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New Fortress Energy Inc. - Quarter Report: 2021 March (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 March 31, 2021

OR

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

For the transition period from __________ to__________

Commission File Number: 001-38790

New Fortress Energy Inc.
(Exact Name of Registrant as Specified in its Charter)

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

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
Securities registered pursuant to Section 12(b) of the Act:

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

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







TABLE OF CONTENTS

ii
 
 
iii
 
 
4
 
 
Item 1.
4
 
 
 
Item 2.
26
 
 
 
Item 3.
40
 
 
 
Item 4.
41
 
 
 
42
 
 
Item 1.
42
 
 
 
Item 1A.
42
 
 
 
Item 2.
90
 
 
 
Item 3.
90
 
 
 
Item 4.
90
 
 
 
Item 5.
90
 
 
 
Item 6.
91
 
 
 
94


i

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

Btu
the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute pressure of 14.696 pounds per square inch gage
   
CAA
Clean Air Act
   
CERCLA
Comprehensive Environmental Response, Compensation and Liability Act
   
CWA
Clean Water Act
   
DOE
U.S. Department of Energy
   
FERC
Federal Energy Regulatory Commission
   
GAAP
generally accepted accounting principles in the United States
   
GHG
greenhouse gases
   
GSA
gas sales agreement
   
Henry Hub
a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange
   
ISO container
International Organization of Standardization, an intermodal container
   
LNG
natural gas in its liquid state at or below its boiling point at or near atmospheric pressure
   
MMBtu
one million Btus, which corresponds to approximately 12.1 gallons of LNG
   
MW
megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt
   
NGA
Natural Gas Act of 1938, as amended
   
non-FTA countries
countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted
   
OPA
Oil Pollution Act
   
OUR
Office of Utilities Regulation (Jamaica)
   
PHMSA
Pipeline and Hazardous Materials Safety Administration
   
PPA
power purchase agreement
   
SSA
steam supply agreement
   
TBtu
one trillion Btus, which corresponds to approximately 12,100,000 gallons of LNG

ii

CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS

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

our limited operating history;
loss of one or more of our customers;
inability to procure LNG on a fixed-price basis, or otherwise to manage LNG price risks, including hedging arrangements;
the completion of construction on our LNG terminals, facilities, power plants or Liquefaction Facilities (as defined herein) and the terms of our construction contracts for the completion of these assets;
cost overruns and delays in the completion of one or more of our LNG terminals, facilities, power plants or Liquefaction Facilities, as well as difficulties in obtaining sufficient financing to pay for such costs and delays;
our ability to obtain additional financing to effect our strategy;
We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers;
failure to produce or purchase sufficient amounts of LNG or natural gas at favorable prices to meet customer demand;
hurricanes or other natural or manmade disasters;
failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
operational, regulatory, environmental, political, legal and economic risks pertaining to the construction and operation of our facilities;
inability to contract with suppliers and tankers to facilitate the delivery of LNG on their chartered LNG tankers;
cyclical or other changes in the demand for and price of LNG and natural gas;
failure of natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
competition from third parties in our business;
inability to re-finance our outstanding indebtedness;
changes to environmental and similar laws and governmental regulations that are adverse to our operations;
inability to enter into favorable agreements and obtain necessary regulatory approvals;
the tax treatment of us or of an investment in our Class A shares;
the completion of the Exchange Transactions (as defined below);
a major health and safety incident relating to our business;
increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;
risks related to the jurisdictions in which we do, or seek to do, business, particularly Florida, Jamaica, Brazil and the Caribbean; and
other risks described in the “Risk Factors” section of this Quarterly Report.

All forward-looking statements speak only as of the date of this Quarterly Report. When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in our Annual Report on Form 10-K for the year ended December 31, 2020 (our “Annual Report”), this Quarterly Report and in our other filings with the Securities and Exchange Commission (the “SEC”). The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, levels of activity, performance, projections or achievements.


iii


PART I
FINANCIAL INFORMATION

Item 1.
Financial Statements.

