New Fortress Energy Inc. 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q ☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2021 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to__________ Commission File Number: 001-38790 New Fortress Energy Inc. (Exact Name of Registrant as Specified in its Charter) Delaware 83-1482060 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 111 W. 19th Street , 8th Floor New York , NY 10011 (Address of principal executive offices) (Zip Code) Registrant’s telephone number, including area code: ( 516 ) 268-7400 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Class A common stock “ NFE ” Nasdaq Global Select Market As of October 29 , 2021, the registrant had 206,863,242 shares of Class A common stock outstanding. TABLE OF CONTENTS GLOSSARY OF TERMS ii CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS iii PART I FINANCIAL INFORMATION 1 Item 1. Financial Statements. 1 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 39 Item 3. Quantitative and Qualitative Disclosures About Market Risks. 63 Item 4. Controls and Procedures. 64 PART II OTHER INFORMATION 65 Item 1. Legal Proceedings. 65 Item 1A. Risk Factors. 65 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. 113 Item 3. Defaults upon Senior Securities. 113 Item 4. Mine Safety Disclosures. 113 Item 5. Other Information. 113 Item 6. Exhibits. 113 SIGNATURES 119 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: Btu the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute pressure of 14.696 pounds per square inch gage CAA Clean Air Act CERCLA Comprehensive Environmental Response, Compensation and Liability Act CWA Clean Water Act DOE U.S. Department of Energy FERC Federal Energy Regulatory Commission GAAP generally accepted accounting principles in the United States GHG greenhouse gases GSA gas sales agreement Henry Hub a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange ISO container International Organization of Standardization, an intermodal container LNG natural gas in its liquid state at or below its boiling point at or near atmospheric pressure MMBtu one million Btus, which corresponds to approximately 12.1 gallons of LNG MW megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt NGA Natural Gas Act of 1938, as amended non-FTA countries countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted OPA Oil Pollution Act OUR Office of Utilities Regulation (Jamaica) PHMSA Pipeline and Hazardous Materials Safety Administration PPA power purchase agreement SSA steam supply agreement TBtu one trillion Btus, which corresponds to approximately 12,100,000 gallons of LNG ii 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; • loss of one or more of our customers; • inability to procure LNG on a fixed-price basis, or otherwise to manage LNG price risks, including hedging arrangements; • the completion of construction on our LNG terminals, facilities, power plants or Liquefaction Facilities (as defined herein) and the terms of our construction contracts for the completion of these assets; • cost overruns and delays in the completion of one or more of our LNG terminals, facilities, power plants or Liquefaction Facilities, as well as difficulties in obtaining sufficient financing to pay for such costs and delays; • our ability to obtain additional financing to effect our strategy; • We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers; • failure to produce or purchase sufficient amounts of LNG or natural gas at favorable prices to meet customer demand; • hurricanes or other natural or manmade disasters; • failure to obtain and maintain approvals and permits from governmental and regulatory agencies; • operational, regulatory, environmental, political, legal and economic risks pertaining to the construction and operation of our facilities; • inability to contract with suppliers and tankers to facilitate the delivery of LNG on their chartered LNG tankers; • cyclical or other changes in the demand for and price of LNG and natural gas; • failure of natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate; • competition from third parties in our business; • inability to re-finance our outstanding indebtedness; • changes to environmental and similar laws and governmental regulations that are adverse to our operations; • inability to enter into favorable agreements and obtain necessary regulatory approvals; • the tax treatment of us or of an investment in our Class A shares; • the completion of the Exchange Transactions (as defined below); • a major health and safety incident relating to our business; • increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel; • risks related to the jurisdictions in which we do, or seek to do, business, particularly Florida, Jamaica, Brazil and the Caribbean; and • other risks described in the “Risk Factors” section of this Quarterly Report. All forward-looking statements speak only as of the date of this Quarterly Report. When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in our Annual Report on Form 10-K for the year ended December 31, 2020 (our “Annual Report”), this Quarterly Report and in our other filings with the Securities and Exchange Commission (the “SEC”). The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, levels of activity, performance, projections or achievements. iii Table of Contents PART I FINANCIAL INFORMATION Item 1. Financial Statements. New Fortress Energy Inc. Condensed Consolidated Balance Sheets As of September 30, 2021 and December 31, 2020 (Unaudited, in thousands of U.S. dollars, except share amounts) September 30, 2021 December 31, 2020 Assets Current assets Cash and cash equivalents $ 224,383 $ 601,522 Restricted cash 72,338 12,814 Receivables, net of allowances of $ 130 and $ 98 , respectively 161,008 76,544 Inventory 82,390 22,860 Prepaid expenses and other current assets, net 75,602 48,270 Total current assets 615,721 762,010 Restricted cash 37,879 15,000 Construction in progress 973,880 234,037 Property, plant and equipment, net 2,025,688 614,206 Equity method investments 1,227,991 - Right-of-use assets 145,941 141,347 Intangible assets, net 166,964 46,102 Finance leases, net 603,662 7,044 Goodwill 740,132 - Deferred tax assets, net 6,087 2,315 Other non-current assets, net 121,142 86,030 Total assets $ 6,665,087 $ 1,908,091 Liabilities Current liabilities Current portion of long-term debt $ 249,752 $ - Accounts payable 210,259 21,331 Accrued liabilities 159,304 90,352 Current lease liabilities 32,009 35,481 Due to affiliates 6,910 8,980 Other current liabilities 109,662 35,006 Total current liabilities 767,896 191,150 Long-term debt 3,597,659 1,239,561 Non-current lease liabilities 93,321 84,323 Deferred tax liabilities, net 284,176 2,330 Other long-term liabilities 37,885 15,641 Total liabilities 4,780,937 1,533,005 Commitments and contingencies (Note 20) Stockholders’ equity Class A common stock, $ 0.01 par value, 750.0 million shares authorized, 206.9 million issued and outstanding as of September 30, 2021; 174.6 million issued and outstanding as of December 31, 2020 2,069 1,746 Additional paid-in capital 1,912,643 594,534 Accumulated deficit ( 283,256 ) ( 229,503 ) Accumulated other comprehensive income 24,625 182 Total stockholders’ equity attributable to NFE 1,656,081 366,959 Non-controlling interest 228,069 8,127 Total stockholders’ equity 1,884,150 375,086 Total liabilities and stockholders’ equity $ 6,665,087 $ 1,908,091 The accompanying notes are an integral part of these condensed consolidated financial statements. 1 Table of Contents New Fortress Energy Inc. Condensed Consolidated Statements of Operations and Comprehensive Loss For the three and nine months ended September 30, 2021 and 2020 (Unaudited, in thousands of U.S. dollars, except share and per share amounts) Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Revenues Operating revenue $ 188,389 $ 83,863 $ 382,421 $ 223,542 Vessel charter revenue 78,656 - 143,217 - Other revenue 37,611 52,995 148,541 82,412 Total revenues 304,656 136,858 674,179 305,954 Operating expenses Cost of sales 135,432 71,665 333,533 209,780 Vessel operating expenses 15,301 - 30,701 - Operations and maintenance 20,144 13,802 54,960 31,785 Selling, general and administrative 46,802 26,821 124,954 87,273 Transaction and integration costs 1,848 4,028 42,564 4,028 Contract termination charges and loss on mitigation sales - - - 124,114 Depreciation and amortization 31,194 9,489 68,080 22,363 Total operating expenses 250,721 125,805 654,792 479,343 Operating income (loss) 53,935 11,053 19,387 ( 173,389 ) Interest expense 57,595 19,813 107,757 50,901 Other (income) expense, net ( 5,400 ) 2,569 ( 13,458 ) 4,179 Loss on extinguishment of debt, net - 23,505 - 33,062 Net income (loss) before income from equity method investments and income taxes 1,740 ( 34,834 ) ( 74,912 ) ( 261,531 ) (Loss) income from equity method investments ( 15,983 ) - 22,958 - Tax provision 3,526 1,836 7,058 1,949 Net loss ( 17,769 ) ( 36,670 ) ( 59,012 ) ( 263,480 ) Net loss attributable to non-controlling interest 7,963 312 5,259 81,163 Net loss attributable to stockholders $ ( 9,806 ) $ ( 36,358 ) $ ( 53,753 ) $ ( 182,317 ) Net income (loss) per share – basic and diluted $ ( 0.05 ) $ ( 0.21 ) $ ( 0.27 ) $ ( 2.14 ) Weighted average number of shares outstanding – basic and diluted 207,497,013 170,074,532 195,626,564 85,009,385 Other comprehensive loss: Net loss $ ( 17,769 ) $ ( 36,670 ) $ ( 59,012 ) $ ( 263,480 ) Currency translation adjustment 76,996 ( 971 ) ( 23,697 ) ( 1,122 ) Comprehensive loss ( 94,765 ) ( 35,699 ) ( 35,315 ) ( 262,358 ) Comprehensive loss (income) attributable to non-controlling interest 8,162 ( 926 ) 6,005 80,156 Comprehensive loss attributable to stockholders $ ( 86,603 ) $ ( 36,625 ) $ ( 29,310 ) $ ( 182,202 ) The accompanying notes are an integral part of these condensed consolidated financial statements. 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, 2021 and 2020 (Unaudited, in thousands of U.S. dollars, except share amounts) Class A shares Class B shares Class A common stock Additional paid-in Accumulated Accumulated other comprehensive Non- controlling Total stockholders’ Shares Amount Shares Amount Shares Amount capital Deficit (loss) income interest equity Balance as of December 31, 2020 - $ - - $ - 174,622,862 $ 1,746 $ 594,534 $ ( 229,503 ) $ 182 $ 8,127 $ 375,086 Net loss - - - - - - - ( 37,903 ) - ( 1,606 ) ( 39,509 ) Other comprehensive loss - - - - - - - - ( 123 ) ( 874 ) ( 997 ) Share-based compensation expense - - - - - - 1,770 - - - 1,770 Issuance of shares for vested RSUs - - - - 1,335,787 - - - - - - Shares withheld from employees related to share-based compensation, at cost - - - - ( 638,235 ) - ( 27,571 ) - - - ( 27,571 ) Dividends - - - - - - ( 17,598 ) - - - ( 17,598 ) Balance as of March 31, 2021 - $ - - $ - 175,320,414 $ 1,746 $ 551,135 $ ( 267,406 ) $ 59 $ 5,647 $ 291,181 Net (loss) income - - - - - - - ( 6,044 ) - 4,310 ( 1,734 ) Other comprehensive income - - - - - - - - 101,363 327 101,690 Share-based compensation expense - - - - - - 1,613 - - - 1,613 Shares issued as consideration in business combinations - - - - 31,372,549 314 1,400,470 - - - 1,400,784 Issuance of shares for vested RSUs - - - - 8,930 - - - - - - Shares withheld from employees related to share-based compensation, at cost - - - - ( 3,329 ) - ( 164 ) - - - ( 164 ) Non-controlling interest acquired in business combinations - - - - - - - - - 229,285 229,285 Dividends - - - - - - ( 20,736 ) - - - ( 20,736 ) Balance as of June 30, 2021 - $ - - $ - 206,698,564 $ 2,060 $ 1,932,318 $ ( 273,450 ) $ 101,422 $ 239,569 $ 2,001,919 Net loss - - - - - - - ( 9,806 ) - ( 7,963 ) ( 17,769 ) Other comprehensive loss - - - - - - - - ( 76,797 ) ( 199 ) ( 76,996 ) Share-based compensation expense - - - - - - 1,562 - - - 1,562 Adjustments related to business combinations - - - - - - - - - ( 319 ) ( 319 ) Issuance of shares for vested RSUs - - - - 193,193 9 ( 9 ) - - - - Shares withheld from employees related to share-based compensation, at cost - - - - ( 28,515 ) - ( 478 ) - - - ( 478 ) Dividends - - - - - - ( 20,750 ) - - ( 3,019 ) ( 23,769 ) Balance as of September 30, 2021 - $ - - $ - 206,863,242 $ 2,069 $ 1,912,643 $ ( 283,256 ) $ 24,625 $ 228,069 $ 1,884,150 Class A shares Class B shares Class A common stock Additional paid-in Accumulated Accumulated other comprehensive Non- controlling Total stockholders’ Shares Amount Shares Amount Shares Amount capital Deficit (loss) income interest equity Balance as of December 31, 2019 23,607,096 $ 130,658 144,342,572 $ - - $ - $ - $ ( 45,823 ) $ ( 30 ) $ 302,519 $ 387,324 Cumulative effect of accounting changes - - - - - - - ( 1,533 ) - ( 7,780 ) ( 9,313 ) Net loss - - - - - - - ( 8,466 ) - ( 51,757 ) ( 60,223 ) Other comprehensive loss - - - - - - - - ( 53 ) ( 316 ) ( 369 ) Share-based compensation expense - 2,508 - - - - - - - - 2,508 Issuance of shares for vested RSUs 1,212,907 - - - - - - - - - - Shares withheld from employees related to share-based compensation, at cost ( 583,508 ) ( 6,132 ) - - - - - - - - ( 6,132 ) Balance as of March 31 , 2020 24,236,495 $ 127,034 144,342,572 $ - - $ - $ - $ ( 55,822 ) $ ( 83 ) $ 242,666 $ 313,795 Net loss - - - - - - - ( 137,493 ) - ( 29,094 ) ( 166,587 ) Other comprehensive income - - - - - - - - 435 85 520 Share-based compensation expense - 1,922 - - - - - - - - 1,922 Issuance of shares for vested RSUs 11,529 - - - - - - - - - - Shares withheld from employees related to share-based compensation, at cost ( 3,250 ) ( 40 ) - - - - - - - - ( 40 ) Exchange of NFI units 144,342,572 206,587 ( 144,342,572 ) - - - - - - ( 206,587 ) - Balance as of June 30, 2020 168,587,346 $ 335,503 - $ - - $ - $ - $ ( 193,315 ) $ 352 $ 7,070 $ 149,610 Conversion from LLC to Corporation ( 168,587,346 ) ( 335,503 ) - - 168,587,346 1,687 333,816 - - - - Net loss - - - - - - - ( 36,358 ) - ( 312 ) ( 36,670 ) Other comprehensive income (loss) - - - - - - - - ( 267 ) 1,238 971 Share-based compensation expense - - - - - - 2,071 - - - 2,071 Issuance of shares for vested RSUs - - - - 157,148 - - - - - - Shares withheld from employees related to share-based compensation, at cost - - - - ( 6,071 ) - ( 239 ) - - - ( 239 ) Dividends - - - - - - ( 17,006 ) - - - ( 17,006 ) Balance as of September 30, 2020 - $ - - $ - 168,738,423 $ 1,687 $ 318,642 $ ( 229,673 ) $ 85 $ 7,996 $ 98,737 The accompanying notes are an integral part of these condensed consolidated financial statements. 3 Table of Contents New Fortress Energy Inc. Condensed Consolidated Statements of Cash Flows For the nine months ended September 30, 2021 and 2020 (Unaudited, in thousands of U.S. dollars) Nine Months Ended September 30, 2021 2020 Cash flows from operating activities Net loss $ ( 59,012 ) $ ( 263,480 ) Adjustments for: Amortization of deferred financing costs and debt guarantee, net 9,503 9,949 Depreciation and amortization 68,971 23,025 (Earnings) losses of equity method investees ( 22,958 ) - Dividends received from equity method investees 14,259 - Sales-type lease payments received in excess of interest income 1,458 - Change in market value of derivatives ( 4,955 ) - Contract termination charges and loss on mitigation sales - 71,510 Loss on extinguishment and financing expenses - 37,090 Deferred taxes ( 4,280 ) 388 Change in value of Investment of equity securities ( 7,265 ) 2,376 Share-based compensation 4,945 6,501 Other 72 1,895 Changes in operating assets and liabilities, net of acquisitions: (Increase) in receivables ( 75,633 ) ( 43,307 ) (Increase) Decrease in inventories ( 56,172 ) 26,691 Decrease (Increase) in other assets 25,500 ( 16,526 ) Decrease in right-of-use assets 3,149 31,910 (Decrease) Increase in accounts payable/accrued liabilities ( 2,530 ) 23,982 (Decrease) in amounts due to affiliates ( 2,070 ) ( 1,033 ) (Decrease) in lease liabilities ( 2,510 ) ( 30,930 ) (Decrease) Increase in other liabilities ( 30,159 ) 4,249 Net cash (used in) operating activities ( 139,687 ) ( 115,710 ) Cash flows from investing activities Capital expenditures ( 430,549 ) ( 115,841 ) Cash paid for business combinations, net of cash acquired ( 1,586,042 ) - Entities acquired in asset acquisitions, net of cash acquired ( 8,817 ) - Other investing activities ( 5,750 ) 137 Net cash (used in) provided by investing activities ( 2,031,158 ) ( 115,704 ) Cash flows from financing activities Proceeds from borrowings of debt 2,234,650 1,832,144 Payment of deferred financing costs ( 35,846 ) ( 27,099 ) Repayment of debt ( 229,887 ) ( 1,490,002 ) Payments related to tax withholdings for share-based compensation ( 29,717 ) ( 6,356 ) Payment of dividends ( 65,051 ) ( 16,871 ) Net cash provided by financing activities 1,874,149 291,816 Impact of changes in foreign exchange rates on cash and cash equivalents 1,960 - Net (decrease) increase in cash, cash equivalents and restricted cash ( 294,736 ) 60,402 Cash, cash equivalents and restricted cash – beginning of period 629,336 93,035 Cash, cash equivalents and restricted cash – end of period $ 334,600 $ 153,437 Supplemental disclosure of non-cash investing and financing activities: Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions $ 187,295 $ ( 4,682 ) Liabilities associated with consideration paid for entities acquired in asset acquisitions 9,959 - Consideration paid in shares for business combinations 1,400,784 - The accompanying notes are an integral part of these condensed consolidated financial statements. 4 Table of Contents 1. Organization New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs and is engaged in providing energy and development services to end-users worldwide seeking to convert their operating assets from diesel or heavy fuel oil to LNG. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica and Brazil. Subsequent to the Mergers (defined below), the Company has marine operations with vessels operating under time charters and in the spot market globally. On April 15, 2021 , the Company completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers”. NFE paid $ 580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $ 3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interests of GMLP’s general partner, totaling $ 251 million . The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger. The results of operations of Hygo and GMLP have been included in the Company’s condensed consolidated financial statements for the period subsequent to the Mergers. As a result of the Mergers, the Company acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50 % interest in a 1.5 GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Facility”) and Santa Catarina, Brazil (the “Santa Catarina Facility”). The Company acquired the Nanook , a newbuild FSRU moored and in service at the Sergipe Facility. In addition to the Nanook, the Company acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (the “Hilli”), which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support the Company ’s existing facilities and international project pipeline. The majority of the FSRUs are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market. The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the busines s. 2. Significant accounting policies The principal accounting policies adopted are set out below. (a) Basis of presentation and principles of consolidation The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020. The condensed consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest. All significant intercompany transactions and balances have been eliminated on consolidation. Certain prior year amounts have been reclassified to conform to current year presentation. A variable interest entity (“VIE”) is an entity that by design meets any of the following characteristics: (1) lacks sufficient equity to allow the entity to finance its activities without additional subordinated financial support; (2) as a group, equity investors do not have the ability to make significant decisions relating to the entity’s operations through voting rights, or do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of the entity; or (3) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. The primary beneficiary of a VIE is required to consolidate the assets and liabilities of the VIE. The primary beneficiary is the party that has both (1) the power to direct the economic activities of the VIE that most significantly impact the VIE’s economic performance; and (2) through its interest in the VIE, the obligation to absorb the losses or the right to receive the benefits from the VIE that could potentially be significant to the VIE. 5 Table of Contents The sale and leaseback financings of certain vessels acquired in the Mergers were consummated with VIEs. As part of these financings, the asset was sold to a single asset entity of the lending bank and then leased back. While the Company does not hold an equity investment in these entities, these entities are VIEs, and the Company has a variable interest in the entities due to the guarantees and fixed price repurchase options that absorb the losses of the VIE that could potentially be significant to the entity. The Company has concluded that it has the power to direct the economic activities that most impact the economic performance as it controls the significant decisions relating to the assets and it has the obligation to absorb losses or the right to receive the residual returns from the leased asset. As NFE has no equity interest in these VIEs, all equity attributable to these VIEs is included in non-controlling interests in the condensed consolidated financial statements. (b) Revenue recognition Terminals and Infrastructure Within the Terminals and Infrastructure segment, the Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from the Company’s natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is delivered in containers transported by truck to customer sites, but may also be delivered via vessel to an unloading point specified in a contract. Revenue from sales of LNG is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, the Company has presented Operating revenue on an aggregated basis. The Company has concluded that variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer. The Company’s contracts with customers to supply natural gas or LNG may contain a lease of equipment, which may be accounted for as a finance or operating lease. For the Company’s operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated the lease component. The lease component of such operating leases is recognized as Operating revenue in the condensed consolidated statements of operations and comprehensive loss. The Company allocates consideration in agreements containing finance leases between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term . The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net on the condensed consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. In addition to the revenue recognized from the finance lease components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as the Company transfers control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and the Company recognizes revenue for the interest income component over the term of the financing as Other revenue. 6 Table of Contents The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration; unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed consolidated balance sheets. Shipping and handling costs are not considered to be separate performance obligations. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas. The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has elected to present sales tax collections in the condensed consolidated statements of operations and comprehensive loss on a net basis and, accordingly, such taxes are excluded from reported revenues. The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less. Ships Charter contracts for the use of the FSRUs and LNG carriers acquired as part of the Mergers are leases as the contracts convey the right to obtain substantially all of the economic benefits from the use of the asset and allow the customer to direct the use of that asset. At inception, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. In making the classification assessment, the Company estimates the residual value of the underlying asset at the end of the lease term with reference to broker valuations. None of the vessel lease contracts contain residual value guarantees. Renewal periods and termination options are included in the lease term if the Company believes such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. The Company assesses leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease. For charter contracts that are determined to be finance leases accounted for as sales-type leases, the profit from the sale of the vessel is recognized upon lease commencement in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Revenues include lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenues generated from charters contracts are recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Lease payments includes fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, the Company has elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based become probable or occur. Repositioning fees are included in Vessel charter revenues and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee will be recognized evenly over the term of the charter. Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss over the lease term. 7 Table of Contents The Company’s LNG carriers may participate in an LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as the Cool Pool. The Cool Pool allows the pool participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as an agent, for the marketing and chartering of the participating vessels and paying certain voyage costs such as port call expenses and brokers’ commissions in relation to employment contracts, with each of the Pool Participants continuing to be fully responsible for fulfilling the performance obligations in the contract. The Company is primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and the Company is the principal in such time charters. Revenue and expenses for charters of the Company’s vessels that participate in the Cool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the condensed consolidated statements of operations and comprehensive loss. The Company’s allocation of its share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss. (c) Business combinations Business combinations are accounted for under the acquisition method. On acquisition, the identifiable assets acquired and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the purchase price over the fair values of the identifiable net assets acquired is recognized as goodwill. Acquisition related costs are expensed as incurred. The results of operations of acquired businesses are included in the Company’s condensed consolidated statements of operations and comprehensive loss from the date of acquisition. If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values. (d) Equity method investments The Company accounts for investments in entities over which the Company has significant influence, but do not meet the criteria for consolidation, under the equity method of accounting. Under the equity method of accounting, the Company’s investment is recorded at cost, or in the case of equity method investments acquired as part of the Mergers, at the acquisition date fair value of the investment. The carrying amount is adjusted for the Company’s share of the earnings or losses, and dividends received from the investee reduce the carrying amount of the investment. The Company allocates the difference between the fair value of investments acquired in the Mergers and the Company’s proportionate share of the carrying value of the underlying assets, or basis difference, across the assets and liabilities of the investee. The basis difference assigned to amortizable net assets is included in Income (loss) from equity method investments in the condensed consolidated statements of operations and comprehensive loss. When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee. (e) Lessor expense recognition Vessel operating expenses, which are recognized when incurred, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and third-party management fees. Voyage expenses principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. Initial direct costs include costs directly related to the negotiation and consummation of the lease are deferred and recognized in Vessel operating expenses over the lease term. (f) Guarantees Guarantees issued by the Company, excluding those that are guaranteeing the Company’s own performance, are recognized at fair value at the time that the guarantees are issued and recognized in Other current liabilities and Other non-current liabilities on the condensed consolidated balance sheets. The guarantee liability is amortized each period as a reduction to Selling, general and administrative expenses. If it becomes probable that the Company will have to perform under a guarantee, the Company will recognize an additional liability if the amount of the loss can be reasonably estimated. 8 Table of Contents (g) Derivatives As part of the Mergers, the Company acquired derivative positions that were used to reduce market risks associated with interest rates and foreign exchange rates. All derivative instruments are initially recorded at fair value as either assets or liabilities on the condensed consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The Company has not designated any derivatives as cash flow or fair value hedges; however, certain instruments may be considered economic hedges. (h) Property, plant and equipment, net Property, plant and equipment is recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Vessel refurbishment costs are capitalized and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs increase the capacity or improve the efficiency or safety of vessels and equipment. Expenditures for routine maintenance and repairs for assets in the Terminals and Infrastructure segment are charged to expense as incurred within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss; such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses. Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul. Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years . For vessels, the Company utilizes the “built-in overhaul” method of accounting. The built-in overhaul method is based on the segregation of vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals to reflect the different useful lives of the components of the assets. The estimated cost of the drydocking component is depreciated until the date of the first drydocking following acquisition of the vessel, upon which the cost is capitalized, and the process is repeated. If drydocking occurs prior to the expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive loss. The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives: Useful life (Yrs) Vessels 5 - 30 Terminal and power plant equipment 4 - 24 CHP facilities 4 - 20 Gas terminals 5 - 24 ISO containers and associated equipment 3 - 25 LNG liquefaction facilities 20 - 40 Gas pipelines 4 - 24 Leasehold improvements 2 - 20 The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted. Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the condensed consolidated statements of operations and comprehensive loss. When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal. (i) Transaction and integration costs Transaction and integration costs are comprised of costs related to business combinations and include advisory, legal, accounting, valuation and other professional or consulting fees. This caption also includes gains or losses recognized in connection with business combinations, including the settlement of preexisting relationships between the Company and an acquired entity. Financing costs which are not deferred as part of the cost of the financing on the balance sheet are recognized within this caption including fees associated with debt modifications. 9 Table of Contents 3. Adoption of new and revised standards (a) New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2021: In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06 , Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. ASU 2020-06 is effective for public companies for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption of all amendments in the same period permitted. The Company will adopt this guidance in the first quarter of 2022 and does not expect it to have a material impact on the Company’s financial position results of operations or cash flows. (b) New and amended standards adopted by the Company: In December 2019, FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes, including removing certain exceptions related to the general principles in ASU 740, Income Taxes. ASU 2019-12 also clarifies and simplifies other aspects of the accounting for income taxes. The adoption of this guidance in the first quarter of 2021 did not have a material impact on the Company’s financial position, results of operations or cash flows. 4. Acquisitions Hygo Merger On April 15, 2021, the Company completed the acquisition of all of the outstanding common and preferred shares representing all voting interests of Hygo, a 50 - 50 joint venture between Golar LNG Limited (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd., a fund managed by Stonepeak Infrastructure Partners (“Stonepeak”), in exchange for 31,372,549 shares of NFE Class A common stock and $ 580,000 in cash. The acquisition of Hygo expands the Company’s footprint in South America with three gas-to-power projects in Brazil’s large and fast-growing market. Based on the closing price of NFE’s common stock on April 15, 2021, the total value of consideration in the Hygo Merger was $ 1.98 billion, shown as follows: Consideration As of April 15, 2021 Cash consideration for Hygo Preferred Shares $ 180,000 Cash consideration for Hygo Common Shares 400,000 Total Cash Consideration $ 580,000 Merger consideration to be paid in shares of NFE Common Stock 1,400,784 Total Non-Cash Consideration 1,400,784 Total Consideration $ 1,980,784 The Company has determined it is the accounting acquirer of Hygo, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of Hygo based on their respective estimated fair values as of the closing date. 10 Table of Contents The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment in determining the appropriate assumptions and estimates. The Company is in the process of finalizing the valuation of assets acquired, liabilities assumed and non-controlling interests of Hygo, and therefore the purchase price allocation should be considered preliminary. The preliminary purchase price allocation may be subject to further refinement as the evaluation of the underlying inputs and assumptions of third-party valuations and the assessment of acquisition-related income taxes are finalized. The goodwill balance may be adjusted pending the completion of the valuation of the assets acquired, liabilities assumed and non-controlling interests of Hygo as described above. The preliminary estimates may be subject to adjustments during the measurement period, not to exceed one year, based upon new information obtained about facts and circumstances that existed as of the acquisition date. Preliminary fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of Hygo as of the closing date were as follows: Hygo As of April 15, 2021 Assets Acquired Cash and cash equivalents $ 26,641 Restricted cash 48,183 Accounts receivable 5,126 Inventory 1,022 Other current assets 8,095 Assets under development 128,625 Property, plant and equipment, net 385,389 Equity method investments 823,521 Finance leases, net 601,000 Deferred tax assets, net 1,065 Other non-current assets 52,996 Total assets acquired: $ 2,081,663 Liabilities Assumed Current portion of long-term debt $ 38,712 Accounts payable 3,059 Accrued liabilities 39,149 Other current liabilities 13,495 Long-term debt 433,778 Deferred tax liabilities, net 254,949 Other non-current liabilities 21,520 Total liabilities assumed: 804,662 Non-controlling interest 36,115 Net assets acquired: 1,240,886 Goodwill $ 739,898 During the three months ended September 30, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of Hygo due to additional information utilized to determine fair value during the measurement period. The measurement period adjustment impacted the fair value of debt assumed, including associated impacts to non-controlling interests and deferred tax liabilities. The measurement period adjustment decreased goodwill by $ 7,039 , and the Company recognized additional interest expense of $ 1,088 in the three months ended September 30, 2021. The fair value of Hygo’s non-controlling interest (“NCI”) as of April 15, 2021 was $ 36,115 , including the fair value of the net assets of VIEs that Hygo has consolidated. These VIEs are special purpose vehicles (“SPV”) for the sale and leaseback of certain vessels, and Hygo has no equity investment in these entities. The fair value of NCI was determined based on the valuation of the SPV’s external debt and the lease receivable asset associated with the sales leaseback transaction with Hygo’s subsidiary, using a discounted cash flow method. The fair value of receivables acquired from Hygo is $ 8,009 , which approximates the gross contractual amount; no material amounts are expected to be uncollectible. Goodwill is calculated as the excess of the purchase price over the net assets acquired. Goodwill represents access to additional LNG and natural gas distribution systems and power markets, including a local workforce that will allow the Company to rapidly develop and deploy LNG to power solutions. The Company’s results of operations for the nine months ended September 30, 2021 include Hygo’s result of operations from the date of acquisition, April 15, 2021, through September 30, 2021. Revenue and net income (loss) attributable to Hygo during the period was $ 42,136 and $ 9,324 , respectively. 11 Table of Contents GMLP Merger On April 15, 2021, the Company completed the acquisition of all of the outstanding common units, representing all voting interests, of GMLP in exchange for $ 3.55 in cash per common unit and for each of the outstanding membership interest of GMLP’s general partner. In conjunction with the closing of the GMLP Merger, NFE simultaneously extinguished a portion of GMLP’s debt for total consideration of $ 1.15 billion. With the acquisition of GMLP, the Company gains vessels to support the existing terminals and business development pipeline, as well as an interest in a floating natural gas facility (“FLNG”), which is expected to provide consistent cash flow streams under a long-term tolling arrangement. The interest in the FLNG facility also provides the Company access to intellectual property that will be used to develop future FLNG solutions. The consideration paid by the Company in the GMLP Merger was as follows: Consideration As of April 15, 2021 GMLP Common Units ($ 3.55 per unit x 69,301,636 units) $ 246,021 GMLP General Partner Interest ($ 3.55 per unit x 1,436,391 units) 5,099 Partnership Phantom Units ($ 3.55 per unit x 58,960 units) 209 Cash Consideration $ 251,329 GMLP debt repaid in acquisition 899,792 Total Cash Consideration 1,151,121 Cash settlement of preexisting relationship ( 3,978 ) Total Consideration $ 1,147,143 The Company has determined it is the accounting acquirer of GMLP, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of GMLP based on their respective estimated fair values as of the closing date. 12 Table of Contents The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment in determining the appropriate assumptions and estimates. The Company is in the process of finalizing the valuation of assets acquired, liabilities assumed and non-controlling interests of GMLP, and therefore the purchase price allocation should be considered preliminary. The preliminary purchase price allocation may be subject to further refinement as the evaluation of the underlying inputs and assumptions of third-party valuations and the assessment of acquisition-related income taxes are finalized. The goodwill balance may be adjusted pending the completion of the valuation of the assets acquired, liabilities assumed and non-controlling interests of GMLP as described above. The preliminary estimates may be subject to adjustments during the measurement period, not to exceed one year, based upon new information obtained about facts and circumstances that existed as of the acquisition date. Preliminary fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of GMLP as of the closing date were as follows: GMLP As of April 15, 2021 Assets Acquired Cash and cash equivalents $ 41,461 Restricted cash 24,816 Accounts receivable 3,195 Inventory 2,151 Other current assets 2,789 Equity method investments 355,500 Property, plant and equipment, net 1,063,215 Intangible assets, net 120,000 Deferred tax assets, net 963 Other non-current assets 4,400 Total assets acquired: $ 1,618,490 Liabilities Assumed Current portion of long-term debt $ 158,073 Accounts payable 3,019 Accrued liabilities 17,226 Other current liabilities 73,774 Deferred tax liabilities, net 16,008 Other non-current liabilities 10,630 Total liabilities assumed: 278,730 Non-controlling interest 192,851 Net assets to be acquired: 1,146,909 Goodwill $ 234 During the three months ended September 30, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of GMLP due to additional information utilized to determine fair value during the measurement period. The measurement period adjustment impacted the fair value of debt assumed, including associated impacts to non-controlling interests. The measurement period adjustment decreased goodwill by $ 1,431 , and the Company recognized an amortization of the discount on debt of $ 11,119 as an addition to interest expense for the period after the GMLP Merger. The fair value of GMLP’s NCI as of April 15, 2021 was $ 192,851 , which represents the fair value of other investors’ interest in the Mazo , GMLP’s preferred units which were not acquired by the Company and the fair value of net assets of an SPV formed for the purpose of a sale and leaseback of the Eskimo . The fair value of GMLP’s preferred units and the valuation of the SPV’s external debt and the lease receivable asset associated with the sale leaseback transaction have been estimated using a discounted cash flow method. The fair value of receivables acquired from GMLP is $ 4,797 , which approximates the gross contractual amount; no material amounts are expected to be uncollectible. The Company acquired favorable and unfavorable leases for the use of GMLP’s vessels. The fair value of the favorable contracts is $ 120,000 and the fair value of the unfavorable contracts is $ 13,400 . The total weighted average amortization period is approximately three years ; the favorable contract asset has a weighted average amortization period of approximately three years and the unfavorable contract liability has a weighted average amortization period of approximately one year . The Company and GMLP had an existing lease agreement prior to the GMLP Merger. As a result of the acquisition, the lease agreement and any associated receivable and payable balances are effectively settled. The lease agreement also included provisions that required a subsidiary of NFE to indemnify GMLP to the extent that GMLP incurred certain tax liabilities as a result of the lease. A loss of $ 3,978 related to settlement of this indemnification provision was recognized in Transaction and integration costs in the condensed consolidated statements of operations and comprehensive loss in the second quarter of 2021. The Company’s results of operations for the nine months ended September 30, 2021 include GMLP’s result of operations from the date of acquisition, April 15, 2021, through September 30 , 2021. Revenue and net income (loss) attributable to GMLP during this period was $ 123,261 and $ 82,310 , respectively. Acquisition costs associated with the Mergers of $ 58 and $ 33,530 for the three and nine months ended September 30, 2021 were included in Transaction and integration costs in the Company’s condensed consolidated statements of operations and comprehensive loss. 13 Table of Contents Unaudited pro forma financial information The following table summarizes the unaudited pro forma condensed financial information of the Company as if the Mergers had occurred on January 1, 2020. Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Revenue $ 304,656 $ 229,619 $ 780,875 $ 571,892 Net income (loss) ( 8,994 ) ( 35,127 ) ( 75,963 ) ( 357,190 ) Net income (loss) attributable to stockholders ( 12,822 ) ( 36,870 ) ( 95,954 ) ( 281,127 ) The unaudited pro forma financial information is based on historical results of operations as if the acquisitions had occurred on January 1, 2020, adjusted for transaction costs incurred, adjustments to depreciation expense associated with the recognition of the fair value of vessels acquired, additional amortization expense associated with the recognition of the fair value of favorable and unfavorable customer contracts for vessel charters, additional interest expense as a result of incurring new debt and extinguishing historical debt, elimination of a pre-existing lease relationship between the Company and GMLP, and a step-up of the equity method investments and a favorable power purchase agreement contract. Pro forma net income (loss) for the nine months ended September 30, 2020 includes non-recurring expenses associated with the Mergers of $ 37,508 ; such non-recurring expenses have been removed from the pro forma financial information for the nine months ended September 30, 2021. Transaction costs incurred and the elimination of a pre-existing lease relationship between the Company and GMLP are considered to be non-recurring. The unaudited pro forma financial information does not give effect to any synergies, operating efficiencies or cost savings that may result from the Mergers. GLNG management and services agreements In connection with the closing of the Mergers, the Company entered into multiple agreements with Golar Management Limited, a subsidiary of GLNG (“Golar Management”), including omnibus agreements, transition services agreements, ship management agreements and other services agreements described as follows: • The Company and Golar Management entered into transition service agreements whereby Golar Management provides certain administrative and consulting services to facilitate the integration of GMLP and Hygo (the “Transition Services Agreements”). The Transition Services Agreements commenced on April 15, 2021 and will terminate on April 30, 2022 unless terminated earlier by either party. The Company pays Golar Management monthly payments of $ 250 and will reimburse Golar Management for all reasonable and documented out-of-pocket expenses or remittances of funds paid to a third party in connection with the provision of the Transition Services. • The Company’s vessel-owning subsidiaries entered into ship management agreements with Golar Management (the “Ship Management Agreements”), pursuant to which Golar Management provides certain technical, crew, insurance and commercial management services for the acquired vessels for a specified annual cost per vessel. The Ship Management Agreements commenced on April 15, 2021 will continue until terminated by either party by notice, in which event the relevant Ship Management Agreements will terminate upon the later of 12 months after April 15, 2021 or two months from the date on which such notice is received. • The Company also entered into certain agreements to facilitate the integration of the acquired businesses and their operations whereby GLNG or its subsidiaries will continue to provide certain guarantees and indemnities under charter arrangements or GMLP’s and Hygo’s sale leaseback agreements. NFE pays the relevant Charter Guarantor or Golar an annual guarantee fee of $ 250 per vessel. • The Company and Golar Management (Bermuda) Limited (“Golar Bermuda”) entered into a services agreement (the “Bermuda Services Agreement”) pursuant to which Golar Bermuda will act as GMLP’s and Hygo’s registered office in Bermuda and provide certain corporate secretarial, registrar and administration services (the “Bermuda Services Agreements”). The Bermuda Services Agreements commenced on April 15, 2021. Either party may terminate the Bermuda Services Agreements upon 30 days’ prior written notice. Golar Partners and Hygo pay Golar Bermuda an aggregate annual fee of $ 50 for the Bermuda services and will reimburse Golar Bermuda for all incidental documented costs and expenses reasonably incurred by Golar Bermuda and its designees in connection with the provision of the Bermuda services. During the period subsequent to the completion of the Mergers, the Company incurred $ 3,387 and $ 6,487 for the three and nine months ended September 30, 2021, respectively, in management, services or guarantee fees under these agreements with GLNG, Golar Management or GLNG affiliated entities. 14 Table of Contents Asset acquisitions On January 12, 2021, the Company acquired 100 % of the outstanding share quota of CH4 Energia Ltda. (“CH4”), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37 GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $ 903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to approximately $ 3,600 . As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $ 3,047 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the condensed consolidated balance sheets. The selling shareholders of CH4 may also receive future payments based on gas consumed by the power plant or sold to customers from the LNG terminal. For the three and nine months ended September 30, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $ 62 and $ 9 , respectively , which is presented in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss. The purchase of CH4 has been accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $ 295 were included in the purchase consideration. The total purchase consideration of $ 5,776 , which includes a deferred tax liability of $ 1,531 recognized as a result from the acquisition, was allocated to permits and authorizations acquired and was recorded within Intangible assets, net. On March 11, 2021, the Company acquired 100 % of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold grants to operate as an independent power provider and 15 -year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. The Company is seeking to obtain the necessary approvals to transfer the power purchase agreements in connection with the construction the gas-fired power plant and LNG import terminal at the Port of Suape. The purchase consideration consisted of $ 8,041 of cash paid at closing in addition to potential future payments contingent on achieving commercial operations of the gas-fired power plant at the Port of Suape of up to approximately $ 10.5 million. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $ 7,473 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the condensed consolidated balance sheets. The selling shareholders may also receive future payments based on power generated by the power plant in Suape, subject to a maximum payment of approximately $ 4.6 million. For the three and nine months ended September 30, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $ 843 and $ 427 , respectively, which is presented in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss. The purchases of Pecém and Muricy were accounted for as asset acquisitions. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $ 1,275 were included in the purchase consideration. Of the total purchase consideration, $ 16,585 was allocated to acquired power purchase agreements and recorded in Intangible assets, net on the condensed consolidated balance sheets; the remaining purchase consideration was related to working capital acquired. 5. VIEs L essor VIEs The Company assumed sale leaseback arrangements for four vessels as part of the Mergers. The counterparty to each of these sale leaseback arrangements is a VIE, and these lessor VIEs are SPVs wholly owned by financial institutions. While the Company does not own hold an equity investment in these entities, these lessor VIEs are consolidated in the condensed consolidated financial statements. As the Company has no equity attributable to these lessor VIEs, all equity attributable to these lessor VIEs is included in non- controlling interests in the condensed consolidated financial statements. Transactions between our wholly-owned subsidiaries and these VIEs are eliminated in consolidation, including sale leaseback transactions. China Merchants Bank Lending (“CMBL”) In November 2015, the Eskimo was sold to a subsidiary of CMBL, Sea 23 Leasing Co. Limited, and subsequently leased back under a bareboat charter for a term of ten years . The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the ten-year lease period. 