Annual Statements Open main menu

New Fortress Energy Inc. - Quarter Report: 2023 September (Form 10-Q)

Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2023
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)
Delaware83-1482060
(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 x 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 x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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 x
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 x
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class A common stock
“NFE”
Nasdaq Global Select Market
As of November 6, 2023, the registrant had 205,031,406 shares of Class A common stock outstanding.


Table of Contents
TABLE OF CONTENTS
i

Table of Contents
GLOSSARY OF TERMS
As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this Quarterly Report on Form 10-Q (“Quarterly Report”), the terms listed below have the following meanings:
ADOautomotive diesel oil
Bcf/yrbillion cubic feet per year
Btuthe 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
CAAClean Air Act
CERCLAComprehensive Environmental Response, Compensation and Liability Act
CWAClean Water Act
DOEU.S. Department of Energy
DOTU.S. Department of Transportation
EPAU.S. Environmental Protection Agency
FTA countriescountries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAPgenerally accepted accounting principles in the United States
GHGgreenhouse gases
GSAgas sales agreement
Henry Huba natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange
ISO containerInternational Organization of Standardization, an intermodal container
LNGnatural gas in its liquid state at or below its boiling point at or near atmospheric pressure
MMBtuone million Btus, which corresponds to approximately 12.1 gallons of LNG
mtpametric tons per year
MWmegawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt
NGANatural Gas Act of 1938, as amended
non-FTA countriescountries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted
OPAOil Pollution Act
ii

Table of Contents
OUROffice of Utilities Regulation (Jamaica)
PHMSAPipeline and Hazardous Materials Safety Administration
PPApower purchase agreement
SSAsteam supply agreement
TBtuone trillion Btus, which corresponds to approximately 12,100,000 gallons of LNG
iii

Table of Contents
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;
the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us;
construction and operational risks related to our facilities and assets, including cost overruns and delays;
failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;
delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;
failure to maintain sufficient working capital for the development and operation of our business and assets;
failure to convert our customer pipeline into actual sales;
lack of asset, geographic or customer diversification, including loss of one or more of our customers;
competition from third parties in our business;
cyclical or other changes in the demand for and price of LNG and natural gas;
inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;
inability to successfully develop and implement our technological solutions;
inability to service our debt and comply with our covenant restrictions;
inability to obtain additional financing to effect our strategy;
inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits;
economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;
weather events or other natural or manmade disasters or phenomena;
the extent of the global COVID-19 pandemic or any other major health and safety incident;
increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;
the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A shares; 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, 2022 (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.


iv

Table of Contents
PART I
FINANCIAL INFORMATION
Item 1.    Financial Statements.
New Fortress Energy Inc.
Condensed Consolidated Balance Sheets
As of September 30, 2023 and December 31, 2022
(Unaudited, in thousands of U.S. dollars, except share amounts)
September 30, 2023December 31, 2022
Assets
Current assets
Cash and cash equivalents$171,329 $675,492 
Restricted cash66,162 165,396 
Receivables, net of allowances of $1,133 and $884, respectively
360,820 280,313 
Inventory103,331 39,070 
Prepaid expenses and other current assets, net164,559 226,883 
Total current assets866,201 1,387,154 
Construction in progress4,789,799 2,418,608 
Property, plant and equipment, net2,563,871 2,116,727 
Equity method investments139,058 392,306 
Right-of-use assets474,483 377,877 
Intangible assets, net67,443 85,897 
Goodwill776,760 776,760 
Deferred tax assets, net8,074 8,074 
Other non-current assets, net110,681 141,679 
Total assets$9,796,370 $7,705,082 
Liabilities
Current liabilities
Current portion of long-term debt and short-term borrowings$270,547 $64,820 
Accounts payable892,924 80,387 
Accrued liabilities435,692 1,162,412 
Current lease liabilities142,296 48,741 
Other current liabilities169,744 52,878 
Total current liabilities1,911,203 1,409,238 
Long-term debt5,897,528 4,476,865 
Non-current lease liabilities318,082 302,121 
Deferred tax liabilities, net27,206 25,989 
Other long-term liabilities63,789 49,010 
Total liabilities8,217,808 6,263,223 
Commitments and contingencies (Note 19)
Stockholders’ equity
Class A common stock, $0.01 par value, 750 million shares authorized, 205.0 million issued and outstanding as of September 30, 2023; 208.8 million issued and outstanding as of December 31, 2022
2,050 2,088 
Additional paid-in capital1,039,428 1,170,254 
Retained earnings331,282 62,080 
Accumulated other comprehensive income 63,312 55,398 
Total stockholders’ equity attributable to NFE1,436,072 1,289,820 
Non-controlling interest142,490 152,039 
Total stockholders’ equity1,578,562 1,441,859 
Total liabilities and stockholders’ equity$9,796,370 $7,705,082 
The accompanying notes are an integral part of these condensed consolidated financial statements.
1

Table of Contents
New Fortress Energy Inc.
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
For the three and nine months ended September 30, 2023 and 2022
(Unaudited, in thousands of U.S. dollars, except share and per share amounts)
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Revenues
Operating revenue$420,868 $632,684 $1,417,175 $1,529,999 
Vessel charter revenue67,287 92,860 209,651 260,414 
Other revenue26,307 6,386 28,112 31,490 
Total revenues514,462 731,930 1,654,938 1,821,903 
Operating expenses
Cost of sales (exclusive of depreciation and amortization shown separately below)191,920 393,830 602,626 874,529 
Vessel operating expenses11,613 20,318 36,347 61,910 
Operations and maintenance60,819 22,033 121,187 65,691 
Selling, general and administrative49,107 67,601 157,048 165,952 
Transaction and integration costs2,739 5,620 4,787 12,387 
Depreciation and amortization48,670 35,793 125,160 106,439 
Asset impairment expense— — — 48,109 
Total operating expenses364,868 545,195 1,047,155 1,335,017 
Operating income149,594 186,735 607,783 486,886 
Interest expense64,822 63,588 200,891 156,344 
Other (income) expense, net(2,271)10,214 16,150 (31,613)
Loss on extinguishment of debt, net— 14,997 — 14,997 
Income before income from equity method investments and income taxes87,043 97,936 390,742 347,158 
Income (loss) from equity method investments489 (31,734)12,738 (354,426)
Tax provision (benefit)25,194 9,971 69,476 (126,249)
Net income62,338 56,231 334,004 118,981 
Net (income) loss attributable to non-controlling interest(1,117)5,617 (3,329)11,371 
Net income attributable to stockholders$61,221 $61,848 $330,675 $130,352 
Net income per share – basic$0.30 $0.30 $1.60 $0.62 
Net income per share – diluted$0.30 $0.29 $1.59 $0.62 
Weighted average number of shares outstanding – basic205,032,928 209,629,936 206,249,474 209,749,139 
Weighted average number of shares outstanding – diluted205,032,928 209,800,427 206,804,833 209,869,058 
Other comprehensive income (loss):
Net income$62,338 $56,231 $334,004 $118,981 
Currency translation adjustment(11,356)(33,087)7,693 48,040 
Comprehensive income50,982 23,144 341,697 167,021 
Comprehensive (income) loss attributable to non-controlling interest (795)6,085 (3,108)11,029 
Comprehensive income attributable to stockholders$50,187 $29,229 $338,589 $178,050 
The accompanying notes are an integral part of these condensed consolidated financial statements.
2

Table of Contents
New Fortress Energy Inc.
Condensed Consolidated Statements of Changes in Stockholders’ Equity
For the three and nine months ended September 30, 2023 and 2022
(Unaudited, in thousands of U.S. dollars, except share amounts)
Class A common stockAdditional
paid-in
capital
Retained earningsAccumulated other
comprehensive
income
Non-
controlling
interest
Total
stockholders’ equity
Shares Amount
Balance as of December 31, 2022208,770,088 $2,088 $1,170,254 $62,080 $55,398 $152,039 $1,441,859 
Net income— — — 150,206 — 1,360 151,566 
Other comprehensive income— — — — 1,946 195 2,141 
Cancellation of shares(4,100,000)(41)(122,713)— — — (122,754)
Dividends— — — (20,467)— (3,019)(23,486)
Balance as of March 31, 2023204,670,088 $2,047 $1,047,541 $191,819 $57,344 $150,575 $1,449,326 
Net income— — — 119,248 — 852 120,100 
Other comprehensive income (loss)— — — — 17,002 (94)16,908 
Share-based compensation expense— — 1,179 — — — 1,179 
Issuance of shares for vested share-based compensation awards689,401 — — — — 
Shares withheld from employees related to share-based compensation, at cost(328,083)— (9,519)— — — (9,519)
Dividends— — — (20,503)— (6,619)(27,122)
Balance as of June 30, 2023205,031,406 $2,050 $1,039,201 $290,564 $74,346 $144,714 $1,550,875 
Net income— — — 61,221 — 1,117 62,338 
Other comprehensive loss— — — — (11,034)(322)(11,356)
Share-based compensation expense— — 227 — — — 227 
Dividends— — — (20,503)— (3,019)(23,522)
Balance as of September 30, 2023205,031,406 $2,050 $1,039,428 $331,282 $63,312 $142,490 $1,578,562 
3