New Fortress Energy Inc.
Condensed Consolidated Balance Sheets
As of March 31, 2021 and December 31, 2020
(Unaudited, in thousands of U.S. dollars, except share amounts)

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

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

4


New Fortress Energy Inc.
Condensed Consolidated Statements of Operations and Comprehensive Loss
For the three months ended March 31, 2021 and 2020
(Unaudited, in thousands of U.S. dollars, except share and per share amounts)

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

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

5


New Fortress Energy Inc.
Condensed Consolidated Statements of Changes in Stockholders’ Equity
For the three months ended March 31, 2021 and 2020
(Unaudited, in thousands of U.S. dollars, except share amounts)

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

                   
Additional
         
Accumulated other
   
Non-
   
Total
 
   
Class A shares
   
Class B shares
   
Class A common stock
   
paid-in
   
Accumulated
   
comprehensive
   
controlling
   
stockholders'
 
   
Shares
   
Amount
   
Shares
   
Amount
   
Shares
   
Amount
   
capital
   
deficit
   
(loss) income
   
interest
   
equity
 
Balance as of December 31, 2019
   
23,607,096
   
$
130,658
     
144,342,572
   
$
-
     
-
   
$
-
   
$
-
   
$
(45,823
)
 
$
(30
)
 
$
302,519
   
$
387,324
 
Cumulative effect of accounting change
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(1,533
)
   
-
     
(7,780
)
   
(9,313
)
Net loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(8,466
)
   
-
     
(51,757
)
   
(60,223
)
Other comprehensive loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(53
)
   
(316
)
   
(369
)
Share-based compensation expense
   
-
     
2,508
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
2,508
 
Issuance of shares for vested RSUs
   
1,212,907
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Shares withheld from employees related to share-based compensation, at cost
   
(583,508
)
   
(6,132
)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(6,132
)
Balance as of March 31, 2020
   
24,236,495
   
$
127,034
     
144,342,572
   
$
-
     
-
   
$
-
   
$
-
   
$
(55,822
)
 
$
(83
)
 
$
242,666
   
$
313,795
 

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

6


New Fortress Energy Inc.
Condensed Consolidated Statements of Cash Flows
For the three months ended March 31, 2021 and 2020
(Unaudited, in thousands of U.S. dollars)

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

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

7


1.
Organization

New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”) is a Delaware corporation formed by New Fortress Energy Holdings LLC (“New Fortress Energy Holdings”). The Company is a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs and is engaged in providing energy and development services to end-users worldwide seeking to convert their operating assets from diesel or heavy fuel oil to LNG. The Company currently sources LNG from a combination of its own liquefaction facility in Miami, Florida and purchases on the open market. The Company has liquefaction, regasification and power generation operations in the United States and Jamaica.

The Company manages, analyzes and reports on its business and results of operations on the basis of one operating segment. The chief operating decision maker makes resource allocation decisions and assesses performance based on financial information presented on a consolidated basis.

2.
Significant accounting policies

The principal accounting policies adopted are set out below.

(a)
Basis of presentation and principles of consolidation

The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with GAAP and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. The condensed consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest.  All significant intercompany transactions and balances have been eliminated on consolidation. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020.

On February 4, 2019, the Company completed an initial public offering (“IPO”) and a series of other transactions, in which the Company issued and sold 20,000,000 Class A shares at an IPO price of $14.00 per share. The Company’s Class A shares began trading on Nasdaq Global Select Market (“Nasdaq”) under the symbol “NFE” on January 31, 2019. Net proceeds from the IPO were $257.0 million, after deducting underwriting discounts and commissions and transaction costs. These proceeds were contributed to New Fortress Intermediate LLC (“NFI”), an entity formed in conjunction with the IPO, in exchange for 20,000,000 limited liability company units in NFI (“NFI LLC Units”). In addition, New Fortress Energy Holdings contributed all of its interests in consolidated subsidiaries that comprised substantially all of its historical operations to NFI in exchange for NFI LLC Units. In connection with the IPO, New Fortress Energy Holdings also received 147,058,824 Class B shares of NFE, which is equal to the number of NFI LLC Units held by New Fortress Energy Holdings immediately following the IPO. New Fortress Energy Holdings retained a significant interest in NFE through its ownership of 147,058,824 Class B shares, representing an 88.0% voting and non-economic interest. New Fortress Energy Holdings also had an 88.0% economic interest in NFI through its ownership of 147,058,824 of NFI LLC Units. New Fortress Energy Holdings is NFE’s predecessor for accounting purposes.