15 Table of Contents CCB Financial Leasing Corporation Limited (“CCBFL”) In September 2018, the Nanook was sold to a subsidiary of CCBFL, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years . The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period. Oriental Shipping Company (“COSCO”) In December 2019, the Penguin was sold to a subsidiary of COSCO, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years . The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period. AVIC International Leasing Company Limited (“AVIC”) In March 2020, the Celsius was sold to a subsidiary of AVIC, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years . The Company has options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period. While the Company does not hold an equity investment in the above SPVs, the Company has a variable interest in these SPVs. The Company is the primary beneficiary of these VIEs and, accordingly, these VIEs are consolidated into the Company’s financial results for the period after the Mergers. The effect of the bareboat charter arrangements is eliminated upon consolidation of the SPVs. The equity attributable to CMBL, CCBFL, COSCO and AVIC in their respective VIEs are included in non-controlling interests in the condensed consolidated financial statements. As of September 30, 2021, the Eskimo , Penguin and Celsius are recorded as Property, plant and equipment, net on the condensed consolidated balance sheet, and the Nanook was recognized in Finance leases, net on the condensed consolidated balance sheet. The following table gives a summary of the sale and leaseback arrangements, including repurchase options and obligations as of September 30, 2021: Vessel End of lease term Date of next repurchase option Repurchase price at next repurchase option date Repurchase obligation at end of lease term Eskimo $ November 2025 $ November 2021 $ 189,100 $ 128,250 Nanook September 2030 December 2021 202,116 94,179 Penguin December 2025 December 2021 92,761 63,040 Celsius March 2027 March 2022 98,290 45,000 A summary of payment obligations under the bareboat charters with the lessor VIEs as of September 30, 2021, are shown below: Vessel Remaining 2021 2022 2023 2024 2025 _ 2026+ Eskimo $ 3,353 $ - $ - $ - $ - $ - Nanook 5,477 21,561 20,964 20,390 19,768 85,754 Penguin 2,955 11,663 11,322 10,962 8,002 - Celsius 3,976 15,574 15,023 14,484 13,922 12,753 The payment obligation table above includes variable rental payments due under the lease based on an assumed LIBOR plus margin but excludes the repurchase obligation at the end of lease term. The assets and liabilities of these lessor VIEs that most significantly impact the condensed consolidated balance sheet as of September 30, 2021 are as follows: Eskimo Nanook Penguin Celsius Assets Restricted cash $ - $ 19,533 $ 9,690 $ 24,924 Liabilities Long-term interest bearing debt - current portion $ 152,004 $ - $ 18,813 $ 5,870 Long-term interest bearing debt - non-current portion - 202,006 77,738 110,336 16 Table of Contents As a result of the Mergers, the most significant impact of the lessor VIEs operations on the Company’s condensed consolidated statement of operations is an addition to interest expense of $ 15,263 and $ 8,628 for the three and nine months ended September 30, 2021, respectively. Upon assumption of the debt held by VIEs in conjunction with the Mergers, the Company recognized the liabilities assumed at fair value, and the amortization of the discount of $ 11,550 and $ 1,843 has been recognized as an addition to interest expense incurred of $ 3,713 and $ 6,785 for the three and nine months ended, respectively. The most significant impact of the lessor VIEs cash flows on the condensed consolidated statements of cash flows is net cash used in financing activities of $ 21,061 for the period subsequent to the completion of the Mergers. Other VIEs Hilli LLC The Company acquired an interest of 50 % of the common units of Hilli LLC (“Hilli Common Units”) as part of the acquisition of GMLP. Hilli LLC owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Company determined that Hilli LLC is a VIE, and the Company is not the primary beneficiary of Hilli LLC. Thus, Hilli LLC has not been consolidated into the financial statements and has been recognized as an equity method investment. As of September 30, 2021 the maximum exposure as a result of the Company’s ownership in the Hilli LLC is the carrying value of the equity method investment of $ 363,543 and the outstanding portion of the Hilli Leaseback (defined below) which have been guaranteed by the Company. 6. Revenue recognition Operating revenue includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam. Other revenue includes revenue for development services as well as interest income from the Company’s finance leases and other revenue. The table below summarizes the balances in Other revenue: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Development services revenue $ 25,264 $ 51,974 $ 125,924 $ 79,540 Interest income and other revenue 12,347 1,021 22,617 2,872 Total other revenue $ 37,611 $ 52,995 $ 148,541 $ 82,412 Development services revenue recognized in the three and nine months ended September 30, 2021 included $ 25,264 and $ 114,654 , respectively, for the customer’s use of natural gas as part of commissioning their assets. Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of September 30, 2021 and December 31, 2020, receivables related to revenue from contracts with customers totaled $ 126,783 and $ 76,431 , respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $ 130 and $ 98 , respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases which are accounted for outside the scope of ASC 606 and receivables associated with reimbursable costs. The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are expected to be satisfied during the next 12 months, and the contract liabilities are classified within Other current liabilities on the condensed consolidated balance sheets. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. The contract liabilities and contract assets balances as of September 30, 2021 and December 31, 2020 are detailed below: September 30, 2021 December 31, 2020 Contract assets, net - current $ 7,310 $ 4,029 Contract assets, net - non-current 38,554 30,434 Total contract assets, net $ 45,864 $ 34,463 Contract liabilities $ 2,371 $ 8,399 Revenue recognized in the year from: Amounts included in contract liabilities at the beginning of the year $ 6,340 $ 6,542 17 Table of Contents Contract assets are presented net of expected credit losses of $ 530 and $ 376 as of September 30, 2021 and December 31, 2020, respectively. As of September 30, 2021 and December 31, 2020, contract assets was comprised of $ 45,513 and $ 6,821 of unbilled receivables, respectively, that represent unconditional rights to payment only subject to the passage of time. The Company has recognized costs to fulfill a contract with a significant customer, which primarily consist of expenses required to enhance resources to deliver under the agreement with the customer. As of September 30, 2021, the Company has capitalized $ 11,132 , of which $ 604 of these costs is presented within Other current assets and $ 10,528 is presented within Other non-current assets on the condensed consolidated balance sheets. As of December 31, 2020, the Company had capitalized $ 11,276 , of which $ 588 of these costs was presented within Other current assets and $ 10,688 was presented within Other non-current assets on the condensed consolidated balance sheets. In the first quarter of 2020, the Company began delivery under the agreement and started recognizing these costs on a straight-line basis over the expected term of the agreement. Transaction price allocated to remaining performance obligations Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts. The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements represents the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period: Period Revenue Remainder of 2021 $ 67,761 2022 474,995 2023 515,235 2024 511,719 2025 503,099 Thereafter 8,446,430 Total $ 10,519,239 For all other sales contracts that have a term exceeding one year, the Company has elected the practical expedient in ASC 606 under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied. Lessor arrangements The Company’s vessel charters of LNG carriers and FSRUs can take the form of operating or finance leases. Property, plant and equipment subject to vessel charters accounted for as operating leases is included within Vessels within Note 14 Property, plant and equipment, net. The following is the carrying amount of property, plant and equipment that is leased to customers under operating leases: September 30, 2021 December 31, 2020 Property, plant and equipment $ 1,274,293 $ 18,394 Accumulated depreciation ( 20,128 ) ( 932 ) Property, plant and equipment, net $ 1,254,165 $ 17,462 18 Table of Contents The components of lease income from vessel operating leases for the three and nine months ended September 30, 2021 were as follows: Three Months Ended Nine Months Ended September 30, 2021 September 30 , 2021 Operating lease income $ 74,069 $ 136,095 Variable lease income 3,096 4,466 Total operating lease income $ 77,165 $ 140,561 The Company’s charter of the Nanook to CELSE and certain equipment leases provided in connection with the supply of natural gas or LNG are accounted for as finance leases. The Company recognized interest income of $ 11,607 and $ 21,288 for the three months and nine months ended September 30, 2021, respectively, related to the finance lease of the Nanook included within Other revenue in the condensed consolidated statements of operations and comprehensive loss. The Company recognized revenue of $ 1,491 and $ 2,656 for the three months and nine months ended September 30, 2021, respectively, related to the operation and services agreement within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. As of September 30, 2021, there were outstanding balances due from CELSE of $ 6,183 , of which $ 4,210 is recognized in Receivables, net and a loan to CELSE of $ 1,973 is recognized in Prepaid expenses and other current assets, net on the condensed consolidated balance sheets. CELSE is an affiliate due to the equity method investment held in CELSE’s parent, CELSEPAR, and as such, these transactions and balances are related party in nature. The following table shows the expected future lease payments as of September 30, 2021, for the remainder of 2021 through 2025 and thereafter: Future cash receipts Financing Leases Operating Leases Remainder of 2021 $ 12,478 $ 64,827 2022 49,951 244,239 2023 50,616 144,375 2024 51,442 105,572 2025 51,876 25,961 Thereafter 1,104,102 - Total minimum lease receivable $ 1,320,465 $ 584,974 Unguaranteed residual value 107,000 Gross investment in sales-type lease $ 1,427,465 Less: Unearned interest income 818,758 Less: Current expected credit losses 1,546 Net investment in leased vessel $ 607,161 Current portion of net investment in leased asset $ 3,499 Non-current portion of net investment in leased asset 603,662 7. Leases, as lessee The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability. The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period. 19 Table of Contents As of September 30, 2021 and December 31, 2020, right-of-use assets, current lease liabilities and non-current lease liabilities consisted of the following: September 30, 2021 December 31, 2020 Operating right-of-use-assets $ 126,424 $ 141,347 Finance right-of-use-assets (1) 19,517 - Total right-of-use assets $ 145,941 $ 141,347 Current lease liabilities: Operating lease liabilities $ 28,871 $ 35,481 Finance lease liabilities 3,138 - Total current lease liabilities $ 32,009 $ 35,481 Non-current lease liabilities: Operating lease liabilities $ 80,736 $ 84,323 Finance lease liabilities 12,585 - Total non-current lease liabilities $ 93,321 $ 84,323 (1) Finance lease right-of-use assets are recorded net of accumulated amortization of $ 289 as of September 30, 2021 . 20 Table of Contents For the three and nine months ended September 30, 2021 and 2020, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive loss were as follows : Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Fixed lease cost $ 9,450 $ 11,160 $ 30,231 $ 28,024 Variable lease cost 221 1,054 1,417 1,767 Short-term lease cost 523 473 2,752 1,088 Lease cost - Cost of sales $ 7,954 $ 10,690 $ 27,983 $ 26,150 Lease cost - Operations and maintenance 486 619 1,592 1,447 Lease cost - Selling, general and administrative 1,754 1,378 4,825 3,282 For the three and nine months ended September 30, 2021, the Company has capitalized $ 5,297 and $ 8,809 of lease costs, respectively, for vessels and port space used during the commissioning of development projects in addition to short-term lease costs for vessels chartered by the Company to transport inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory. Beginning in the second quarter of 2021, leases for ISO tanks and a parcel of land that transfer the ownership in underlying assets to the Company at the end of the lease have commenced, and these leases are treated as finance leases. For the three and nine months ended September 30, 2021, the Company recognized interest expense related to finance leases of $ 152 and $ 202 , respectively, which are included within Interest expense, net in the condensed consolidated statements of operations and comprehensive loss. For the three and nine months ended September 30, 2021, the Company recognized amortization of the right-of-use asset related to finance leases of $ 228 and $ 289 , respectively, which are included within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive loss. Cash paid for operating leases is reported in operating activities in the condensed consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the nine months ended September 30, 2021 and 2020 : Nine Months Ended September 30, 2021 2020 Operating cash outflows for operating lease liabilities $ 26,905 $ 32,230 Financing cash outflows for finance lease liabilities 1,092 - Right-of-use assets obtained in exchange for new operating lease liabilities 7,377 172,053 Right-of-use assets obtained in exchange for new finance lease liabilities 19,805 - 21 Table of Contents T he future payments due under operating and finance leases as of September 30, 2021 are as follows : Operating Leases Financing Leases Due remainder of 2021 $ 9,788 $ 1,218 2022 33,540 3,449 2023 26,868 3,519 2024 20,496 3,538 2025 12,085 3,538 Thereafter 61,417 2,883 Total Lease Payments $ 164,194 $ 18,145 Less: effects of discounting 54,587 2,422 Present value of lease liabilities $ 109,607 $ 15,723 Current lease liability $ 28,871 $ 3,138 Non-current lease liability 80,736 12,585 As of September 30, 2021, the weighted-average remaining lease term for operating leases was 8.4 years and finance leases was 5.4 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of September 30, 2021 was 8.5 %. The weighted average discount rate associated with finance leases as of September 30, 2021 was 5.1 % . The Company has entered into several leases for ISO tanks that have not commenced as of September 30, 2021 with noncancelable terms of 5 years and including fixed payments of approximately $ 6.3 million. 8. Financial instruments Interest rate and currency risk management In connection with the Mergers, the Company has acquired financial instruments that GMLP and Hygo used to reduce the risk associated with fluctuations in interest rates and foreign exchange rates. Interest rate swaps are used to convert floating rate interest obligations to fixed rates, which from an economic perspective hedges the interest rate exposure. The Company also acquired a cross currency interest rate swap to manage interest rate exposure on the Debenture Loan and the foreign exchange rate exposure on the US dollar cash flows from the charter of the Nanook to CELSE that guarantees the repayments of the Brazilian Real-denominated Debenture Loan. The Company does not hold or issue instruments for speculative or trading purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties. The following table summarizes the terms of interest rate and cross currency interest rate swaps as of September 30, 2021: Instrument Notional Amount Maturity Dates Fixed Interest Rate Forward Foreign Exchange Rate Interest rate swap: Receiving floating, pay fixed $ 372,750,000 March 31, 2026 _ 2.86 % N/A Cross currency interest rate swap - Debenture Loan, due 2024 BRL 230,100,142 September 2024 _ 5.90 % _ 5.424 The mark-to-market gain or loss on our interest rate and foreign currency swaps that are not designated as hedges for accounting purposes for the period are reported in the condensed consolidated statements of operations and comprehensive loss in Other (income) expense, net . Fair value Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows: • Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities. • Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs. 22 Table of Contents • Level 3 - unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability. The valuation techniques that may be used to measure fair value are as follows: • Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. • Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts. • Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of September 30, 2021 and December 31, 2020: _ Fair Value Hierarchy September 30, 2021 Carrying Value September 30, 2021 Fair Value December 31, 2020 Carrying Value December 31, 2020 Fair Value Valuation Technique Non-Derivatives: Cash and cash equivalents Level 1 $ 224,383 $ 224,383 $ 601,522 $ 601,522 Market approach Restricted cash Level 1 110,217 110,217 27,814 27,814 Market approach Investment in equity securities Level 1 12,421 12,421 256 256 Market approach Investment in equity securities Level 3 1,849 1,849 1,000 1,000 Market approach Long-term debt (1) Level 2 3,888,894 3,685,935 1,250,000 1,327,488 Market approach Derivatives: Derivative liability (2)(3) Level 3 31,803 31,803 10,716 10,716 Income approach Equity agreement (3)(4) Level 3 18,893 18,893 22,768 22,768 Income approach Interest rate swap liability (5)(6) Level 2 28,046 28,046 - - Income approach (1) Long-term debt is recorded at amortized cost on the condensed consolidated balance sheets, and is presented in the above table gross of deferred financing costs of $ 41,483 and $ 10,439 as of September 30, 2021 and December 31, 2020, respectively. (2) Consideration due to the sellers in assets acquisitions when certain contingent events occur. The liability associated with the derivative liabilities is recorded within Other long-term liabilities on the condensed consolidated balance sheets. (3) The Company estimates fair value of the derivative liability and equity agreement using a discounted cash flows method with discount rates based on the average yield curve for bonds with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent event occurring. (4) To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received for the facility in development in Shannon, Ireland. The liability associated with the equity agreement is recorded within Other current liabilities on the condensed consolidated balance sheets. (5) Interest rate swap liability and cross currency interest rate swap liability is presented within Other current liabilities on the condensed consolidated balance sheet s . (6) The fair value of certain derivative instruments, including interest rate swaps, is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties. The Company believes the carrying amounts of cash and cash equivalents, accounts receivable, finance lease receivables and accounts payable approximated their fair value as of September 30, 2021 and December 31, 2020. As part of the Hygo Merger, the Company assumed liabilities for payments due to sellers in asset acquisitions completed prior to the Hygo Merger, and these liabilities are reflected as derivative liabilities. Activity during the nine months ended September 30, 2021 also included the recognition of additional derivative liabilities from transactions accounted for as asset acquisitions of $ 10,520 (Note 4). During the three and nine months ended September 30, 2021 and 2020, the Company had no settlements of the equity agreement or derivative liabilities or any transfers in or out of Level 3 in the fair value hierarchy. The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, the derivative liability and equity agreement, as well as the cross currency interest rate swap and the interest rate swap. These adjustments have been recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2021 and 2020 : Three Months Ended September 30, Nine Months Ended September 30 , 2021 2020 2021 2020 Derivative liability/Equity agreement - Fair value adjustment - Loss (Gain) $ 155 $ 2,892 $ ( 558 ) $ 2,598 Interest rate swap - Fair value adjustment - Loss (gain) 227 - ( 119 ) - Cross currency interest rate swap - Fair value adjustment - Loss (gain) 4,051 - ( 1,962 ) - 23 Table of Contents Under the Company’s interest rate swap, the Company is required to provide cash collateral, and as of September 30, 2021, $ 12,500 of cash collateral is presented as restricted cash on the condensed consolidated balance sheets . 9. Restricted cash As of September 30, 2021 and December 31, 2020, restricted cash consisted of the following: September 30, 2021 December 31, 2020 Cash held by lessor VIEs $ 54,147 $ - Collateral for interest rate swaps 12,500 - Collateral for performance under customer agreements 15,000 15,000 Collateral for LNG purchases - 11,664 Collateral for letters of credit and performance bonds 27,814 900 Other restricted cash 756 250 Total restricted cash $ 110,217 $ 27,814 Current restricted cash $ 72,338 $ 12,814 Non-current restricted cash 37,879 15,000 Restricted cash does not include minimum consolidated cash balances of $ 30,000 required to be maintained as part of the financial covenants for sale and leaseback financings and the Vessel Term Loan Facility that is included in Cash and cash equivalents on the condensed consolidated balance sheets as of September 30, 2021. 10. Inventory As of September 30, 2021 and December 31, 2020, inventory consisted of the following: September 30, 2021 December 31, 2020 LNG and natural gas inventory $ 66,660 $ 13,986 Automotive diesel oil inventory 4,659 3,986 Bunker fuel, materials, supplies and other 11,071 4,888 Total inventory $ 82,390 $ 22,860 Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. No adjustments were recorded during the nine months ended September 30, 2021 and 2020. 11. Prepaid expenses and other current assets As of September 30, 2021 and December 31, 2020, prepaid expenses and other current assets consisted of the following: September 30, 2021 December 31, 2020 Prepaid LNG $ 6,143 $ 11,987 Prepaid expenses 10,710 4,941 Due from affiliates 2,919 1,881 Other current assets 55,830 29,461 Total prepaid expenses and other current assets, net $ 75,602 $ 48,270 Other current assets as of September 30, 2021 and December 31, 2020 primarily consists of receivables for recoverable taxes and deposits. 24 Table of Contents 12. Equity method investments As a result of the Mergers, the Company acquired investments in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and Hilli LLC, both of which have been recognized as equity method investments. The Company has a 50 % ownership interest in both entities. The investments are reflected in the Terminals and Infrastructure and Ships segments, respectively. Changes in the balance of the Company’s equity method investments is as follows: September 30, 2021 Equity method investments as of December 31, 2020 $ - Acquisition of equity method investments in the Mergers 1,179,021 Dividends ( 14,259 ) Equity in earnings / losses of investees 22,958 Foreign currency translation adjustment 40,271 Equity method investments as of September 30, 2021 $ 1,227,991 The carrying amount of equity method investments as of September 30 , 2021 is as follows: September 30, 2021 Hilli LLC $ 363,543 CELSEPAR 864,448 Total $ 1,227,991 As of September 30, 2021 , the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $ 930,071 . In conjunction with the preliminary purchase accounting for the Mergers, the basis difference was allocated to tangible assets, identifiable intangible assets, liabilities and goodwill, and the basis difference attributable to amortizable net assets is amortized to (Loss) income from equity method investments over the remaining estimated useful lives of the underlying assets. CELSEPAR CELSEPAR is jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounts for this 50 % investment using the equity method. CELSEPAR owns 100 % of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of the Sergipe Power Plant. Hilli LLC The Company acquired an interest of 50 % of the Hilli Common Units as part of the acquisition of GMLP. The ownership interests in Hilli LLC are represented by three classes of units, Hilli Common Units, Series A Special Units and Series B Special Units. The Company did not acquire any of the Series A Special Units or Series B Special Units. The Hilli Common Units provide the Company with significant influence over Hilli LLC. The Hilli is currently operating under an 8-year liquefaction tolling agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures. Within 60 days after the end of each quarter, GLNG, the managing member of Hilli LLC, shall determine the amount of Hilli LLC’s available cash and appropriate reserves, and Hilli LLC shall make a distribution to the unitholders of Hilli LLC (“Hilli Unitholders”) of the available cash, subject to such reserves. Hilli LLC shall make distributions to the Hilli Unitholders when, as and if declared by GLNG; provided, however, that no distributions may be made on the Hilli Common Units on any distribution date unless Series A Distributions and Series B Distributions for the most recently ended quarter and any accumulated Series A Distributions and Series B Distributions in arrears for any past quarter have been or contemporaneously are being paid or provided for. Series A Distributions are calculated based on cash received by Hilli Corp for any tolling fees under the LTA relating to an increase in the Brent Crude price above $ 60 per barrel, adjusted by incremental taxes and costs that arise from underperformance of the Hilli . Series B Distributions are calculated as 95 % of “Revenues Less Expenses”, which is based on the cash receipts as a direct result of the employment of more than the first 50 % of LNG production capacity for the Hilli , adjusted for incremental operating expenses, capital costs, financing and tax costs associated with making more than 50 % capacity available and costs that arise from underperformance. The Hilli Common Units may receive 5 % of Revenues less Expenses received by Hilli Corp during such quarter. 