases		-		11,664
Collateral for letters of credit and performance bonds		27,814		900
Other restricted cash		756		250
Total restricted cash	$	110,217	$	27,814

Current restricted cash	$	72,338	$	12,814
Non-current restricted cash		37,879		15,000

Restricted cash does not include minimum consolidated cash balances of $30,000 required to be maintained as part of the financial covenants for sale and leaseback financings and the Vessel Term Loan Facility that is included in Cash and cash equivalents on the condensed consolidated balance sheets as of September 30, 2021.

10.

Inventory

As of September 30, 2021 and December 31, 2020, inventory consisted of the following:

	September 30, 2021		December 31, 2020
LNG and natural gas inventory	$	66,660	$	13,986
Automotive diesel oil inventory		4,659		3,986
Bunker fuel, materials, supplies and other		11,071		4,888
Total inventory	$	82,390	$	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 nine months ended September 30, 2021 and 2020.

11.

Prepaid expenses and other current assets

As of September 30, 2021 and December 31, 2020, prepaid expenses and other current assets consisted of the following:

	September 30, 2021		December 31, 2020
Prepaid LNG	$	6,143	$	11,987
Prepaid expenses		10,710		4,941
Due from affiliates		2,919		1,881
Other current assets		55,830		29,461
Total prepaid expenses and other current assets, net	$	75,602	$	48,270

Other current assets as of September 30, 2021 and December 31, 2020 primarily consists of receivables for recoverable taxes and deposits.

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12.	Equity method investments

As a result of the Mergers, the Company acquired investments in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and Hilli LLC, both of which have been recognized as equity method investments. The Company has a 50% ownership interest in both entities. The investments are reflected in the Terminals and Infrastructure and Ships segments, respectively.

Changes in the balance of the Company’s equity method investments is as follows:

	September 30, 2021
Equity method investments as of December 31, 2020	$	-
Acquisition of equity method investments in the Mergers		1,179,021
Dividends		(14,259	)
Equity in earnings / losses of investees		22,958
Foreign currency translation adjustment		40,271
Equity method investments as of September 30, 2021	$	1,227,991

The carrying amount of equity method investments as of September 30, 2021 is as follows:

	September 30, 2021
Hilli LLC	$	363,543
CELSEPAR		864,448
Total	$	1,227,991

As of September 30, 2021, the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $930,071. In conjunction with the preliminary purchase accounting for the Mergers, the basis difference was allocated to tangible assets, identifiable intangible assets, liabilities and goodwill, and the basis difference attributable to amortizable net assets is amortized to (Loss) income from equity method investments over the remaining estimated useful lives of the underlying assets.

CELSEPAR

CELSEPAR is jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounts for this 50% investment using the equity method. CELSEPAR owns 100% of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of the Sergipe Power Plant.

Hilli LLC

The Company acquired an interest of 50% of the Hilli Common Units as part of the acquisition of GMLP. The ownership interests in Hilli LLC are represented by three classes of units, Hilli Common Units, Series A Special Units and Series B Special Units. The Company did not acquire any of the Series A Special Units or Series B Special Units. The Hilli Common Units provide the Company with significant influence over Hilli LLC. The Hilli is currently operating under an 8-year liquefaction tolling agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures.

Within 60 days after the end of each quarter, GLNG, the managing member of Hilli LLC, shall determine the amount of Hilli LLC’s available cash and appropriate reserves, and Hilli LLC shall make a distribution to the unitholders of Hilli LLC (“Hilli Unitholders”) of the available cash, subject to such reserves. Hilli LLC shall make distributions to the Hilli Unitholders when, as and if declared by GLNG; provided, however, that no distributions may be made on the Hilli Common Units on any distribution date unless Series A Distributions and Series B Distributions for the most recently ended quarter and any accumulated Series A Distributions and Series B Distributions in arrears for any past quarter have been or contemporaneously are being paid or provided for.

Series A Distributions are calculated based on cash received by Hilli Corp for any tolling fees under the LTA relating to an increase in the Brent Crude price above $60 per barrel, adjusted by incremental taxes and costs that arise from underperformance of the Hilli. Series B Distributions are calculated as 95% of “Revenues Less Expenses”, which is based on the cash receipts as a direct result of the employment of more than the first 50% of LNG production capacity for the Hilli, adjusted for incremental operating expenses, capital costs, financing and tax costs associated with making more than 50% capacity available and costs that arise from underperformance. The Hilli Common Units may receive 5% of Revenues less Expenses received by Hilli Corp during such quarter.

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The Company is required to reimburse other investors in Hilli LLC for 50% of the amount, if any, by which certain operating expenses and withholding taxes of Hilli LLC are below an annual threshold for up to $20,000 in the aggregate through 2026. Other investors are required to reimburse the Company for 50% of the amount, if any, by which certain operating expenses and withholding taxes are above an annual threshold for up to $20,000 in the aggregate through 2026. No operating expense reimbursements were included in distributions for the period after the GMLP Merger.

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”). The Hilli Leaseback provided for postconstruction financing for the Hilli in the amount of $960 million. Under the Hilli Leaseback, Hilli Corp will pay to Fortune forty consecutive equal quarterly repayments of 1.375% of the construction cost, plus interest based on LIBOR plus a margin of 4.15%.

13.

Construction in progress

The Company’s construction in progress activity during the nine months ended September 30, 2021 is detailed below:

	September 30, 2021
Balance at beginning of period	$	234,037
Acquisition of construction in progress from business combinations		128,625
Additions		608,043
Impact of change in FX rates		9,803
Transferred to property, plant and equipment, net or finance leases		(6,628	)
Balance at end of period	$	973,880

Interest expense of $18,924 and $22,441, inclusive of amortized debt issuance costs, was capitalized for the nine months ended September 30, 2021 and 2020, respectively.

14.

Property, plant and equipment, net

As of September 30, 2021 and December 31, 2020, the Company’s property, plant and equipment, net consisted of the following:

	September 30, 2021			December 31, 2020
Vessels	$	1,441,211		$	-
Terminal and power plant equipment		189,472			188,855
CHP facilities		122,776			119,723
Gas terminals		120,810			120,810
ISO containers and other equipment		120,041			100,137
LNG liquefaction facilities		63,213			63,213
Gas pipelines		58,987			58,974
Land		16,714			16,246
Leasehold improvements		9,256			8,723
Accumulated depreciation		(116,792	)		(62,475	)
Total property, plant and equipment, net	$	2,025,688		$	614,206

Depreciation for the three months ended September 30, 2021 and 2020 totaled $23,929 and $9,370, respectively, of which $322 and $212, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. Depreciation for the nine months ended September 30, 2021 and 2020 totaled $55,070 and $22,120, respectively, of which $898 and $662 is respectively included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss.

Capitalized drydocking costs of $6,573 are included in the vessel cost for September 30, 2021 which are depreciated from the completion of drydocking until the next expected dry docking.

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15.

Intangible assets

The following table summarizes the composition of intangible assets as of September 30, 2021 and December 31, 2020:

	September 30, 2021
	Gross Carrying Amount		Accumulated Amortization			Currency Translation Adjustment		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Favorable vessel charter contracts	$	120,000	$	(18,974	)	$	-	$	101,026		3
Permits and development rights		49,285		(3,643	)		145		45,787		40
Acquired power purchase agreements		16,585		-			1,028		17,613		17
Easements		1,559		(229	)		-		1,330		30

Indefinite-lived intangible assets
Easements		1,191		-			17		1,208		n/a
Total intangible assets	$	188,620	$	(22,846	)	$	1,190	$	166,964

	December 31, 2020
	Gross Carrying Amount		Accumulated Amortization			Currency Translation Adjustment		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Permits	$	42,441	$	(2,438	)	$	3,456	$	43,459		40
Easements		1,559		(190	)		-		1,369		30

Indefinite-lived intangible assets
Easements		1,191		-			83		1,274		n/a
Total intangible assets	$	45,191	$	(2,628	)	$	3,539	$	46,102

In conjunction with the Mergers, the Company acquired charter contracts with contractual rates that were favorable as compared to market rates and on the date of acquisition recognized intangible assets of $120,000. 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 4. Acquisitions).

As of September 30, 2021 and December 31, 2020, the weighted-average remaining amortization periods for the intangible assets were 12.7 and 37.5 years, respectively. Amortization expense for the three months ended September 30, 2021 and 2020 totaled $7,334 and $309, respectively. Amortization expense was $13,550 and $861 for the nine months ended September 30, 2021 and 2020, respectively.

16.

Other non-current assets

As of September 30, 2021 and December 31, 2020, Other non-current assets consisted of the following:

	September 30, 2021		December 31, 2020
Nonrefundable deposit	$	30,335	$	28,509
Contract asset, net (Note 6)		38,554		30,434
Cost to fulfill (Note 6)		10,528		10,688
Upfront payments to customers		9,934		6,330
Other		31,791		10,069
Total other non-current assets, net	$	121,142	$	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 investments in equity securities of $14,270 and $1,256 as of September 30, 2021 and December 31, 2020. The Company recognized unrealized gains of $7,176 and $7,264 for the three and nine months ended September 30, 2021 within Other (income), net in the condensed consolidated statements of operations and comprehensive loss. Other also includes upfront payments to our service providers and a long-term refundable deposit.

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17.

Accrued liabilities

As of September 30, 2021 and December 31, 2020, accrued liabilities consisted of the following:

	September 30, 2021		December 31, 2020
Accrued development costs	$	52,646	$	16,631
Accrued interest		15,235		27,938
Accrued consideration in asset acquisitions		18,660		-
Accrued bonuses		19,517		17,344
Accrued vessel operating and drydocking expenses		12,601		-
Other accrued expenses		40,645		28,439
Total accrued liabilities	$	159,304	$	90,352

18.

Debt

As of September 30, 2021 and December 31, 2020, debt consisted of the following:

	September 30, 2021		December 31, 2020
Senior Secured Notes, due September 15, 2025	$	1,240,677	$	1,239,561
Senior Secured Notes, due September 30, 2026		1,477,638		-
Vessel Term Loan Facility, due September 18, 2024		423,839		-
Debenture loan due 2024		42,126		-
CHP Facility		96,364		-
Revolving Facility		-		-
Subtotal (excluding lessor VIE loans)		3,280,644		1,239,561
CMBL VIE loan:
Golar Eskimo SPV facility, due 2025		152,004		-
CCBFL VIE loan:
Golar Nanook SPV facility, due 2030		202,006		-
COSCO VIE loan:
Golar Penguin SPV facility, due 2025		96,551		-
AVIC VIE loan:
Golar Celsius SPV facility, due 2023/2027		116,206		-
Total debt	$	3,847,411	$	1,239,561
Current portion of long-term debt	$	249,752	$	-
Long-term debt		3,597,659		1,239,561

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Our outstanding debt as of September 30, 2021 is repayable as follows:

	September 30, 2021
Due remainder of 2021	$	171,850
2022		88,261
2023		135,039
2024		323,689
2025		1,322,536
2026		1,509,874
Thereafter		339,219
Total debt		3,890,468
Add: fair value adjustments to assumed debt obligations		(1,574	)
Less: deferred finance charges		(41,483	)
Total debt, net deferred finance charges	$	3,847,411

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, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.

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 previous 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 previous credit agreement was a modification, in the third quarter of 2020, the Company recognized $4,028 of third-party fees as an expense 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 $4,566. As of September 30, 2021 and December 31, 2020, remaining unamortized deferred financing costs for the 2025 Notes was $9,323 and $10,439, respectively.

2026 Notes

On April 12, 2021, the Company issued $1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. The Company may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, 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.

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

In connection with the issuance of the 2026 Notes, the Company incurred $24,588 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $22,362.

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Vessel Term Loan Facility

On September 18, 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”). Under this facility, the Company borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels.