Table of Contents
Class A common stockAdditional
paid-in
capital
Retained earnings (Accumulated
deficit)
Accumulated other
comprehensive income (loss)
Non-
controlling
interest
Total
stockholders’
equity
Shares Amount
Balance as of December 31, 2021206,863,242 $2,069 $1,923,990 $(132,399)$(2,085)$202,479 $1,994,054 
Net income— — — 238,269 — 2,912 241,181 
Other comprehensive income— — — — 118,874 1,956 120,830 
Share-based compensation expense— — 880 — — — 880 
Issuance of shares for vested RSUs1,121,255 — — — — 
Shares withheld from employees related to share-based compensation, at cost(442,146)— (15,274)— — — (15,274)
Dividends— — (20,754)— — (3,019)(23,773)
Balance as of March 31, 2022207,542,351 $2,076 $1,888,842 $105,870 $116,789 $204,328 $2,317,905 
Net loss— — — (169,765)— (8,666)(178,431)
Other comprehensive loss— — — — (38,557)(1,146)(39,703)
Share-based compensation expense— — 358 — — — 358 
Issuance of shares for vested RSUs13,898 — — — — — — 
Dividends— — (20,582)— — (7,019)(27,601)
Balance as of June 30, 2022207,556,249 $2,076 $1,868,618 $(63,895)$78,232 $187,497 $2,072,528 
Net income (loss)— — — 61,848 — (5,617)56,231 
Other comprehensive loss— — — — (32,619)(468)(33,087)
Share-based compensation expense— — 13,417 — — — 13,417 
Issuance of shares for vested RSU/PSUs2,291,060 12 (12)— — — — 
Shares withheld from employees related to share-based compensation, at cost(1,077,221)— (59,548)— — — (59,548)
Deconsolidation of vessels— — — — — (23,569)(23,569)
Dividends— — (20,756)— — (3,019)(23,775)
Balance as of September 30, 2022208,770,088 $2,088 $1,801,719 $(2,047)$45,613 $154,824 $2,002,197 




The accompanying notes are an integral part of these condensed consolidated financial statements.
4

Table of Contents
New Fortress Energy Inc.
Condensed Consolidated Statements of Cash Flows
For the nine months ended September 30, 2023 and 2022
(Unaudited, in thousands of U.S. dollars)
Nine Months Ended September 30,
2023 2022
Cash flows from operating activities
Net income$334,004 $118,981 
Adjustments for:
Depreciation and amortization125,853 107,185 
(Earnings) losses of equity method investees(12,738)354,426 
Dividends received from equity method investees5,830 23,195 
Change in market value of derivatives(2,672)(6,700)
Deferred taxes1,217 (203,026)
Asset impairment expense— 48,109 
Earnings recognized from vessels chartered to third parties transferred to Energos(112,608)(14,341)
Loss on the disposal of equity method investment37,401 — 
Loss on extinguishment of debt— 14,997 
Loss on sale of net investment in lease— 11,592 
Other2,211 15,464 
Changes in operating assets and liabilities:
(Increase) in receivables(86,743)(287,748)
(Increase) in inventories(29,238)(28,078)
Decrease (Increase) in other assets56,512 (93,329)
Decrease in right-of-use assets68,360 51,265 
Increase (decrease) in accounts payable/accrued liabilities73,211 (10,487)
Increase (decrease) in amounts due to affiliates1,613 (3,220)
(Decrease) in lease liabilities(56,908)(47,237)
Increase in other liabilities131,879 40,057 
Net cash provided by operating activities537,184 91,105 
Cash flows from investing activities
Capital expenditures(2,191,605)(787,166)
Sale of equity method investment100,000 — 
Proceeds from sale of net investment in lease— 593,000 
Other investing activities26,043 (1,794)
Net cash used in investing activities(2,065,562)(195,960)
Cash flows from financing activities
Proceeds from borrowings of debt1,768,715 1,932,020 
Payment of deferred financing costs(18,064)(16,093)
Repayment of debt(104,530)(1,518,471)
Payments related to tax withholdings for share-based compensation(9,519)(72,597)
Payment of dividends(700,440)(75,149)
Other financing activities(12,090)— 
Net cash provided by financing activities924,072 249,710 
Impact of changes in foreign exchange rates on cash and cash equivalents923 (4,896)
Net (decrease) increase in cash, cash equivalents and restricted cash(603,383)139,959 
Cash, cash equivalents and restricted cash – beginning of period855,083 264,030 
Cash, cash equivalents and restricted cash – end of period$251,700 $403,989 
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$641,967 $112,886 
Principal payments on financing obligation to Energos by third party charterers(52,035)(5,438)
Shares received in Hilli Exchange(122,754)— 
5

Table of Contents
Investment in Energos— 129,518 
Non-cash financing— 41,264 
The following table identifies the balance sheet line-items included in Cash and cash equivalents, Current restricted cash, and Non-current restricted cash presented in the Condensed Consolidated Statement of Cash Flows:
Nine Months Ended September 30,
20232022
Cash and cash equivalents$171,329 $364,313 
Current restricted cash66,162 24,204 
Non-current restricted cash— 2,581 
Cash and cash equivalents classified as held for sale14,209 12,891 
Cash, cash equivalents and restricted cash – end of period$251,700 $403,989 
Cash and cash equivalents as of September 30, 2023 and 2022 includes $14,209 and $12,891, respectively, which have been classified as assets held for sale and included in Other current assets on the condensed consolidated balance sheets.















The accompanying notes are an integral part of these condensed consolidated financial statements.
6

Table of Contents

1. Organization
New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. The Company owns and operates natural gas and liquefied natural gas ("LNG") infrastructure, ships and logistics assets to rapidly deliver turnkey energy solutions to global markets. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, Brazil and Mexico. The Company has marine operations with vessels operating under time charters and in the spot market globally.
The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business.
2. Basis of presentation
The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2022 (the "Annual Report"). Certain prior year amounts have been reclassified to conform to current year presentation.
The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions, impacting the reported amounts of assets and liabilities, net earnings and disclosures of contingent assets and liabilities as of the date of the condensed consolidated financial statements. Actual results could be different from these estimates.
3. Adoption of new and revised standards
The Company has reviewed recently issued accounting pronouncements and concluded that such pronouncements are either not applicable to the Company or no material impact is expected in the condensed consolidated financial statements as a result of future adoption.
4. Revenue recognition
Operating revenue in the condensed consolidated statements of operations and comprehensive income (loss) 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, and the sale of LNG cargos. The Company did not have any LNG cargo sales in the third quarter of 2023. For the nine months ended September 30, 2023, the Company recognized LNG cargo sales to customers of $617,138, which included $332,000 of contract settlements. LNG cargo sales for the three and nine months ended September 30, 2022 were $350,550 and $944,751, respectively.

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of September 30, 2023 and December 31, 2022, receivables related to revenue from contracts with customers totaled $351,160 and $280,382, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $1,133 and $884, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases, which are accounted for outside the scope of ASC 606, and receivables associated with reimbursable costs.
Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. 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 contract assets and contract liabilities balances as of September 30, 2023 and December 31, 2022 are detailed below:
7

Table of Contents
September 30, 2023December 31, 2022
Contract assets, net - current$8,567 $8,083 
Contract assets, net - non-current22,176 28,651 
Total contract assets, net$30,743 $36,734 
Contract liabilities, net - current$69,254 $12,748 
Contract liabilities, net - non-current41,818 — 
Total contract liabilities, net$111,072 $12,748 
Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year$12,748 $2,951 
Contract assets are presented net of expected credit losses of $326 and $401 as of September 30, 2023 and December 31, 2022, respectively. As of September 30, 2023 and December 31, 2022, contract assets was comprised of $30,603 and $36,483 of unbilled receivables, respectively, which represent unconditional rights to payment only subject to the passage of time.
Contract liabilities increased during the nine months ended September 30, 2023 primarily due to upfront payments received under the Company's contracts in Puerto Rico to provide temporary power and to operate and maintain PREPA's power generation assets. These payments will be recognized as revenue over the expected term of these contracts.
The Company has recognized costs to fulfill contracts with customers, which primarily consist of expenses required to enhance resources to deliver under agreements with these customers. These costs can include set-up and mobilization costs incurred ahead of the service period, and such costs will be recognized on a straight-line basis over the expected terms of the agreements. As of September 30, 2023, the Company has capitalized $26,587 of which $2,753 of these costs is presented within Prepaid expenses and other current assets, net and $23,834 is presented within Other non-current assets, net on the condensed consolidated balance sheets. As of December 31, 2022, the Company had capitalized $10,377, of which $604 of these costs was presented within Prepaid expenses and other current assets, net and $9,773 was presented within Other non-current assets, net on the condensed consolidated balance sheets.
Transaction price allocated to remaining performance obligations
Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.
The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements represents the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:
PeriodRevenue
Remainder of 2023
$473,460 
20242,044,859 
20251,449,971 
2026528,514 
2027525,643 
Thereafter8,004,334 
Total$13,026,781 
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
8

Table of Contents
variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied.
Lessor arrangements
Property, plant and equipment subject to vessel charters accounted for as operating leases is included within Vessels within "Note 12 Property, plant and equipment, net." Vessels included in the Energos Formation Transaction (defined below in "Note 10 Equity method investments"), including those vessels chartered to third parties, continue to be recognized on the condensed consolidated balance sheet. The carrying amount of these vessels that are leased to third parties under operating leases is as follows:
September 30, 2023December 31, 2022
Property, plant and equipment$917,563 $1,292,957 
Accumulated depreciation(84,503)(80,233)
Property, plant and equipment, net$833,060 $1,212,724 
The components of lease income from vessel operating leases for the three and nine months ended September 30, 2023 and 2022 are shown below. As the Company has not recognized the sale of all of the vessels included in the Energos Formation Transaction, the operating lease income shown below for the three and nine months ended September 30, 2023 is comprised of revenue from third-party charters of vessels included in the Energos Formation Transaction.
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Operating lease income$66,557 $83,188 $208,921 $235,092 
Variable lease income730 8,238 730 19,470 
Total operating lease income$67,287 $91,426 $209,651 $254,562 
Prior to the completion of the Energos Formation Transaction, the Company's charter of the Nanook was accounted for as a finance lease, and the Company recognized interest income of $5,517 and $28,643 for the three and nine months ended September 30, 2022, respectively, related to this finance lease, which was presented within Other revenue in the condensed consolidated statements of operations and comprehensive income (loss). The Company also recognized revenue of $1,434 and $5,852 for the three and nine months ended September 30, 2022, respectively, related to the operation and services agreement and variable charter revenue within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized the sale of the net investment in the finance lease of the Nanook as part of the Energos Formation Transaction.
Subsequent to the Energos Formation Transaction, all cash receipts on vessel charters, including the finance lease of the Nanook, will be received by Energos. As such, there are no future cash receipts from operating leases, and the future cash receipts from other finance leases are not significant as of September 30, 2023.
9