On March 1, 2019, the underwriters of the IPO exercised their option to purchase an additional 837,272 Class A shares at the IPO price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting $0.7 million of underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. In connection with the exercise of the underwriters’ option to purchase an additional 837,272 Class A shares, NFE contributed such additional net proceeds to NFI in exchange for 837,272 NFI LLC Units.

Until the Exchange Transactions (as defined below) were completed, NFE was a holding company whose sole material asset was a controlling equity interest in NFI. As the sole managing member of NFI, NFE operated and controlled all of the business and affairs of NFI, and through NFI and its subsidiaries, conducted the Company’s historical business. The contribution of the assets of New Fortress Energy Holdings and net proceeds from the IPO to NFI was treated as a reorganization of entities under common control (the “Reorganization”). As a result, NFE presented the condensed consolidated balance sheets and statements of operations and comprehensive loss of New Fortress Energy Holdings for all periods prior to the IPO.

8

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

Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s condensed consolidated financial statements. Results of operations for the period prior to the date of the Exchange Transactions, June 10, 2020, was attributed to non-controlling interest based on the Exchanging Members’ interest in NFI; subsequent to the Exchange Transactions, results of operations, excluding results attributable to other investors in non-wholly owned subsidiaries, were recognized as net income or loss attributable to stockholders. Amounts that were attributable to these Exchanging Members' prior interest in NFI previously shown as non-controlling interest on the Company’s consolidated balance sheets have been reclassified to Class A shares.

On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (“the Conversion”). Since the IPO, NFE LLC had been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation had no effect on the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion was converted into one issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of NFE (“Class A common stock”). Class A shares shown on the Company’s condensed consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity. As of March 31, 2021, NFE had 175,320,414 Class A common stock outstanding.

(b)
Revenue recognition

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

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

The Company’s contracts with customers to supply natural gas or LNG may contain a lease of equipment. The Company allocates consideration received from customers between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term.

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

9

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

The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration; unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Both unbilled receivables and contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed consolidated balance sheets.

Shipping and handling costs are not considered to be separate performance obligations. These costs are recognized in the period in which the costs are incurred and presented within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas.

The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has elected to present sales tax collections in the condensed consolidated statements of operations and comprehensive loss on a net basis and, accordingly, such taxes are excluded from reported revenues.

The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.

3.
Adoption of new and revised standards

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

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. ASU 2020-06 is effective for public companies for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption of all amendments in the same period permitted. The Company is currently assessing the impact of adoption of this guidance.

(b)
New and amended standards adopted by the Company:

In December 2019, FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes, including removing certain exceptions related to the general principles in ASU 740, Income Taxes. ASU 2019-12 also clarifies and simplifies other aspects of the accounting for income taxes. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

10


4.
Revenue from contracts with customers

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of March 31, 2021 and December 31, 2020, receivables related to revenue from contracts with customers totaled $95,753 and $76,431, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $203 and $98, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent receivables associated with reimbursable costs and leases which are accounted for outside the scope of ASC 606.

The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are expected to be satisfied during the next 12 months, and the contract liabilities are classified within Other current liabilities on the condensed consolidated balance sheets. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. The contract liabilities and contract assets balances as of March 31, 2021 and December 31, 2020 are detailed below:

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

Contract assets are presented net of expected credit losses of $484 and $372 as of March 31, 2021 and December 31, 2020, respectively. As of March 31, 2021, the Company has unbilled receivables, net of current expected credit losses, of $6,729, of which $356 is presented within Other current assets and $6,373 is presented within Other non-current assets on the condensed consolidated balance sheet. These unbilled receivables represent unconditional right to payment subject only to the passage of time.