Loans under the Vessel Term Loan Facility bear interest at a rate of LIBOR plus a margin of 3 percent. The Vessel Term Loan Facility shall be repaid in quarterly installments of $15,357, with the final repayment date in September 2024. Quarterly principal payments will be increased to reflect any upsize of the Vessel Term Loan Facility to reflect a straight-line amortization profile over the remaining term.

Obligations under the Vessel Term Loan Facility are guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of September 30, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $666,674.

The Company may prepay outstanding indebtedness without penalty, and certain events, such as (i) total loss; (ii) minimum security value; (iii) the sale or transfer of certain vessels; or (iv) the termination of the charter over the Hilli, will require a mandatory prepayment.

The Vessel Term Loan Facility contains customary representations and warranties and customary affirmative and negative covenants, including financial covenants, chartering restrictions, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness and dividends and other distributions. Financial covenants include requirements that GMLP and Golar Partners Operating LLC maintain a certain amount of Free Liquid Assets, that the EBITDA to Consolidated Debt Service and the Net Debt to EBITDA ratios are no less than 1.15:1 and no greater than 6.50:1, respectively, and that Consolidated Net Worth is greater than $250,000, each as defined in the Vessel Term Loan Facility. The Company was in compliance with these covenants as of September 30, 2021.

In connection with the closing the Vessel Term Loan Facility, the Company incurred $6,229 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $6,161.

Debenture Loan

As part of the Hygo Merger, the Company assumed non-convertible Brazilian debentures issued by NFE Brasil, an indirect subsidiary of Hygo, in the aggregate principal amount of BRL 255.6 million ($45.0 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debenture Loan”). The Debenture Loan was recognized at fair value of $44,566 on the date of the Hygo Merger, and the discount recognized in purchase accounting will result in additional interest expense until maturity. Interest and principal is payable on the Debenture Loan semi-annually on September 13 and March 13.

The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares issued by NFE Brasil owned by the Company’s consolidated subsidiary, LNG Power Ltd.

CHP Facility

On August 3, 2021, NFE South Power Holdings Limited, a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially drawing $100,000. The CHP Facility is secured by the Company’s combined heat and power plant in Clarendon, Jamaica. The Company incurred $3,651 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the CHP Facility on the condensed consolidated balance sheets. As of September 30, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,636.

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Revolving Facility

On April 15, 2021, the Company entered into a $200,000 senior secured revolving facility (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 $100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for the Company to extend the maturity date once in a one-year increment.

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

The obligations under the Revolving Facility are guaranteed by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes. The Revolving Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. Financial covenants include requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility). The Company was in compliance with these covenants as of September 30, 2021.

The Company incurred $3,974 in origination, structuring and other fees, associated with entry into the Revolving Facility. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,658.

During the second and third quarters of 2021, the Company drew $152,500 and $47,500 on the Revolving Facility, respectively. During the third quarter of 2021, the Company repaid the amounts outstanding on the Revolving Facility, and as of September 30, 2021, there are no amounts outstanding.

Lessor VIE debt

The Company assumed the following loans in the Mergers related to lessor VIE entities, including CMBL, CCBFL, COSCO and AVIC, that are consolidated as VIEs. Although the Company has no control over the funding arrangements of these entities, the Company is the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the condensed consolidated financial statements.

CMBL – Eskimo SPV facility

The SPV, Sea 23 Leasing Co. Limited, the owner of the Eskimo, has a long-term loan facility that is denominated in USD, has a loan term of ten years and bears interest at a rate of LIBOR plus a margin of 2.66%. As of the acquisition date of GMLP, the outstanding principal balance was $160,520, and the Company recognized the fair value of this facility of $158,072 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity.

CCBFL – Nanook SPV facility

The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, has a long-term loan facility that is denominated in USD, has a loan term of twelve years and bears interest at a fixed rate of 2.7%. As of the acquisition date of Hygo, the outstanding principal balance was $202,249, and the Company recognized the fair value of this facility of $201,484 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity.

COSCO – Penguin SPV facility

The SPV, Oriental Fleet LNG 02 Limited, the owner of the Penguin, has a long-term loan facility that is denominated in USD, is repayable in quarterly installments over a term of approximately six years and bears interest at LIBOR plus a margin of 1.7%. The SPV also has amounts payable to its parent. As of the acquisition date of Hygo, the outstanding principal balance was $104,882, and the Company recognized the fair value of this facility and the amount due to the parent of $105,126 on the date of the Mergers. The premium recognized in purchase accounting will result in a reduction to interest expense until maturity.

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AVIC – Celsius SPV facility

The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, has two long-term loan facilities that are denominated in USD. The first facility is repayable in quarterly installments over a term of approximately seven years with a balloon payment of $37,179 at the end of the term and bears interest at LIBOR plus a margin of 1.8%; the outstanding principal balance as of the acquisition date of this facility was $76,179. The SPV has another facility with its parent for the remaining principal of $45,200 as of the acquisition date, which is due as a balloon payment upon maturity in March 2023 and bears interest at a fixed rate of 4.0%. As of the acquisition date of Hygo, the total outstanding principal balance was $121,379, and the Company recognized the fair value of this facility and the amount due to the parent of $121,308 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity.

Debt and lease restrictions

The VIE loans and certain lease agreements with customers assumed in the Mergers contain certain operating and financing restrictions and covenants that require: (a) certain subsidiaries to maintain a minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70:1. As of September 30, 2021, the Company was in compliance with all covenants under debt and lease agreements.

The Company has also entered into an Uncommitted Letter of Credit and Reimbursement Agreement with a financial institution for the issuance of letters of credit. As of September 30, 2021, the Company had issued $75,000 of letters of credit under this agreement. The Company is required to comply with affirmative and negative covenants customary for such facilities, including financial covenants that are consistent with those under the Revolving Facility. The Company was in compliance with all covenants as of September 30, 2021.

Interest Expense

Interest and related amortization of debt issuance costs, premiums and discounts 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 and nine months ended September 30, 2021 and 2020 consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Interest per contractual rates	$	53,140	$	19,936	$	120,445	$	58,576
Amortization of fair value adjustments to assumed debt obligations		12,207		-		1,912		-
Amortization of debt issuance costs, premiums and discounts		1,710		4,416		4,122		14,766
Interest expense incurred on finance lease obligations		152		-		202		-
Total interest costs	$	67,209	$	24,352	$	126,681	$	73,342
Capitalized interest		9,614		4,539		18,924		22,441
Total interest expense	$	57,595	$	19,813	$	107,757	$	50,901

19.

Income taxes

As a result of the Mergers, the Company recognized deferred tax liabilities to reflect the impact of fair value adjustments, primarily the increased value of equity method investments, which did not impact tax basis. The Company acquired tax attribute carryforwards including net operating losses in certain jurisdictions for which net deferred tax assets have not been recognized as a result of cumulative losses and the developmental status of the entities.

The effective tax rate for the three months ended September 30, 2021 was (24.75)%, compared to (5.27)% for the three months ended September 30, 2020. The total tax provision for the three months ended September 30, 2021 was $3,526, compared to $1,836 for the three months ended September 30, 2020. The effective tax rate for the nine months ended September 30, 2021 was (13.58)%, compared to (0.75)% for the nine months ended September 30, 2020. The total tax provision for the nine months ended September 30, 2021 was $7,058, compared to $1,949 for the nine months ended September 30, 2020. The calculation of the effective tax rate for the period after the Mergers includes income from equity method investments recognized for the three and nine months ended September 30, 2021.

The increases to the tax provision and effective tax rate for both the three and nine months ended September 30, 2021 was primarily driven by an increase in pretax income for certain profitable non-U.S. operations and the inclusion of GMLP and Hygo into expected pre-tax results of operations for the year ended December 31, 2021. Tax expense recognized includes the results of the acquired entities from the date of acquisition through September 30, 2021. For the nine months ended September 30, 2021, these increases in tax expense were partially offset by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $1,800.

The Company assumed a liability for tax contingencies in the Mergers of $19,382 primarily related to potential tax obligations for payments under certain charter agreements for acquired vessels; this liability is included in Other current liabilities on the condensed consolidated balance sheets. The Company has not recorded any other material liabilities for uncertain tax positions as of September 30, 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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20.

Commitments and contingencies

Legal proceedings and claims

The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business, and the Company has evaluated the contingencies that have been assumed in conjunction with the Mergers. 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.

In conjunction with the Mergers, the Company has assumed contingencies for VAT in Indonesia. Indonesian tax authorities have issued letters to PTGI, a consolidated subsidiary, to revoke a previously granted VAT importation waiver for approximately $24,000 for the NR Satu. The Company does not believe it probable that a liability exists as no Tax Underpayment Assessment Notice has been received within the statute of limitations period, and the Company believes PTGI will be indemnified by PT Nusantara Regas, the charterer of the NR Satu, for any VAT liability as well as related interest and penalties under the time charter party agreement.

Prior to the Mergers, Indonesian tax authorities also issued tax assessments for land and buildings tax to PTGI for the years 2015 to 2019 in relation to the NR Satu, for approximately $3,400 (IDR 48,378.3 million). The Company intends to appeal against the assessments for the land and buildings tax as the tax authorities have not accepted the initial objection letter. The Company believes there are reasonable grounds for success on the basis of no precedent set from past case law and the new legislation effective prospectively from January 1, 2020, that now specifically lists FSRUs as being an object liable to land and buildings tax, when it previously did not. The assessed tax was paid in January 2020 to avoid further penalties and the payment is presented in Other non-current assets on the condensed consolidated balance sheets.

Prior to the Mergers, Jordanian tax authorities concluded their tax audit into GMLP’s Jordan branch for the years 2015 and 2016 assessing additional tax of approximately $1,600 (JOD 1.10 million) and $3,100 (JOD 2.20 million), respectively. The Company has submitted an appeal to the tax notice, and a provision has not been recognized as the Company does not believes that the tax inspector has followed the correct tax audit process and the claim by the tax authorities to not allow tax depreciation is contrary to Jordan’s tax legislation.

21.

Earnings per share

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Numerator:
Net loss	$	(17,769	)	$	(36,670	)	$	(59,012	)	$	(263,480	)
Less: net (income) loss attributable to non-controlling interests		7,963			312			5,259			81,163
Net loss attributable to Class A common stock		(9,806	)		(36,358	)		(53,753	)		(182,317	)
Denominator:
Weighted-average shares-basic and diluted		207,497,013			170,074,532			195,626,564			85,009,385

Net loss per share - basic and diluted	$	(0.05	)	$	(0.21	)	$	(0.27	)	$	(2.14	)

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.

	September 30, 2021		September 30, 2020
Unvested RSUs⁽¹⁾		679,909		1,555,363
Shannon Equity Agreement shares⁽²⁾		684,962		478,654
Total		1,364,871		2,034,017

⁽¹⁾	Represents the number of instruments outstanding at the end of the period.

⁽²⁾	Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

The Company declared dividends of $17,598, $20,736 and $20,750 during the first, second and third quarters of 2021, respectively, representing $0.10 per Class A share. The Company paid $17,657, $20,670 and $20,686 of dividends during the first, second and third quarters of 2021, respectively, inclusive of dividends that were accrued in prior periods.

A portion of non-controlling interest includes $140,259 attributable to GMLP’s 8.75% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). As these equity interests have been issued by the Company’s consolidated subsidiary, the value of the Series A Preferred Units is recognized as non-controlling interest in the condensed consolidated financial statements. After the Mergers, the Company paid a dividend of $6,038 to holders of the Series A Preferred Units.

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22.