Table of Contents
5. Leases, as lessee
The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the right-of-use ("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.
As of September 30, 2023 and December 31, 2022, ROU assets, current lease liabilities and non-current lease liabilities consisted of the following:
September 30, 2023 December 31, 2022
Operating right-of-use-assets$418,265 $355,883 
Finance right-of-use-assets (1)
56,218 21,994 
Total right-of-use assets$474,483 $377,877 
Current lease liabilities:
Operating lease liabilities$114,536 $44,371 
Finance lease liabilities27,760 4,370 
Total current lease liabilities$142,296 $48,741 
Non-current lease liabilities:
Operating lease liabilities$294,972 $290,899 
Finance lease liabilities23,110 11,222 
Total non-current lease liabilities$318,082 $302,121 
(1) Finance lease ROU assets are recorded net of accumulated amortization of $15,582 and $2,134 as of September 30, 2023 and December 31, 2022, respectively.
For the three and nine months ended September 30, 2023 and 2022, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive income (loss) was as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Fixed lease cost$33,840 $19,433 $73,066 $58,346 
Variable lease cost1,435 622 3,036 1,558 
Short-term lease cost11,502 6,204 17,421 12,326 
Lease cost - Cost of sales$28,409 $23,438 $59,300 $64,453 
Lease cost - Operations and maintenance16,274 1,066 28,322 2,675 
Lease cost - Selling, general and administrative2,094 1,755 5,901 5,102 
For the three months ended September 30, 2023 and 2022, the Company has capitalized $8,111 and $4,005 of lease costs, respectively. For the nine months ended September 30, 2023 and 2022, the Company has capitalized $26,816 and $15,220
10

Table of Contents
of lease costs, respectively. Capitalized costs include vessels and port space used during the commissioning of development projects. Short-term lease costs for vessels chartered by the Company to transport inventory from a supplier’s facilities to the Company’s storage locations are capitalized to inventory.
The Company has leases of turbines, ISO tanks and a parcel of land that are recognized as finance leases. For the three and nine months ended September 30, 2023 and 2022, the Company’s finance interest expense and amortization recorded in Interest expense and Depreciation and amortization, respectively, within the condensed consolidated statements of operations and comprehensive income (loss) were as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Interest expense related to finance leases$1,080 $208 $2,766 $655 
Amortization of right-of-use asset related to finance leases5,888 378 13,448 1,137 
Cash paid for operating leases is reported in operating activities in the condensed consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the nine months ended September 30, 2023 and 2022:
Nine Months Ended September 30,
20232022
Cash outflows for operating lease liabilities$89,326 $73,389 
Cash outflows for finance lease liabilities13,582 3,654 
Right-of-use assets obtained in exchange for new operating lease liabilities130,646 135,075 
Right-of-use assets obtained in exchange for new finance lease liabilities47,672 — 
The future payments due under operating and finance leases as of September 30, 2023 are as follows:
Operating LeasesFinancing Leases
Due remainder of 2023
$39,454 $8,101 
2024137,439 29,997 
202575,637 12,427 
202652,744 3,041 
202752,281 436 
Thereafter187,505 943 
Total lease payments$545,060 $54,945 
Less: effects of discounting135,552 4,075 
Present value of lease liabilities$409,508 $50,870 
Current lease liability$114,536 $27,760 
Non-current lease liability294,972 23,110 
As of September 30, 2023, the weighted average remaining lease term for operating leases was 6.4 years and finance leases was 2.2 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of September 30, 2023 was 8.8% and as of December 31, 2022 was 8.5%. The weighted average discount rate associated with finance leases as of September 30, 2023 was 8.2% and as of December 31, 2022 was 5.1%.
11

Table of Contents
6. Financial instruments
Commodity risk management
The Company has utilized commodity swap transactions to manage exposure to changes in market pricing of natural gas or LNG. Realized and unrealized gains and losses on these transactions have been recognized in Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).
During the fourth quarter of 2022, the Company entered into a commodity swap transaction to swap market pricing exposure for approximately 6.8 TBtus for a fixed price of $40.55 per MMBtu. The swap settled during the first quarter of 2023 resulting in a gain of $41,315 recognized as a reduction to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss). The gain was comprised of a realized gain of $146,112 and the reversal of the unrealized gain of $104,797 recognized in the fourth quarter of 2022.
In January 2023, the Company entered into a series of commodity swap transactions. Mark-to-market unrealized gains of $975 for the three months ended September 30, 2023 and unrealized losses of $1,841 for the nine months ended September 30, 2023 on this instrument have been recognized in Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).
Interest rate and currency risk management
The Company was party to an interest rate swap, and in the first quarter of 2023, the interest rate swap was terminated.
The Company does not hold or issue instruments for speculative purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties.
The mark-to-market gain or loss on the interest rate swap and other derivative instruments that are not intended to mitigate commodity risk are reported in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss).
Fair value
Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:
Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.
Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.
Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.
The valuation techniques that may be used to measure fair value are as follows:
Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.
Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The Company uses the market approach when valuing investment in equity securities which is recorded in Other non-current assets on the condensed consolidated balance sheets as of September 30, 2023 and December 31, 2022.
12

Table of Contents
The Company uses the income approach when valuing the following financial instruments:
Interest rate swap - The Company did not have any interest rate swaps outstanding as of September 30, 2023. As of December 31, 2022, the Company had an interest rate swap that was recorded within Other non-current assets on the condensed consolidated balance sheets.
The liability and asset associated with commodity swaps are recorded within Other current liabilities and Prepaid expenses and other current assets on the condensed consolidated balance sheets as of September 30, 2023 and December 31, 2022, respectively.
Contingent consideration derivative liability represents consideration due to the sellers in asset acquisitions when certain contingent events occur. The liabilities associated with these derivative liabilities are recorded within Other current liabilities and Other long-term liabilities on the condensed consolidated balance sheets based on the timing of expected settlement.
The fair value of derivative instruments, including commodity swaps is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties. The Company estimates fair value of the contingent consideration derivative liabilities 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 events occurring.
The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of September 30, 2023 and December 31, 2022:
Level 1Level 2Level 3Total
September 30, 2023
Assets
Investment in equity securities$— $— $7,678 $7,678 
Liabilities
Commodity swap$— $1,841 $— $1,841 
Contingent consideration derivative liabilities— — 40,946 40,946 
December 31, 2022
Assets
Investment in equity securities$10,128 $— $7,678 $17,806 
Interest rate swap— 11,650 — 11,650 
Commodity swap— 104,797 — 104,797 
Liabilities
Contingent consideration derivative liabilities$— $— $46,619 $46,619 
The Company believes the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value as of September 30, 2023 and December 31, 2022 and are classified as Level 1 within the fair value hierarchy.
The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, including the contingent consideration derivative liabilities. These adjustments have been recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss) for the three and nine months ended September 30, 2023 and 2022:
13

Table of Contents
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Contingent consideration derivative liabilities - Fair value adjustment - (gain) / loss$(2,722)$177 $(5,757)$1,161 
Foreign currency forward purchase - (gain)— (2,923)— (20,394)
During the nine months ended September 30, 2023 and 2022, the Company had no settlements or transfers in or out of Level 3 in the fair value hierarchy.
7. Restricted cash
As of September 30, 2023 and December 31, 2022, restricted cash consisted of the following:
September 30, 2023December 31, 2022
Cash restricted under the terms of loan agreements$3,825 $124,085 
Collateral for letters of credit and performance bonds62,337 41,392 
Collateral for interest rate swaps— 2,500 
  Total restricted cash$66,162 $167,977 
Current restricted cash$66,162 $165,396 
Non-current restricted cash— 2,581 
As of September 30, 2023, the balance presented as collateral for letters of credit and performance bonds includes $21,300 to support a letter of credit to facilitate the purchase of turbines that was completed in the third quarter of 2023. A portion of these turbines will be utilized to support the Company's contract to generate temporary power in Puerto Rico.
Use of cash proceeds under the Barcarena Term Loan are restricted to certain payments to construct the Barcarena Power Plant (each as defined in our Annual Report). Non-current restricted cash is presented in Other non-current assets, net on the condensed consolidated balance sheets.
8. Inventory
As of September 30, 2023 and December 31, 2022, inventory consisted of the following:
September 30, 2023December 31, 2022
LNG and natural gas inventory$73,936 $15,398 
Automotive diesel oil inventory9,848 8,164 
Bunker fuel, materials, supplies and other19,547 15,508 
Total inventory$103,331 $39,070 
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 income (loss). In the second quarter of 2023, the Company acquired a spot cargo at a higher cost to obtain a new customer contract. The net realizable value of this cargo was below the cost as of June 30, 2023, and as such, we recognized an adjustment to inventory of $6,232. No adjustments were recorded during the three months ended September 30, 2023 or the nine months ended September 30, 2022.
14