Operating revenue which includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, was $91,196 and $63,502 for the three months ended March 31, 2021 and 2020, respectively.

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

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

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

Transaction price allocated to remaining performance obligations

Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.

11

The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements is $10,478,395 as of March 31, 2021, representing the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:

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

For all other sales contracts that have a term exceeding one year, the Company has elected the practical expedient in ASC 606 under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied.

The Company has recognized costs to fulfill a contract with a significant customer, which primarily consist of expenses required to enhance resources to deliver under the agreement with the customer. As of March 31, 2021, the Company has capitalized $11,434 of which $604 of these costs is presented within Other current assets and $10,830 is presented within Other non-current assets on the condensed consolidated balance sheets. As of December 31, 2020, the Company had capitalized $11,276, of which $588 of these costs was presented within Other current assets and $10,688 was presented within Other non-current assets on the condensed consolidated balance sheets. In the first quarter of 2020, the Company began delivery under the agreement and started recognizing these costs on a straight-line basis over the expected term of the agreement.

5.
Leases


Lessee

The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.

The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.

12

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

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

For the three months ended March 31, 2021, the Company has capitalized $1,199 of lease costs, for vessels and port space used during the commissioning of development projects, in addition to short-term lease costs for vessels chartered by the Company to bring inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.

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

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

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

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

As of March 31, 2021, the weighted-average remaining lease term for all operating leases was 7.3 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of March 31, 2021 was 8.4%.

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

13


Lessor

In the Company’s agreements to sell LNG or natural gas to customers, the Company may also lease certain equipment to customers which are accounted for either as a finance or an operating lease. Property, plant and equipment subject to operating leases is included within ISO containers and other equipment within Note 11. Property, plant and equipment, net. The following is the amount of property, plant and equipment that is leased to customers:

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

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

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

6.
Fair value

Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:

Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.

Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.

Level 3 - unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.

The valuation techniques that may be used to measure fair value are as follows:

Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.

Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

14

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

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

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

(1)
Consideration due to the sellers in assets acquistions when certain contingent events occur.
(2)
To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received as specified in the amended Shannon LNG Agreement.

The Company estimates fair value of the derivative liability and equity agreement using a discounted cash flows method with discount rates based on the average yield curve for bonds with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent event occurring. The table below summarizes the fair value adjustment to the derivative liability and equity agreement, recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss, for the three months ended March 31, 2021 and 2020:

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

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

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

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

15


7.
Restricted cash

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

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

8.
Inventory

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

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

Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. No adjustments were recorded during the three months ended March 31, 2021 and 2020.

9.
Prepaid expenses and other current assets

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

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

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

16


10.
Construction in progress

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

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

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

11.
Property, plant and equipment, net

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

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

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

12.
Intangible assets

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

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

 
December 31, 2020
 
   
Gross Carrying
Amount
   
Accumulated
Amortization
   
Net Carrying
Amount
   
Weighted
Average Life
 
Definite-lived intangible assets
                       
Permits
 
$
45,897
   
$
2,438
   
$
43,459
     
40
 
Easements
   
1,559
     
190
     
1,369
     
30
 
                                 
Indefinite-lived intangible assets
                               
Easements
   
1,274
     
-
     
1,274
     
n/a
 
Total intangible assets
 
$
48,730
   
$
2,628
   
$
46,102
         

17

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

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

13.
Other non-current assets

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

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

Nonrefundable deposits are primarily related to deposits for planned land purchases in Pennsylvania and Ireland.

Upfront payments to customers consist of amounts the Company has paid in relation to two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own.

Other includes issuance costs associated with the 2026 Notes and Revolving Facility (both defined below) that closed in April 2021, upfront payments to our service providers, a long-term refundable deposit and investments in equity securities. During the fourth quarter of 2020, the Company invested $1,000 in a hydrogen technology development company through a Simple Agreement for Future Equity (“SAFE”).  During the first quarter of 2021, the investee completed a qualified financing which converted the Company’s investment into preferred shares; the Company also invested an additional $750 in this qualified financing.