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 nine months ended September 30, 2021:

	Restricted Stock Units			Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2020		1,538,060		$	13.49
Granted		-			-
Vested		(818,846	)		13.45
Forfeited		(39,305	)		13.73
Non-vested RSUs as of September 30, 2021		679,909		$	13.49

The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operations and maintenance	$	207	$	142	$	641	$	632
Selling, general and administrative		1,355		1,929		4,304		5,869
Total share-based compensation expense	$	1,562	$	2,071	$	4,945	$	6,501

For the three months ended September 30, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $116 and $278, respectively, was reversed. For the nine months ended September 30, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $173 and $827, 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 September 30, 2021, the Company had 679,909 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $2,710. 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 0.46 years as of September 30, 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. As of September 30, 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	$	30,467	0.25 years
Q1 2021	400,507	0 to 801,014		31,932	1.25 years

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

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23.

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, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $1,352 and $1,749 for the three months ended September 30, 2021 and 2020, respectively, and $5,073 and $5,894 for the nine months ended September 30, 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 September 30, 2021 and December 31, 2020, $4,264 and $5,535 were due to Fortress, respectively.

In addition to 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 $436 and $242 for the three months ended September 30, 2021 and 2020, respectively, and $3,385 and $1,526 for the nine months ended September 30, 2021 and 2020. As of September 30, 2021 and December 31, 2020, $598 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 $103 during the three months ended September 30, 2021 and 2020, and $332 and $309 during the nine months ended September 30, 2021 and 2020, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss. As of September 30, 2021 and December 31, 2020, $0 and $316 was due to FECI, respectively. As of September 30, 2021, the Company has recorded a lease liability of $3,305 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. During the third quarter of 2021, the Company settled all outstanding amounts due under notes payable; the consulting agreement was also restructured to settle all previous amounts owed to DevTech and to include a royalty payment based on certain volumes sold in Jamaica. The Company paid $988 to settle these outstanding amounts.

As of September 30, 2021 and December 31, 2020, $0 and $715 was owed to DevTech on the note payable; prior to settlement, the outstanding note payable due to DevTech was included in Other long-term liabilities on the condensed consolidated balance sheets. The interest expense on the note payable due to DevTech was $0 and $19 for the three months ended September 30, 2021 and 2020, respectively, and $29 and $57 for the nine months ended September 30, 2021 and 2020, respectively. As of September 30, 2021 and December 31, 2020, $0 and $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 September 30, 2021 and December 31, 2020, $352 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 and nine months ended September 30, 2021, $201 and $595, respectively, of rent and office related expenses were incurred by this affiliate. As of September 30, 2021 and December 31, 2020, $595 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 $571 and $808 for the three months ended September 30, 2021 and 2020, respectively, and $2,048 and $1,657 for the nine months ended September 30, 2021 and 2020. As of September 30, 2021 and December 31, 2020, $2,048 and $2,657 were due to Fortress affiliated entities, respectively.

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Agency agreement with PT Pesona Sentra Utama (or PT Pesona)

PT Pesona, an Indonesian company, owns 51% of the issued share capital in the Company’s subsidiary, PTGI, the owner and operator of NR Satu, and provides agency and local representation services for the Company with respect to NR Satu. During the period after the Mergers, PT Pesona did not receive any agency fees. PT Pesona and certain of its subsidiaries charged vessel management fees to the Company for the provision of technical and commercial management of the vessels amounting to $61 and $187 for the three and nine months ended September 30, 2021, respectively.

Hilli guarantees

As part of the GMLP Merger, the Company agreed to assume a guarantee (the “Partnership Guarantee”) of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. The Company also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under the LTA. Under the LOC Guarantee, the Company is severally liable for any outstanding amounts that are payable, up to approximately $19,000.

Subsequent to the GMLP Merger, under the Partnership Guarantee and the LOC Guarantee NFE’s subsidiary, GMLP, is required to comply with the following covenants and ratios:

• free liquid assets of at least $30 million throughout the Hilli Leaseback period;

• a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; and

• a consolidated tangible net worth of $123.95 million.

As of September 30, 2021, the amount the Company has guaranteed under the Partnership Guarantee and the LOC Guarantee is $364,500, and the fair value of debt guarantee after amortization, presented under Other current liabilities and Other non-current liabilities on the condensed consolidated balance sheet, amounted to $5,286 and $3,549, respectively. As of September 30, 2021 the Company was in compliance with the covenants and ratios for both Hilli guarantees.

24.

Segments

As of September 30, 2021, the Company operates in two reportable segments: Terminals and Infrastructure and Ships:

•

Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning 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. Leased vessels as well as acquired vessels that are utilized in the Company’s terminal or logistics operations are included in this segment.

•

Ships includes FSRUs and LNG carriers that are leased to customers under long-term or spot arrangements. FSRUs are stationed offshore for customer’s operations to regasify LNG; six of the FSRUs acquired in the Mergers are included in this segment, including the Nanook. LNG carriers are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally. Five of the LNG carriers acquired in the Mergers are included in this segment. The Company’s investment in Hilli LLC is also included in the Ships segment.

The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value. Terminals and Infrastructure Segment Operating Margin includes our effective share of revenue, expenses and segment operating margin attributable to our 50% ownership of CELSEPAR. Ships Operating Margin includes our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC.

Management considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance.

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The table below presents segment information for the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30, 2021
(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾			Consolidated
Statement of operations:
Total revenues	$	349,140	$	116,050	$	465,190	$	(160,534	)	$	304,656
Cost of sales		206,131		-		206,131		(70,699	)		135,432
Vessel operating expenses		-		21,210		21,210		(5,909	)		15,301
Operations and maintenance		27,371		-		27,371		(7,227	)		20,144
Segment Operating Margin	$	115,638	$	94,840	$	210,478	$	(76,699	)	$	133,779
Balance sheet:
Total assets⁽⁵⁾	$	4,146,251	$	2,518,836	$	6,665,087	$	-		$	6,665,087
Other segmental financial information:
Capital expenditures⁽⁵⁾	$	292,982	$	5,766	$	298,748	$	-		$	298,748

	Nine Months Ended September 30, 2021
(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾			Consolidated
Statement of operations:
Total revenues	$	676,372	$	211,812	$	888,184	$	(214,005	)	$	674,179
Cost of sales		406,253		-		406,253		(72,720	)		333,533
Vessel operating expenses		-		41,385		41,385		(10,684	)		30,701
Operations and maintenance		67,266		-		67,266		(12,306	)		54,960
Segment Operating Margin	$	202,853	$	170,427	$	373,280	$	(118,295	)	$	254,985
Balance sheet:
Total assets⁽⁵⁾	$	4,146,251	$	2,518,836	$	6,665,087	$	-		$	6,665,087
Other segmental financial information:
Capital expenditures⁽⁵⁾	$	609,533	$	6,799	$	616,332	$	-		$	616,332

	Three Months Ended September 30, 2020
(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾		Consolidated
Statement of operations:
Total revenues	$	136,858	$	-	$	136,858	$	-	$	136,858
Cost of sales		71,665		-		71,665		-		71,665
Vessel operating expenses		-		-		-		-		-
Operations and maintenance		13,802		-		13,802		-		13,802
Segment Operating Margin	$	51,391	$	-	$	51,391	$	-	$	51,391
Balance sheet:
Total assets⁽⁵⁾	$	1,399,813	$	-	$	1,399,813	$	-	$	1,399,813
Other segmental financial information:
Capital expenditures⁽⁵⁾	$	9,128	$	-	$	9,128	$	-	$	9,128

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	Nine Months Ended September 30, 2020
(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾		Consolidated
Statement of operations:
Total revenues	$	305,954	$	-	$	305,954	$	-	$	305,954
Cost of sales		209,780		-		209,780		-		209,780
Vessel operating expenses		-		-		-		-		-
Operations and maintenance		31,785		-		31,785		-		31,785
Segment Operating Margin	$	64,389	$	-	$	64,389	$	-	$	64,389
Balance sheet:
Total assets⁽⁴⁾	$	1,399,813	$	-	$	1,399,813	$	-	$	1,399,813
Other segmental financial information:
Capital expenditures⁽⁴⁾⁽⁵⁾	$	90,433	$	-	$	90,433	$	-	$	90,433

^⁽¹⁾ Terminals and Infrastructure includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The losses and earnings attributable to the investment of $27,792 and $655 for the three and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations. Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $2,316 for the three and nine months ended September 30, 2021 reported in Cost of sales.

^⁽²⁾ Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $11,809 and $22,303 for the three months and nine months ended September 30, 2021, respectively, are reported in income (loss) from equity method investments on the condensed consolidated statements of operations and comprehensive loss.

^⁽³⁾ Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.

^⁽⁴⁾ Total assets and capital expenditure by segment refers to assets held and capital expenditures related to the development of the Company’s terminals and vessels. The Terminals and Infrastructure segment includes the net book value of vessels utilized within the Terminals and Infrastructure segment.

^⁽⁵⁾ Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period.

Consolidated Segment Operating Margin is defined as net loss, adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, interest expense, other (income) expense, income from equity method investments and tax expense.

The following table reconciles Net loss, the most comparable financial statement measure, to Consolidated Segment Operating Margin:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands of $)	2021			2020			2021			2020
Net loss	$	(17,769	)	$	(36,670	)	$	(59,012	)	$	(263,480	)
Add:
Selling, general and administrative		46,802			26,821			124,954			87,273
Transaction and integration costs		1,848			4,028			42,564			4,028
Contract termination charges and loss on mitigation sales		-			-			-			124,114
Depreciation and amortization		31,194			9,489			68,080			22,363
Interest expense		57,595			19,813			107,757			50,901
Other (income) expense, net		(5,400	)		2,569			(13,458	)		4,179
Loss on extinguishment of debt, net		-			23,505			-			33,062
Tax provision		3,526			1,836			7,058			1,949
Loss (income) from equity method investments		15,983			-			(22,958	)		-
Consolidated Segment Operating Margin	$	133,779		$	51,391		$	254,985		$	64,389

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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 generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in thousands.

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

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”.

On April 15, 2021, we completed the 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. The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger.

As a result of the Mergers, we acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50% interest in a 1.5GW 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”).

We acquired the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. In addition to the Nanook, the we also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (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 are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

Subsequent to the completion of the Mergers, our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.

Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third party suppliers and from our own liquefaction facility in Miami, Florida. Leased vessels as well as the cost to operate our vessels that are utilized in our terminal or logistics operations are included in this segment. The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico and Brazil, including our interest in the Sergipe Power Plant.

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Our Ships segment includes all vessels acquired in the Mergers which are leased to customers under long-term or spot arrangements, including the 25 year charter of Nanook with CELSE. The Company’s investment in Hilli LLC, owner and operator of the Hilli, is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.

Our Current Operations – Terminals and Infrastructure

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

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

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 is an offshore facility consisting of an FSRU that is capable of processing approximately six million gallons of LNG (500,000 MMBtus) per day. The Old Harbour Facility commenced commercial operations in June 2019 and 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. In March 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliver gas to Jamalco to utilize in their gas-fired boilers.

San Juan Facility

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. In the third quarter of 2021, commission for Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed under the terms of our agreement with PREPA. See “—Other Matters” for additional information regarding our San Juan Facility.

Sergipe Power Plant and Sergipe Facility

As part of the Hygo Merger, we acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), which owns Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of the Sergipe Power Plant. The Sergipe Power Plant, a 1.5 GW combined cycle power plant, receives natural gas from the Sergipe Facility through a dedicated 8-kilometer pipeline. The Sergipe Power Plant is the largest natural gas-fired thermal power station in South America and was built to provide electricity on demand, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region. CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant is delivering power to 26 committed offtakers for a period of 25 years. In any period in which power is not being produced pursuant to the PPAs, we are able to sell merchant power into the electricity grid at spot prices, subject to local regulatory approval.

We also acquired a 75% interest in Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), which owns rights to expand the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for an incremental 1.7GW of power generation. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions.

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The Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Sergipe Facility is expected to utilize approximately 230,000 MMBtu/d (30% of the facility’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant, at full dispatch.