Table of Contents
9. Prepaid expenses and other current assets
As of September 30, 2023 and December 31, 2022, prepaid expenses and other current assets consisted of the following:
September 30, 2023December 31, 2022
Prepaid expenses$26,831 $56,380 
Recoverable taxes68,748 37,504 
Commodity swap— 104,797 
Due from affiliates1,542 698 
Assets held for sale48,879 — 
Other current assets18,559 27,504 
Total prepaid expenses and other current assets, net$164,559 $226,883 
Prepaid expenses as December 31, 2022 included $34,882 of prepaid LNG inventory. The Company does not have any significant prepaid LNG inventory as of September 30, 2023. Other current assets as of September 30, 2023 and December 31, 2022 primarily consists of deposits and the current portion of contract assets (Note 4).
Assets held for sale
In the third quarter of 2022, NFE Brazil Holdings LLC ("Brazil Holdings"), a consolidated indirect subsidiary of NFE and indirect owner of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”), and Centrais Elétricas de Pernambuco S.A. – EPESA (“EPESA”), entered into a Share Purchase Agreement pursuant to which Brazil Holdings agreed to sell 100% of the shares of Pecém and Muricy to EPESA, following an internal reorganization. The sale price includes cash consideration of BRL 59 million (approximately $12 million using the exchange rate as of September 30, 2023), as well as additional consideration for the satisfaction of certain milestones. Consideration under this agreement also includes potential future earnout payments based on the revenue generated from power purchase agreements held by Pecém and Muricy. The sale of Pecém and Muricy was approved by Agência Nacional de Energia Elétrica ("ANEEL") after the balance sheet date; the sale is subject to customary terms and conditions and conditions precedent prior to closing.
All assets and liabilities of Pecém and Muricy were classified as held for sale as of September 30, 2023 and December 31, 2022. The estimated fair value of these entities based on the consideration in the agreement was in excess of the carrying value, and no impairment loss was recognized upon classification as held for sale. Assets held for sale include a cash balance of $14,209 and $11,614 as of September 30, 2023 and December 31, 2022, respectively, which have been included in the ending cash and cash equivalents on the condensed consolidated statement of cash flows.
10. Equity method investments
Changes in the balance of the Company’s equity method investments is as follows:
September 30, 2023
Equity method investments as of December 31, 2022
$392,306 
Dividends(5,830)
Equity in earnings of investees12,738 
Sale of equity method investments(260,156)
Equity method investments as of September 30, 2023
$139,058 
15

Table of Contents
The carrying amounts of the Company's equity method investments as of September 30, 2023 and December 31, 2022 are:
September 30, 2023December 31, 2022
Hilli LLC$— $260,000 
Energos139,058 132,306 
Total$139,058 $392,306 
As of September 30, 2023, the carrying value of the Company’s equity method investment was less than its proportionate share of the underlying net assets of its investee by $1,548. At December 31, 2022, the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $16,976, and the basis difference attributable to amortizable net assets was amortized to Income (loss) from equity method investments in the condensed consolidated statements of operations and comprehensive income (loss) over the remaining estimated useful lives of the underlying assets.
Hilli LLC
On March 15, 2023, the Company completed a transaction with Golar LNG Limited ("GLNG") for the sale of the Company's investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100,000 in cash (the "Hilli Exchange"). In the fourth quarter of 2022, the Company recognized an other-than-temporary impairment on the investment in Hilli LLC of $118,558; this impairment was recognized in Income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss). Upon completion of the Hilli Exchange, a loss on disposal of $37,401 was recognized in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss). As a result of the Hilli Exchange, the Company no longer has an ownership interest in the Hilli. NFE shares received from GLNG were cancelled upon closing of the Hilli Exchange.
The Company had guaranteed 50% of the outstanding principal and interest amounts payable by Hilli Corp., a direct subsidiary of Hilli LLC. The Company had also guaranteed letters of credit issued by a financial institution in the event of Hilli Corp.’s underperformance or non-performance under the liquefaction tolling agreement with its customer. In conjunction with the Hilli Exchange, the Company is no longer a guarantor under these arrangements, and the remaining guarantee liability of $2,286 was derecognized as a reduction to Selling, general and administrative in the condensed consolidated statements of operations in the first quarter of 2023.
Energos
In August 2022, the Company completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which the Company transferred ownership of 11 vessel to Energos Infrastructure ("Energos") in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. The Company's equity investment provides certain rights, including representation on the board of directors, which give the Company significant influence over the operations of Energos, and as such, the investment has been accounted for under the equity method; this investment is included within the Ships segment. Energos is also an affiliate, and all transactions with Energos are transactions with an affiliate.
Due to the timing and availability of financial information of Energos, the Company recognizes its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. For the three and nine months ended September 30, 2023, the Company has recognized earnings from Energos of $489 and $6,752.
16

Table of Contents
11. Construction in progress
The Company’s construction in progress activity during the nine months ended September 30, 2023 is detailed below:
September 30, 2023
Construction in progress as of December 31, 2022
$2,418,608 
Additions2,889,770 
Impact of currency translation adjustment13,811 
Assets placed in service(532,390)
Construction in progress as of September 30, 2023
$4,789,799 
Interest expense of $201,890 and $56,778, inclusive of amortized debt issuance costs, was capitalized for the nine months ended September 30, 2023 and 2022, respectively.
The Company has significant development activities in Latin America as well as the development of the Company's Fast LNG liquefaction solution, and the completion of such developments are subject to risks of successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. The Company's development activities for the nine months ended September 30, 2023 were primarily focused on Fast LNG and the construction of temporary power generation assets to support the Puerto Rican grid stabilization project; additions to construction in progress in the first nine months of 2023 of $2,569,197 were to develop Fast LNG projects and Puerto Rican temporary power.
Assets placed in service during 2023 are primarily comprised of assets to support our Puerto Rican temporary power project and our power plant at the Port of Pichilingue in Baja California Sur, Mexico.
12. Property, plant and equipment, net
As of September 30, 2023 and December 31, 2022, the Company’s property, plant and equipment, net consisted of the following:
September 30, 2023December 31, 2022
Vessels$1,527,684 $1,518,839 
Terminal and power plant equipment430,883 218,296 
CHP facilities273,978 123,897 
Gas terminals179,103 177,780 
ISO containers and other equipment148,756 134,324 
LNG liquefaction facilities63,316 63,316 
Gas pipelines66,319 65,985 
Land52,759 52,995 
Leasehold improvements152,962 9,377 
Accumulated depreciation(331,889)(248,082)
Total property, plant and equipment, net$2,563,871 $2,116,727 
The book value of the vessels that was recognized due to the failed sale leaseback in the Energos Formation Transaction as of September 30, 2023 and December 31, 2022 was $1,308,795 and $1,328,553, respectively.
Depreciation expense for the three months ended September 30, 2023 and 2022 totaled $36,705 and $26,326, respectively, of which $230 and $222, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss). Depreciation expense for the nine months ended September 30, 2023 and 2022 totaled $92,980 and $78,393, respectively, of which $693 and $749, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).
17

Table of Contents
13. Goodwill and intangible assets
Goodwill
The carrying amount of goodwill was $776,760 as of both September 30, 2023 and December 31, 2022.

Intangible assets
The following tables summarize the composition of intangible assets as of September 30, 2023 and December 31, 2022:
September 30, 2023
Gross Carrying
Amount
Accumulated
Amortization
Currency Translation
Adjustment
Net Carrying
Amount
Weighted
Average Life
Definite-lived intangible assets
Favorable vessel charter contracts$106,500 $(82,373)$— $24,127 3
Permits and development rights48,217 (5,020)(2,207)40,990 38
Easements1,556 (330)— 1,226 30
Indefinite-lived intangible assets
Easements1,191 — (91)1,100 n/a
Total intangible assets$157,464 $(87,723)$(2,298)$67,443 
December 31, 2022
Gross Carrying
Amount
Accumulated
Amortization
Currency Translation
Adjustment
Net Carrying
Amount
Weighted
Average Life
Definite-lived intangible assets
Favorable vessel charter contracts$106,500 $(64,836)$— $41,664 3
Permits and development rights48,217 (4,115)(2,239)41,863 38
Easements1,556 (294)— 1,262 30
Indefinite-lived intangible assets
Easements1,191 — (83)1,108 n/a
Total intangible assets$157,464 $(69,245)$(2,322)$85,897 
Amortization expense for the three months ended September 30, 2023 and 2022 was $6,290 and $9,287, respectively. Amortization expense for the nine months ended September 30, 2023 and 2022 was $19,371 and $27,589, respectively. Amortization expense is inclusive of reductions in expense for the amortization of unfavorable contract liabilities.
Intangible assets associated with the acquired power purchase agreements have been classified as held for sale as of September 30, 2023 and December 31, 2022; no impairment loss was recognized upon classification as held for sale (See Note 9).
In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied the Company's application for the development of an LNG terminal and power plant in Shannon, Ireland. The Company is challenging this decision. Capitalized permits and development rights are primarily comprised of capitalized costs related to this project. The Company has concluded that these recent events do not indicate that these assets are not recoverable. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect to the Company's results of operations.

18

Table of Contents
14. Other non-current assets, net

As of September 30, 2023 and December 31, 2022, Other non-current assets consisted of the following:
September 30, 2023December 31, 2022
Assets held for sale$— $40,685 
Cost to fulfill (Note 4)
23,834 9,773 
Contract assets, net (Note 4)
22,176 28,651 
Upfront payments to customers8,715 9,158 
Investments in equity securities (Note 6)
7,678 17,806 
Other48,278 35,606 
Total other non-current assets, net$110,681 $141,679 
During the third quarter of 2023, the Company sold certain investments in equity securities recognizing a realized loss of $374. The remaining investments in equity securities of $7,678 as of September 30, 2023 are investments without a readily determinable fair value.
The Company recognized unrealized losses of $672 and $1,629 on its investments in equity securities for the three months ended September 30, 2023 and 2022, respectively, within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized an unrealized gain of $539 and an unrealized loss of $2,720 on its investments in equity securities for the nine months ended September 30, 2023 and 2022, respectively, within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss).
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 non-current assets includes deferred financing costs related to the Revolving Facility.
15. Accrued liabilities
As of September 30, 2023 and December 31, 2022, accrued liabilities consisted of the following:
September 30, 2023December 31, 2022
Accrued development costs$265,061 $364,157 
Accrued interest72,970 51,994 
Accrued inventory29,800 45,511 
Accrued bonuses28,378 37,739 
Accrued dividend— 626,310 
Other accrued expenses39,483 36,701 
Total accrued liabilities$435,692 $1,162,412 

19

Table of Contents
16. Other current liabilities
As of September 30, 2023 and December 31, 2022, other current liabilities consisted of the following:
September 30, 2023December 31, 2022
Derivative liabilities$20,045 $19,458 
Contract liabilities69,254 12,748 
Income tax payable31,180 6,261 
Due to affiliates9,112 7,499 
Liabilities held for sale (See Note 9)21,407 — 
Other current liabilities18,746 6,912 
Total other current liabilities$169,744 $52,878 