25 Table of Contents The Company is required to reimburse other investors in Hilli LLC for 50 % of the amount, if any, by which certain operating expenses and withholding taxes of Hilli LLC are below an annual threshold for up to $ 20,000 in the aggregate through 2026 . Other investors are required to reimburse the Company for 50 % of the amount, if any, by which certain operating expenses and withholding taxes are above an annual threshold for up to $ 20,000 in the aggregate through 2026 . No operating expense reimbursements were included in distributions for the period after the GMLP Merger. Hilli Corp is a party to a Memorandum of Agreement, dated September 9, 2015 , with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). The Hilli Leaseback provided for postconstruction financing for the Hilli in the amount of $ 960 million. Under the Hilli Leaseback, Hilli Corp will pay to Fortune forty consecutive equal quarterly repayments of 1.375 % of the construction cost, plus interest based on LIBOR plus a margin of 4.15 % . 13. Construction in progress The Company’s construction in progress activity during the nine months ended September 30, 2021 is detailed below: September 30, 2021 Balance at beginning of period $ 234,037 Acquisition of construction in progress from business combinations 128,625 Additions 608,043 Impact of change in FX rates 9,803 Transferred to property, plant and equipment, net or finance leases ( 6,628 ) Balance at end of period $ 973,880 Interest expense of $ 18,924 and $ 22,441 , inclusive of amortized debt issuance costs, was capitalized for the nine months ended September 30, 2021 and 2020, respectively . 14. Property, plant and equipment, net As of September 30, 2021 and December 31, 2020, the Company’s property, plant and equipment, net consisted of the following: September 30, 2021 December 31, 2020 Vessels $ 1,441,211 $ - Terminal and power plant equipment 189,472 188,855 CHP facilities 122,776 119,723 Gas terminals 120,810 120,810 ISO containers and other equipment 120,041 100,137 LNG liquefaction facilities 63,213 63,213 Gas pipelines 58,987 58,974 Land 16,714 16,246 Leasehold improvements 9,256 8,723 Accumulated depreciation ( 116,792 ) ( 62,475 ) Total property, plant and equipment, net $ 2,025,688 $ 614,206 Depreciation for the three months ended September 30, 2021 and 2020 totaled $ 23,929 and $ 9,370 , respectively, of which $ 322 and $ 212 , respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. Depreciation for the nine months ended September 30, 2021 and 2020 totaled $ 55,070 and $ 22,120 , respectively, of which $ 898 and $ 662 is respectively included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss. Capitalized drydocking costs of $ 6,573 are included in the vessel cost for September 30, 2021 which are depreciated from the completion of drydocking until the next expected dry docking. 26 Table of Contents 15. Intangible assets The following table summarizes the composition of intangible assets as of September 30, 2021 and December 31, 2020: September 30, 2021 Gross Carrying Amount Accumulated Amortization Currency Translation Adjustment Net Carrying Amount Weighted Average Life Definite-lived intangible assets Favorable vessel charter contracts $ 120,000 $ ( 18,974 ) $ - $ 101,026 3 Permits and development rights 49,285 ( 3,643 ) 145 45,787 40 Acquired power purchase agreements 16,585 - 1,028 17,613 17 Easements 1,559 ( 229 ) - 1,330 30 Indefinite-lived intangible assets Easements 1,191 - 17 1,208 n/a Total intangible assets $ 188,620 $ ( 22,846 ) $ 1,190 $ 166,964 December 31, 2020 Gross Carrying Amount Accumulated Amortization Currency Translation Adjustment Net Carrying Amount Weighted Average Life Definite-lived intangible assets Permits $ 42,441 $ ( 2,438 ) $ 3,456 $ 43,459 40 Easements 1,559 ( 190 ) - 1,369 30 Indefinite-lived intangible assets Easements 1,191 - 83 1,274 n/a Total intangible assets $ 45,191 $ ( 2,628 ) $ 3,539 $ 46,102 In conjunction with the Mergers, the Company acquired charter contracts with contractual rates that were favorable as compared to market rates and on the date of acquisition recognized intangible assets of $ 120,000 . During the first quarter of 2021, the Company recognized additions to permits of $ 5,776 acquired in a transaction accounted for as asset acquisition related to licenses and rights to develop a gas-fired power plant and associated infrastructure in the Port of Suape in Brazil. The Company also acquired rights operated a power generation facility and sell power in Brazil of $ 16,585 (see Note 4. Acquisitions). As of September 30, 2021 and December 31, 2020, the weighted-average remaining amortization periods for the intangible assets were 12.7 and 37.5 years, respectively. Amortization expense for the three months ended September 30, 2021 and 2020 totaled $ 7,334 and $ 309 , respectively. Amortization expense was $ 13,550 and $ 861 for the nine months ended September 30, 2021 and 2020, respectively. 16. Other non-current assets As of September 30, 2021 and December 31, 2020, Other non-current assets consisted of the following: September 30, 2021 December 31, 2020 Nonrefundable deposit $ 30,335 $ 28,509 Contract asset, net (Note 6) 38,554 30,434 Cost to fulfill (Note 6) 10,528 10,688 Upfront payments to customers 9,934 6,330 Other 31,791 10,069 Total other non-current assets, net $ 121,142 $ 86,030 Nonrefundable deposits are primarily related to deposits for planned land purchases in Pennsylvania and Ireland. Upfront payments to customers consist of amounts the Company has paid in relation to two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own. Other includes investments in equity securities of $ 14,270 and $ 1,256 as of September 30, 2021 and December 31, 2020. The Company recognized unrealized gains of $ 7,176 and $ 7,264 for the three and nine months ended September 30, 2021 within Other (income), net in the condensed consolidated statements of operations and comprehensive loss. Other also includes upfront payments to our service providers and a long-term refundable deposit. 27 Table of Contents 17. Accrued liabilities As of September 30, 2021 and December 31, 2020, accrued liabilities consisted of the following: September 30, 2021 December 31, 2020 Accrued development costs $ 52,646 $ 16,631 Accrued interest 15,235 27,938 Accrued consideration in asset acquisitions 18,660 - Accrued bonuses 19,517 17,344 Accrued vessel operating and drydocking expenses 12,601 - Other accrued expenses 40,645 28,439 Total accrued liabilities $ 159,304 $ 90,352 18 . Debt As of September 30, 2021 and December 31, 2020, debt consisted of the following: September 30, 2021 December 31, 2020 Senior Secured Notes, due September 15, 2025 $ 1,240,677 $ 1,239,561 Senior Secured Notes, due September 30, 2026 1,477,638 - Vessel Term Loan Facility, due September 18, 2024 423,839 - Debenture loan due 2024 42,126 - CHP Facility 96,364 - Revolving Facility - - Subtotal (excluding lessor VIE loans) 3,280,644 1,239,561 CMBL VIE loan: Golar Eskimo SPV facility, due 2025 152,004 - CCBFL VIE loan: Golar Nanook SPV facility, due 2030 202,006 - COSCO VIE loan: Golar Penguin SPV facility, due 2025 96,551 - AVIC VIE loan: Golar Celsius SPV facility, due 2023 / 2027 116,206 - Total debt $ 3,847,411 $ 1,239,561 Current portion of long-term debt $ 249,752 $ - Long-term debt 3,597,659 1,239,561 28 Table of Contents Our outstanding debt as of September 30, 2021 is repayable as follows: September 30, 2021 Due remainder of 2021 $ 171,850 2022 88,261 2023 135,039 2024 323,689 2025 1,322,536 2026 1,509,874 Thereafter 339,219 Total debt 3,890,468 Add: fair value adjustments to assumed debt obligations ( 1,574 ) Less: deferred finance charges ( 41,483 ) Total debt, net deferred finance charges $ 3,847,411 2025 Notes On September 2, 2020, the Company issued $ 1,000,000 of 6.75 % senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025 . The Company may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2025 Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The 2025 Notes may limit the Company’s ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions. The Company used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses. In connection with the issuance of the 2025 Notes, the Company incurred $ 17,937 in origination, structuring and other fees. Issuance costs of $ 13,909 were deferred as a reduction of the principal balance of the 2025 Notes on the condensed consolidated balance sheets; unamortized deferred financing costs related to lenders in the previous credit agreement that participated in the 2025 Notes were $ 6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the previous credit agreement was a modification, in the third quarter of 2020, the Company recognized $ 4,028 of third-party fees as an expense in the condensed consolidated statements of operations and comprehensive loss. On December 17, 2020, the Company issued $ 250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of $ 13,125 , which was offset by additional financing costs incurred of $ 4,566 . As of September 30, 2021 and December 31, 2020, remaining unamortized deferred financing costs for the 2025 Notes was $ 9,323 and $ 10,439 , respectively. 2026 Notes On April 12, 2021, the Company issued $ 1,500,000 of 6.50 % senior secured notes in a private offering pursuant to Rule 144 A under the Securities Act (the “ 2026 Notes”) at an issue price equal to 100 % of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021 ; no principal payments are due until maturity on September 30, 2026 . The Company may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes. The Company used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses. In connection with the issuance of the 2026 Notes, the Company incurred $ 24,588 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $ 22,362 . 29 Table of Contents Vessel Term Loan Facility On September 18, 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”). Under this facility, the Company borrowed an initial amount of $ 430,000 , which may be increased to $ 725,000 , subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. Loans under the Vessel Term Loan Facility bear interest at a rate of LIBOR plus a margin of 3 percent. The Vessel Term Loan Facility shall be repaid in quarterly installments of $ 15,357 , with the final repayment date in September 2024 . Quarterly principal payments will be increased to reflect any upsize of the Vessel Term Loan Facility to reflect a straight-line amortization profile over the remaining term. Obligations under the Vessel Term Loan Facility are guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of September 30, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $ 666,674 . The Company may prepay outstanding indebtedness without penalty, and certain events, such as (i) total loss; (ii) minimum security value; (iii) the sale or transfer of certain vessels; or (iv) the termination of the charter over the Hilli, will require a mandatory prepayment. The Vessel Term Loan Facility contains customary representations and warranties and customary affirmative and negative covenants, including financial covenants, chartering restrictions, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness and dividends and other distributions. Financial covenants include requirements that GMLP and Golar Partners Operating LLC maintain a certain amount of Free Liquid Assets, that the EBITDA to Consolidated Debt Service and the Net Debt to EBITDA ratios are no less than 1.15 :1 and no greater than 6.50 :1, respectively, and that Consolidated Net Worth is greater than $ 250,000 , each as defined in the Vessel Term Loan Facility. The Company was in compliance with these covenants as of September 30, 2021. In connection with the closing the Vessel Term Loan Facility, the Company incurred $ 6,229 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $ 6,161 . Debenture Loan As part of the Hygo Merger, the Company assumed non-convertible Brazilian debentures issued by NFE Brasil, an indirect subsidiary of Hygo, in the aggregate principal amount of BRL 255.6 million ($ 45.0 million) due September 2024 , bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65 % (the “Debenture Loan”). The Debenture Loan was recognized at fair value of $ 44,566 on the date of the Hygo Merger, and the discount recognized in purchase accounting will result in additional interest expense until maturity. Interest and principal is payable on the Debenture Loan semi-annually on September 13 and March 13. The Debenture Loan is fully and unconditionally guaranteed by 100 % of the shares issued by NFE Brasil owned by the Company’s consolidated subsidiary, LNG Power Ltd. CHP Facility On August 3, 2021, NFE South Power Holdings Limited, a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially drawing $ 100,000 . The CHP Facility is secured by the Company’s combined heat and power plant in Clarendon, Jamaica. The Company incurred $ 3,651 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the CHP Facility on the condensed consolidated balance sheets. As of September 30, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $ 3,636 . 30 Table of Contents Revolving Facility On April 15, 2021, the Company entered into a $ 200,000 senior secured revolving facility (the “Revolving Facility”). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). Letters of credit issued under the $ 100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for the Company to extend the maturity date once in a one-year increment. Borrowings under the Revolving Facility will bear interest at a per annum rate equal to LIBOR plus 2.50 % if the usage under the Revolving Facility is equal to or less than 50 % of the commitments under the Revolving Facility and LIBOR plus 2.75 % if the usage under the Revolving Facility is in excess of 50 % of the commitments under the Revolving Facility, subject in each case to a 0.00 % LIBOR floor. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium. The obligations under the Revolving Facility are guaranteed by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes. The Revolving Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. Financial covenants include requirements to maintain Debt to Capitalization Ratio of less than 0.7 :1.0, and for quarters in which the Revolving Facility is greater than 50 % drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0 :1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0 :1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility). The Company was in compliance with these covenants as of September 30, 2021. The Company incurred $ 3,974 in origination, structuring and other fees, associated with entry into the Revolving Facility. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $ 3,658 . During the second and third quarters of 2021, the Company drew $ 152,500 and $ 47,500 on the Revolving Facility, respectively. During the third quarter of 2021, the Company repaid the amounts outstanding on the Revolving Facility, and as of September 30, 2021, there are no amounts outstanding. Lessor VIE debt The Company assumed the following loans in the Mergers related to lessor VIE entities, including CMBL, CCBFL, COSCO and AVIC, that are consolidated as VIEs. Although the Company has no control over the funding arrangements of these entities, the Company is the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the condensed consolidated financial statements. CMBL – Eskimo SPV facility The SPV, Sea 23 Leasing Co. Limited, the owner of the Eskimo, has a long-term loan facility that is denominated in USD, has a loan term of ten years and bears interest at a rate of LIBOR plus a margin of 2.66 %. As of the acquisition date of GMLP, the outstanding principal balance was $ 160,520 , and the Company recognized the fair value of this facility of $ 158,072 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity. CCBFL – Nanook SPV facility The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, has a long-term loan facility that is denominated in USD, has a loan term of twelve years and bears interest at a fixed rate of 2.7 %. As of the acquisition date of Hygo, the outstanding principal balance was $ 202,249 , and the Company recognized the fair value of this facility of $ 201,484 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity. COSCO – Penguin SPV facility The SPV, Oriental Fleet LNG 02 Limited, the owner of the Penguin, has a long-term loan facility that is denominated in USD, is repayable in quarterly installments over a term of approximately six years and bears interest at LIBOR plus a margin of 1.7 %. The SPV also has amounts payable to its parent. As of the acquisition date of Hygo, the outstanding principal balance was $ 104,882 , and the Company recognized the fair value of this facility and the amount due to the parent of $ 105,126 on the date of the Mergers. The premium recognized in purchase accounting will result in a reduction to interest expense until maturity. 31 Table of Contents AVIC – Celsius SPV facility The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, has two long-term loan facilities that are denominated in USD. The first facility is repayable in quarterly installments over a term of approximately seven years with a balloon payment of $ 37,179 at the end of the term and bears interest at LIBOR plus a margin of 1.8 %; the outstanding principal balance as of the acquisition date of this facility was $ 76,179 . The SPV has another facility with its parent for the remaining principal of $ 45,200 as of the acquisition date, which is due as a balloon payment upon maturity in March 2023 and bears interest at a fixed rate of 4.0 % . As of the acquisition date of Hygo, the total outstanding principal balance was $ 121,379 , and the Company recognized the fair value of this facility and the amount due to the parent of $ 121,308 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity. Debt and lease restrictions The VIE loans and certain lease agreements with customers assumed in the Mergers contain certain operating and financing restrictions and covenants that require: (a) certain subsidiaries to maintain a minimum level of liquidity of $ 30,000 and consolidated net worth of $ 123,950 , (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20 :1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5 :1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110 % and 120 %, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70 :1. As of September 30, 2021, the Company was in compliance with all covenants under debt and lease agreements. The Company has also entered into an Uncommitted Letter of Credit and Reimbursement Agreement with a financial institution for the issuance of letters of credit. As of September 30, 2021, the Company had issued $ 75,000 of letters of credit under this agreement. The Company is required to comply with affirmative and negative covenants customary for such facilities, including financial covenants that are consistent with those under the Revolving Facility. The Company was in compliance with all covenants as of September 30, 2021. Interest Expense Interest and related amortization of debt issuance costs, premiums and discounts recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the three and nine months ended September 30, 2021 and 2020 consisted of the following: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Interest per contractual rates $ 53,140 $ 19,936 $ 120,445 $ 58,576 Amortization of fair value adjustments to assumed debt obligations 12,207 - 1,912 - Amortization of debt issuance costs, premiums and discounts 1,710 4,416 4,122 14,766 Interest expense incurred on finance lease obligations 152 - 202 - Total interest costs $ 67,209 $ 24,352 $ 126,681 $ 73,342 Capitalized interest 9,614 4,539 18,924 22,441 Total interest expense $ 57,595 $ 19,813 $ 107,757 $ 50,901 19. Income taxes As a result of the Mergers, the Company recognized deferred tax liabilities to reflect the impact of fair value adjustments, primarily the increased value of equity method investments, which did not impact tax basis. The Company acquired tax attribute carryforwards including net operating losses in certain jurisdictions for which net deferred tax assets have not been recognized as a result of cumulative losses and the developmental status of the entities. The effective tax rate for the three months ended September 30, 2021 was ( 24.75 )%, compared to ( 5.27 )% for the three months ended September 30, 2020. The total tax provision for the three months ended September 30, 2021 was $ 3,526 , compared to $ 1,836 for the three months ended September 30, 2020. The effective tax rate for the nine months ended September 30, 2021 was ( 13.58 )%, compared to ( 0.75 )% for the nine months ended September 30, 2020. The total tax provision for the nine months ended September 30, 2021 was $ 7,058 , compared to $ 1,949 for the nine months ended September 30, 2020. The calculation of the effective tax rate for the period after the Mergers includes income from equity method investments recognized for the three and nine months ended September 30, 2021. The increases to the tax provision and effective tax rate for both the three and nine months ended September 30, 2021 was primarily driven by an increase in pretax income for certain profitable non-U.S. operations and the inclusion of GMLP and Hygo into expected pre-tax results of operations for the year ended December 31, 2021. Tax expense recognized includes the results of the acquired entities from the date of acquisition through September 30, 2021. For the nine months ended September 30, 2021, these increases in tax expense were partially offset by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $ 1,800 . The Company assumed a liability for tax contingencies in the Mergers of $ 19,382 primarily related to potential tax obligations for payments under certain charter agreements for acquired vessels; this liability is included in Other current liabilities on the condensed consolidated balance sheets. The Company has not recorded any other material liabilities for uncertain tax positions as of September 30, 2021. The Company remains subject to periodic audits and reviews by the taxing authorities, and NFE’s returns since its formation remain open for examination. 32 Table of Contents 20. Commitments and contingencies Legal proceedings and claims The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business, and the Company has evaluated the contingencies that have been assumed in conjunction with the Mergers. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows. In conjunction with the Mergers, the Company has assumed contingencies for VAT in Indonesia. Indonesian tax authorities have issued letters to PTGI, a consolidated subsidiary, to revoke a previously granted VAT importation waiver for approximately $ 24,000 for the NR Satu . The Company does not believe it probable that a liability exists as no Tax Underpayment Assessment Notice has been received within the statute of limitations period, and the Company believes PTGI will be indemnified by PT Nusantara Regas, the charterer of the NR Satu , for any VAT liability as well as related interest and penalties under the time charter party agreement. Prior to the Mergers, Indonesian tax authorities also issued tax assessments for land and buildings tax to PTGI for the years 2015 to 2019 in relation to the NR Satu , for approximately $ 3,400 (IDR 48,378.3 million ). The Company intends to appeal against the assessments for the land and buildings tax as the tax authorities have not accepted the initial objection letter. The Company believes there are reasonable grounds for success on the basis of no precedent set from past case law and the new legislation effective prospectively from January 1, 2020 , that now specifically lists FSRUs as being an object liable to land and buildings tax, when it previously did not. The assessed tax was paid in January 2020 to avoid further penalties and the payment is presented in Other non-current assets on the condensed consolidated balance sheets. Prior to the Mergers, Jordanian tax authorities concluded their tax audit into GMLP’s Jordan branch for the years 2015 and 2016 assessing additional tax of approximately $ 1,600 (JOD 1.10 million ) and $ 3,100 (JOD 2.20 million ), respectively. The Company has submitted an appeal to the tax notice, and a provision has not been recognized as the Company does not believes that the tax inspector has followed the correct tax audit process and the claim by the tax authorities to not allow tax depreciation is contrary to Jordan’s tax legislation. 21. Earnings per share Three Months Ended September 30, Nine Months Ended September 30 , 2021 2020 2021 2020 Numerator: Net loss $ ( 17,769 ) $ ( 36,670 ) $ ( 59,012 ) $ ( 263,480 ) Less: net (income) loss attributable to non-controlling interests 7,963 312 5,259 81,163 Net loss attributable to Class A common stock ( 9,806 ) ( 36,358 ) ( 53,753 ) ( 182,317 ) Denominator: Weighted-average shares-basic and diluted 207,497,013 170,074,532 195,626,564 85,009,385 Net loss per share - basic and diluted $ ( 0.05 ) $ ( 0.21 ) $ ( 0.27 ) $ ( 2.14 ) The following table presents potentially dilutive securities excluded from the computation of diluted net loss per share for the periods presented because its effects would have been anti-dilutive. September 30, 2021 September 30, 2020 Unvested RSUs (1) 679,909 1,555,363 Shannon Equity Agreement shares (2) 684,962 478,654 Total 1,364,871 2,034,017 (1) Represents the number of instruments outstanding at the end of the period. (2) Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement. The Company declared dividends of $ 17,598 , $ 20,736 and $ 20,750 during the first, second and third quarters of 2021, respectively, representing $ 0.10 per Class A share. The Company paid $ 17,657 , $ 20,670 and $ 20,686 of dividends during the first, second and third quarters of 2021, respectively, inclusive of dividends that were accrued in prior periods . A portion of non-controlling interest includes $ 140,259 attributable to GMLP’s 8.75 % Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). As these equity interests have been issued by the Company’s consolidated subsidiary, the value of the Series A Preferred Units is recognized as non-controlling interest in the condensed consolidated financial statements. After the Mergers, the Company paid a dividend of $ 6,038 to holders of the Series A Preferred Units. 