Miami Facility

Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 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.

Our Current Operations – Ships

Our Ships segment includes six FSRUs and five LNGCs which are leased to customers under long-term or spot arrangements, including a 25-year charter of Nanook with CELSE. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. We began to use one acquired LNGC in our terminal operations in the third quarter of 2021, and the results of operations of this vessel are no longer included in the Ships segment.

The Company’s investment in Hilli LLC, owner and operator of the Hilli, is also included in the Ships segment. Hilli Corp, a wholly owned subsidiary of Hilli LLC, has a Liquefication Tolling Agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures under which the Hilli provides liquefaction services through July 2026. Under the LTA, Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil.

Our Development Projects

La Paz Facility

In July 2021 we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, we are supplying CFEnergia with natural gas to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day, and we are in commercial discussions with CFEnergia to increase the volumes and extend the tenor of agreements to further their transition to gas-fired power. Once fully operational, the La Paz Facility is expected to supply approximately an additional 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 which we have developed, own and will operate once fully operational, which may be increased to approximately 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power.

Puerto Sandino Facility

Construction of our LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”) is expected to be completed in the fourth quarter of 2021 with commissioning of the power plant expected to begin in the first quarter of 2022. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and our 300 MW natural gas-fired power plant will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day.

Suape Facility

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 are seeking to obtain the necessary approvals from ANEEL and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics to develop and construct an initial 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 (the “Suape Facility”).

Barcarena Facility

The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to utilize approximately 92,000 MMBtu/d (12% of the facility’s maximum regasification capacity) to service the Barcarena Power Plant upon commencement of operations.

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As part of the Mergers, we acquired multiple 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant to be located in Pará, Brazil and to be supplied by the Barcarena Facility (the “Barcarena Power Plant”). The Barcarena Power Plant will utilize LNG sourced and processed at the Barcarena Facility for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019.

Santa Catarina Facility

The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. We are also developing a 31-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million gallons per day.

Sri Lanka Facility

In September 2021, we signed an agreement to acquire a 40% ownership stake in West Coast Power Limited (“WCP”), the owner of the 310 MW Yugadanvi Power Plant in Colombo, Sri Lanka. We plan to develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, where 310 MW of power is operational today and an additional 700 MW scheduled to be built, of which 350 MW is scheduled to be operational by 2023. We expect to initially provide the equivalent of an estimated 1.2 million gallons of LNG per day (35,000 MMBtu/d), with the expectation of significant growth as new power plants become operational. Our agreement with WCP is subject to certain conditions precedent, and we expect that these conditions will be finalized in the first half of 2022.

Fast LNG

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

Recent Developments

Cargo Sales

Since August 2021, LNG prices have increased materially. We have supply commitments to secure LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. Due to this significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of these cargos in the market, and these sales have positively impacted our results for the third quarter of 2021. We expect to deliver these cargos in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021.

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, including our marine operations acquired in the Mergers. Customers in our Terminals and Infrastructure segment primarily operate under long-term contracts, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We continue to invoice our customers for fixed minimum volumes even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections.

Many of the vessels acquired in the Mergers operate under long-term contracts with fixed payments. We are required to have adequate crewing aboard our vessels to fulfill the obligations under our contracts, and we have implemented safety measures to ensure that we have healthy qualified officers and crew. We monitor local or international transport or quarantine restrictions limiting the ability to transfer crew members off vessels or bring a new crew on board, and restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives, and we have not experienced significant disruptions in our operations due to these measures or restrictions.

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Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities. For the three months and nine months ended September 30, 2021, we have incurred approximately $0.2 million and $0.6 million, respectively, for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

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

Other Matters

On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which is September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit. To date, no other party has sought review of FERC’s orders. While our petitions for review are pending, and in order to comply with the FERC’s directive, on September 15, 2021 we filed an application for authorization to operate the San Juan Facility.

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Results of Operations – Three and Nine Months Ended September 30, 2021 compared to Three and Nine Months Ended September 30, 2020

Segment performance is evaluated based on segment operating margin and the tables below presents our segment information for the three and nine months ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021

(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾			Consolidated
Total revenues	$	349,140	$	116,050	$	465,190	$	(160,534	)	$	304,656
Cost of sales		206,131		-		206,131		(70,699	)		135,432
Vessel operating expenses		-		21,210		21,210		(5,909	)		15,301
Operations and maintenance		27,371		-		27,371		(7,227	)		20,144
Segment Operating Margin	$	115,638	$	94,840	$	210,478	$	(76,699	)	$	133,779

Nine Months Ended September 30, 2021

(in thousands of $)	Terminals and Infrastructure⁽¹⁾		Ships⁽²⁾		Total Segment		Consolidation and Other⁽³⁾			Consolidated
Total revenues	$	676,372	$	211,812	$	888,184	$	(214,005	)	$	674,179
Cost of sales		406,253		-		406,253		(72,720	)		333,533
Vessel operating expenses		-		41,385		41,385		(10,684	)		30,701
Operations and maintenance		67,266		-		67,266		(12,306	)		54,960
Segment Operating Margin	$	202,853	$	170,427	$	373,280	$	(118,295	)	$	254,985

⁽¹⁾ Terminals and Infrastructure includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The losses and earnings attributable to the investment of $27,792 and $655 for the three and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations. Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $2,316 for the three and nine months ended September 30, 2021 reported in Cost of sales.

⁽²⁾ Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $11,809 and $22,303 for the three months and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations and comprehensive loss.

⁽³⁾ Consolidation and Other adjust for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.

	Terminals and Infrastructure
(in thousands of $)	Three months ended September 30, 2020		Nine months ended September 30, 2020
Total revenues	$	136,858	$	305,954
Cost of sales		71,665		209,780
Vessel operating expenses		-		-
Operations and maintenance		13,802		31,785
Segment Operating Margin	$	51,391	$	64,389

Terminals and Infrastructure Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands of $)	2021		2020		Change		2021		2020		Change
Total revenues	$	349,140	$	136,858	$	212,282	$	676,372	$	305,954	$	370,418
Cost of sales		206,131		71,665		134,466		406,253		209,780		196,473
Vessel operating expenses		-		-		-		-		-		-
Operations and maintenance		27,371		13,802		13,569		67,266		31,785		35,481
Segment Operating Margin	$	115,638	$	51,391	$	64,247	$	202,853	$	64,389	$	138,464

Total revenue

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Total revenue for the Terminals and Infrastructure Segment increased $212,282 and $370,418 for the three and nine months ended September 30, 2021 as compared to the three months and nine months ended September 30, 2020, respectively. The increase was primarily driven by increases in revenue from the sale of cargos of LNG to third parties outside of our terminal operations and the inclusion of incremental revenue in our segment measure from CELSEPAR after the completion of the Mergers. Our contracts with customers in this segment are primarily priced based on the Henry Hub index, and there have been significant increases in this price index in 2021, positively impacting our revenue. The average Henry Hub index pricing used to invoice our customers increased by 103% and 69% for the three and nine months ended September 2021 as compared to the three and nine months ended September 30, 2020, respectively. Additionally, we recognized additional revenue from more volumes sold to the San Juan Power Plant in Puerto Rico.

Revenue from cargo sales outside of our terminal operations was $32,605 for the three and nine months ended September 30, 2021; there were no comparable transactions in the three and nine months ended September 30, 2020.

The Old Harbour Facility sold additional volumes in the three and nine months ended September 30, 2021 as compared to the three and nine months ended September 30, 2020, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020. Increases in revenue were further impacted by substantial increases to natural gas pricing.

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For the three months ended September 30, 2021, we recognized $62,488 of revenue from volumes sold at the Old Harbour Facility, as compared to $50,064 for the three months ended September 30, 2020, driven primarily by an increase in the Henry Hub index used to invoice our customers when compared to the third quarter of 2020. Volumes consumed at the Old Harbour Power Plant increased by 6.2 million gallons (0.6 TBtu), partially offset by a decrease of 1.5 million gallons (0.2 TBtu) in consumption by Jamalco’s boilers. The Jamalco refinery experienced a fire in August 2021, and no gas volumes have been consumed by their boilers since this event. Volumes delivered to the Old Harbour Power Plant increased to 33.1 million gallons (2.8 TBtu) in the three months ended September 30, 2021 from 26.9 million gallons (2.2 TBtu) in the three months ended September 30, 2020. Volumes delivered to the CHP Plant and Jamalco’s boilers decreased to 27.1 million gallons (2.2 TBtu) in the three months ended September 30, 2021 from 28.6 million gallons (2.4 TBtu) in the three months ended September 30, 2020.

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For the nine months ended September 30, 2021, we recognized $170,402 of revenue from volumes sold at the Old Harbour Facility, as compared to $129,313 for the nine months ended September 30, 2020, primarily driven by an increase in the Henry Hub index used to invoice our customers and additional volumes consumed at the Old Harbour Power Plant, CHP Plant and Jamalco’s boilers, which began consuming gas in August 2020. Volumes delivered to the Old Harbour Power Plant increased by 13.5 million gallons (1.2 TBtu) to 91.9 million gallons (7.7 TBtu) in the nine months ended September 30, 2021 from 78.4 million gallons (6.5 TBtu) in the nine months ended September 30, 2020. Volumes delivered to the CHP Plant and Jamalco’s boilers increased by 18.9 million gallons (1.5 TBtu) to 81.3 million gallons (6.7 TBtu) in the nine months ended September 30, 2021 from 62.4 million gallons (5.2 TBtu) in the nine months ended September 30, 2020.

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Revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco was $7,237 and $21,567 for the three and nine months ended September 30, 2021, respectively, as compared to $7,280 and $15,957 in revenue for the three and nine months ended September 30, 2020, respectively. After the fire at the Jamalco refinery, we did not deliver any steam to Jamalco. However, steam revenue was consistent in the third quarter of 2021 with previous periods as our contract with Jamalco has take-or-pay provisions that allow us to invoice for minimum volumes.

Revenue was also impacted by operations at our Montego Bay Facility.

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Sales at the Montego Bay Facility increased by $4,298 from $23,515 for the three months ended September 30, 2020 to $27,813 for the three months ended September 30, 2021. The increase in sales at the Montego Bay Facility was due to an increase in the Henry Hub index used to invoice our customers compared to the third quarter of 2020. Volumes delivered at the Montego Bay Facility remained relatively consistent for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020, decreasing by 0.1 million gallons (0.0 TBtu) from 23.9 million gallons (2.0 TBtu) during the three months ended September 30, 2020 to 23.8 million gallons (2.0 TBtu) during the three months ended September 30, 2021.

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Sales at the Montego Bay Facility increased by $10,103 from $69,072 for the nine months ended September 30, 2020 to $79,175 for the nine months ended September 30, 2021. The increase in sales at the Montego Bay Facility was primarily due to an increase in the Henry Hub index used to invoice our customers compared to the first nine months of 2020. Volumes delivered at the Montego Bay Facility increased by 1.9 million gallons (0.2 TBtu) from 70.5 million gallons (5.9 TBtu) during the nine months ended September 30, 2020 to 72.4 million gallons (6.1 TBtu) during the nine months ended September 30, 2021.

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We also recognize revenue from development services for 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. Such services are provided under certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Natural gas delivered to the San Juan Power Plant was recognized as revenue from development services, until commissioning of Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed in the third quarter of 2021. After this point, all natural gas delivered to the San Juan Power Plant was recognized as operating revenue.

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Sales at the San Juan Power Plant increased by $24,087 from $51,974 for the three months ended September 30, 2020 to $76,061 for the three months ended September 30, 2021. The increase was driven by additional volumes consumed at the San Juan Power Plant. Volumes delivered to the San Juan Power Plant increased by 13.0 million gallons (1.0 TBtu) to 71.6 million gallons (5.8 TBtu) in the three months ended September 30, 2021 from 58.6 million gallons (4.8 TBtu) in the three months ended September 30, 2020.