17. Debt
As of September 30, 2023 and December 31, 2022, debt consisted of the following:
September 30, 2023December 31, 2022
Senior Secured Notes, due September 2025
$1,245,069 $1,243,351 
Senior Secured Notes, due September 2026
1,484,944 1,481,639 
Vessel Financing Obligation, due August 2042
1,369,701 1,406,091 
Revolving Facility866,600 — 
Bridge Term Loan, due August 2024391,764 — 
South Power 2029 Bonds, due May 2029
216,782 216,177 
Equipment Notes, due July 2026195,399 — 
Barcarena Term Loan, due February 2024
198,725 194,427 
EB-5 Loan, due July 202837,256 — 
Short-term Borrowings161,835 — 
Total debt$6,168,075 $4,541,685 
Current portion of long-term debt and short-term borrowings$270,547 $64,820 
Long-term debt5,897,528 4,476,865 
Long-term debt is recorded at amortized cost on the condensed consolidated balance sheets. The fair value of the Company's long-term debt is $6,014,096 and $4,327,311 as of September 30, 2023 and December 31, 2022, respectively, and is classified as Level 2 within the fair value hierarchy.
Subsequent to September 30, 2023, the Company entered into the BNDES Credit Agreement, Barcarena Debentures and Term Loan B Credit Agreement (each defined and described in Note 24. Subsequent events). Proceeds from these new credit arrangements have been or will be used to refinance the Bridge Term Loan and the Barcarena Term Loan on a long term basis, and as such, these principal balances have been shown as non-current on the condensed consolidated balance sheets as of September 30, 2023.
The terms of the Company's debt instruments have been described in the Annual Report on Form 10-K. Significant changes to the Company's outstanding debt are described below.
Revolving Facility
In April 2021, the Company entered into a $200,000 senior secured revolving credit facility (the "Revolving Facility"). The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The Revolving Facility will mature in 2026 if the 2025 Notes (as
20

Table of Contents
defined in the Annual Report) are refinanced prior to maturity, with the potential for the Company to extend the maturity date of the Revolving Facility once for a one-year increment; if not, the Revolving Facility becomes due approximately 60 days prior to the maturity of the 2025 Notes. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.
In 2022, the Revolving Facility was amended twice to increase the borrowing capacity by a total of $240,000, and in first three quarters of 2023, the Company entered into amendments which increased the borrowing capacity by $426,600, for a total capacity of $866,600. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. During the first nine months of 2023, the Company drew $866,600 from the Revolving Facility, which is outstanding as of September 30, 2023.
The Company incurred $5,398 in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees to expand the facility in 2022. During the first three quarters of 2023, the Company incurred an additional $7,027 in fees in relation to the 2023 amendments. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of September 30, 2023 and December 31, 2022, total remaining unamortized deferred financing costs for the Revolving Facility was $10,167 and $5,172, respectively.
The obligations under the Revolving Facility are guaranteed by certain of the Company's subsidiaries. The Company is required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 and onwards. The Company was in compliance with all covenants as of September 30, 2023.
Bridge Term Loan Credit Agreement
On August 3, 2023, the Company entered into a Bridge Term Loan Credit Agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to the Company in an aggregate principal amount of $400,000. Bridge Term Loan proceeds may be used for working capital and other general corporate purposes. The Bridge Term Loans were to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans were repaid in full without penalty using proceeds from the Term Loan B which closed after September 30, 2023 (See Note 24. Subsequent events).
The Bridge Term Loans were guaranteed on a senior secured basis by each domestic and foreign subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report). The Bridge Term Loans were secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes and Revolving Facility. The Bridge Term Loan Agreement contained usual and customary representations and warranties, and usual and customary affirmative and negative covenants, including requirements to maintain certain levels of total debt to capitalization and total first lien debt to EBITDA, and the ratios required to be maintained were consistent with the requirements under the Revolving Facility.
The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%. The Company incurred $9,628 in origination, structuring and other fees, associated with entry into the Bridge Term Loans Facility. As of September 30, 2023, total remaining unamortized deferred financing costs for the Bridge Term Loans was $8,236.
Equipment Notes
In June 2023, the Company executed a Master Loan and Security Agreement with a lender to borrow up to $200,000 under promissory notes secured by certain turbines acquired in the first quarter of 2023 to support our grid stabilization project in Puerto Rico (the “Equipment Notes”). During the second and third quarters of 2023, the Company borrowed the full
21

Table of Contents
capacity bearing interest at approximately 7.7%, and the principal is partially repayable in monthly installments over the 36 month term of the loan with the balance due upon maturity in July 2026.
The Equipment Notes contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Equipment Notes do not contain any restrictive financial covenants.
Proceeds received were net of upfront fees due to the lender, and through September 30, 2023, the Company has incurred $2,516 in origination, structuring and other fees, associated with entry into the Equipment Notes. As of September 30, 2023, total remaining unamortized deferred financing costs for the Equipment Notes was $2,423.
EB-5 Loan Agreement
On July 21, 2023, the Company entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100,000, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the third quarter of 2023, $37,928 was funded under the EB-5 Loan Agreement.
The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.
The Company has incurred $693 in origination, structuring and other fees, associated with entry into the EB-5 Loan Agreement. As of September 30, 2023, total remaining unamortized deferred financing costs for the EB-5 Loan Agreement was $672.
Short-term Borrowings
The Company may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby the Company sells to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of September 30, 2023, the Company had $161,835 due under repurchase arrangements with a weighted average interest rate of 9.74%.

Interest expense

Interest and related amortization of debt issuance costs, premiums and discounts recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the three and nine months ended September 30, 2023 and 2022 consisted of the following:
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Interest per contractual rates$89,908 $58,740 $229,327 $174,751 
Interest expense on Vessel Financing Obligation 52,373 29,340 159,168 29,340 
Amortization of debt issuance costs, premiums and discounts4,777 2,583 11,520 8,376 
Interest expense incurred on finance lease obligations1,080 208 2,766 655 
Total interest costs$148,138 $90,871 $402,781 $213,122 
Capitalized interest83,316 27,283 201,890 56,778 
Total interest expense$64,822 $63,588 $200,891 $156,344 
Interest expense on the Vessel Financing Obligation includes non-cash expense of $37,285 and $119,648 for the three and nine months ended September 30, 2023 related to payments received by Energos from third-party charterers.
22

Table of Contents
18. Income Taxes
The effective tax rate for the three months ended September 30, 2023 was 28.8% compared to 15.1% for the three months ended September 30, 2022. The total tax provision for the three months ended September 30, 2023 was $25,194 compared to a provision of $9,971 for the three months ended September 30, 2022. The Company’s current and prior year interim period effective tax rate and tax provision differ primarily due to significant discrete items recognized in the prior year including the windfalls from share-based compensation and the other-than-temporary impairment recognized on the Company's investment in CELSEPAR.
The effective tax rate for the nine months ended September 30, 2023 was 17.2% compared to 1,737.1% for the nine months ended September 30, 2022. The total tax provision for the nine months ended September 30, 2023 was $69,476 compared to a benefit of $126,249 for the nine months ended September 30, 2022. Our prior year benefit and effective tax rate was primarily driven by significant discrete items, including the remeasurement of a deferred tax liability in conjunction with an internal reorganization. The Company has not recognized any significant discrete items in the first nine months of 2023.
19. 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.
20. Earnings per share
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Numerator:
Net income (loss)$62,338 $56,231 $334,004 $118,981 
Net (income) loss attributable to non-controlling interests(1,117)5,617 (3,329)11,371 
Net income attributable to Class A common stock$61,221 $61,848 $330,675 $130,352 
Denominator:
Weighted-average shares - basic205,032,928 209,629,936 206,249,474 209,749,139 
Net income per share - basic$0.30 $0.30 $1.60 $0.62 
Diluted
Numerator:
Net income (loss)$62,338 $56,231 $334,004 $118,981 
Net (income) loss attributable to non-controlling interests(1,117)5,617 (3,329)11,371 
Adjustments attributable to dilutive securities— — (1,113)— 
Net income (loss) attributable to Class A common stock61,221 61,848 329,562 130,352 
Denominator:
Weighted-average shares - diluted205,032,928 209,800,427 206,804,833 209,869,058 
Net income per share - diluted$0.30 $0.29 $1.59 $0.62 
23

Table of Contents
The following table presents potentially dilutive securities excluded from the computation of diluted net income per share for the periods presented because its effects would have been anti-dilutive.
Three Months Ended
September 30,
Nine Months Ended
September 30,
2023202220232022
Equity Agreement shares (1)
555,359 422,680 — 422,680 
Total555,359 422,680 — 422,680 

(1) Represents Class A common stock that would be issued in relation to an agreement to issue shares executed in conjunction with a prior year asset acquisition.
In the fourth quarter of 2022, the Board declared a dividend of $626,310 representing $3.00 per Class A share, which was paid in January 2023. The Company also declared and paid dividends of $20,503 and $20,756 during the three months ended September 30, 2023 and 2022, respectively, representing $0.10 per Class A share. The Company declared and paid dividends of $61,473 and $62,092 during the nine months ended September 30, 2023 and 2022, respectively, representing $0.10 per Class A share.
During each of the three months ended September 30, 2023 and 2022, the Company paid dividends of $3,019 to holders of Golar LNG Partners LP's ("GMLP") 8.75% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). During each of the nine months ended September 30, 2023 and 2022, the Company paid dividends of $9,057 to holders of the Series A Preferred Units. As these equity interests have been issued by one of the Company’s consolidated subsidiaries, the value of the Series A Preferred Units is recognized as non-controlling interest in the condensed consolidated financial statements.
21. Share-based compensation
The Company has granted Performance Share Units ("PSUs") to certain employees and non-employees that contain a performance condition under the New Fortress Energy Inc. 2019 Omnibus Incentive Plan. Vesting is determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. As of September 30, 2023, the Company determined it was not probable that the performance condition required for the PSUs granted in the fourth quarter of 2022 ("2022 Grant") to vest would be achieved, and as such, no compensation expense was recognized for this award.
PSUs GrantedUnits GrantedRange of VestingUnits Vested / Probable of Vesting
Unrecognized
Compensation
Cost(1)
Weighted Average
Remaining Vesting
Period
2022 Grant746,296
0 to 1,492,592
$47,797 0.25 years
(1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest.
22. Related party transactions
Management services
Messrs. Edens, chief executive officer and chairman of the Board of Directors, and Nardone, member of the Board of Directors, are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $1,643 and $1,117 for the three months ended September 30, 2023 and 2022, respectively, and totaled $4,284 and $3,776 for the nine months ended September 30, 2023 and 2022, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive income (loss). As of September 30, 2023 and December 31, 2022, $4,130 and $4,629 were due to Fortress, respectively.
24