14.
Accrued liabilities

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

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

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

18


15.
Debt

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

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

2025 Notes

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

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

The Company used a portion of the net cash proceeds received from the 2025 Notes to repay in full the outstanding principal and interest under the Credit Agreement (as defined below), including related costs and expenses. The Company also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds (as defined below), including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The Company completed the redemption of the Senior Secured Bonds and Senior Unsecured Bonds on September 21, 2020.

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

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

The Credit Agreement

On January 10, 2020, the Company entered into a credit agreement to borrow $800,000 in term loans (the “Credit Agreement”). The Credit Agreement was set to mature in January 2023 with the full principal balance due upon maturity. Interest was payable quarterly and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floor of 1.50%, plus a margin of 6.25%. The interest rate margin was to increase each year of the term by 1.50%. A portion of the proceeds received were utilized to extinguish the Term Loan Facility (defined below), including outstanding principal of $495,000.

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

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

19

Term Loan Facility

On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000, and proceeds received from this credit agreement were utilized to repay prior debt facilities. On December 31, 2018, the Company amended this credit agreement to increase the available borrowing principal amount to $500,000 (as amended, the “Term Loan Facility”), and as of December 31, 2018, the Company had an outstanding principal balance of $280,000 under the Term Loan Facility. On March 21, 2019, the Company drew an additional $220,000, bringing the Company’s total outstanding borrowings to $500,000 under the Term Loan Facility.

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

The Term Loan Facility had a maturity date of December 31, 2019 with an option to extend the maturity date for two additional six-month periods. Upon the exercise of each extension option, the Company would pay a fee equal to 1.0% of the outstanding principal balance at the time of the exercise and the spread on LIBOR and Base Rate would increase by 0.5%. On December 30, 2019, the Company entered into an amendment with the lenders to extend the maturity to January 21, 2020; no fees were due to lenders from the execution of this amendment. On January 15, 2020, the Company repaid the full amount outstanding including fees due to the lenders using proceeds from the Credit Agreement to extinguish the Term Loan Facility.  In conjunction with the extinguishment of the Term Loan Facility, the Company recognized a loss on extinguishment of debt of $9,557 in the condensed consolidated statements of operations and comprehensive loss.

South Power Bonds

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

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

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

The Company paid approximately $3,892 of fees in connection with the issuance of Senior Secured Bonds and Senior Unsecured Bonds. These fees were capitalized on a pro-rata basis as a reduction of the Senior Secured Bonds and Senior Unsecured Bonds on the condensed consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the 2025 Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds in the third quarter of 2020, the Company recognized a loss on extinguishment of debt of $7,195, including the write-off of $3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $3,601.

20

Interest Expense

Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the three months ended March 31, 2021 and 2020 consisted of the following:

 
Three Months Ended March 31,
 
   
2021
   
2020
 
Interest per contractual rates
 
$
20,834
   
$
18,874
 
Amortization of debt issuance costs
   
487
     
4,622
 
Total interest costs
   
21,321
     
23,496
 
Capitalized interest
   
2,641
     
9,606
 
Total interest expense
 
$
18,680
   
$
13,890
 
 
16.
Income taxes

In the third quarter of 2020, the Company completed the Conversion; NFE LLC had been a corporation for U.S. federal tax purposes and converting NFE LLC from a limited liability company to a corporation had no effect on the U.S. federal tax treatment of the Company or its shareholders.

In connection with the IPO, NFE LLC contributed the net proceeds from the IPO to NFI in exchange for NFI LLC Units, and NFE LLC became the managing member of NFI. Prior to the Exchange Transactions, NFI was a limited liability company that was treated as a partnership for U.S. federal income tax purposes and for most applicable state and local income tax purposes. As a partnership, NFI was not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by NFI was passed through to and included in the taxable income or loss of its members, on a pro rata basis, subject to applicable tax regulations. Subsequent to the Exchange Transactions completed on June 10, 2020, 100% of NFI’s operations are included in the NFE income tax provision; there was no impact on income tax expense due to the Exchange Transactions. NFE is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of NFI. Additionally, NFI and its subsidiaries are subject to income taxes in the various foreign jurisdictions in which they operate.