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Sales at the San Juan Power Plant increased by $108,263 from $68,458 for the nine months ended September 30, 2020 to $176,721 for the nine months ended September 30, 2021. The increase was driven by additional volumes consumed at the San Juan Power Plant, as our San Juan Facility was not completed until July 2020. Volumes delivered to the San Juan Power Plant increased by 88.0 million gallons (7.1 TBtu) to 165.9 million gallons (13.5 TBtu) in the nine months ended September 30, 2021 from 77.9 million gallons (6.4 TBtu) in the nine months ended September 30, 2020.

Subsequent to the acquisition of our interest in the Sergipe Facility as part of the Mergers, our share of revenue from our investment in CELSEPAR was $134,523 and $166,292 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of fixed capacity payments received under our PPAs. Revenue recognized from the operation of the Sergipe Power Plant was significantly increased in the third quarter of 2021 by emergency dispatch due to poor hydrological conditions in Brazil during the third quarter. Our proportionate share of revenue from the Sergipe Facility is included in this discussion as such revenue is included in our segment measure; in our consolidated statement of operations and comprehensive loss, we report the results from our investment in CELSEPAR as Income (loss) from equity method investments.

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 $134,466 and $196,473 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020, respectively.

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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 $44,581 for the three months ended September 30, 2021, respectively as compared to the three months ended September 30, 2020. The increase was primarily attributable to a 15% increase in volumes delivered compared to the three months ended September 30, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020 to $0.58 per gallon ($6.98 per MMBtu) for the three months ended September 30, 2021.

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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 $87,852 for the nine months ended September 30, 2021, respectively as compared to the nine months ended September 30, 2020. The increase was primarily attributable to a 42% increase in volumes delivered compared to the nine months ended September 30, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.51 per gallon ($6.13 per MMBtu) for the nine months ended September 30, 2020 to $0.54 per gallon ($6.58 per MMBtu) for the nine months ended September 30, 2021.

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Cost of LNG from the sale of cargos in the market were $18,191 for the three and nine months ended September 30, 2021 as compared to $0 for the three and nine months ended September 30, 2020. Since August 2021, due to the significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market. The weighted-average cost of LNG from the sale of a portion of our cargos was $0.69 per gallon ($8.33 per MMBTU) for the three and nine months ended September 30, 2021.

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•

Subsequent to the acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Cost of sales from our investment in CELSEPAR was $73,015 and $75,042 for the three and nine months ended September 30, 2021, respectively, which was comprised of LNG costs to fuel the power plant and costs of power to fulfill requirements under the PPAs.

The weighted-average cost of our LNG inventory balance to be used in our Jamaican and Puerto Rican operations as of September 30, 2021 and December 31, 2020 was $0.64 per gallon ($7.71 per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively.

Charter costs decreased Cost of sales by $2,901 for the three months ended September 30, 2021. As a result of the Mergers, we have effectively settled our charter agreement for the Freeze, one of the acquired vessels, and as such, the decrease in charter costs was attributable to the lower costs associated with the Freeze.

Charter costs increased Cost of sales by $3,441 for the nine months ended September 30, 2021, respectively. 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 an additional vessel lease that we assumed as part of the Mergers. These increases were partially offset by lower costs associated with the Freeze.

Operations and maintenance

Operations and maintenance includes costs of operating our Facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance increased $13,569 and $35,481 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020.

•

Subsequent to acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Operations and maintenance from our investment in CELSEPAR was $7,227 and $12,306 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of costs related to the operation and services agreement for the Nanook, insurance costs and costs for connecting to the transmission system.

•

The increase for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020 was primarily the result of costs of operating the San Juan Facility and CHP Plant and higher payroll costs, maintenance costs, insurance costs and port fees; these additional costs were $8,878.

•

The increase for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 was primarily the result of San Juan Facility and the CHP Facility that were still in development during a portion of the nine months ended September 30, 2020. Operations and maintenance increased by the costs of operating the San Juan Facility and CHP Plant of $10,732. We also incurred $13,092 of payroll costs, maintenance costs, insurance costs and port fees.

Ships Segment

	Three Months		Nine Months
(in thousands of $)	Ended September 30, 2021		Ended September 30, 2021
Total revenues	$	116,050	$	211,812
Vessel operating expenses		21,210		41,385
Segment Operating Margin	$	94,840	$	170,427

Prior to the completion of the Mergers, we reported our results of operations in a single segment; all the assets and operations that comprise the Ships segment were acquired in the Mergers, and as such, there are no results of operations prior to the completion of the Mergers during the second quarter of 2021, and the results of operations for the Ships segment for the nine months ended September 30, 2021 represents five and a half months of operations.

Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for repositioning vessels as well as the reimbursement of certain vessel operating costs. We have also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook.

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Subsequent to the completion of the Mergers, five of the FSRUs and one LNGCs were on hire under long-term charter agreements for the full period. Two LNGCs were operating in the spot market for a portion of the period subsequent to the completion of the Mergers through June 30, 2021. In the third quarter, one of these LNGCs, the Grand, began to be utilized in our terminal and logistics operations, and as such, the results of operations of the Grand are included in the Terminals and Infrastructure segment in the third quarter of 2021. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels.

Two of the vessels acquired in the Mergers, the Celsius and the Penguin, have participated in a pooling arrangement, which we refer to as the Cool Pool. Under this arrangement, the pool manager markets participating vessels in the LNG shipping spot market, and the vessel owner continues to be fully responsible for the manning and technical management of their respective vessels. Revenue for charters of our vessels in the Cool Pool is presented on a gross basis in revenue, and our allocation of our share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses. The Penguin exited the Cool Pool in the third quarter of 2021, and we have chartered this vessel to a third party outside of the Cool Pool.

For the three and nine months ended September 30, 2021, revenue recognized in the Ships segment included $11,607 and $21,288 of interest income for the Nanook sales-type lease and $1,491 and $2,656 of revenue for operating services, respectively, provided to CELSE. As all operations of the Ships segment were acquired in the Mergers, the results of operations for the Nanook for the nine months ended September 30, 2021 represents five and a half months of operations.

Our segment measure includes our proportionate share of the results of operations of the Hilli. Our share of revenue from our investment in Hilli LLC was $26,011 and $47,758 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of fees received under the long-term tolling arrangement. The Hilli maintained 100% commercial uptime during the period subsequent to the Mergers.

Vessel operating expenses

Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and management fees. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

For the three and nine months ended September 30, 2021, we recognized $21,210 and $41,385, respectively, in Vessel operating expenses. As all operations of the Ships segment were acquired in the Mergers, Vessel operating expenses for the nine months ended September 30, 2021 represents five and a half months of operations of each of the acquired vessels.

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Other operating results

	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands of $)	2021			2020			Change			2021			2020			Change
Selling, general and administrative	$	46,802		$	26,821		$	19,981		$	124,954		$	87,273		$	37,681
Transaction and integration costs		1,848			4,028			(2,180	)		42,564			4,028			38,536
Contract termination charges and loss on mitigation sales		-			-			-			-			124,114			(124,114	)
Depreciation and amortization		31,194			9,489			21,705			68,080			22,363			45,717
Total operating expenses		250,721			125,805			124,916			654,792			479,343			175,449
Operating income (loss)		53,935			11,053			42,882			19,387			(173,389	)		192,776
Interest expense		57,595			19,813			37,782			107,757			50,901			56,856
Other (income) expense, net		(5,400	)		2,569			(7,969	)		(13,458	)		4,179			(17,637	)
Loss on extinguishment of debt, net		-			23,505			(23,505	)		-			33,062			(33,062	)
Net income (loss) before income from equity method investments and income taxes		1,740			(34,834	)		36,574			(74,912	)		(261,531	)		186,619
(Loss) income from equity method investments		(15,983	)		-			(15,983	)		22,958			-			22,958
Tax provision		3,526			1,836			1,690			7,058			1,949			5,109
Net loss	$	(17,769	)	$	(36,670	)	$	18,901		$	(59,012	)	$	(263,480	)	$	204,468

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 screening costs associated with development activities for projects that are in initial stages and development is not yet probable.

Selling, general and administrative increased $19,981 for the three months ended September 30, 2021, as compared to the three months ended September 30, 2020. The increase was primarily attributable to $10,558 of higher payroll costs associated with increased headcount for the three months ended September 30, 2021. Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees, professional services, and other costs attributable to our expanded operations of $6,076.

Selling, general and administrative increased $37,681 for the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020. The increase was primarily attributable to $21,451 of higher payroll costs associated with increased headcount for the nine months ended September 30, 2021. Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees, professional services, and other costs attributable to our expanded operations of $14,875.

Transaction and integration costs

Transaction and integration costs decreased $2,180 and increased $38,536 for the three and nine months ended September 30, 2021, as compared to the three and nine months ended September 30, 2020, respectively. For the three months ended September 30, 2021, we incurred $1,848 in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.

For the nine months ended September 30, 2021, we incurred $42,564 for transaction and integration costs. As part of arranging financing for the Mergers, we incurred $15,000 in bridge financing commitment fees. We issued the 2026 Notes to pay for a portion of the consideration for the Mergers and did not utilize the commitments under the bridge financing, and as such, the fees were expensed with the termination of the bridge financing commitment letter in the second quarter of 2021. We also incurred $3,978 of costs related to the settlement of a contractual indemnification obligation under a pre-existing lease arrangement prior to the GMLP Merger. The remaining transaction and integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.

For the three and nine months ended September 30, 2020, we incurred $4,028 of third-party fees associated with a new credit agreement that was accounted for as a modification.

Contract termination charges and loss on mitigation sales

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Loss on mitigation sales for the three and nine months ended September 30, 2020 was $0 and $124,114, respectively. In June 2020, we executed an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of $105,000, and we recognized this cancellation charge during the three months ended June 30, 2020. We terminated our obligation in the second quarter of 2020 to both take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs. Additionally, in the second quarter of 2020, we experienced lower than expected consumption by some of our customers, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica. As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was recognized during the second quarter of 2020. We did not have such transactions during the three and nine months ended September 30, 2021.

Depreciation and amortization

Depreciation and amortization increased $21,705 and $45,717 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to the following:

•

Subsequent to the completion of the Mergers, our results of operations include depreciation expense primarily for the vessels acquired. We recognized $13,691 and $25,100 of incremental depreciation expense for the acquired vessels during the three and nine months ended September 30, 2021 as compared to the same periods in the prior year;

•

Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $6,779 and $12,128 for the three and nine months ended September 30, 2021, respectively;

•

Increase in depreciation of $427 and $5,229 for the San Juan Facility that went into service in July 2020 for the three and nine months ended September 30, 2021, respectively; and

•

Increase in depreciation of $2,297 for the CHP Plant that went into service in March 2020 for the nine months ended September 30, 2021.

Interest expense

Interest expense increased by $37,782 and $56,856 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2025 Notes in September 2020, the 2026 Notes in April 2021, draws on the Revolving Facility in the second and third quarters of 2021, borrowings under the Vessel Term Loan Facility and the CHP Facility (all defined below); principal outstanding on outstanding facilities was $3,888,894 as of September 30, 2021 as compared to total outstanding debt of $1,000,000 as of September 30, 2020.

In conjunction with the Mergers, we assumed outstanding debentures issued by a subsidiary of Hygo and the outstanding debt of variable interest entities (“VIEs”) that are now consolidated in our financial statements, totaling $630,563 as of the acquisition date. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the condensed consolidated financial statements.

Upon assumption of the debt held by VIEs, we recognized the liabilities assumed at fair value and amortization of the discount from carrying value has been recorded as additional interest expense. For the three months and nine months ended September 30, 2021, we recognized additional interest expense attributable to assumed debt of $15,263 and $8,628, respectively.