Table of Contents
In addition to administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator rates, charter costs of $523 and $750 for the three months ended September 30, 2023 and 2022, respectively, and $1,934 and $2,897 for the nine months ended September 30, 2023 and 2022, respectively. As of September 30, 2023 and December 31, 2022, $1,216 and $416 was due to this affiliate, respectively.
Fortress affiliated entities
The Company provides certain administrative services to related parties including Fortress affiliated entities. No costs are incurred for such administrative services by the Company as the Company is fully reimbursed for all costs incurred. The Company has subleased a portion of office space to affiliates of entities managed by Fortress, and for the three months ended September 30, 2023 and 2022, $280 and $99 of rent and office related expenses were incurred by these affiliates, respectively. For the nine months ended September 30, 2023 and 2022, $821 and $491 of rent and office related expenses were incurred by these affiliates, respectively. As of September 30, 2023 and December 31, 2022, $1,456 and $700, respectively, were due from all Fortress affiliated entities.
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 $767 and $663 for the three months ended September 30, 2023 and 2022, respectively, and $2,016 and $1,845 for the nine months ended September 30, 2023 and 2022, respectively. As of September 30, 2023 and December 31, 2022, $3,698 and $2,455 were due to Fortress affiliated entities, respectively.
Land leases
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 September 30, 2023 and 2022, respectively, and $378 and $310 during the nine months ended September 30, 2023 and 2022, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive income (loss). The Company has amounts due to FECI of $69 and $0 as of September 30, 2023 and December 31, 2022, respectively. As of September 30, 2023 and December 31, 2022, the Company has recorded a lease liability of $3,363 and $3,340, respectively, on the condensed consolidated balance sheets.
In September 2023, the Company entered into a lease agreement to lease land from Jefferson Terminal South LLC, which is an indirect, majority-owned subsidiary of a public company which is managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $30 during three months ended and nine months ended September 30, 2023, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive income (loss). The Company does not have any amounts due to Jefferson Terminal South LLC as of September 30, 2023. As of September 30, 2023 the Company has recorded a lease liability of $4,003 on the condensed consolidated balance sheets.
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 was reflected as non-controlling interest in the Company’s condensed consolidated financial statements. The Company recognized approximately $117 and $111 in expense within Selling, general and administrative for the three months ended September 30, 2023 and 2022, respectively, and $318 and $328 in expense within Selling, general and administrative for the nine months ended September 30, 2023 and 2022, respectively. As of September 30, 2023 and December 31, 2022, $117 and $80 were due to DevTech, respectively.
23. Segments
As of September 30, 2023, the Company operates in two reportable segments: Terminals and Infrastructure and Ships:
Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities
25

Table of Contents
and conversion or development of natural gas-fired power generation. Vessels that are utilized in the Company’s terminal or logistics operations are included in this segment.
Terminals and Infrastructure Operating Margin included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% investment in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”); the Company disposed of this investment in the fourth quarter of 2022.

Terminal and Infrastructure segment includes realized gains and losses from the settlement of derivative transactions entered into as economic hedges to reduce market risks associated with commodity prices.
Ships includes vessels that are leased to customers under long-term or spot arrangements, and as of September 30, 2023, six vessels are included in this segment. The Company’s investment in Energos is also included in the Ships segment.
Ships Operating Margin included our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC prior to the disposition of this investment in first quarter of 2023.
The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value.
Management considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance.
The table below presents segment information for the three and nine months ended September 30, 2023 and 2022:
Three Months Ended September 30, 2023
(in thousands of $)Terminals and
Infrastructure
ShipsTotal
Segment
Consolidation
and Other(4)
Consolidated
Statement of operations:
Total revenues$447,905 $66,557 $514,462 $— $514,462 
Cost of sales(1) (3)
192,343 — 192,343 (423)191,920 
Vessel operating expenses— 11,613 11,613 — 11,613 
Operations and maintenance60,819 — 60,819 — 60,819 
Segment Operating Margin$194,743 $54,944 $249,687 $423 $250,110 
Balance sheet:
Total assets$8,738,875 $1,057,495 $9,796,370 $— $9,796,370 
Other segmental financial information:
Capital expenditures(2)
$662,717 $— $662,717 $— $662,717 
26

Table of Contents
Nine Months Ended September 30, 2023
(in thousands of $)Terminals and
Infrastructure
ShipsTotal
Segment
Consolidation
and Other(4)
Consolidated
Statement of operations:
Total revenues$1,446,017 $230,315 $1,676,332 $(21,394)$1,654,938 
Cost of sales(1) (3)
488,512 — 488,512 114,114 602,626 
Vessel operating expenses— 42,295 42,295 (5,948)36,347 
Operations and maintenance121,187 — 121,187 — 121,187 
Segment Operating Margin$836,318 $188,020 $1,024,338 $(129,560)$894,778 
Balance sheet:
Total assets$8,738,875 $1,057,495 $9,796,370 $— $9,796,370 
Other segmental financial information:
Capital expenditures(2)
$2,911,345 $— $2,911,345 $— $2,911,345 
Three Months Ended September 30, 2022
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(4)
Consolidated
Statement of operations:
Total revenues$687,437 $111,660 $799,097 $(67,167)$731,930 
Cost of sales(3)
402,458 — 402,458 (8,628)393,830 
Vessel operating expenses3,431 23,799 27,230 (6,912)20,318 
Operations and maintenance30,079 — 30,079 (8,046)22,033 
Segment Operating Margin$251,469 $87,861 $339,330 $(43,581)$295,749 
Balance sheet:
Total assets$5,366,730 $2,074,254 $7,440,984 $— $7,440,984 
Other segmental financial information:
Capital expenditures(2)
$451,360 $12,690 $464,050 $— $464,050 
27

Table of Contents
Nine Months Ended September 30, 2022
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(4)
Consolidated
Statement of operations:
Total revenues$1,711,241 $337,626 $2,048,867 $(226,964)$1,821,903 
Cost of sales(3)
909,938 — 909,938 (35,409)874,529 
Vessel operating expenses11,178 71,029 82,207 (20,297)61,910 
Operations and maintenance89,861 — 89,861 (24,170)65,691 
Segment Operating Margin$700,264 $266,597 $966,861 $(147,088)$819,773 
Balance sheet:
Total assets$5,366,730 $2,074,254 $7,440,984 $— $7,440,984 
Other segmental financial information:
Capital expenditures(2)
$890,558 $27,127 $917,685 $— $917,685 
(1) Cost of sales in the Company’s segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and realized losses of $293 and realized gains of $141,560 for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure.

The Company recognized unrealized gains of $423 and unrealized losses of $107,882 on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).

The Company has excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $0 and $6,232 for the three and nine months ended September 30, 2023, respectively, reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).

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

(3) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss).

(4) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR and the common units of Hilli LLC in the segment measure prior to the disposition of these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments, and the exclusion of non-capitalizable contract acquisition costs.
Consolidated Segment Operating Margin is defined as net income, adjusted for Selling, general and administrative expenses, Transaction and integration costs, Depreciation and amortization, Asset impairment expense, Interest expense, Other (income) expense, net, Loss on extinguishment of debt, net, Tax provision (benefit) and Income from equity method investments.
The following table reconciles Net income, the most comparable financial statement measure, to Consolidated Segment Operating Margin:
28

Table of Contents
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands of $)2023202220232022
Net income$62,338 $56,231 $334,004 $118,981 
Add:
Selling, general and administrative49,107 67,601 157,048 165,952 
Transaction and integration costs2,739 5,620 4,787 12,387 
Depreciation and amortization48,670 35,793 125,160 106,439 
Asset impairment expense— — — 48,109 
Interest expense64,822 63,588 200,891 156,344 
Other (income) expense, net(2,271)10,214 16,150 (31,613)
Loss on extinguishment of debt, net— 14,997 — 14,997 
Tax provision (benefit)25,194 9,971 69,476 (126,249)
(Income) from equity method investments(489)31,734 (12,738)354,426 
Consolidated Segment Operating Margin$250,110 $295,749 $894,778 $819,773 

24. Subsequent events
The financing transactions described below were entered into subsequent to September 30, 2023. Proceeds from these financing transactions, combined with the expected contractual cash flows from recent projects placed in service, are expected to provide the Company with the liquidity necessary to meets its obligations as they become due in the ordinary course of its business.
Barcarena Financings
In October 2023, certain of the Company's Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant"). Proceeds received will be used to repay the current Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025.
The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). The Company is able to borrow up to R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"). Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045.
The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.
Additionally, the parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures"). Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. The Company is able to prepay the Barcarena Debentures, subject to customary break funding
29

Table of Contents
costs, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal.
The Barcarena Debentures are convertible to shares of one of the Company's indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.
The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own Company's LNG regasification terminals located in Pará, Brazil ("Barcarena Terminal") and Santa Catarina, Brazil. NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.
Term Loan B Credit Agreement
On October 30, 2023, the Company entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal amount of $856 million ("Term Loan B"). The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature in October 2028 if the 2025 Notes and 2026 Notes (each as defined in the Annual Report) are refinanced prior to their maturities; if not, the Term Loan B becomes due approximately 60 days prior to the maturity of each the 2025 Notes and 2026 Notes. Quarterly principal payments of approximately $2.1 million begin to be due starting March 2024.
The Term Loan B is guaranteed on a senior secured basis by each domestic subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report) and will be guaranteed on a senior secured basis by each foreign guarantor that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility on a post-closing basis. The Term Loan B is and will be secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes, the Company's letter of credit facility and Revolving Facility. Additionally the Term Loan B is secured by assets comprising the Company's first Fast LNG project in Altamira, Mexico.
The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, the Company will be required to prepay the Term Loan B with the Company’s Excess Cash Flow (as defined in the Term Loan B Agreement).
The Term Loan B Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Agreement.