33 Table of Contents 22. Share-based compensation RSUs The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the New Fortress Energy Inc. 2019 Omnibus Incentive Plan. The fair value of RSUs on the grant date is estimated based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model. The following table summarizes the RSU activity for the nine months ended September 30, 2021: Restricted Stock Units Weighted-average grant date fair value per share Non-vested RSUs as of December 31, 2020 1,538,060 $ 13.49 Granted - - Vested ( 818,846 ) 13.45 Forfeited ( 39,305 ) 13.73 Non-vested RSUs as of September 30 , 2021 679,909 $ 13.49 The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three and nine months ended September 30, 2021 and 2020: Three Months Ended September 30, Nine Months Ended September 30 , 2021 2020 2021 2020 Operations and maintenance $ 207 $ 142 $ 641 $ 632 Selling, general and administrative 1,355 1,929 4,304 5,869 Total share-based compensation expense $ 1,562 $ 2,071 $ 4,945 $ 6,501 For the three months ended September 30, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $ 116 and $ 278 , respectively, was reversed . For the nine months ended September 30, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $ 173 and $ 827 , respectively, was reversed. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized. As of September 30, 2021, the Company had 679,909 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $ 2,710 . The non-vested RSUs will vest over a period from ten months to three years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 0.46 years as of September 30, 2021. Performance Share Units (“PSUs”) During the first quarter of 2020 and 2021 , the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting will be determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. As of September 30, 2021, the Company determined that it was not probable that the performance condition required for any of the PSUs to vest would be achieved, and as such, no compensation expense has been recognized in the condensed consolidated statements of operations and comprehensive loss. PSUs Granted Units Granted Range of Vesting Unrecognized Compensation Cost (1) Weighted Average Remaining Vesting Period Q1 2020 1,109,777 0 to 2,219,554 $ 30,467 0.25 years Q1 2021 400,507 0 to 801,014 31,932 1.25 years (1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest. 34 Table of Contents 23. Related party transactions Management services The Company is majority owned by Messrs. Edens (our chief executive officer and chairman of our Board of Directors) and Nardone (one of our Directors) who are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $ 1,352 and $ 1,749 for the three months ended September 30, 2021 and 2020, respectively, and $ 5,073 and $ 5,894 for the nine months ended September 30, 2021 and 2020, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss. As of September 30, 2021 and December 31, 2020, $ 4,264 and $ 5,535 were due to Fortress, respectively. In addition to administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator market rates, charter costs of $ 436 and $ 242 for the three months ended September 30, 2021 and 2020 , respectively, and $ 3,385 and $ 1,526 for the nine months ended September 30, 2021 and 2020. As of September 30, 2021 and December 31, 2020 , $ 598 and $ 472 was due to this affiliate, respectively. Land lease The Company has leased land from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $ 103 during the three months ended September 30, 2021 and 2020, and $ 332 and $ 309 during the nine months ended September 30, 2021 and 2020, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss. As of September 30, 2021 and December 31, 2020, $ 0 and $ 316 was due to FECI, respectively. As of September 30, 2021, the Company has recorded a lease liability of $ 3,305 within Non-current lease liabilities on the condensed consolidated balance sheet. DevTech investment In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10 % interest in a consolidated subsidiary. The 10 % interest is reflected as non-controlling interest in the Company’s condensed consolidated financial statements. DevTech purchased 10 % of a note payable due to an affiliate of the Company. During the third quarter of 2021, the Company settled all outstanding amounts due under notes payable; the consulting agreement was also restructured to settle all previous amounts owed to DevTech and to include a royalty payment based on certain volumes sold in Jamaica. The Company paid $ 988 to settle these outstanding amounts. As of September 30, 2021 and December 31, 2020, $ 0 and $ 715 was owed to DevTech on the note payable; prior to settlement, the outstanding note payable due to DevTech was included in Other long-term liabilities on the condensed consolidated balance sheets. The interest expense on the note payable due to DevTech was $ 0 and $ 19 for the three months ended September 30, 2021 and 2020, respectively, and $ 29 and $ 57 for the nine months ended September 30, 2021 and 2020, respectively. As of September 30, 2021 and December 31, 2020 , $ 0 and $ 343 was due from DevTech. Fortress affiliated entities Since 2017, the Company has provided certain administrative services to related parties including Fortress affiliated entities. As of September 30, 2021 and December 31, 2020, $ 352 and $ 1,334 were due from affiliates, respectively. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred. Beginning in the fourth quarter of 2020, the Company began to sublease a portion of office space to an affiliate of an entity managed by Fortress, and for the three and nine months ended September 30, 2021, $ 201 and $ 595 , respectively, of rent and office related expenses were incurred by this affiliate. As of September 30, 2021 and December 31, 2020, $ 595 and $ 204 were due from this affiliate, respectively. Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative services to the Company, as well as providing office space under a month-to-month non-exclusive license agreement. The Company incurred rent and administrative expenses of approximately $ 571 and $ 808 for the three months ended September 30, 2021 and 2020, respectively, and $ 2,048 and $ 1,657 for the nine months ended September 30, 2021 and 2020. As of September 30, 2021 and December 31, 2020, $ 2,048 and $ 2,657 were due to Fortress affiliated entities, respectively. 35 Table of Contents Agency agreement with PT Pesona Sentra Utama (or PT Pesona) PT Pesona, an Indonesian company, owns 51 % of the issued share capital in the Company’s subsidiary, PTGI, the owner and operator of NR Satu , and provides agency and local representation services for the Company with respect to NR Satu . During the period after the Mergers, PT Pesona did not receive any agency fees. PT Pesona and certain of its subsidiaries charged vessel management fees to the Company for the provision of technical and commercial management of the vessels amounting to $ 61 and $ 187 for the three and nine months ended September 30, 2021, respectively. Hilli guarantees As part of the GMLP Merger, the Company agreed to assume a guarantee (the “Partnership Guarantee”) of 50 % of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. The Company also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under the LTA. Under the LOC Guarantee, the Company is severally liable for any outstanding amounts that are payable, up to approximately $ 19,000 . Subsequent to the GMLP Merger, under the Partnership Guarantee and the LOC Guarantee NFE’s subsidiary, GMLP, is required to comply with the following covenants and ratios: • free liquid assets of at least $ 30 million throughout the Hilli Leaseback period; • a maximum net debt to EBITDA ratio for the previous 12 months of 6.5 :1; and • a consolidated tangible net worth of $ 123.95 million. As of September 30, 2021, the amount the Company has guaranteed under the Partnership Guarantee and the LOC Guarantee is $ 364,500 , and the fair value of debt guarantee after amortization, presented under Other current liabilities and Other non-current liabilities on the condensed consolidated balance sheet, amounted to $ 5,286 and $ 3,549 , respectively. As of September 30, 2021 the Company was in compliance with the covenants and ratios for both Hilli guarantees. 24. Segments As of September 30, 2021, the Company operates in two reportable segments: Terminals and Infrastructure and Ships: • Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. Leased vessels as well as acquired vessels that are utilized in the Company’s terminal or logistics operations are included in this segment. • Ships includes FSRUs and LNG carriers that are leased to customers under long-term or spot arrangements. FSRUs are stationed offshore for customer’s operations to regasify LNG; six of the FSRUs acquired in the Mergers are included in this segment, including the Nanook . LNG carriers are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally. Five of the LNG carriers acquired in the Mergers are included in this segment. The Company’s investment in Hilli LLC is also included in the Ships segment. The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value. Terminals and Infrastructure Segment Operating Margin includes our effective share of revenue, expenses and segment operating margin attributable to our 50 % ownership of CELSEPAR. Ships Operating Margin includes our effective share of revenue, expenses and operating margin attributable to our ownership of 50 % of the common units of Hilli LLC. Management considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance. 36 Table of Contents The table below presents segment information for the three and nine months ended September 30, 2021 and 2020: Three Months Ended September 30, 2021 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships ⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Statement of operations: Total revenues $ 349,140 $ 116,050 $ 465,190 $ ( 160,534 ) $ 304,656 Cost of sales 206,131 - 206,131 ( 70,699 ) 135,432 Vessel operating expenses - 21,210 21,210 ( 5,909 ) 15,301 Operations and maintenance 27,371 - 27,371 ( 7,227 ) 20,144 Segment Operating Margin $ 115,638 $ 94,840 $ 210,478 $ ( 76,699 ) $ 133,779 Balance sheet: Total assets⁽⁵⁾ $ 4,146,251 $ 2,518,836 $ 6,665,087 $ - $ 6,665,087 Other segmental financial information: Capital expenditures⁽⁵⁾ $ 292,982 $ 5,766 $ 298,748 $ - $ 298,748 Nine Months Ended September 30, 2021 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Statement of operations: Total revenues $ 676,372 $ 211,812 $ 888,184 $ ( 214,005 ) $ 674,179 Cost of sales 406,253 - 406,253 ( 72,720 ) 333,533 Vessel operating expenses - 41,385 41,385 ( 10,684 ) 30,701 Operations and maintenance 67,266 - 67,266 ( 12,306 ) 54,960 Segment Operating Margin $ 202,853 $ 170,427 $ 373,280 $ ( 118,295 ) $ 254,985 Balance sheet: Total assets⁽⁵⁾ $ 4,146,251 $ 2,518,836 $ 6,665,087 $ - $ 6,665,087 Other segmental financial information: Capital expenditures⁽⁵⁾ $ 609,533 $ 6,799 $ 616,332 $ - $ 616,332 Three Months Ended September 30, 2020 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Statement of operations: Total revenues $ 136,858 $ - $ 136,858 $ - $ 136,858 Cost of sales 71,665 - 71,665 - 71,665 Vessel operating expenses - - - - - Operations and maintenance 13,802 - 13,802 - 13,802 Segment Operating Margin $ 51,391 $ - $ 51,391 $ - $ 51,391 Balance sheet: Total assets⁽⁵⁾ $ 1,399,813 $ - $ 1,399,813 $ - $ 1,399,813 Other segmental financial information: Capital expenditures⁽⁵⁾ $ 9,128 $ - $ 9,128 $ - $ 9,128 37 Table of Contents Nine Months Ended September 30, 2020 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Statement of operations: Total revenues $ 305,954 $ - $ 305,954 $ - $ 305,954 Cost of sales 209,780 - 209,780 - 209,780 Vessel operating expenses - - - - - Operations and maintenance 31,785 - 31,785 - 31,785 Segment Operating Margin $ 64,389 $ - $ 64,389 $ - $ 64,389 Balance sheet: Total assets⁽⁴⁾ $ 1,399,813 $ - $ 1,399,813 $ - $ 1,399,813 Other segmental financial information: Capital expenditures⁽⁴⁾⁽⁵⁾ $ 90,433 $ - $ 90,433 $ - $ 90,433 ⁽¹⁾ Terminals and Infrastructure includes the Company’s effective share of revenues, expenses and operating margin attributable to 50 % ownership of CELSEPAR. The losses and earnings attributable to the investment of $ 27,792 and $ 655 for the three and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations. Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $ 2,316 for the three and nine months ended September 30, 2021 reported in Cost of sales. ⁽²⁾ Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to 50 % ownership of the Hilli Common Units. The earnings attributable to the investment of $ 11,809 and $ 22,303 for the three months and nine months ended September 30, 2021, respectively, are reported in income (loss) from equity method investments on the condensed consolidated statements of operations and comprehensive loss. ⁽³⁾ Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50 % ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments. ⁽⁴⁾ Total assets and capital expenditure by segment refers to assets held and capital expenditures related to the development of the Company’s terminals and vessels. The Terminals and Infrastructure segment includes the net book value of vessels utilized within the Terminals and Infrastructure segment. ⁽⁵⁾ Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period. Consolidated Segment Operating Margin is defined as net loss, adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, interest expense, other (income) expense, income from equity method investments and tax expense. The following table reconciles Net loss, the most comparable financial statement measure, to Consolidated Segment Operating Margin: Three Months Ended September 30, Nine Months Ended September 30, (in thousands of $) 2021 2020 2021 2020 Net loss $ ( 17,769 ) $ ( 36,670 ) $ ( 59,012 ) $ ( 263,480 ) Add: Selling, general and administrative 46,802 26,821 124,954 87,273 Transaction and integration costs 1,848 4,028 42,564 4,028 Contract termination charges and loss on mitigation sales - - - 124,114 Depreciation and amortization 31,194 9,489 68,080 22,363 Interest expense 57,595 19,813 107,757 50,901 Other (income) expense, net ( 5,400 ) 2,569 ( 13,458 ) 4,179 Loss on extinguishment of debt, net - 23,505 - 33,062 Tax provision 3,526 1,836 7,058 1,949 Loss (income) from equity method investments 15,983 - ( 22,958 ) - Consolidated Segment Operating Margin $ 133,779 $ 51,391 $ 254,985 $ 64,389 38 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, 2020 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in thousands. Unless the context otherwise requires, references to ‘‘Company,’’ ‘‘NFE,’’ ‘‘we,’’ ‘‘our,’’ ‘‘us’’ or similar terms refer to (i) prior to our conversion from a limited liability company to a corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc. and its subsidiaries. Overview We are a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs. We deliver targeted energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading carbon emission-free independent power providing companies. We discuss this important goal in more detail in the Annual Report, “Items 1 and 2: Business and Properties” under “Toward a Carbon-Free Future”. On April 15, 2021, we completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers”. NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interest of GMLP’s general partner, totaling $251 million. The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger. As a result of the Mergers, we acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Facility”) and Santa Catarina, Brazil (the “Santa Catarina Facility”). We acquired the Nanook , a newbuild FSRU moored and in service at the Sergipe Facility. In addition to the Nanook, the we also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (the “Hilli”), which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support our existing facilities and international project pipeline. The majority of the FSRUs are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market. Subsequent to the completion of the Mergers, our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships. Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third party suppliers and from our own liquefaction facility in Miami, Florida. Leased vessels as well as the cost to operate our vessels that are utilized in our terminal or logistics operations are included in this segment. The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico and Brazil, including our interest in the Sergipe Power Plant. 39 Table of Contents Our Ships segment includes all vessels acquired in the Mergers which are leased to customers under long-term or spot arrangements, including the 25 year charter of Nanook with CELSE. The Company’s investment in Hilli LLC, owner and operator of the Hilli , is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire. Our Current Operations – Terminals and Infrastructure Our management team has successfully employed our strategy to secure long-term contracts with significant customers in Jamaica and Puerto Rico, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers. We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our Miami Facility. Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including Fast LNG and our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”). Montego Bay Facility The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay, Jamaica. Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 740,000 gallons of LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users. Old Harbour Facility The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing approximately six million gallons of LNG (500,000 MMBtus) per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the new 190MW Old Harbour power plant (the “Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term PPA. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay SSA. In March 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliver gas to Jamalco to utilize in their gas-fired boilers. San Juan Facility In July 2020, we finalized the development of the San Juan Facility. The San Juan Facility is near the San Juan Power Plant and serves as our supply hub for the San Juan Power Plant and other industrial end-user customers in Puerto Rico. We have delivered natural gas used for the commissioning of PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020. In the third quarter of 2021, commission for Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed under the terms of our agreement with PREPA. See “—Other Matters” for additional information regarding our San Juan Facility. Sergipe Power Plant and Sergipe Facility As part of the Hygo Merger, we acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), which owns Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of the Sergipe Power Plant. The Sergipe Power Plant, a 1.5 GW combined cycle power plant, receives natural gas from the Sergipe Facility through a dedicated 8-kilometer pipeline. The Sergipe Power Plant is the largest natural gas-fired thermal power station in South America and was built to provide electricity on demand, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region. CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant is delivering power to 26 committed offtakers for a period of 25 years. In any period in which power is not being produced pursuant to the PPAs, we are able to sell merchant power into the electricity grid at spot prices, subject to local regulatory approval. We also acquired a 75% interest in Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), which owns rights to expand the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for an incremental 1.7GW of power generation. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. 40 Table of Contents The Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Sergipe Facility is expected to utilize approximately 230,000 MMBtu/d (30% of the facility’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant, at full dispatch. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers. Our Current Operations – Ships Our Ships segment includes six FSRUs and five LNGCs which are leased to customers under long-term or spot arrangements, including a 25-year charter of Nanook with CELSE. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. We began to use one acquired LNGC in our terminal operations in the third quarter of 2021, and the results of operations of this vessel are no longer included in the Ships segment. The Company’s investment in Hilli LLC, owner and operator of the Hilli , is also included in the Ships segment. Hilli Corp, a wholly owned subsidiary of Hilli LLC, has a Liquefication Tolling Agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures under which the Hilli provides liquefaction services through July 2026. Under the LTA, Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil. Our Development Projects La Paz Facility In July 2021 we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, we are supplying CFEnergia with natural gas to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day, and we are in commercial discussions with CFEnergia to increase the volumes and extend the tenor of agreements to further their transition to gas-fired power. Once fully operational, the La Paz Facility is expected to supply approximately an additional 270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW of power supplied by gas-fired modular power units which we have developed, own and will operate once fully operational, which may be increased to approximately 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power. Puerto Sandino Facility Construction of our LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”) is expected to be completed in the fourth quarter of 2021 with commissioning of the power plant expected to begin in the first quarter of 2022. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and our 300 MW natural gas-fired power plant will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day. Suape Facility On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold certain 15-year power purchase agreements totaling 288 MW for the development of the thermoelectric power plants in the State of Bahia, Brazil. We are seeking to obtain the necessary approvals from ANEEL and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics to develop and construct an initial 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil (the “Suape Facility”). Barcarena Facility The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to utilize approximately 92,000 MMBtu/d (12% of the facility’s maximum regasification capacity) to service the Barcarena Power Plant upon commencement of operations. 41 Table of Contents As part of the Mergers, we acquired multiple 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant to be located in Pará, Brazil and to be supplied by the Barcarena Facility (the “Barcarena Power Plant”). The Barcarena Power Plant will utilize LNG sourced and processed at the Barcarena Facility for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019. Santa Catarina Facility The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. We are also developing a 31-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million gallons per day. Sri Lanka Facility In September 2021, we signed an agreement to acquire a 40% ownership stake in West Coast Power Limited (“WCP”), the owner of the 310 MW Yugadanvi Power Plant in Colombo, Sri Lanka. We plan to develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, where 310 MW of power is operational today and an additional 700 MW scheduled to be built, of which 350 MW is scheduled to be operational by 2023. We expect to initially provide the equivalent of an estimated 1.2 million gallons of LNG per day (35,000 MMBtu/d), with the expectation of significant growth as new power plants become operational. Our agreement with WCP is subject to certain conditions precedent, and we expect that these conditions will be finalized in the first half of 2022. Fast LNG We are currently developing a modular floating liquefaction facility to provide a low-cost supply of liquefied natural gas for our growing customer base. The “Fast LNG” design pairs advancements in modular, midsize liquefaction technology with jack up rigs or similar floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels. A permanently moored FSU will serve as an LNG storage facility alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. Recent Developments Cargo Sales Since August 2021, LNG prices have increased materially. We have supply commitments to secure LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. Due to this significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of these cargos in the market, and these sales have positively impacted our results for the third quarter of 2021. We expect to deliver these cargos in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021. COVID-19 Pandemic We are closely monitoring the impact of the novel coronavirus (“COVID-19”) pandemic on all aspects of our operations and development projects, including our marine operations acquired in the Mergers. Customers in our Terminals and Infrastructure segment primarily operate under long-term contracts, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We continue to invoice our customers for fixed minimum volumes even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections. Many of the vessels acquired in the Mergers operate under long-term contracts with fixed payments. We are required to have adequate crewing aboard our vessels to fulfill the obligations under our contracts, and we have implemented safety measures to ensure that we have healthy qualified officers and crew. We monitor local or international transport or quarantine restrictions limiting the ability to transfer crew members off vessels or bring a new crew on board, and restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives, and we have not experienced significant disruptions in our operations due to these measures or restrictions. 