Other (income) expense, net

Other (income) expense, net increased by $7,969 and $17,637 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to the following::

•

Gains in investments in equity securities compared to losses in the same periods in 2020, contributing $7,335 and $9,640 for the three and nine months ended September 30, 2021, respectively;

•

Increase from the reduction in losses resulting from the fair value of derivative liabilities and equity agreement associated with payments due to sellers in asset acquisitions of $2,737 and $3,156, for the three and nine months ended September 30, 2021, respectively; and

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•

Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulting in expense of $4,278 and additional income of $2,081, for the three and nine months ended September 30, 2021, respectively.

Loss on extinguishment of debt, net

Loss on extinguishment of debt for the three and nine months ended September 30, 2020 was $23,505 and $33,062, respectively, as a result of the extinguishment of previous credit facilities in January 2020 and September 2020. We did not have such transactions during the three and nine months ended September 30, 2021.

Tax provision

We recognized a tax provision for the three and nine months ended September 30, 2021 of $3,526 and $7,058, respectively, compared to tax provision of $1,836 and $1,949 for the three and nine months ended September 30, 2020, respectively. The increases to the tax provision and effective tax rate for both the three and nine months ended September 30, 2021 was primarily driven by an increase in pre-tax income in certain profitable non-U.S. operations and the inclusion of operations of certain jurisdictions of acquired business. For the nine months ended September 30, 2021, these increases in tax expense were partially offset by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $1,800.

Income from equity method investments

During the period after the completion of the Mergers, we recognized losses and income from our investments in Hilli and CELSEPAR of $(15,983) and $22,958 for the three and nine months ended September 30, 2021, respectively. Our proportionate share of the losses and earnings of $(7,101) and $37,614, respectively, were offset by amortization of basis differences through our equity earnings of $8,882 and $14,656 for the three and nine months ended September 30, 2021, respectively. During the period after the Mergers, our share of earnings from CELSEPAR was significantly impacted by a foreign currency remeasurement loss of $17,709 for the three months ended September 30, 2021 and a gain of $8,067 for the nine months ended September 30, 2021, primarily as a result of the remeasurement of the Nanook finance lease obligation.

Factors Impacting Comparability of Our Financial Results

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

	•	Our historical financial results include the results of operations of Hygo and GMLP only since the completion of the Mergers in April 2021 and do not include all integration and transaction costs expected to be incurred associated with these acquisitions. Upon completion of the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an interest in a floating liquefaction vessel. We also acquired 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. The results of operations of Hygo and GMLP began to be included in our financial statements upon the closing of the acquisitions on April 15, 2021. Our results of operations 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.
	•	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 and nine months ended September 30, 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 Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects. Our current results also exclude other developments, including the Suape Facility, the Barcarena Facility, the Santa Catarina Facility 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 and nine months ended September 30, 2021, respectively, a significant portion of which is under an LNG supply agreement signed in 2018. During 2020 and 2021, we also entered into LNG supply agreements for the purchase of approximately 601 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 have now secured supply for LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years.

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

Since August 2021, LNG prices have increased materially. Due to this significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021.

Liquidity and Capital Resources

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

•

In April 2021, we issued $1,500,000 of 2026 Notes; we also entered into the $200,000 Revolving Facility that has a term of approximately five years.

•

In August 2021, we entered into the CHP Facility (defined below) and initially drew $100,000, which may be increased to $285,000.

•

In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility (defined below). Under this facility, we borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels.

We have assumed total committed expenditures for all completed and existing projects to be approximately $1,663 million, with approximately $1,154 million having already been spent through September 30, 2021. This estimate represents the committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Suape Facility, the Barcarena Facility and the Santa Catarina Facility, as well committed expenditures to serve new industrial end-users. We expect to be able to fund all such committed projects with a combination of cash on hand, cash flows from operations, proceeds from the financing of the CHP Plant and borrowings under our Revolving Facility. We may also enter into other financing arrangements to generate proceeds to fund our developments. Through September 30, 2021, we have spent approximately $128 million to develop the Pennsylvania Facility. Approximately $22 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106 million, has been capitalized, and to date, we have repurposed approximately $17 million of engineering and equipment to our Fast LNG project.

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Cash Flows

The following table summarizes the changes to our cash flows for the nine months ended September 30, 2021 and 2020, respectively:

	Nine Months Ended September 30,
(in thousands)	2021			2020			Change
Cash flows from:
Operating activities	$	(139,687	)	$	(115,710	)	$	(23,977	)
Investing activities		(2,031,158	)		(115,704	)		(1,915,454	)
Financing activities		1,874,149			291,816			1,582,333
Net (decrease) increase in cash, cash equivalents, and restricted cash	$	(296,696	)	$	60,402		$	(357,098	)

Cash used in operating activities

Our cash flow used in operating activities was $139,687 for the nine months ended September 30, 2021, which increased by $23,977 from $115,710 for the nine months ended September 30, 2020. Our net loss for the nine months ended September 30, 2021, when adjusted for non-cash items, decreased by $111,484 from the nine months ended September 30, 2020. The reduction to the net loss was offset by changes in working capital accounts, primarily significant increases in receivables, inventory and accrued liabilities, including costs attributable to the Mergers.

Cash used in investing activities

Our cash flow used in investing activities was $2,031,158 for the nine months ended September 30, 2021, which increased by $1,915,454 from $115,704 for the nine months ended September 30, 2020. Cash used for the Mergers, net of cash acquired was $1,586,042. Cash outflows for investing activities during the nine months ended September 30, 2021 were also used for continued development of the Puerto Sandino Facility, Suape Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution.

During the nine months ended September 30, 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 nine months ended September 30, 2020.

Cash provided by financing activities

Our cash flow provided by financing activities was $1,874,149 for the nine months ended September 30, 2021, which increased by $1,582,333 from cash provided by financing activities of $291,816 for the nine months ended September 30, 2020. Cash provided by financing activities during the nine months ended September 30, 2021 was due to proceeds received from the borrowings under the 2026 Notes of $1,500,000, the draw of $200,000 on the Revolving Facility, and the draw of $430,000 million on the Vessel Term Loan Facility. The proceeds received were further offset by financing fees paid in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the nine months ended September 30, 2021.

Cash flow provided by financing activities during the nine months ended September 30, 2020 were primarily consisted of proceeds received from the borrowings under the 2025 Notes of $1,000,000 and the borrowings under our previous credit agreement of $800,000, partially offset by an original issue discount of $20,000 and financing fees. Additionally, the remaining proceeds from secured bonds issued in Jamaica of $52,144 were received during the first quarter of 2020. A portion of these proceeds was used to fund the repayment of our previous credit agreement of $800,000, the senior secured and unsecured bonds that had been issued in Jamaica of $183,600, and our previous term loan facility of $506,402.

Long-Term Debt and Preferred Stock

2025 Notes

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

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We used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.

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 the previously 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 previous credit agreement was a modification, in the third quarter of 2020, the Company recorded $4,028 of third-party fees as an expense in the condensed consolidated statements of operations and comprehensive loss.

On December 17, 2020, we 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 $4,566. As of September 30, 2021 and December 31, 2020, remaining unamortized deferred financing costs for the 2025 Notes was $9,323 and $10,439, respectively.

2026 Notes

On April 12, 2021, we issued $1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, 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 our existing first lien obligations under the 2025 Notes.

We used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses. In connection with the issuance of the 2026 Notes, we incurred $24,588 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $22,362.

Vessel Term Loan Facility

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In connection with the closing the Vessel Term Loan Facility, we incurred $6,229 in origination, structuring and other fees, which were deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $6,161.

Debenture Loan

As part of the Mergers, we assumed non-convertible Brazilian debentures issued by NFE Brasil, our indirect subsidiary, in the aggregate principal amount of BRL 255.6 million ($45 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debenture Loan”). The Debenture Loan was recognized at fair value of $44,566 on the date of the Mergers, and the discount recognized in purchase accounting will result in additional interest expense until maturity. Interest and principal is payable on the Debenture Loan semi-annually on September 13 and March 13.

The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares issued by NFE Brasil owned by our consolidated subsidiary, LNG Power Ltd.

CHP Facility

On August 3, 2021, NFE South Power Holdings Limited, a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”). We initially drew $100,000 under the CHP Facility, and the CHP Facility is secured by our combined heat and power plant in Clarendon, Jamaica. We incurred $3,651 in origination, structuring and other fees associated with entry into the CHP Facility, which was deferred as a reduction of the principal balance of the CHP Facility on the condensed consolidated balance sheets. As of September 30, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,636.

Revolving Facility

On April 15, 2021, we entered into a $200,000 senior secured revolving facility (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 $100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for us to extend the maturity date once in a one-year increment.

Borrowings under the Revolving Facility 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 our option, 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 our 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. Financial covenants include requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility). The Company was in compliance with these covenants as of September 30, 2021.

We incurred $3,974 in origination, structuring and other fees, associated with entry into the Revolving Facility. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,658.

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SPV Leasebacks and Loans

We assumed sale leaseback arrangements for four vessels as part of the Mergers. The counterparty to each of the sale leaseback arrangements is a special purpose vehicle (“SPV”) wholly owned by financial institutions. The sale leasebacks with SPVs were funded by loan facilities obtained by the SPV. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of the SPVs and consolidate the SPVs. Therefore, the effects of the sale leaseback arrangements are eliminated upon consolidation of the SPVs and only the outstanding loan facilities are presented as part of our condensed consolidated financial statements. The SPVs service the loan facilities through payments made by us under the sale leaseback arrangements.

The SPV loans and the sale leaseback arrangements assumed in the Mergers contain certain operating and financing restrictions and covenants that require: (a) certain subsidiaries to maintain a minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70:1. As of September 30, 2021, the Company was in compliance with all covenants under debt and lease agreements.

Eskimo Leaseback and Credit Facility

As part of the Mergers, we have assumed obligations under a sale and leaseback of the Eskimo with Sea 23 Leasing Co. Limited of China Merchants Bank Leasing (the “Eskimo Leaseback”). Payments are due monthly in 120 installments of $1,069 along with amounts owed for interest of LIBOR plus 3.85%, with a balloon payment of $128,250 due upon maturity.

Sea 23 Leasing Co. Limited, the owner of the Eskimo, has a long-term loan facility that is denominated in USD, has a loan term of ten years and bears interest at a rate of LIBOR plus a margin of 2.66% (the “Eskimo SPV Facility”). As of the acquisition date of GMLP, the outstanding principal balance was $160,520, and we recognized the fair value of this facility of $158,072 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity.

Nanook Leaseback and Credit Facility

As part of the Mergers, we have assumed obligations under a sale and leaseback of the Nanook with Compass Shipping 23 Corporation Limited (the “Nanook Leaseback”). Payments are due quarterly in 48 installments of $2,943 along with amounts owed for interest due based on LIBOR plus 3.5%, with a balloon payment of approximately $94,000 upon maturity.

Compass Shipping 23 Corporation Limited, the owner of the Nanook, has a long-term loan facility that is denominated in USD, has a loan term of twelve years, bears interest at a fixed rate of 2.7% (the “Nanook SPV Facility”) and is repayable in a balloon payment on maturity. As of the acquisition date, the outstanding principal balance was $202,249, and we recognized the fair value of this facility of $201,484 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity.

Penguin Leaseback and Credit Facility

As part of the Mergers, we have assumed obligations under a sale and leaseback of the Penguin with Oriental LNG 02 Limited (the “Penguin Leaseback”). Payments are due quarterly in 24 installments of $1,890 along with amounts owed for interest due based on LIBOR plus 3.6%, with a balloon payment of approximately $63,000 upon maturity.