30

Table of Contents
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, 2022 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.
Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries.
Overview
We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. 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 companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Very-Low Carbon Future.”
Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.
Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida. Upon the completion of commissioning, we expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply and fleet.
Our Ships segment includes all vessels which are leased to customers under long-term or spot arrangements. The Company’s investment in Energos (defined below) is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.
Our Current Operations – Terminals and Infrastructure
Our management team has successfully employed our strategy to secure long-term contracts with significant customers, 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, the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility,
31

Table of Contents
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.
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 ("Bogue Power Plant"). Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 61,000 MMBtu of LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.
Old Harbour Facility
The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“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 (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.
In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. ("Weston") for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas. Weston has been contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 150MW of duel-fuel power generation using our gas supply in the second quarter of 2023, and the remaining 200MW was commissioned in September 2023.
In the first quarter of 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-Year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico. We will receive an annual management fee and be eligible for performance-based incentive fees, beginning after the service period under the contract commenced on July 1, 2023.
La Paz Facility
In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu of LNG per day to our 100MW gas-fired modular power units (the “La Paz Power Plant”), which we placed into service in the third quarter of 2023. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu of LNG per day for up to 135MW of power.
In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant.
Miami Facility
Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida,
32

Table of Contents
including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.
Our LNG Supply and Cargo Sales
NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts expected to commence in 2027; 3) our Miami Facility; and 4) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in 2027. Finally, we plan to commence production from our own Fast LNG facilities upon the completion of commissioning. We plan to expand that capacity when additional Fast LNG units come online over the next two years.
The recent geopolitical events in Europe have substantially impacted the natural gas and LNG markets with unprecedented price increases and volatility. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production expected to commence in the fourth quarter of 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.
Our Current Operations – Ships
Our Ships segment includes Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term or spot arrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we plan to charter these vessels for our own operational purposes. The results of operations of vessels utilized in our terminal operations are reflected in the Terminals and Infrastructure segment.
In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of 11 vessel to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net.
Our Development Projects
Our projects currently under development include our development of a series of modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); and our LNG terminal (“Ireland Facility”) and power plant in Ireland. We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.
The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-
33

Table of Contents
consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.
We describe each of our current development projects below.
Fast LNG
We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. The “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than land-based site-built alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application.
Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. Our first Fast LNG unit is being deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years.
We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.
Altamira
In the first quarter of 2023, we executed an agreement, which include conditions to effectiveness that have not been satisfied, with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in process of commissioning the project.
We have also entered into a non-binding MOU with CFE to develop and operate an onshore liquefied natural gas terminal with up to four 1.4 MTPA FLNG units. The terminal is to be located at the existing Altamira LNG import facility and would source feedgas from the Sur de-Texas Tuxpan Pipeline. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.
Louisiana
In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.
Lakach
Also, in the fourth quarter of 2022, we finalized agreements, which include conditions to effectiveness that have not been satisfied, with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. If the agreements become effective, NFE would invest in the continued development of the Lakach field over a two-year period by completing seven offshore wells and deploy a 1.4 MTPA Fast LNG unit to liquefy the majority of the produced natural gas. Remaining natural gas and associated condensate volumes would be utilized by Pemex in Mexico's onshore domestic market.
34

Table of Contents
Puerto Sandino Facility
We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.
Barcarena Facility
The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to third-party industrial and power customers as well as the Barcarena Power Plant, a new 630MW combined cycle thermal power plant to be located in Pará, Brazil, which we own. The Barcarena Power Plant is supported by multiple 25-year power purchase agreements to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025. We substantially completed our Barcarena Facility in 2022 and expect to commence operations in the first quarter of 2024. We expect to complete the Barcarena Power Plant and to commence operations in 2025.
We have financed the development of the Barcarena Power Plant pursuant to a financing agreement. For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in our Annual Report.
Santa Catarina Facility
The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations in the first quarter of 2024.
Ireland Facility
We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We are challenging this decision. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations.
Recent Developments
Barcarena Financings
In October 2023, certain the Company's Brazilian subsidiaries entered into two long-term financing arrangements fully funding the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant"). Proceeds received will be used to repay the current Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025.
The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). The Company is able to borrow up to R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"). Each tranche bears a
35

Table of Contents
different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045.
The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.
Additionally, the parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures"). Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. The Company is able to prepay the Barcarena Debentures, subject to customary break funding costs, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal.
The Barcarena Debentures are convertible to shares of one of the Company's indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.
The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own Company's LNG regasification terminals located in Pará, Brazil ("Barcarena Terminal") and Santa Catarina, Brazil. NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.
Term Loan B Credit Agreement
On October 30, 2023, the Company entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal amount of $856 million ("Term Loan B"). The proceeds from the Term Loan B issuance will be used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature in October 2028 if the 2025 Notes and 2026 Notes (each as defined in the Annual Report) are refinanced prior to their maturities; if not, the Term Loan B becomes due approximately 60 days prior to the maturity of each the 2025 Notes and 2026 Notes. Quarterly principal payments of approximately $2.1 million begin to be due starting March 2024.
The Term Loan B is guaranteed on a senior secured basis by each domestic subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report) and will be guaranteed on a senior secured basis by each foreign guarantor that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility on a post-closing basis. The Term Loan B is and will be secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes, the Company's letter of credit facility and Revolving Facility. Additionally the Term Loan B is secured by assets comprising our first Fast LNG project in Altamira, Mexico.
The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, the Company will be required to prepay the Term Loan B with the Company’s Excess Cash Flow (as defined in the Term Loan B Agreement).
The Term Loan B Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Agreement.
Other Matters
On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not
36

Table of Contents
believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.
On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect.
Results of Operations – Three Months Ended September 30, 2023 compared to Three Months Ended June 30, 2023 and Nine Months Ended September 30, 2023 compared to Nine Months Ended September 30, 2022
Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.
Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income/(loss) from operations, net income/(loss), cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.
37

Table of Contents
The tables below present our segment information for the three months ended September 30, 2023 and June 30, 2023, and for the nine months ended September 30, 2023 and September 30, 2022:

Three Months Ended September 30, 2023
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(3)
Consolidated
Total revenues$447,905 $66,557 $514,462 $— $514,462 
Cost of sales(1)(2)
192,343 — 192,343 (423)191,920 
Vessel operating expenses(4)
— 11,613 11,613 — 11,613 
Operations and maintenance(4)
60,819 — 60,819 — 60,819 
Segment Operating Margin$194,743 $54,944 $249,687 $423 $250,110 

Three Months Ended September 30, 2023
(in thousands of $)Consolidated
Gross margin (GAAP)$201,440 
Depreciation and amortization48,670 
Consolidated Segment Operating Margin (Non-GAAP)$250,110 

Three Months Ended June 30, 2023
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(3)
Consolidated
Total revenues$495,504 $65,841 $561,345 $561,345 
Cost of sales(2)
222,371 — 222,371 3,397 225,768 
Vessel operating expenses(4)
— 11,443 11,443 11,443 
Operations and maintenance(4)
33,697 — 33,697 — 33,697 
Segment Operating Margin$239,436 $54,398 $293,834 $(3,397)$290,437 

Three Months Ended June 30, 2023
(in thousands of $)Consolidated
Gross margin (GAAP)$248,322 
Depreciation and amortization42,115 
Consolidated Segment Operating Margin (Non-GAAP)$290,437 
38

Table of Contents

Nine Months Ended September 30, 2023
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(3)
Consolidated
Total revenues$1,446,017 $230,315 $1,676,332 $(21,394)$1,654,938 
Cost of sales(1)(2)
488,512 — 488,512 114,114 602,626 
Vessel operating expenses(4)
— 42,295 42,295 (5,948)36,347 
Operations and maintenance(4)
121,187 — 121,187 — 121,187 
Segment Operating Margin$836,318 $188,020 $1,024,338 $(129,560)$894,778 

Nine Months Ended September 30, 2023
(in thousands of $)Consolidated
Gross margin (GAAP)$769,618 
Depreciation and amortization125,160 
Consolidated Segment Operating Margin (Non-GAAP)$894,778 

Nine Months Ended September 30, 2022
(in thousands of $)Terminals and
Infrastructure
ShipsTotal Segment
Consolidation
and Other(3)
Consolidated
Total revenues$1,711,241 $337,626 $2,048,867 $(226,964)$1,821,903 
Cost of sales(2)
909,938 — 909,938 (35,409)874,529 
Vessel operating expenses(4)
11,178 71,029 82,207 (20,297)61,910 
Operations and maintenance(4)
89,861 — 89,861 (24,170)65,691 
Segment Operating Margin$700,264 $266,597 $966,861 $(147,088)$819,773 

Nine Months Ended September 30, 2022
(in thousands of $)Consolidated
Gross margin (GAAP)$713,334 
Depreciation and amortization106,439 
Consolidated Segment Operating Margin (Non-GAAP)$819,773 

(1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and realized losses of $0.3 million and realized gains of $141.6 million for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure.

We recognized unrealized gains of $0.4 million and unrealized losses of $107.9 million on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).

We have excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6.2 million for the three and nine months ended September 30, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).
39

Table of Contents

(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss).

(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and the common units of Hilli LLC in the segment measure, prior to the disposition to these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments, and the exclusion of non-capitalizable contract acquisition costs.