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

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

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

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

17.
Commitments and contingencies

The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company's financial position, results of operations or cash flows.

21


18.
Earnings per share

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

The following table presents potentially dilutive securities excluded from the computation of diluted net loss per share for the periods presented because its effects would have been anti-dilutive.

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

1
Represents the number of instruments outstanding at the end of the period.
2
Class B shares at the end of the period are considered potentially dilutive Class A shares. In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares.
3
Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

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

19.
Share-based compensation

RSUs

The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the New Fortress Energy Inc. 2019 Omnibus Incentive Plan. The fair value of RSUs on the grant date is estimated based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model.

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

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

22

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

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

For the three months ended March 31, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $0 and $61, respectively, was reversed. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized.

As of March 31, 2021, the Company had 869,262 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $6,400. The non-vested RSUs will vest over a period from ten months to three years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 1.05 years as of March 31, 2021.

Performance Share Units (“PSUs”)

During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting will be determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. For the three months ended March 31, 2021, the Company determined that it was not probable that the performance condition required for any of the PSUs to vest would be achieved, and as such, no compensation expense has been recognized in the condensed consolidated statements of operations and comprehensive loss

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

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

20.
Related party transactions

Management services

The Company is majority owned by Messrs. Edens (our chief executive officer and chairman of our Board of Directors) and Nardone (one of our Directors) who are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, has historically charged the Company for administrative and general expenses incurred pursuant to its Management Services Agreement (“Management Agreement”). Upon completion of the IPO, the Management Agreement was terminated and replaced by an Administrative Services Agreement (“Administrative Agreement”) to charge the Company for similar administrative and general expenses. The charges under the Administrative Agreement that are attributable to the Company totaled $1,927 and $2,231 for the three months ended March 31, 2021 and 2020, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss. As of March 31, 2021 and December 31, 2020, $7,145 and $5,535 were due to Fortress, respectively.

In addition to management and administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator market rates, charter costs of $1,609 and $1,239 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $554 and $472 was due to this affiliate, respectively.

Land lease

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

23

DevTech Investment

In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest is reflected as non-controlling interest in the Company’s condensed consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. As of March 31, 2021 and December 31, 2020, $715 was owed to DevTech on the note payable, and the outstanding note payable due to DevTech is included in Other long-term liabilities on the condensed consolidated balance sheets. The interest expense on the note payable due to DevTech was $21 and $19 for the three months ended March 31, 2021 and 2020, respectively. No interest has been paid, and accrued interest has been recognized within Other current liabilities on the condensed consolidated balance sheets. As of March 31, 2021 and December 31, 2020, $343 was due from DevTech.

Fortress affiliated entities

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

Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative services to the Company, as well as providing office space under a month-to-month non-exclusive license agreement. The Company incurred rent and administrative expenses of approximately $803 and $1,165 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $3,160 and $2,657 were due to Fortress affiliated entities, respectively.

Due to/from Affiliates

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

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

21.
Asset acquisitions

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

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

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

24

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

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

22.
Subsequent events

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

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

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

On April 15, 2021, we entered into a $200 million senior secured revolving facility (the “Revolving Facility”). The Revolving Facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.



25

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

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

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

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

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

Overview

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

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

Our Current Operations

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

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

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Montego Bay Facility

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

Old Harbour Facility

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

San Juan Facility

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

Miami Facility

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

Suape Development

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

Other Development Projects

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

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

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

27

Recent Developments: Hygo and GMLP Acquisitions

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

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

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

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

COVID-19 Pandemic

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

Based on the essential nature of the services we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities. For the three months ended March 31, 2021, we have incurred approximately $0.4 million for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

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

Other Matters

We received an order from FERC on June 18, 2020, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the Natural Gas Act. While we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, have sought rehearing of the March 19, 2021 FERC order and such rehearing requests remain pending before FERC. FERC’s orders in the proceeding would be subject to subsequent judicial review.