Oriental Fleet LNG 02 Limited, the owner of the Penguin, has a long-term loan facility that is denominated in USD, is repayable in quarterly installments over a term of approximately six years and bears interest at LIBOR plus a margin of 1.7%. The SPV also has amounts payable to its parent. As of the acquisition date, the outstanding principal balance was $104,882, and we recognized the fair value of this facility and the amount due to the parent of $105,126 on the date of the Mergers. The premium recognized in purchase accounting will result in a reduction to interest expense until maturity.

Celsius Leaseback and Credit Facility

As part of the Mergers, we have assumed obligations under a sale and leaseback of the Celsius with Noble Celsius Shipping Limited (the “Celsius Leaseback”). Payments are due quarterly in 28 installments of $2,679 in addition to amounts owed for interest based on LIBOR plus 3.9%, with a balloon payment of approximately $45,000 upon maturity.

Noble Celsius Shipping Limited, the owner of the Celsius, has a long-term loan facility that is denominated in USD, $76,179 of which is repayable in quarterly installments over a term of approximately seven years with a balloon payment of $37,179 at maturity and bears interest at LIBOR plus a margin of 1.8%. The SPV has another facility with its parent for the remaining principal of $45,200, which is due as a balloon payment upon maturity in March 2023 and bears interest at a fixed rate of 4.0%. As of the acquisition date, the total outstanding principal balance was $121,379, and we recognized the fair value of these facilities of $121,308 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity.

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Series A Preferred Units

The 8.75% Series A Cumulative Redeemable Preferred Units issued by GMLP (the “Series A Preferred Units”) remained outstanding following the GMLP Merger and were recognized as non-controlling interest on the condensed consolidated balance sheets. Distributions on the Series A 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 Series A 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 Series A 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.

Debt obligations of equity method investees

We account for the investments in CELSEPAR and Hilli LLC acquired in the Mergers under the equity method of accounting. The debt obligations of these entities are not reported separately in our consolidated financial statements, and the following discussion summarizes the key terms of each entity’s obligations.

Sergipe Debt Financing

To finance construction of the Sergipe Facility and the Sergipe Power Plant, CELSE signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 (the “CELSE Facility”). As of September 30, 2021, 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. The CELSE Facility matures in April 2032.

Credit facility (Real and USD in millions)	Amount Outstanding		Effective interest rate
IFC	R$	927.7($171.4)		10.2	%
Inter-American Development Bank	R$	766.9($141.7)		10.0	%
IDB Invest⁽¹⁾	$	37.4		5.6	%
IDB China Fund	$	49.2		5.6	%

CELSE also issued debentures in the aggregate principal amount of R$3,370.0 million (net proceeds of $897.2 million as of the issuance date), due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”). As of September 30, 2021, the balance of the CELSE Debentures was R$3,324.02 million ($614.0 million as of September 30, 2021). 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, that commenced 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 July 2, 2021, CELSE successfully completed a consent solicitation to amend certain provisions of the financing documents to permit CELSE to incur certain debt related to the working capital facility described below and to release certain existing security over the variable revenues to be received by CELSE under its power purchase agreements.

CELSEPAR has 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 NFE Power Brasil Participações S.A (“NFE Brazil”), each as sponsor (the “GE Credit Facility”). Pursuant to the GE Credit Facility, GE Capital agreed to provide $120,000 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, 2020. All interest due to date has been capitalized into the principal balance, and there have been no principal payments paid to date. The GE Credit Facility matures on November 30, 2024. The GE Credit Facility includes covenants and events of default that are customary for similar transactions.

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On July 9, 2021, CELSE and CELSEPAR entered into a working capital facility for the posting of certain letters of credit in favor of the supplier of LNG and the financing of LNG costs to satisfy dispatch requirements prior to receiving related variable revenues. The working capital facility is in an aggregate amount of up to $200.0 million (or its equivalent in Reais). The facility has a term of 12 months, renewable for equal periods by mutual agreement of the parties. Amounts disbursed under the working capital facility accrue interest at a rate of (i) DI Rate + 3.50% per year in respect of a bank credit bill, (ii) 2.50% per year for standby letters of credit, (iii) DI Rate + 3.50% per year in respect of any import financing (FINIMP) modality, and (iv) DI Rate + 3.50% per year for any bank loan. The DI Rate is made by reference to Libor+, according to the pricing at the time of request. On July 9, 2021, a standby letter of credit was issued under this facility for the benefit of CELSE pursuant to the working capital facility in an amount of $31.1 million with an expiration date of September 15, 2021. The standby letter of credit is guaranteed, jointly but not severally, by CELSE’s shareholders, NFE and Electricidade do Brasil S.A.—Ebrasil.

Golar Hilli Leaseback

As part of the Mergers, we acquired an investment in Hilli LLC; Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC. and is a party to a Memorandum of Agreement 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”). Under the Hilli Facility, Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%. Our 50% share of Hilli Corp’s indebtedness of $729,000 amounted to $364,500 as of September 30, 2021.

As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. We also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under its tolling agreement. Certain of our subsidiaries are 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; and (iii) a consolidated tangible net worth of $123,950.

Letter of Credit Facility

On July 16, 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to $75,000. Outstanding letters of credit are subject to a fee of 1.75% to be paid quarterly, and interest is payable on the principal amounts of unreimbursed letter of credit draws under the facility at a rate of the higher of the bank’s prime rate or the Federal Funds Effective Rate plus 0.50% and a margin of 1.75%. We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash. A portion of our restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital needs of the business.

Off Balance Sheet Arrangements

As of September 30, 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

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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. In 2021, we amended one of these supply agreements to increase our total commitment through 2030 to 601 TBtus at a price indexed to Henry Hub. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018.

Lease obligations

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

The Company currently has seven vessels under time charter leases with non-cancellable terms ranging from three months to four 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.

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Revenue recognition

Terminals and infrastructure

Within the Terminals and Infrastructure segment, 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 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 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.

Our contracts with customers to supply natural gas or LNG may contain a lease of equipment, which may be accounted for as a finance or operating lease. For operating leases, we have concluded that the predominant component of the transaction is the sale of natural gas or LNG and has elected not to separate the lease component. The lease component of such operating leases is recognized as Operating revenue in the condensed consolidated statements of operations and comprehensive loss. We allocate consideration in agreements containing finance leases 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.

In addition to the revenue recognized from the finance lease 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 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 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 we recognize 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.

We collect sales taxes from our customers based on sales of taxable products and remits such collections to the appropriate taxing authority. We have 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.

We elected the practical expedient under which we do not adjust consideration for the effects of a significant financing component for those contracts where we expect 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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Ships

At inception, we make an assessment on whether the charter contract is an operating lease or a finance lease. In making the classification assessment, we estimate the residual value of the underlying asset at the end of the lease term with reference to broker valuations. None of the vessel lease contracts contain residual value guarantees. Renewal periods and termination options are included in the lease term if we believe such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. We assess leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease.

Revenues include fixed minimum lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenues generated from charters contracts are recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Fixed revenue includes fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, we have elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based occur.

Repositioning fees are included in Vessel charter revenues and are recognized at the end of the charter when the fee becomes fixed and determinable. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee will be recognized evenly over the term of the charter.

The Company’s LNG carriers may participate in a LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as the Cool Pool. The Cool Pool allows the pool participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as agent, for the marketing and chartering of the participating vessels and paying certain voyage costs such as port call expenses and brokers’ commissions in relation to employment contracts, with each of the Pool Participants continuing to be fully responsible for fulfilling the performance obligations in the contract.

The Company is primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and the Company is the principal in such time charters. Revenue and expenses for charters of our vessels that participate in the Cool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the condensed consolidated statements of operations and comprehensive loss. Our allocation of our share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss.

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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.

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 largely 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, changes in the price of LNG do not 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, including Fast LNG and our expanded delivery logistics chain in the Pennsylvania Facility.

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, including long-term charter contracts acquired in the Mergers and 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 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 operations and development projects have not been significantly impacted by responses to the COVID-19 pandemic to date. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be performed.

The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil 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. Although LNG is currently trading at historical high prices, we believe that over the long-term LNG and natural gas will remain a competitive fuel source for customers.

We have considered that the market price of LNG can vary widely, including decreases throughout 2019 and 2020 and dramatic increases in the third quarter of 2021. Our extensive and growing portfolio of downstream terminals and infrastructure, together with our locked-in gas supply, provides powerful flexibility to serve customer needs and participate in the opportunities created by market disruptions. During periods of declining LNG prices in 2019 and 2020, we executed four long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower our supply contract executed in 2018. Further, we took advantage of the lower market pricing of LNG to supply our operations for the second half of 2020. We also executed an additional addendum to one of our supply agreements in 2021 to continue to secure 100% of our LNG supply needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility through 2030. During dramatic increases of LNG prices in recent months, we have been able to take advantage of flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021.

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.

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As of September 30, 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.

Business combinations and goodwill

We evaluate each purchase transaction to determine whether the acquired assets meet the definition of a business. If substantially all of the fair value of gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, then the set of transferred assets and activities is not a business. If not, for an acquisition to be considered a business, it would have to include an input and a substantive process that together significantly contribute to the ability to create outputs. A substantive process is not ancillary or minor, cannot be replaced without significant costs, effort or delay or is otherwise considered unique or scarce. To qualify as a business without outputs, the acquired assets would require an organized workforce with the necessary skills, knowledge and experience that performs a substantive process.

For acquisitions that are not deemed to be businesses, the assets acquired are recognized based on their cost to us as the acquirer, and no gain or loss is recognized. The cost of assets acquired in a group is allocated to individual assets within the group based on their relative fair values and no goodwill is recognized. Transaction costs related to acquisition of assets are included in the cost basis of the assets acquired.

We account for acquisitions that qualify as business combinations by applying the acquisition method. Transaction costs related to the acquisition of a business are expensed as incurred and excluded from the fair value of consideration transferred. Under the acquisition method of accounting, the identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity are recognized and measured at their estimated fair values. The excess of the fair value of consideration transferred over the fair values of identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity, net of fair value of any previously held interest in the acquired entity, is recorded as goodwill.

The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests. Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, estimates of projected revenues, costs and cash flows, and discount rates. The Company estimated the fair value of the vessels acquired in the Mergers using a combination of the income approach and the cost approach, which determines the replacement costs for the assets, adjusting for age and condition. Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. As a result, actual results may differ from these estimates. During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill. Upon the conclusion of a measurement period, any subsequent adjustments are recorded to earnings.

We use estimates, assumptions and judgments when assessing the recoverability of goodwill. We test for impairment on an annual basis, or more frequently if a significant event of circumstance indicates the carrying amounts may not be recoverable. The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which the goodwill is assigned is less than the carrying value. If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss.

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 largely 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. However, we have secured 100% of our LNG supply needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandido Facility through 2030.

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Interest Rate Risk

The 2025 Notes and 2026 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 and 2026 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 $60 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve.

Interest under the Vessel Term Loan Facility has a component based on LIBOR or other market indices should LIBOR become unavailable. A 100-basis point increase or decrease in the market interest rate would decrease or increase our interest expense by approximately $4.3 million.

As a result of the Mergers, we assumed the Debenture Loan and a cross-currency interest rate swap to protect against adverse movements in interest rates of the Debenture Loan. We also acquired an interest rate swap to manage the exposure to adverse movements in interest rates of debt held by our equity method investee, Hilli LLC, but we do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our other outstanding indebtedness.

Foreign Currency Exchange Risk

After the completion of the Hygo Merger, we began to have more significant transactions, assets and liabilities denominated in Brazilian reais; our Brazilian subsidiaries and investments receive income and pays expenses in Brazilian reais. A portion of our exposure to exchange rates is economically hedged by a cross-currency interest rate swap. Based on our Brazilian reais revenues and expenses for the period since the completion of the Hygo Merger, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations.

Outside of Brazil, our operations are primarily conducted 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 other than Brazil that are paid in local currencies, but we expect our international operations to continue to grow in the near term.