(4) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.
Terminals and Infrastructure Segment
Three Months Ended,
(in thousands of $)September 30, 2023June 30, 2023Change
Total revenues$447,905 $495,504 $(47,599)
Cost of sales (exclusive of depreciation and amortization) 192,343 222,371 (30,028)
Operations and maintenance60,819 33,697 27,122 
Segment Operating Margin$194,743 $239,436 $(44,693)
Nine Months Ended,
(in thousands of $)September 30, 2023September 30, 2022Change
Total revenues$1,446,017 $1,711,241 $(265,224)
Cost of sales (exclusive of depreciation and amortization) 488,512 909,938 (421,426)
Vessel operating expenses— 11,178 (11,178)
Operations and maintenance121,187 89,861 31,326 
Segment Operating Margin$836,318 $700,264 $136,054 
Total revenue
Total revenue for the Terminals and Infrastructure Segment decreased by $47.6 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. The decrease was primarily driven by decreases to revenue from LNG cargo sales to third parties, partially offset by additional gas sales in Puerto Rico and increases to the Henry Hub index. The index forms a portion of the pricing to invoice most of our customers in this segment.
The decrease in revenue in third quarter of 2023 when compared to the second quarter of 2023 was primarily attributable to the following:
We had no revenue from LNG cargo sales for the three months ended September 30, 2023, decreasing from $267.8 million for the three months ended June 30, 2023, as we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations.
Such decrease was offset by increases to revenue in the three months ended September 30, 2023 when compared to the three months ended June 30, 2023, due to the following:
Volumes delivered to downstream terminal customers increased from 14.0 TBtus in the second quarter of 2023 to 20.1 TBtu in the third quarter of 2023. We continue to support the grid stabilization project in Puerto Rico, and we recognized a full quarter of operations for our Palo Seco Power Plant during the third quarter. We also completed the commissioning of additional power assets at the San Juan Power Plant in September. Additionally, in August 2023, we placed our La Paz Power Plant into service, and we began to recognize revenue from power sales from this plant in the local spot market.
40

Table of Contents
The average Henry Hub index pricing used to invoice our downstream customers increased by 22% for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.
Total revenue for the Terminals and Infrastructure Segment decreased by $265.2 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decrease was primarily driven by lower LNG cargo sales, no pro rata share of revenue from our former investment in CELSEPAR and a reduction in the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. The decrease in revenue was partially offset by increased revenue from sales to downstream terminal customers.
The decrease in revenue in the nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022 was primarily attributable to the following:
Our LNG cargo sales to third parties decreased by $327.7 million for the nine months ended September 30, 2023, decreasing from $944.8 million for the nine months ended September 30, 2022 to $617.1 million nine months ended September 30, 2023. In the third quarter of 2023, we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations.
After the completion of the sale of our investment in CELSEPAR in the fourth quarter of 2022, we no longer recognize revenue from this investment in our segment measure. Our share of revenue from CELSEPAR was $148.3 million for the nine months ended September 30, 2022, which was primarily comprised of fixed capacity payments received under related PPAs.
The average Henry Hub index pricing used to invoice our downstream customers decreased by 60% for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022
Such decrease was offset by increases to revenue in the nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022, due to the following:
Volumes delivered to downstream customers were 46.1 TBtu for the nine months ended September 30, 2023 as compared to 28.5 TBtu for the nine months ended September 30, 2022, and these increased volumes were primarily attributable to our operations in Jamaica, Puerto Rico and Mexico.
In the prior year, maintenance activities significantly lowered consumption at our facilities; there has been no significant maintenance downtime during 2023. The maintenance downtime in the prior year was across our facilities, including downtime at our CHP Plant for unplanned maintenance, downtime at our Montego Bay Facility due to a reconfiguration of our assets required by the Port of Montego Bay and maintenance at PREPA's San Juan Power Plants. Volumes delivered across from these facilities increased by 12.8 TBtu as compared to the nine months ended September 30, 2022.
In May 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets at the Palo Seco Power Plant. In September 2023, we finished commissioning additional power generation assets at the San Juan Power Plant. We have consumed 4.7 TBtu at these power plants during the nine months ended September 30, 2023 as part of this project.
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. 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 decreased by $30.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023, which was attributable to the following:
We did not incur any cost of LNG purchased from third parties for LNG cargo sales, decreasing our cost by $76.9 million during the third quarter of 2023.
41

Table of Contents
Vessel costs increased by $23.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Vessels were used for commissioning of our La Paz Power Plant and our enhanced supply chain for our Puerto Rican operations in the second quarter, and such vessel costs were capitalized. As these projects became operational in the third quarter we recognized higher expense associated with these vessels. Further, certain vessels were placed into service at our terminals during the third quarter resulting in higher vessel charter costs.
Increase in cost of LNG purchased from third parties for sale to our downstream customers of $18.4 million related to higher terminal sales; volumes delivered to our downstream customers increased by approximately 43% in the current quarter. Our cost to deliver these volumes decreased to $6.76 per MMBtu for the three months ended September 30, 2023 from $8.08 per MMBtu for the three months ended June 30, 2023.
Cost of sales decreased by $421.4 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022, which was attributable to the following:
We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $212.6 million during the nine months ended September 30, 2023, resulting from no LNG cargo sales in the third quarter as well as lower cost under our LNG supply contracts for cargos sold earlier in 2023.
Realized gains of $141.6 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales. For segment performance measures, unrealized mark to market gains and losses are excluded until settled.
Vessel costs decreased by $37.6 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 primarily due to the capitalization of vessel costs for the commissioning of development projects, as well as, vessel costs recognized as inventory when our vessels are used to transport inventory from a supplier's facility to our storage locations and terminals.
Cost of sales for the nine months ended September 30, 2022 included $28.6 million of our share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel a power plant owned by CELSEPAR.
We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $15.3 million during the nine months ended September 30, 2023 due to increased volumes delivered; we delivered 62% more volumes to our downstream terminal customers in the current period as compared to the nine months ended September 30, 2022. While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was substantially lower, decreasing to $7.26 per MMBtu for the nine months ended September 30, 2023 from $10.78 per MMBtu for the nine months ended September 30, 2022.
The weighted-average cost of our LNG inventory balance to be used in our downstream terminal operations as of September 30, 2023 and December 31, 2022 was $7.30 per MMBtu and $10.42 per MMBtu, respectively.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, and these costs are typically included in the Ships segment. Once we begin to use a vessel in our terminal operations, the costs of the vessel begin to be included in the Terminals and Infrastructure segment. For the nine months ended September 30, 2022, we incurred $11.2 million of vessel operating expenses in this segment; we did not incur vessel operating costs in this segment during the nine months ended September 30, 2023.
Operations and maintenance
Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales.
Operations and maintenance increased by $27.1 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide
42

Table of Contents
operations and maintenance services for PREPA's thermal generation assets, and we recognized payroll and other operating costs of $16.3 million. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. In the third quarter, we also undertook activities to ensure that we have LNG supply available for our expanded Puerto Rican operations, including leasing berth space to place a storage vessel to service Puerto Rico, and we incurred additional lease cost associated with this berth space in the third quarter of 2023.
Operations and maintenance increased $31.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The increase was primarily attributable to reimbursable payroll and operating costs of Genera and increased lease costs associated with our Puerto Rican operations incurred in the third quarter of 2023. Additionally, we leased turbines to generate power at the Palo Seco Power Plant as part of the grid stabilization project in Puerto Rico, increasing operations and maintenance costs when compared to the prior year. These increases were partially offset by the exclusion of our share of Operations and maintenance from the investment in CELSEPAR; after the sale of our investment in CELSEPAR in the fourth quarter of 2022, we do not include these costs during nine months ended September 30, 2023.
Ships Segment
Three Months Ended,
(in thousands of $)September 30, 2023June 30, 2023Change
Total revenues$66,557 $65,841 $716 
Vessel operating expenses11,613 11,443 170 
Segment Operating Margin$54,944 $54,398 $546 
Nine Months Ended,
(in thousands of $)September 30, 2023September 30, 2022Change
Total revenues$230,315 $337,626 $(107,311)
Vessel operating expenses42,295 71,029 (28,734)
Segment Operating Margin$188,020 $266,597 $(78,577)
Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. Prior to the completion of the Energos Formation Transaction, we also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook. We included the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements represented our ongoing ordinary business operations.
On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). In the fourth quarter of 2022, we recognized a loss on the investment in the Hilli of $118.6 million; this loss was recognized in Loss from equity method investments in the consolidated statements of operations and comprehensive income (loss). Upon completion of the Hilli Exchange during the first quarter of 2023, we recognized an additional loss on disposal of $37.4 million, which was included in Other (income) expense, net. As a result of the Hilli Exchange we no longer have an ownership interest in the Hilli. NFE shares received from GLNG were cancelled upon the closing of the Hilli Exchange.
As of September 30, 2023, four FSRUs and two LNG carriers were leased to customers under long-term or spot arrangements. In July 2023, we sold the vessel Golar Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. The gain on sale is included in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss). The Mazo continues to be in cold lay-up, and no vessel charter revenue was generated from the vessel.
43

Table of Contents
Total revenue
Total revenue for the Ships segment increased $0.7 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. During the third quarter, there were no reclassifications of vessels out of the Ships segment; there were also no significant changes the vessel charters.
Total revenue for the Ships segment decreased $107.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decrease in revenue was primarily the result of the sale of the Nanook as part of the Energos Formation Transaction; we no longer recognize revenue related to the Nanook in 2023. One of our vessel charters was renewed at the beginning of 2023 at a lower rate; additionally the charters for two vessels concluded in the first quarter of 2023, lowering vessel revenue for the full nine months ended September 30, 2023. We plan to utilize these vessels in our operations following conversion and other upgrades starting later in 2023.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli prior to the Hilli Exchange discussed above. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.
Vessel operating expenses increased $0.2 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.
Vessel operating expenses decreased $28.7 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the Hilli Exchange at the end of the first quarter of 2023. Vessel operating expenses also decreased as a result of the sale of the Nanook as part of the Energos Formation Transaction; we recognized vessel operating expenses related to the Nanook during 2022 and n