28

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

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

Revenues

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

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

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

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

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Other revenue includes revenue from development services, which is recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our power generation facilities, and such services are included within certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Other revenue increased $43,460 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020, and the increases were due to an increase in revenue for development services in Puerto Rico for the three months ended March 31, 2021, including gas used by our customer for testing and commissioning their assets. Development services revenue recognized in the three months ended March 31, 2021 included $45,618 for the customer’s use of 48.7 million gallons (4.0 TBtu) of natural gas as part of commissioning their assets.  The increase was partially offset by a decrease in development services revenue of $1,033 related to conversion of the customer’s infrastructure within the San Juan Power Plant.

Cost of sales

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

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

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

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

Operations and maintenance

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

Selling, general and administrative

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

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

Contract termination charges and loss on mitigation sales

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

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Depreciation and amortization

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

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

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

Interest expense

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

Other (income) expense, net

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

Loss on extinguishment of debt, net

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

Tax (benefit)

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

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

Factors Impacting Comparability of Our Financial Results

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

32

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

Hygo Debt

Sergipe Debt Financing

To finance construction of the Sergipe Facility and the Sergipe Power Plant, in April 2018, CELSE—Centrais Elétricas de Sergipe S.A. (“CELSE”) signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 and 2019 (the “CELSE Facility”). As of December 31, 2020, amounts outstanding and the effective interest rates under the CELSE Facility were as set forth below. Principal and interest payments are due each October and April, beginning October 2020. The CELSE Facility matures in April 2032.
           
Credit facility (Real and USD in millions)
 
Amount
Outstanding
 
Effective
interest rate
IFC
 
R$
844.9 ($156.8)
   
9.79
%
Inter-American Development Bank
 
R$
694.6 ($128.9)
   
9.69
%
IDB Invest
 
$
38.0
   
6.35
%
IDB China Fund
 
$
50.0
   
6.35
%

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

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

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

Debenture Loan

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

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Golar Nanook Leaseback and Credit Facility

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

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

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

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

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

Golar Penguin Leaseback and Credit Facility

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

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

Golar Celsius Leaseback and Credit Facility

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

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

GMLP Debt

Golar Eskimo Leaseback and Credit Facility

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

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

34

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

Golar Hilli Leaseback

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

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

Series A Preferred Units

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

Cash Flows

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

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

Cash (used in) operating activities

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

Cash (used in) investing activities

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

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

Cash (used in) provided by financing activities

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

35

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

Long-Term Debt

2025 Notes

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

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

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

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

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

2026 Notes

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

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

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

Revolving Facility

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

36

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

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

Off Balance Sheet Arrangements

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

Contractual Obligations

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

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

Long-term debt obligations

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

Purchase obligations

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

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

Lease obligations

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

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

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

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

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

Summary of Critical Accounting Estimates

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

Revenue recognition

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

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

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

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

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

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

Impairment of long-lived assets

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

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

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

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

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

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

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

Share-based compensation

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

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

Recent Accounting Standards

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


Item 3.
Quantitative and Qualitative Disclosures About Market Risks.

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

Commodity Price Risk

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

Interest Rate Risk

The 2025 Notes were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the 2025 Notes but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $50 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve.

We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Foreign Currency Exchange Risk

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

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Item 4.
Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2021 at the reasonable assurance level.
 
Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II
OTHER INFORMATION

Item 1.
Legal Proceedings.

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

Item 1A.
Risk Factors.

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

References to “NFE,” the “Company,” “we,” “us,” “our” and similar terms in this section refer to NFE Inc. and its subsidiaries, including Hygo and its subsidiaries, and including GMLP and its subsidiaries. References to “Hygo” and “GMLP”, respectively, in this section, refer to Hygo and GMLP and their respective subsidiaries, along with the Company and its subsidiaries.