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 September 30, 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 September 30, 2021 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

On April 15, 2021, we completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”). As part of the ongoing integration of the acquired businesses, we are in the process of incorporating the controls and related procedures of Hygo and GMLP and expect that this effort will be completed in 2021. Pursuant to the SEC’s guidance that an assessment of a recently acquired business may be omitted from the scope of an assessment in the year of acquisition, the scope of our assessment of the effectiveness of our internal controls over financial reporting at December 31, 2021 will not include Hygo or GMLP.

Other than the foregoing, there has been no change 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 September 30, 2021 that has materially affected, or is 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;

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

•

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;

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

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Our current lack of asset and geographic diversification;

•

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 as well as Brazil 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

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

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

•

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

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.

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:

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managing a larger company;

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attracting, 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.

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.

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. As of September 30, 2021, we had approximately $3,890 million aggregate principal amount of indebtedness. 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. 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.

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. For example, 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.

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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.

We may experience delays, unforeseen expenses or other obstacles as we develop projects in new jurisdictions that could 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 and Africa, 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;

•

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.

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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.

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 we have not achieved profitability for any annual period or for the six months ended June 30, 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, Puerto Rico and Brazil, 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, Puerto Rico and Brazil 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 and Brazil. 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 and Brazil 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:

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upon the occurrence of certain events of force majeure;

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if we fail to make available specified scheduled cargo quantities;

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the occurrence of certain uncured payment defaults;

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the occurrence of an insolvency event;

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the occurrence of certain uncured, material breaches; and

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

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

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

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

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

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

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

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insufficient LNG tanker capacity;

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weather conditions and natural disasters;

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reduced demand and lower prices for natural gas;

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

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

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

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

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

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political conditions in natural gas producing regions;

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

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

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 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. 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, some of our other executive officers and other key employees. 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 or employees 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:

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

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

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

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

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

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

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

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

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

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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:

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

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

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

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attract, develop and retain skilled personnel, including engineers;

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post required construction bonds and comply with the terms thereof;

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

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maintain their own financial condition, including adequate working capital.

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

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

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

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

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

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

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

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

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

Under the GSAs with JPS, SJPC and PREPA, we are required to deliver to JPS, SJPC and PREPA specified amounts of natural gas at specified times, while under the SSA with Jamalco, we are required to deliver steam, and under the PPAs with JPS and the Nicaraguan electrical authority, 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 a counterparty 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 our currently contracted and expected LNG volumes through 2027, we may need to purchase significant additional LNG volumes to meet our delivery obligations to our downstream customers. Failure to secure contracts for the purchase of a sufficient amount of natural gas could materially and adversely affect our business, operating results, cash flows and liquidity.

Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurances that we will complete the Pennsylvania Facility or be able to supply our Facilities with LNG produced at our own Liquefaction Facilities or Fast LNG infrastructure. Even if we do complete the Pennsylvania Facility or implement our Fast LNG strategy, 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.

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

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

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

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

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

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

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

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decreases in the price of LNG; and

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

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

As part of our business development, we enter into non-binding agreements, and may not agree to 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.

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.

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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 was determined to be unconstitutional by a Mexican court, but the administration may propose a constitutional amendment to implement the change. More recently, on May 4, 2021, an amendment to the Mexican Hydrocarbons Law (Ley de Hidrocarburos) was published which would negatively impact our permits in Mexico. This amendment is being challenged as unconstitutional. If the amendment is enforced against us, it could negatively affect our permitting applications, our revenue and results of operations. If either 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 delay our ability to obtain permits necessary to commence operations or 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.

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.

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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:

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natural disasters;

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mechanical failures;

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grounding, fire, explosions and collisions;

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piracy;

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human error; and

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war and terrorism.

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

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

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

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marine disasters;

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piracy;

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bad weather;

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mechanical failures;

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environmental accidents;

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grounding, fire, explosions and collisions;

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human error; and

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war and terrorism.

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

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

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delays in the delivery of cargo;

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loss of revenues;

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termination of charter contracts;

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governmental fines, penalties or restrictions on conducting business;

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higher insurance rates; and

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damage to our reputation and customer relationships generally.

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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. 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. 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.

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.

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

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

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

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

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changes in governmental regulations or maritime self-regulatory organizations;

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

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bankruptcy or other financial crisis of shipbuilders;

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quality or engineering problems;

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

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

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

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

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

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

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

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

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

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

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

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expected supply is less than the amount hedged;

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

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

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

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

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

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

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

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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.

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.

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

The design, construction and operation of energy-related infrastructure, including our existing and proposed facilities, the import and export of LNG and the transportation of natural gas, are highly regulated activities at the federal, state and local levels. The process to obtain the permits, approvals and authorizations we need to conduct our business is complex, challenging and varies in each jurisdiction in which we operate.

In the United States and Puerto Rico, 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 its NEPA regulations. These regulations have taken legal effect, and although they have been challenged in court, they have not been stayed. The Council on Environmental Quality has announced that it is engaged in an ongoing and comprehensive review of the revised regulations and is assessing whether and how the Council may ultimately undertake a new rulemaking to revise the regulations. The impacts of any such future revisions that may be adopted are uncertain and indeterminable for the foreseeable future. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which is September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19, 2021 and July 15, 2021 orders with the United States Court of the Appeals for the District of Columbia Circuit. To date, no other party has sought review of FERC’s orders. While our petitions for review are pending, we intend to comply with FERC’s directive to file an application for authorization to operate the San Juan Facility no later than the September 15, 2021 deadline.

In Mexico, we have obtained substantially all permits and have commenced operations but are awaiting regassification and transmission permits. The regulatory authority that issues the regassification permit is temporarily closed because of COVID restrictions, and we do not know the precise date when we will receive the permits we need to commence full commercial operations.

We cannot control the outcome of any review or approval process in Mexico or any other jurisdiction where we operate, 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.

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

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

We currently conduct a meaningful portion of our business in Brazil, Jamaica and Puerto Rico and we soon expect to commence commercial operations in Mexico and Nicaragua. 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 these jurisdictions.

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

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

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

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change in applicable laws;

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an increase in oil, natural gas or petrochemical prices;

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devaluation of the applicable currency;

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higher inflation; or

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an increase in domestic interest rates,

then our business, results of operations, financial condition and prospects may also be significantly affected by actions taken by the government in the jurisdictions in which we operate. The COVID-19 pandemic has resulted in lower economic activity. 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.

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.

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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. 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.

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.

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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.

While Hygo has conducted its own internal investigation and did not identify evidence establishing bribery or other corrupt conduct involving Hygo, Hygo does not know if any authority is conducting an investigation of Mr. Antonello or Hygo, the results of any investigation, or 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, NFE Power Comercializadora de Gás Natural Ltda. (“NFE Power Comercializadora”), participated in a public competitive bid process sponsored by Petrobras for the lease of the Bahìa Facility. Although NFE Power Comercializadora was the only qualifying participant to submit a bid, in October 2020, Petrobras notified all participants that NFE Power Comercializadora was disqualified. NFE Power Comercializadora subsequently filed an administrative appeal before the Petrobras Bid Committee challenging the final result of the competitive process. In December 2020, NFE Power Comercializadora lost the appeal and was not awarded the bid for the Bahìa Facility.

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

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the amount of LNG or natural gas sold to customers;

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market price of LNG;

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

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

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

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

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

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prevailing economic conditions.

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

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

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

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

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

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

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.

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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.

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

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

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due to inflexibility or necessity of the generator;

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

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

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

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for purposes of exportation of power to foreign markets.

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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.

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.

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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.

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.

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

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

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

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

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

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

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

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.

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

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warnings;

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

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prohibition on operations;

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

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restrictions on the operation of existing facilities and projects; or

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

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

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

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

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

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

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

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

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

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

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

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NFE 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. NFE 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, NFE's ability to supply electricity under that plant's PPAs is adversely affected, which can lead to a decrease in NFE's revenues and increase NFE'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 and February 2021 is expected to decrease the Sergipe Power Plant's Physical Guarantee by up to 106MW for a 5 year period between 2022-2027. CELSE will need to purchase this capacity on the spot market in order to fulfill its obligations under the PPA and receive capacity payments. Additionally, 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 all of its business in Brazil. As a result, Hygo’s current business, results of operations, financial condition and prospects are materially dependent upon economic, political and other conditions and developments in Brazil. For example, on July 8, 2019, Petróleo Brasileiro S.A. – Petrobras (“Petrobras”) the state-owned oil company in Brazil, entered into an agreement (Termo de Compromisso de Cessão de Prática) with Brazilian antitrust authorities (Conselho Administrativo de Defesa Econômica - CADE) pursuant to which it has agreed to divest its equity participation in the gas pipelines and state gas distribution companies in Brazil by December 31, 2021. Such divestment plan, intended to end Petrobras’s monopoly on the distribution of gas in Brazil, will increase competition and may affect Hygo’s business.

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

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

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

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

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

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

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

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.

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.

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

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

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

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

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the quality and experience of its seafaring crew;

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

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its relationships with shipyards and construction management experience; and

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its willingness to accept operational risks pursuant to the charter.

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

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

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

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

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

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

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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.

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

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

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

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

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incur or assume unanticipated liabilities, losses or costs;

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

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

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

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

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

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

Hilli Corp, a wholly owned subsidiary of Hilli LLC, is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Facility”). The Hilli Facility provided for post-construction financing for the Hilli in the amount of $960 million.

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

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

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

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

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

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prevailing economic conditions in the natural gas and energy markets;

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a substantial or extended decline in demand for LNG;

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

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the size and age of a vessel; and

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

As GMLP’s vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on its business and operations if GMLP 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.

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.

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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:

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a shift in our investor base;

•

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

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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;

•

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

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

•

the operating and share price performance of other comparable companies;

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overall market fluctuations;

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general economic conditions; and

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

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

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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:

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

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

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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.

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.

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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:

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

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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;

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prohibiting cumulative voting in the election of directors;

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

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

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

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

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

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

The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation, including any debt issued in connection with the financing of the 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.

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.

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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.

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.

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As a public company with stock listed on Nasdaq, we are subject to an extensive body of regulations, 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 increases our legal, accounting, compliance and other expenses. 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. 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.

Not applicable.

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).

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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).

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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 (incorporated by reference to Exhibit 10.30 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).

10.31	Indemnity Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and certain affiliates of Stonepeak (incorporated by reference to Exhibit 10.31 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).

10.32	Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GMLP, GLNG and certain parties thereto (incorporated by reference to Exhibit 10.32 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).

10.33	Indemnification Agreement, dated as of April 15, 2021, by and between NFE International and GLNG (incorporated by reference to Exhibit 10.33 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).

10.34	Facility Agreement, dated September 18, 2021, by and among Golar Partners Operating LLC as the Borrower, Golar LNG Partners LP and certain subsidiaries of the Borrower, with (i) Citibank N.A. and the lenders from time to time party thereto; (ii) Citigroup Global Markets Limited, Morgan Stanley Senior Funding, Inc. and HSBC Bank USA, N.A. as mandated lead arrangers; (iii) Goldman Sachs Bank USA as arranger; (iv) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as bookrunners; (v) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as co-ordinators, (vi) Citibank Europe Plc, UK Branch as agent and (vii) Citibank, N.A., London Branch as security agent.

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

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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: November 3, 2021

	By:	/s/ Wesley R. Edens

	Name:	Wesley R. Edens

	Title:	Chief Executive Officer and Chairman

		(Principal Executive Officer)

Date: November 3, 2021

	By:	/s/ Christopher S. Guinta

	Name:	Christopher S. Guinta

	Title:	Chief Financial Officer

		(Principal Financial Officer)

Date: November 3, 2021

	By:	/s/ Yunyoung Shin

	Name:	Yunyoung Shin

	Title:	Chief Accounting Officer

		(Principal Accounting Officer)

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