Summary Risk Factors

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

Risks Related to the Mergers

• We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers;
• We may not have discovered undisclosed liabilities of either Hygo or GMLP during our due diligence process, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisitions of, Hygo and GMLP;
• We have incurred a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger and as a result of the consummation of the Mergers;

Risks Related to Our Business

• We have not yet completed contracting, construction and commissioning for all of our Facilities and Liquefaction Facilities and there can be no assurance that our Facilities or Liquefaction Facilities will operate as expected or at all;
• We may experience time delays, unforeseen expenses and other complications while developing our projects;
• We may not be profitable for an indeterminate period of time;
• Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;
• Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long term contracts that we have entered into or will enter into in the near future;
• Operation of our LNG infrastructure and other facilities that we may construct involves significant risks;
• The operation of the CHP Plant and any other power plants involves particular, significant risks;
• Information technology failures and cyberattacks could affect us significantly;
• Our insurance may be insufficient to cover losses that may occur to our property or result from our operations;
• We are unable to predict the extent to which the global COVID-19 pandemic will negatively adversely affect our operations financial performance, or ability to achieve our strategic objectives, or our customers and suppliers;
• We perform development or construction services from time to time which are subject to a variety of risks unique to these activities;
• We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations to customers;
• Failure of LNG to be a competitive source of energy in the markets in which we operate could adversely affect our expansion strategy;
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• Our current lack of asset and geographic diversification;
• Our business could be affected adversely by labor disputes, strikes or work stoppages in Brazil;
• Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operation of our facilities could impede operations and construction;

Risks Related to the Jurisdictions in Which We Operate

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

Risks Related to Hygo Business Activities

• Hygo’s Sergipe Facility is not currently operating at full capacity while equipment is being repaired, and we do not know the precise date when the facility will resume operations at full capacity. Once operations fully resume, the facility will be subject to customary operational risk for facilities of this type. Hygo’s other planned facilities are in various stages of contracting, construction, permitting and commissioning, each of which may present challenges to completion;
• Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various contingencies;
• Hygo may not be able to fully utilize the capacity of its facilities;
• Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil;
• Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities;

Risks Related to GMLP Business Activities

• GMLP currently derives all of its revenue from a limited number of customers and will face substantial competition in the future;
• GMLP’s equity investment in Golar Hilli LLC may not result in anticipated profitability or generate cash flow sufficient to justify its investment. In addition, this investment exposes GMLP to risks that may harm its business;
• GMLP may experience operational problems with its vessels that reduce revenue and increase costs;
• GMLP may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits;

Risks Related to Ownership of Our Class A Common Stock

• A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders; and
• The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all.

Risks Related to the Mergers

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

We are dependent on the experience and industry knowledge of our management personnel and other key employees to execute their business plans. Now that the Mergers have been completed, our success depends in part upon on our ability to attract, motivate and retain key management personnel and other key employees. No assurance can be given that we will be able to attract, motivate or retain management personnel and other key employees to the same extent now that the Mergers have been completed.

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

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

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

• managing a larger company;
• maintaining employee morale and attracting and motivating and retaining management personnel and other key employees;
• the possibility of faulty assumptions underlying expectations regarding the integration process;
• retaining existing business and operational relationships and attracting new business and operational relationships;
• consolidating corporate and administrative infrastructures and eliminating duplicative operations;
• coordinating geographically separate organizations;
• unanticipated issues in integrating information technology, communications and other systems; and
• unanticipated changes in federal or state laws or regulations.

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

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

We may not have discovered undisclosed liabilities or other issues of either Hygo or GMLP during our due diligence process, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo and GMLP.

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

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

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

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

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Risks Related to Our Business

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

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

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

We are actively pursuing a significant number of new LNG contracts with multiple counterparties in multiple jurisdictions.  Potential sales contracts may differ meaningfully depending on various factors, including, but not limited to: whether the potential customer is a government entity or a private party; whether the contract process is done pursuant to a public bidding process or a bilateral negotiation; the infrastructure and permits needed for a particular project; customer timing requirement