42 Table of Contents Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities. For the three months and nine months ended September 30, 2021, we have incurred approximately $0.2 million and $0.6 million, respectively, for safety measures introduced into our operations and other responses to the COVID-19 pandemic. W e are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects, charter or terminal operations from the COVID-19 pandemic; however, there are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures. We do not currently expect these factors to have a significant impact on our results of operations, liquidity or financial position, or our development budgets or timelines. Other Matters On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which is September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit. To date, no other party has sought review of FERC’s orders. While our petitions for review are pending, and in order to comply with the FERC’s directive, on September 15, 2021 we filed an application for authorization to operate the San Juan Facility. 43 Table of Contents Results of Operations – Three and Nine Months Ended September 30, 2021 compared to Three and Nine Months Ended September 30, 2020 Segment performance is evaluated based on segment operating margin and the tables below presents our segment information for the three and nine months ended September 30, 2021 and 2020: Three Months Ended September 30, 2021 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Total revenues $ 349,140 $ 116,050 $ 465,190 $ (160,534 ) $ 304,656 Cost of sales 206,131 - 206,131 (70,699 ) 135,432 Vessel operating expenses - 21,210 21,210 (5,909 ) 15,301 Operations and maintenance 27,371 - 27,371 (7,227 ) 20,144 Segment Operating Margin $ 115,638 $ 94,840 $ 210,478 $ (76,699 ) $ 133,779 Nine Months Ended September 30, 2021 (in thousands of $) Terminals and Infrastructure⁽¹⁾ Ships⁽²⁾ Total Segment Consolidation and Other⁽³⁾ Consolidated Total revenues $ 676,372 $ 211,812 $ 888,184 $ (214,005 ) $ 674,179 Cost of sales 406,253 - 406,253 (72,720 ) 333,533 Vessel operating expenses - 41,385 41,385 (10,684 ) 30,701 Operations and maintenance 67,266 - 67,266 (12,306 ) 54,960 Segment Operating Margin $ 202,853 $ 170,427 $ 373,280 $ (118,295 ) $ 254,985 ⁽¹⁾ Terminals and Infrastructure includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The losses and earnings attributable to the investment of $27,792 and $655 for the three and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations. Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $2,316 for the three and nine months ended September 30, 2021 reported in Cost of sales. ⁽²⁾ Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $11,809 and $22,303 for the three months and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations and comprehensive loss. ⁽³⁾ Consolidation and Other adjust for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments. Terminals and Infrastructure (in thousands of $) Three months ended September 30, 2020 Nine months ended September 30, 2020 Total revenues $ 136,858 $ 305,954 Cost of sales 71,665 209,780 Vessel operating expenses - - Operations and maintenance 13,802 31,785 Segment Operating Margin $ 51,391 $ 64,389 Terminals and Infrastructure Segment Three Months Ended September 30, Nine Months Ended September 30, (in thousands of $) 2021 2020 Change 2021 2020 Change Total revenues $ 349,140 $ 136,858 $ 212,282 $ 676,372 $ 305,954 $ 370,418 Cost of sales 206,131 71,665 134,466 406,253 209,780 196,473 Vessel operating expenses - - - - - - Operations and maintenance 27,371 13,802 13,569 67,266 31,785 35,481 Segment Operating Margin $ 115,638 $ 51,391 $ 64,247 $ 202,853 $ 64,389 $ 138,464 Total revenue 44 Table of Contents Total revenue for the Terminals and Infrastructure Segment increased $212,282 and $370,418 for the three and nine months ended September 30, 2021 as compared to the three months and nine months ended September 30, 2020, respectively. The increase was primarily driven by increases in revenue from the sale of cargos of LNG to third parties outside of our terminal operations and the inclusion of incremental revenue in our segment measure from CELSEPAR after the completion of the Mergers. Our contracts with customers in this segment are primarily priced based on the Henry Hub index, and there have been significant increases in this price index in 2021, positively impacting our revenue. The average Henry Hub index pricing used to invoice our customers increased by 103% and 69% for the three and nine months ended September 2021 as compared to the three and nine months ended September 30, 2020, respectively. Additionally, we recognized additional revenue from more volumes sold to the San Juan Power Plant in Puerto Rico. Revenue from cargo sales outside of our terminal operations was $32,605 for the three and nine months ended September 30, 2021; there were no comparable transactions in the three and nine months ended September 30, 2020. The Old Harbour Facility sold additional volumes in the three and nine months ended September 30, 2021 as compared to the three and nine months ended September 30, 2020, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020. Increases in revenue were further impacted by substantial increases to natural gas pricing. • For the three months ended September 30, 2021, we recognized $62,488 of revenue from volumes sold at the Old Harbour Facility, as compared to $50,064 for the three months ended September 30, 2020, driven primarily by an increase in the Henry Hub index used to invoice our customers when compared to the third quarter of 2020. Volumes consumed at the Old Harbour Power Plant increased by 6.2 million gallons (0.6 TBtu), partially offset by a decrease of 1.5 million gallons (0.2 TBtu) in consumption by Jamalco’s boilers. The Jamalco refinery experienced a fire in August 2021, and no gas volumes have been consumed by their boilers since this event. Volumes delivered to the Old Harbour Power Plant increased to 33.1 million gallons (2.8 TBtu) in the three months ended September 30, 2021 from 26.9 million gallons (2.2 TBtu) in the three months ended September 30, 2020. Volumes delivered to the CHP Plant and Jamalco’s boilers decreased to 27.1 million gallons (2.2 TBtu) in the three months ended September 30, 2021 from 28.6 million gallons (2.4 TBtu) in the three months ended September 30, 2020. • For the nine months ended September 30, 2021, we recognized $170,402 of revenue from volumes sold at the Old Harbour Facility, as compared to $129,313 for the nine months ended September 30, 2020, primarily driven by an increase in the Henry Hub index used to invoice our customers and additional volumes consumed at the Old Harbour Power Plant, CHP Plant and Jamalco’s boilers, which began consuming gas in August 2020. Volumes delivered to the Old Harbour Power Plant increased by 13.5 million gallons (1.2 TBtu) to 91.9 million gallons (7.7 TBtu) in the nine months ended September 30, 2021 from 78.4 million gallons (6.5 TBtu) in the nine months ended September 30, 2020. Volumes delivered to the CHP Plant and Jamalco’s boilers increased by 18.9 million gallons (1.5 TBtu) to 81.3 million gallons (6.7 TBtu) in the nine months ended September 30, 2021 from 62.4 million gallons (5.2 TBtu) in the nine months ended September 30, 2020. • Revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco was $7,237 and $21,567 for the three and nine months ended September 30, 2021, respectively, as compared to $7,280 and $15,957 in revenue for the three and nine months ended September 30, 2020, respectively. After the fire at the Jamalco refinery, we did not deliver any steam to Jamalco. However, steam revenue was consistent in the third quarter of 2021 with previous periods as our contract with Jamalco has take-or-pay provisions that allow us to invoice for minimum volumes. Revenue was also impacted by operations at our Montego Bay Facility. • Sales at the Montego Bay Facility increased by $4,298 from $23,515 for the three months ended September 30, 2020 to $27,813 for the three months ended September 30, 2021. The increase in sales at the Montego Bay Facility was due to an increase in the Henry Hub index used to invoice our customers compared to the third quarter of 2020. Volumes delivered at the Montego Bay Facility remained relatively consistent for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020, decreasing by 0.1 million gallons (0.0 TBtu) from 23.9 million gallons (2.0 TBtu) during the three months ended September 30, 2020 to 23.8 million gallons (2.0 TBtu) during the three months ended September 30, 2021. • Sales at the Montego Bay Facility increased by $10,103 from $69,072 for the nine months ended September 30, 2020 to $79,175 for the nine months ended September 30, 2021. The increase in sales at the Montego Bay Facility was primarily due to an increase in the Henry Hub index used to invoice our customers compared to the first nine months of 2020. Volumes delivered at the Montego Bay Facility increased by 1.9 million gallons (0.2 TBtu) from 70.5 million gallons (5.9 TBtu) during the nine months ended September 30, 2020 to 72.4 million gallons (6.1 TBtu) during the nine months ended September 30, 2021. 45 Table of Contents We also recognize revenue from development services for the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our power generation facilities. Such services are provided under certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Natural gas delivered to the San Juan Power Plant was recognized as revenue from development services, until commissioning of Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed in the third quarter of 2021. After this point, all natural gas delivered to the San Juan Power Plant was recognized as operating revenue. • Sales at the San Juan Power Plant increased by $24,087 from $51,974 for the three months ended September 30, 2020 to $76,061 for the three months ended September 30, 2021. The increase was driven by additional volumes consumed at the San Juan Power Plant. Volumes delivered to the San Juan Power Plant increased by 13.0 million gallons (1.0 TBtu) to 71.6 million gallons (5.8 TBtu) in the three months ended September 30, 2021 from 58.6 million gallons (4.8 TBtu) in the three months ended September 30, 2020. • Sales at the San Juan Power Plant increased by $108,263 from $68,458 for the nine months ended September 30, 2020 to $176,721 for the nine months ended September 30, 2021. The increase was driven by additional volumes consumed at the San Juan Power Plant, as our San Juan Facility was not completed until July 2020. Volumes delivered to the San Juan Power Plant increased by 88.0 million gallons (7.1 TBtu) to 165.9 million gallons (13.5 TBtu) in the nine months ended September 30, 2021 from 77.9 million gallons (6.4 TBtu) in the nine months ended September 30, 2020. Subsequent to the acquisition of our interest in the Sergipe Facility as part of the Mergers, our share of revenue from our investment in CELSEPAR was $134,523 and $166,292 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of fixed capacity payments received under our PPAs. Revenue recognized from the operation of the Sergipe Power Plant was significantly increased in the third quarter of 2021 by emergency dispatch due to poor hydrological conditions in Brazil during the third quarter. Our proportionate share of revenue from the Sergipe Facility is included in this discussion as such revenue is included in our segment measure; in our consolidated statement of operations and comprehensive loss, we report the results from our investment in CELSEPAR as Income (loss) from equity method investments. Cost of sales Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities, power generation facilities or to our customers. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales. Cost of sales increased $134,466 and $196,473 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020, respectively. • Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $44,581 for the three months ended September 30, 2021, respectively as compared to the three months ended September 30, 2020. The increase was primarily attributable to a 15% increase in volumes delivered compared to the three months ended September 30, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020 to $0.58 per gallon ($6.98 per MMBtu) for the three months ended September 30, 2021. • Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $87,852 for the nine months ended September 30, 2021, respectively as compared to the nine months ended September 30, 2020. The increase was primarily attributable to a 42% increase in volumes delivered compared to the nine months ended September 30, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.51 per gallon ($6.13 per MMBtu) for the nine months ended September 30, 2020 to $0.54 per gallon ($6.58 per MMBtu) for the nine months ended September 30, 2021. • Cost of LNG from the sale of cargos in the market were $18,191 for the three and nine months ended September 30, 2021 as compared to $0 for the three and nine months ended September 30, 2020. Since August 2021, due to the significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market. The weighted-average cost of LNG from the sale of a portion of our cargos was $0.69 per gallon ($8.33 per MMBTU) for the three and nine months ended September 30, 2021. 46 Table of Contents • Subsequent to the acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Cost of sales from our investment in CELSEPAR was $73,015 and $75,042 for the three and nine months ended September 30, 2021, respectively, which was comprised of LNG costs to fuel the power plant and costs of power to fulfill requirements under the PPAs. The weighted-average cost of our LNG inventory balance to be used in our Jamaican and Puerto Rican operations as of September 30, 2021 and December 31, 2020 was $0.64 per gallon ($7.71 per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively. Charter costs decreased Cost of sales by $2,901 for the three months ended September 30, 2021. As a result of the Mergers, we have effectively settled our charter agreement for the Freeze , one of the acquired vessels, and as such, the decrease in charter costs was attributable to the lower costs associated with the Freeze . Charter costs increased Cost of sales by $3,441 for the nine months ended September 30, 2021, respectively. The increase was attributable to an additional vessel in our fleet associated with our San Juan Facility after our assets were placed in service in the third quarter of 2020, as well as an additional vessel lease that we assumed as part of the Mergers. These increases were partially offset by lower costs associated with the Freeze . Operations and maintenance Operations and maintenance includes costs of operating our Facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance increased $13,569 and $35,481 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. • Subsequent to acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Operations and maintenance from our investment in CELSEPAR was $7,227 and $12,306 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of costs related to the operation and services agreement for the Nanook , insurance costs and costs for connecting to the transmission system. • The increase for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020 was primarily the result of costs of operating the San Juan Facility and CHP Plant and higher payroll costs, maintenance costs, insurance costs and port fees; these additional costs were $8,878. • The increase for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 was primarily the result of San Juan Facility and the CHP Facility that were still in development during a portion of the nine months ended September 30, 2020. Operations and maintenance increased by the costs of operating the San Juan Facility and CHP Plant of $10,732. We also incurred $13,092 of payroll costs, maintenance costs, insurance costs and port fees. Ships Segment Three Months Nine Months (in thousands of $) Ended September 30, 2021 Ended September 30, 2021 Total revenues $ 116,050 $ 211,812 Vessel operating expenses 21,210 41,385 Segment Operating Margin $ 94,840 $ 170,427 Prior to the completion of the Mergers, we reported our results of operations in a single segment; all the assets and operations that comprise the Ships segment were acquired in the Mergers, and as such, there are no results of operations prior to the completion of the Mergers during the second quarter of 2021, and the results of operations for the Ships segment for the nine months ended September 30, 2021 represents five and a half months of operations . Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for repositioning vessels as well as the reimbursement of certain vessel operating costs. We have also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook . 47 Table of Contents Subsequent to the completion of the Mergers, five of the FSRUs and one LNGCs were on hire under long-term charter agreements for the full period. Two LNGCs were operating in the spot market for a portion of the period subsequent to the completion of the Mergers through June 30, 2021. In the third quarter, one of these LNGCs, the Grand, began to be utilized in our terminal and logistics operations, and as such, the results of operations of the Grand are included in the Terminals and Infrastructure segment in the third quarter of 2021. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels. Two of the vessels acquired in the Mergers, the Celsius and the Penguin , have participated in a pooling arrangement, which we refer to as the Cool Pool. Under this arrangement, the pool manager markets participating vessels in the LNG shipping spot market, and the vessel owner continues to be fully responsible for the manning and technical management of their respective vessels. Revenue for charters of our vessels in the Cool Pool is presented on a gross basis in revenue, and our allocation of our share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses. The Penguin exited the Cool Pool in the third quarter of 2021, and we have chartered this vessel to a third party outside of the Cool Pool. For the three and nine months ended September 30, 2021, revenue recognized in the Ships segment included $11,607 and $21,288 of interest income for the Nanook sales-type lease and $1,491 and $2,656 of revenue for operating services, respectively, provided to CELSE. As all operations of the Ships segment were acquired in the Mergers, the results of operations for the Nanook for the nine months ended September 30, 2021 represents five and a half months of operations . Our segment measure includes our proportionate share of the results of operations of the Hilli . Our share of revenue from our investment in Hilli LLC was $26,011 and $47,758 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of fees received under the long-term tolling arrangement. The Hilli maintained 100% commercial uptime during the period subsequent to the Mergers. Vessel operating expenses Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and management fees . We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location , the estimated voyage expenses are recognized over the term of the time charter. For the three and nine months ended September 30, 2021, we recognized $21,210 and $41,385, respectively, in Vessel operating expenses. As all operations of the Ships segment were acquired in the Mergers, Vessel operating expenses for the nine months ended September 30, 2021 represents five and a half months of operations of each of the acquired vessels. 48 Table of Contents Other operating results Three Months Ended September 30, Nine Months Ended September 30, (in thousands of $) 2021 2020 Change 2021 2020 Change Selling, general and administrative $ 46,802 $ 26,821 $ 19,981 $ 124,954 $ 87,273 $ 37,681 Transaction and integration costs 1,848 4,028 (2,180 ) 42,564 4,028 38,536 Contract termination charges and loss on mitigation sales - - - - 124,114 (124,114 ) Depreciation and amortization 31,194 9,489 21,705 68,080 22,363 45,717 Total operating expenses 250,721 125,805 124,916 654,792 479,343 175,449 Operating income (loss) 53,935 11,053 42,882 19,387 (173,389 ) 192,776 Interest expense 57,595 19,813 37,782 107,757 50,901 56,856 Other (income) expense, net (5,400 ) 2,569 (7,969 ) (13,458 ) 4,179 (17,637 ) Loss on extinguishment of debt, net - 23,505 (23,505 ) - 33,062 (33,062 ) Net income (loss) before income from equity method investments and income taxes 1,740 (34,834 ) 36,574 (74,912 ) (261,531 ) 186,619 (Loss) income from equity method investments (15,983 ) - (15,983 ) 22,958 - 22,958 Tax provision 3,526 1,836 1,690 7,058 1,949 5,109 Net loss $ (17,769 ) $ (36,670 ) $ 18,901 $ (59,012 ) $ (263,480 ) $ 204,468 Selling, general and administrative Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors and screening costs associated with development activities for projects that are in initial stages and development is not yet probable. Selling, general and administrative increased $19,981 for the three months ended September 30, 2021, as compared to the three months ended September 30, 2020. The increase was primarily attributable to $10,558 of higher payroll costs associated with increased headcount for the three months ended September 30, 2021. Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees, professional services, and other costs attributable to our expanded operations of $6,076. Selling, general and administrative increased $37,681 for the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020. The increase was primarily attributable to $21,451 of higher payroll costs associated with increased headcount for the nine months ended September 30, 2021. Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees, professional services, and other costs attributable to our expanded operations of $14,875. Transaction and integration costs Transaction and integration costs decreased $2,180 and increased $38,536 for the three and nine months ended September 30, 2021, as compared to the three and nine months ended September 30, 2020, respectively. For the three months ended September 30, 2021, we incurred $1,848 in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs. For the nine months ended September 30, 2021, we incurred $42,564 for transaction and integration costs. As part of arranging financing for the Mergers, we incurred $15,000 in bridge financing commitment fees. We issued the 2026 Notes to pay for a portion of the consideration for the Mergers and did not utilize the commitments under the bridge financing, and as such, the fees were expensed with the termination of the bridge financing commitment letter in the second quarter of 2021. We also incurred $3,978 of costs related to the settlement of a contractual indemnification obligation under a pre-existing lease arrangement prior to the GMLP Merger. The remaining transaction and integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs. For the three and nine months ended September 30, 2020, we incurred $4,028 of third-party fees associated with a new credit agreement that was accounted for as a modification. Contract termination charges and loss on mitigation sales 49 Table of Contents Loss on mitigation sales for the three and nine months ended September 30, 2020 was $0 and $124,114, respectively. In June 2020, we executed an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of $105,000, and we recognized this cancellation charge during the three months ended June 30, 2020. We terminated our obligation in the second quarter of 2020 to both take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs. Additionally, in the second quarter of 2020, we experienced lower than expected consumption by some of our customers, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica. As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was recognized during the second quarter of 2020. We did not have such transactions during the three and nine months ended September 30, 2021. Depreciation and amortization Depreciation and amortization increased $21,705 and $45,717 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to the following: • Subsequent to the completion of the Mergers, our results of operations include depreciation expense primarily for the vessels acquired. We recognized $13,691 and $25,100 of incremental depreciation expense for the acquired vessels during the three and nine months ended September 30, 2021 as compared to the same periods in the prior year; • Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $6,779 and $12,128 for the three and nine months ended September 30, 2021, respectively; • Increase in depreciation of $427 and $5,229 for the San Juan Facility that went into service in July 2020 for the three and nine months ended September 30, 2021, respectively; and • Increase in depreciation of $2,297 for the CHP Plant that went into service in March 2020 for the nine months ended September 30, 2021. Interest expense Interest expense increased by $37,782 and $56,856 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2025 Notes in September 2020, the 2026 Notes in April 2021, draws on the Revolving Facility in the second and third quarters of 2021, borrowings under the Vessel Term Loan Facility and the CHP Facility (all defined below); principal outstanding on outstanding facilities was $3,888,894 as of September 30, 2021 as compared to total outstanding debt of $1,000,000 as of September 30, 2020. In conjunction with the Mergers, we assumed outstanding debentures issued by a subsidiary of Hygo and the outstanding debt of variable interest entities (“VIEs”) that are now consolidated in our financial statements, totaling $630,563 as of the acquisition date. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the condensed consolidated financial statements. Upon assumption of the debt held by VIEs, we recognized the liabilities assumed at fair value and amortization of the discount from carrying value has been recorded as additional interest expense. For the three months and nine months ended September 30, 2021, we recognized additional interest expense attributable to assumed debt of $15,263 and $8,628, respectively. Other (income) expense, net Other (income) expense, net increased by $7,969 and $17,637 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020. The increase was primarily due to the following:: • Gains in investments in equity securities compared to losses in the same periods in 2020, contributing $7,335 and $9,640 for the three and nine months ended September 30, 2021, respectively; • Increase from the reduction in losses resulting from the fair value of derivative liabilities and equity agreement associated with payments due to sellers in asset acquisitions of $2,737 and $3,156, for the three and nine months ended September 30, 2021, respectively; and 50 Table of Contents • Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulting in expense of $4,278 and additional income of $2,081, for the three and nine months ended September 30, 2021, respectively. Loss on extinguishment of debt, net Loss on extinguishment of debt for the three and nine months ended September 30, 2020 was $23,505 and $33,062, respectively, as a result of the extinguishment of previous credit facilities in January 2020 and September 2020. We did not have such transactions during the three and nine months ended September 30, 2021. Tax provision We recognized a tax provision for the three and nine months ended September 30, 2021 of $3,526 and $7,058, respectively, compared to tax provision of $1,836 and $1,949 for the three and nine months ended September 30, 2020, respectively. The increases to the tax provision and effective tax rate for both the three and nine months ended September 30, 2021 was primarily driven by an increase in pre-tax income in certain profitable non-U.S. operations and the inclusion of operations of certain jurisdictions of acquired business. For the nine months ended September 30, 2021, these increases in tax expense were partially offset by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $1,800. Income from equity method investments During the period after the completion of the Mergers, we recognized losses and income from our investments in Hilli and CELSEPAR of $(15,983) and $22,958 for the three and nine months ended September 30, 2021, respectively. Our proportionate share of the losses and earnings of $(7,101) and $37,614, respectively, were offset by amortization of basis differences through our equity earnings of $8,882 and $14,656 for the three and nine months ended September 30, 2021, respectively. During the period after the Mergers, our share of earnings from CELSEPAR was significantly impacted by a foreign currency remeasurement loss of $17,709 for the three months ended September 30, 2021 and a gain of $8,067 for the nine months ended September 30, 2021, primarily as a result of the remeasurement of the Nanook finance lease obligation. Factors Impacting Comparability of Our Financial Results Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons: • Our historical financial results include the results of operations of Hygo and GMLP only since the completion of the Mergers in April 2021 and do not include all integration and transaction costs expected to be incurred associated with these acquisitions. Upon completion of the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an interest in a floating liquefaction vessel. We also acquired the Sergipe Facility, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Facility and the Santa Catarina Facility that are currently in development. The results of operations of Hygo and GMLP began to be included in our financial statements upon the closing of the acquisitions on April 15, 2021. Our results of operations in 2021 will also include transaction costs associated with these acquisitions as well as costs incurred to integrate the operations of Hygo and GMLP into our business, which may be significant. • Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the three and nine months ended September 30, 2021 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We are finalizing development of our La Paz Facility and Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects. Our current results also exclude other developments, including the Suape Facility, the Barcarena Facility, the Santa Catarina Facility and the Ireland Facility. 51 Table of Contents • Our historical financial results do not reflect new LNG supply agreements that will lower the cost of our LNG supply through 2030. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the three and nine months ended September 30, 2021, respectively, a significant portion of which is under an LNG supply agreement signed in 2018. During 2020 and 2021, we also entered into LNG supply agreements for the purchase of approximately 601 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. We have now secured supply for LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. We also anticipate that the deployment of Fast LNG floating liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third party suppliers. Since August 2021, LNG prices have increased materially. Due to this significant increase in market pricing of LNG, we have used flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021. Liquidity and Capital Resources We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities and cash generated from operations. We may also elect to generate additional liquidity through future debt or equity issuances to fund developments and transactions. We have historically funded our developments through proceeds from our IPO and debt and equity financing, most recently as follows: • In January 2020, we borrowed $800,000 under a credit agreement, and repaid our prior term loan facility in full. • In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025. • In December 2020, we received proceeds of $263,125 from the issuance of $250,000 of additional notes on the same terms as the 2025 Notes (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). • In December 2020, we issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs. • In April 2021, we issued $1,500,000 of 2026 Notes; we also entered into the $200,000 Revolving Facility that has a term of approximately five years. • In August 2021, we entered into the CHP Facility (defined below) and initially drew $100,000, which may be increased to $285,000. • In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility (defined below). Under this facility, we borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. We have assumed total committed expenditures for all completed and existing projects to be approximately $1,663 million, with approximately $1,154 million having already been spent through September 30, 2021. This estimate represents the committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Suape Facility, the Barcarena Facility and the Santa Catarina Facility, as well committed expenditures to serve new industrial end-users. We expect to be able to fund all such committed projects with a combination of cash on hand, cash flows from operations, proceeds from the financing of the CHP Plant and borrowings under our Revolving Facility. We may also enter into other financing arrangements to generate proceeds to fund our developments. Through September 30, 2021, we have spent approximately $ 128 million to develop the Pennsylvania Facility. Approximately $22 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106 million, has been capitalized, and to date, we have repurposed approximately $17 million of engineering and equipment to our Fast LNG project. 52 Table of Contents Cash Flows The following table summarizes the changes to our cash flows for the nine months ended September 30, 2021 and 2020, respectively: Nine Months Ended September 30, (in thousands) 2021 2020 Change Cash flows from: Operating activities $ (139,687 ) $ (115,710 ) $ (23,977 ) Investing activities (2,031,158 ) (115,704 ) (1,915,454 ) Financing activities 1,874,149 291,816 1,582,333 Net (decrease) increase in cash, cash equivalents, and restricted cash $ (296,696 ) $ 60,402 $ (357,098 ) Cash used in operating activities Our cash flow used in operating activities was $139,687 for the nine months ended September 30, 2021, which increased by $23,977 from $115,710 for the nine months ended September 30, 2020. Our net loss for the nine months ended September 30, 2021, when adjusted for non-cash items, decreased by $111,484 from the nine months ended September 30, 2020. The reduction to the net loss was offset by changes in working capital accounts, primarily significant increases in receivables, inventory and accrued liabilities, including costs attributable to the Mergers. Cash used in investing activities Our cash flow used in investing activities was $2,031,158 for the nine months ended September 30, 2021, which increased by $1,915,454 from $115,704 for the nine months ended September 30, 2020. Cash used for the Mergers, net of cash acquired was $1,586,042. Cash outflows for investing activities during the nine months ended September 30, 2021 were also used for continued development of the Puerto Sandino Facility, Suape Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution. During the nine months ended September 30, 2020, we completed the CHP Plant and were in the final stages of development of the San Juan Facility, and as such, we incurred lower cash outflows for investing activities for the nine months ended September 30, 2020. Cash provided by financing activities Our cash flow provided by financing activities was $1,874,149 for the nine months ended September 30, 2021, which increased by $1,582,333 from cash provided by financing activities of $291,816 for the nine months ended September 30, 2020. Cash provided by financing activities during the nine months ended September 30, 2021 was due to proceeds received from the borrowings under the 2026 Notes of $1,500,000, the draw of $200,000 on the Revolving Facility, and the draw of $430,000 million on the Vessel Term Loan Facility. The proceeds received were further offset by financing fees paid in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the nine months ended September 30, 2021. Cash flow provided by financing activities during the nine months ended September 30, 2020 were primarily consisted of proceeds received from the borrowings under the 2025 Notes of $1,000,000 and the borrowings under our previous credit agreement of $800,000, partially offset by an original issue discount of $20,000 and financing fees. Additionally, the remaining proceeds from secured bonds issued in Jamaica of $52,144 were received during the first quarter of 2020. A portion of these proceeds was used to fund the repayment of our previous credit agreement of $800,000, the senior secured and unsecured bonds that had been issued in Jamaica of $183,600, and our previous term loan facility of $506,402. Long-Term Debt and Preferred Stock 2025 Notes On September 2, 2020, we issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions. 53 Table of Contents We used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses. In connection with the issuance of the 2025 Notes, we incurred $17,937 in origination, structuring and other fees. Issuance costs of $13,909 were deferred as a reduction of the principal balance of the 2025 Notes on the condensed consolidated balance sheets; unamortized deferred financing costs related to lenders in the previously credit agreement that participated in the 2025 Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the previous credit agreement was a modification, in the third quarter of 2020, the Company recorded $4,028 of third-party fees as an expense in the condensed consolidated statements of operations and comprehensive loss. On December 17, 2020, we issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,566. As of September 30, 2021 and December 31, 2020, remaining unamortized deferred financing costs for the 2025 Notes was $9,323 and $10,439, respectively. 2026 Notes On April 12, 2021, we issued $1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as our existing first lien obligations under the 2025 Notes. We used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses. In connection with the issuance of the 2026 Notes, we incurred $24,588 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $22,362. Vessel Term Loan Facility On September 18, 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”). Under this facility, the Company borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. Loans under the Vessel Term Loan Facility bear interest at a rate of LIBOR plus a margin of 3 percent. The Vessel Term Loan Facility shall be repaid in quarterly installments of $15,357, with the final repayment date in September 2024. Quarterly principal payments will be increased to reflect any upsize of the Vessel Term Loan Facility to reflect a straight-line amortization profile over the remaining term. Obligations under the Vessel Term Loan Facility are guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. The Company may prepay outstanding indebtedness without penalty, and certain events, such as (i) total loss; (ii) minimum security value; (iii) the sale or transfer of certain vessels; or (iv) the termination of the charter over the Hilli, will require a mandatory prepayment. 54 Table of Contents The Vessel Term Loan Facility contains customary representations and warranties and customary affirmative and negative covenants, including financial covenants, chartering restrictions, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness and dividends and other distributions. Financial covenants include requirements that GMLP and Golar Partners Operating LLC maintain a certain amount of Free Liquid Assets, that the EBITDA to Consolidated Debt Service and the Net Debt to EBITDA ratios are no less than 1.15:1 and no greater than 6.50:1, respectively, and that Consolidated Net Worth is greater than $250,000, each as defined in the Vessel Term Loan Facility. The Company was in compliance with these covenants as of September 30, 2021. In connection with the closing the Vessel Term Loan Facility, we incurred $6,229 in origination, structuring and other fees, which were deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $6,161. Debenture Loan As part of the Mergers, we assumed non-convertible Brazilian debentures issued by NFE Brasil , our indirect subsidiary, in the aggregate principal amount of BRL 255.6 million ($45 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debenture Loan”). The Debenture Loan was recognized at fair value of $44,566 on the date of the Mergers, and the discount recognized in purchase accounting will result in additional interest expense until maturity. Interest and principal is payable on the Debenture Loan semi-annually on September 13 and March 13. The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares issued by NFE Brasil owned by our consolidated subsidiary, LNG Power Ltd. CHP Facility On August 3, 2021, NFE South Power Holdings Limited, a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”). We initially drew $100,000 under the CHP Facility, and the CHP Facility is secured by our combined heat and power plant in Clarendon, Jamaica. We incurred $3,651 in origination, structuring and other fees associated with entry into the CHP Facility, which was deferred as a reduction of the principal balance of the CHP Facility on the condensed consolidated balance sheets. As of September 30, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,636. Revolving Facility On April 15, 2021, we entered into a $200,000 senior secured revolving facility (the “Revolving Facility”). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). Letters of credit issued under the $100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for us to extend the maturity date once in a one-year increment. Borrowings under the Revolving Facility bear interest at a per annum rate equal to LIBOR plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and LIBOR plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0.00% LIBOR floor. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium. The obligations under the Revolving Facility are guaranteed by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as our existing first lien obligations under the 2025 Notes. The Revolving Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. Financial covenants include requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility). The Company was in compliance with these covenants as of September 30, 2021. We incurred $3,974 in origination, structuring and other fees, associated with entry into the Revolving Facility. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of September 30, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,658. During the second and third quarters of 2021, the Company drew $152,500 and $47,500 on the Revolving Facility, respectively. During the third quarter of 2021, the Company repaid the amounts outstanding on the Revolving Facility, and as of September 30, 2021, no amounts remain outstanding. 55 Table of Contents SPV Leasebacks and Loans We assumed sale leaseback arrangements for four vessels as part of the Mergers. The counterparty to each of the sale leaseback arrangements is a special purpose vehicle (“SPV”) wholly owned by financial institutions. The sale leasebacks with SPVs were funded by loan facilities obtained by the SPV. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of the SPVs and consolidate the SPVs. Therefore, the effects of the sale leaseback arrangements are eliminated upon consolidation of the SPVs and only the outstanding loan facilities are presented as part of our condensed consolidated financial statements. The SPVs service the loan facilities through payments made by us under the sale leaseback arrangements. The SPV loans and the sale leaseback arrangements assumed in the Mergers contain certain operating and financing restrictions and covenants that require: (a) certain subsidiaries to maintain a minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70:1. As of September 30, 2021, the Company was in compliance with all covenants under debt and lease agreements. Eskimo Leaseback and Credit Facility As part of the Mergers, we have assumed obligations under a sale and leaseback of the Eskimo with Sea 23 Leasing Co. Limited of China Merchants Bank Leasing (the “Eskimo Leaseback”). Payments are due monthly in 120 installments of $1,069 along with amounts owed for interest of LIBOR plus 3.85%, with a balloon payment of $128,250 due upon maturity. Sea 23 Leasing Co. Limited , the owner of the Eskimo , has a long-term loan facility that is denominated in USD, has a loan term of ten years and bears interest at a rate of LIBOR plus a margin of 2.66% (the “Eskimo SPV Facility”). As of the acquisition date of GMLP, the outstanding principal balance was $160,520, and we recognized the fair value of this facility of $158,072 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity. Nanook Leaseback and Credit Facility As part of the Mergers, we have assumed obligations under a sale and leaseback of the Nanook with Compass Shipping 23 Corporation Limited (the “Nanook Leaseback”). Payments are due quarterly in 48 installments of $2,943 along with amounts owed for interest due based on LIBOR plus 3.5%, with a balloon payment of approximately $94,000 upon maturity. Compass Shipping 23 Corporation Limited, the owner of the Nanook , has a long-term loan facility that is denominated in USD, has a loan term of twelve years, bears interest at a fixed rate of 2.7% (the “Nanook SPV Facility”) and is repayable in a balloon payment on maturity. As of the acquisition date, the outstanding principal balance was $202,249, and we recognized the fair value of this facility of $201,484 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity. Penguin Leaseback and Credit Facility As part of the Mergers, we have assumed obligations under a sale and leaseback of the Penguin with Oriental LNG 02 Limited (the “Penguin Leaseback”). Payments are due quarterly in 24 installments of $1,890 along with amounts owed for interest due based on LIBOR plus 3.6%, with a balloon payment of approximately $63,000 upon maturity. Oriental Fleet LNG 02 Limited, the owner of the Penguin , has a long-term loan facility that is denominated in USD, is repayable in quarterly installments over a term of approximately six years and bears interest at LIBOR plus a margin of 1.7%. The SPV also has amounts payable to its parent. As of the acquisition date, the outstanding principal balance was $104,882, and we recognized the fair value of this facility and the amount due to the parent of $105,126 on the date of the Mergers. The premium recognized in purchase accounting will result in a reduction to interest expense until maturity. Celsius Leaseback and Credit Facility As part of the Mergers, we have assumed obligations under a sale and leaseback of the Celsius with Noble Celsius Shipping Limited (the “Celsius Leaseback”). Payments are due quarterly in 28 installments of $2,679 in addition to amounts owed for interest based on LIBOR plus 3.9%, with a balloon payment of approximately $45,000 upon maturity. Noble Celsius Shipping Limited, the owner of the Celsius , has a long-term loan facility that is denominated in USD, $76,179 of which is repayable in quarterly installments over a term of approximately seven years with a balloon payment of $37,179 at maturity and bears interest at LIBOR plus a margin of 1.8%. The SPV has another facility with its parent for the remaining principal of $45,200, which is due as a balloon payment upon maturity in March 2023 and bears interest at a fixed rate of 4.0%. As of the acquisition date, the total outstanding principal balance was $121,379, and we recognized the fair value of these facilities of $121,308 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity. 56 Table of Contents Series A Preferred Units The 8.75% Series A Cumulative Redeemable Preferred Units issued by GMLP (the “Series A Preferred Units”) remained outstanding following the GMLP Merger and were recognized as non-controlling interest on the condensed consolidated balance sheets. Distributions on the Series A Preferred Units are payable out of amounts legally available therefor at a rate equal to 8.75% per annum of the stated liquidation preference. In the event of a liquidation, dissolution or winding up, whether voluntary or involuntary, holders of Series A Preferred Units will have the right to receive a liquidation preference of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of payment, whether declared or not. At any time on or after October 31, 2022, the Series A Preferred Units may be redeemed, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not. Debt obligations of equity method investees We account for the investments in CELSEPAR and Hilli LLC acquired in the Mergers under the equity method of accounting. The debt obligations of these entities are not reported separately in our consolidated financial statements, and the following discussion summarizes the key terms of each entity’s obligations. Sergipe Debt Financing To finance construction of the Sergipe Facility and the Sergipe Power Plant, CELSE signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 (the “CELSE Facility”). As of September 30, 2021, amounts outstanding and the effective interest rates under the CELSE Facility were as set forth below. Principal and interest payments are due each October and April. The CELSE Facility matures in April 2032. Credit facility ( Real and USD in millions) Amount Outstanding Effective interest rate IFC R$ 927.7($171.4) 10.2 % Inter-American Development Bank R$ 766.9($141.7) 10.0 % IDB Invest (1) $ 37.4 5.6 % IDB China Fund $ 49.2 5.6 % CELSE also issued debentures in the aggregate principal amount of R$3,370.0 million (net proceeds of $897.2 million as of the issuance date), due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”). As of September 30, 2021, the balance of the CELSE Debentures was R$3,324.02 million ($614.0 million as of September 30, 2021). Interest is payable on the CELSE Debentures semi-annually on each April 15 and October 15, beginning on October 15, 2018. The CELSE Debentures are amortized and repaid in 24 consecutive semi-annual installments on each of April 15 and October 15, that commenced on October 15, 2020. The indenture governing the CELSE Debentures contains covenants that: (i) requires CELSE to maintain a historical debt service coverage ratio for a twelve month period on or after March 31, 2021 of no less than 1.10 to 1.00; (ii) prohibit certain restricted payments; (iii) limit the ability of CELSE from creating any liens or incurring additional indebtedness; (iv) prohibit certain fundamental changes; (v) limit the ability of CELSE to transfer or purchase assets; (vi) prohibit certain affiliate transactions; (vii) limit the ability of CELSE to make change orders or give other directions under the documents related to the construction and operation of the project in certain circumstances; (viii) limit the ability of CELSE to enter into additional contracts; (ix) limit CELSE’s operating expenses and capital expenditures; and (x) prohibit CELSE from transferring, purchasing or otherwise acquiring any portion of the CELSE Debentures, other than pursuant to the exercise of the put option. On July 2, 2021, CELSE successfully completed a consent solicitation to amend certain provisions of the financing documents to permit CELSE to incur certain debt related to the working capital facility described below and to release certain existing security over the variable revenues to be received by CELSE under its power purchase agreements. CELSEPAR has entered into a Standby Guarantee and Credit Facility Agreement with GE Capital EFS Financing, Inc. (“GE Capital”), as lender, and Ebrasil Energia Ltda. (“Ebrasil”) and NFE Power Brasil Participações S.A (“NFE Brazil”), each as sponsor (the “GE Credit Facility”). Pursuant to the GE Credit Facility, GE Capital agreed to provide $120,000 in credit support in respect of CELSEPAR’s obligation to make certain contingent equity contributions to CELSE. Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate of LIBOR plus a margin of 11.4% and are payable on May 30 and November 30 each year, beginning on May 30, 2020. All interest due to date has been capitalized into the principal balance, and there have been no principal payments paid to date. The GE Credit Facility matures on November 30, 2024. The GE Credit Facility includes covenants and events of default that are customary for similar transactions. 57 Table of Contents On July 9, 2021, CELSE and CELSEPAR entered into a working capital facility for the posting of certain letters of credit in favor of the supplier of LNG and the financing of LNG costs to satisfy dispatch requirements prior to receiving related variable revenues. The working capital facility is in an aggregate amount of up to $200.0 million (or its equivalent in Reais). The facility has a term of 12 months, renewable for equal periods by mutual agreement of the parties. Amounts disbursed under the working capital facility accrue interest at a rate of (i) DI Rate + 3.50% per year in respect of a bank credit bill, (ii) 2.50% per year for standby letters of credit, (iii) DI Rate + 3.50% per year in respect of any import financing (FINIMP) modality, and (iv) DI Rate + 3.50% per year for any bank loan. The DI Rate is made by reference to Libor+, according to the pricing at the time of request. On July 9, 2021, a standby letter of credit was issued under this facility for the benefit of CELSE pursuant to the working capital facility in an amount of $31.1 million with an expiration date of September 15, 2021. The standby letter of credit is guaranteed, jointly but not severally, by CELSE’s shareholders, NFE and Electricidade do Brasil S.A.—Ebrasil. Golar Hilli Leaseback As part of the Mergers, we acquired an investment in Hilli LLC; Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC. and is a party to a Memorandum of Agreement with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). Under the Hilli Facility, Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%. Our 50% share of Hilli Corp’s indebtedness of $729,000 amounted to $364,500 as of September 30, 2021. As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. We also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under its tolling agreement. Certain of our subsidiaries are required to comply with the following covenants and ratios: (i) free liquid assets of at least $30 million throughout the Hilli Leaseback period; (ii) a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; and (iii) a consolidated tangible net worth of $123,950. Letter of Credit Facility On July 16, 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to $75,000. Outstanding letters of credit are subject to a fee of 1.75% to be paid quarterly, and interest is payable on the principal amounts of unreimbursed letter of credit draws under the facility at a rate of the higher of the bank’s prime rate or the Federal Funds Effective Rate plus 0.50% and a margin of 1.75%. We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash. A portion of our restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital needs of the business. Off Balance Sheet Arrangements As of September 30, 2021 and December 31, 2020, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2020: (in thousands) Total Less than 1 year Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 1,675,203 $ 87,703 $ 168,750 $ 1,418,750 $ - Purchase obligations 2,490,347 376,096 724,588 724,090 665,573 Lease obligations 191,991 47,135 56,066 36,006 52,784 Total $ 4,357,541 $ 510,934 $ 949,404 $ 2,178,846 $ 718,357 58 Table of Contents Long-term debt obligations For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2020. Purchase obligations The Company is party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 31, 2020. In 2020, we entered into four LNG supply agreements for the purchase of 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029. In 2021, we amended one of these supply agreements to increase our total commitment through 2030 to 601 TBtus at a price indexed to Henry Hub. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease. The Company currently has seven vessels under time charter leases with non-cancellable terms ranging from three months to four years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services. We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 20 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately five years with an automatic renewal term of five years for up to an additional 20 years. During 2020, we executed multiple lease agreements for the use of ISO tanks, and we began to receive these ISO tanks and the lease terms commenced during the second quarter of 2021. The lease term for each of these leases is five years, and expected payments under these lease agreements have been included in the above table. Office space includes a space shared with affiliated companies in New York with lease terms up to 38 months and an office space in downtown Miami with a lease term of 84 months. Summary of Critical Accounting Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management evaluates its estimates and related assumptions regularly and will continue to do so as we further grow our business. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates. 59 Table of Contents Revenue recognition Terminals and infrastructure Within the Terminals and Infrastructure segment, our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from our natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, we have presented Operating revenue on an aggregated basis. We have concluded that variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer. Our contracts with customers to supply natural gas or LNG may contain a lease of equipment, which may be accounted for as a finance or operating lease. For operating leases, we have concluded that the predominant component of the transaction is the sale of natural gas or LNG and has elected not to separate the lease component. The lease component of such operating leases is recognized as Operating revenue in the condensed consolidated statements of operations and comprehensive loss. We allocate consideration in agreements containing finance leases between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. We estimate the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net on the condensed consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. In addition to the revenue recognized from the finance lease components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as we transfer control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and we recognize revenue for the interest income component over the term of the financing as Other revenue. The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration; unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Both unbilled receivables and contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed consolidated balance sheets. Shipping and handling costs are not considered to be separate performance obligations. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas. We collect sales taxes from our customers based on sales of taxable products and remits such collections to the appropriate taxing authority. We have elected to present sales tax collections in the condensed consolidated statements of operations and comprehensive loss on a net basis and, accordingly, such taxes are excluded from reported revenues. We elected the practical expedient under which we do not adjust consideration for the effects of a significant financing component for those contracts where we expect at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less. 60 Table of Contents Ships Charter contracts for the use of the FSRUs and LNG carriers acquired as part of the Mergers are leases as the contracts convey the right to obtain substantially all of the economic benefits from the use of the asset and allow the customer to direct the use of that asset. At inception, we make an assessment on whether the charter contract is an operating lease or a finance lease. In making the classification assessment, we estimate the residual value of the underlying asset at the end of the lease term with reference to broker valuations. None of the vessel lease contracts contain residual value guarantees. Renewal periods and termination options are included in the lease term if we believe such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. We assess leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease. For charter contracts that are determined to be finance leases accounted for as sales-type leases, the profit from the sale of the vessel is recognized upon lease commencement in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the condensed consolidated statements of operations and comprehensive loss. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Revenues include fixed minimum lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenues generated from charters contracts are recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the condensed consolidated statements of operations and comprehensive loss. Fixed revenue includes fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, we have elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based occur. Repositioning fees are included in Vessel charter revenues and are recognized at the end of the charter when the fee becomes fixed and determinable. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee will be recognized evenly over the term of the charter. Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss over the lease term. The Company’s LNG carriers may participate in a LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as the Cool Pool. The Cool Pool allows the pool participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as agent, for the marketing and chartering of the participating vessels and paying certain voyage costs such as port call expenses and brokers’ commissions in relation to employment contracts, with each of the Pool Participants continuing to be fully responsible for fulfilling the performance obligations in the contract. The Company is primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and the Company is the principal in such time charters. Revenue and expenses for charters of our vessels that participate in the Cool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the condensed consolidated statements of operations and comprehensive loss. Our allocation of our share of the net revenues earned from the other pool participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the condensed consolidated statements of operations and comprehensive loss. 61 Table of Contents Impairment of long-lived assets We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract, or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment. Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations in natural gas and LNG as our pricing is largely based on the Henry Hub index plus a contractual spread. Based on the long-term nature of our contracts and the market value of the underlying assets, changes in the price of LNG do not indicate that a recoverability assessment of our assets is necessary. Further, we plan to utilize our own liquefaction facilities to manufacture our own LNG at attractive prices, secure LNG to supply our expanding operations and reduce our exposure to future LNG price variations in the long term, including Fast LNG and our expanded delivery logistics chain in the Pennsylvania Facility. We have also considered the impacts of the ongoing COVID-19 pandemic, including the restrictions that governments may put in place and the resulting direct and indirect economic impacts on our current operations and expected development budgets and timelines. We primarily operate under long-term contracts with customers, including long-term charter contracts acquired in the Mergers and many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis, even in cases when our customer’s consumption has decreased. We have not changed our payment terms with customers, and there has not been any deterioration in the timing or volume of collections. Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not been significantly impacted by responses to the COVID-19 pandemic to date. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be performed. The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil traded at historic low prices in 2020. Future expansion of our business is dependent upon LNG being a competitive source of energy and available at a lower cost than the cost to deliver other alternative energy sources, such as diesel or other distillate fuels. Although LNG is currently trading at historical high prices, we believe that over the long-term LNG and natural gas will remain a competitive fuel source for customers. We have considered that the market price of LNG can vary widely, including decreases throughout 2019 and 2020 and dramatic increases in the third quarter of 2021. Our extensive and growing portfolio of downstream terminals and infrastructure, together with our locked-in gas supply, provides powerful flexibility to serve customer needs and participate in the opportunities created by market disruptions. During periods of declining LNG prices in 2019 and 2020, we executed four long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower our supply contract executed in 2018. Further, we took advantage of the lower market pricing of LNG to supply our operations for the second half of 2020. We also executed an additional addendum to one of our supply agreements in 2021 to continue to secure 100% of our LNG supply needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility through 2030. During dramatic increases of LNG prices in recent months, we have been able to take advantage of flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021. When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources. Share-based compensation We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model. 62 Table of Contents As of September 30, 2021, management determined that it was not probable that the performance condition for our outstanding PSUs would be met. For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period. A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable. Business combinations and goodwill We evaluate each purchase transaction to determine whether the acquired assets meet the definition of a business. If substantially all of the fair value of gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, then the set of transferred assets and activities is not a business. If not, for an acquisition to be considered a business, it would have to include an input and a substantive process that together significantly contribute to the ability to create outputs. A substantive process is not ancillary or minor, cannot be replaced without significant costs, effort or delay or is otherwise considered unique or scarce. To qualify as a business without outputs, the acquired assets would require an organized workforce with the necessary skills, knowledge and experience that performs a substantive process. For acquisitions that are not deemed to be businesses, the assets acquired are recognized based on their cost to us as the acquirer, and no gain or loss is recognized. The cost of assets acquired in a group is allocated to individual assets within the group based on their relative fair values and no goodwill is recognized. Transaction costs related to acquisition of assets are included in the cost basis of the assets acquired. We account for acquisitions that qualify as business combinations by applying the acquisition method. Transaction costs related to the acquisition of a business are expensed as incurred and excluded from the fair value of consideration transferred. Under the acquisition method of accounting, the identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity are recognized and measured at their estimated fair values. The excess of the fair value of consideration transferred over the fair values of identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity, net of fair value of any previously held interest in the acquired entity, is recorded as goodwill. The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests. Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, estimates of projected revenues, costs and cash flows, and discount rates. The Company estimated the fair value of the vessels acquired in the Mergers using a combination of the income approach and the cost approach, which determines the replacement costs for the assets, adjusting for age and condition. Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. As a result, actual results may differ from these estimates. During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill. Upon the conclusion of a measurement period, any subsequent adjustments are recorded to earnings. We use estimates, assumptions and judgments when assessing the recoverability of goodwill. We test for impairment on an annual basis, or more frequently if a significant event of circumstance indicates the carrying amounts may not be recoverable. The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which the goodwill is assigned is less than the carrying value. If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss. Recent Accounting Standards For descriptions of recently issued accounting standards, see “Note 3. Adoption of new and revised standards” to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report. Item 3 . Quantitative and Qualitative Disclosures About Market Risks. In the normal course of business, the Company encounters several significant types of market risks including commodity and interest rate risks. Commodity Price Risk Commodity price risk is the risk of loss arising from adverse changes in market rates and prices. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a contractual spread. Our exposure to market risk associated with LNG price changes may adversely impact our business. We do not currently have any derivative arrangements to protect against fluctuations in commodity prices, but to mitigate the effect of fluctuations in LNG prices on our operations, we may enter into various derivative instruments. However, we have secured 100% of our LNG supply needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandido Facility through 2030. 63 Table of Contents Interest Rate Risk The 2025 Notes and 2026 Notes were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the 2025 Notes and 2026 Notes but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $60 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve. Interest under the Vessel Term Loan Facility has a component based on LIBOR or other market indices should LIBOR become unavailable. A 100-basis point increase or decrease in the market interest rate would decrease or increase our interest expense by approximately $4.3 million. As a result of the Mergers, we assumed the Debenture Loan and a cross-currency interest rate swap to protect against adverse movements in interest rates of the Debenture Loan. We also acquired an interest rate swap to manage the exposure to adverse movements in interest rates of debt held by our equity method investee, Hilli LLC, but we do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our other outstanding indebtedness. Foreign Currency Exchange Risk After the completion of the Hygo Merger, we began to have more significant transactions, assets and liabilities denominated in Brazilian reais; our Brazilian subsidiaries and investments receive income and pays expenses in Brazilian reais. A portion of our exposure to exchange rates is economically hedged by a cross-currency interest rate swap. Based on our Brazilian reais revenues and expenses for the period since the completion of the Hygo Merger, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations. Outside of Brazil, our operations are primarily conducted in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions other than Brazil that are paid in local currencies, but we expect our international operations to continue to grow in the near term. Item 4. Controls and Procedures. Evaluation of Disclosure Controls and Procedures In accordance with Rules 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2021 at the reasonable assurance level. Changes in Internal Control over Financial Reporting On April 15, 2021, we completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”). As part of the ongoing integration of the acquired businesses, we are in the process of incorporating the controls and related procedures of Hygo and GMLP and expect that this effort will be completed in 2021. Pursuant to the SEC’s guidance that an assessment of a recently acquired business may be omitted from the scope of an assessment in the year of acquisition, the scope of our assessment of the effectiveness of our internal controls over financial reporting at December 31, 2021 will not include Hygo or GMLP. Other than the foregoing, there has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 64 Table of Contents PART II OTHER INFORMATION Item 1. Legal Proceedings. We are not currently a party to any material legal proceedings. In the ordinary course of business, various legal and regulatory claims and proceedings may be pending or threatened against us. If we become a party to proceedings in the future, we may be unable to predict with certainty the ultimate outcome of such claims and proceedings. Item 1A. Risk Factors. An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below. If any of the following risks were to occur, the value of our Class A common stock could be materially adversely affected or our business, financial condition and results of operations could be materially adversely affected and thus indirectly cause the value of our Class A common stock to decline. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business and the value of our Class A common stock. As a result of any of these risks, known or unknown, you may lose all or part of your investment in our Class A common stock. The risks discussed below also include forward-looking statements, and actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement on Forward-Looking Statements”. References to “NFE,” the “Company,” “we,” “us,” “our” and similar terms in this section refer to NFE Inc. and its subsidiaries, including Hygo and its subsidiaries, and including GMLP and its subsidiaries. References to “Hygo” and “GMLP”, respectively, in this section, refer to Hygo and GMLP and their respective subsidiaries, along with the Company and its subsidiaries. Summary Risk Factors Some of the factors that could materially and adversely affect our business, financial condition, results of operations or prospects include the following: Risks Related to the Mergers • We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers; • We may not have discovered undisclosed liabilities of either Hygo or GMLP during our due diligence process, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisitions of, Hygo and GMLP; • We have incurred a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger and as a result of the consummation of the Mergers; Risks Related to Our Business • We have not yet completed contracting, construction and commissioning for all of our Facilities and Liquefaction Facilities and there can be no assurance that our Facilities or Liquefaction Facilities will operate as expected or at all; • We may experience time delays, unforeseen expenses and other complications while developing our projects; • We may not be profitable for an indeterminate period of time; • Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results; • Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long term contracts that we have entered into or will enter into in the near future; • Operation of our LNG infrastructure and other facilities that we may construct involves significant risks; • The operation of the CHP Plant and any other power plants involves particular, significant risks; • Information technology failures and cyberattacks could affect us significantly; • Our insurance may be insufficient to cover losses that may occur to our property or result from our operations; • We are unable to predict the extent to which the global COVID-19 pandemic will negatively adversely affect our operations financial performance, or ability to achieve our strategic objectives, or our customers and suppliers; • We perform development or construction services from time to time which are subject to a variety of risks unique to these activities; • We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations to customers; 65 Table of Contents • Failure of LNG to be a competitive source of energy in the markets in which we operate could adversely affect our expansion strategy; • Our current lack of asset and geographic diversification; • Our business could be affected adversely by labor disputes, strikes or work stoppages in Brazil; • Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operation of our facilities could impede operations and construction; Risks Related to the Jurisdictions in Which We Operate • We are currently highly dependent upon economic, political and other conditions and developments in the Caribbean, particularly Jamaica, Puerto Rico as well as Brazil and the other jurisdictions in which we operate; Risks Related to Hygo Business Activities • Hygo’s Sergipe Facility is not currently operating at full capacity while equipment is being repaired, and we do not know the precise date when the facility will resume operations at full capacity. Once operations fully resume, the facility will be subject to customary operational risk for facilities of this type. Hygo’s other planned facilities are in various stages of contracting, construction, permitting and commissioning, each of which may present challenges to completion; • Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various contingencies; • Hygo may not be able to fully utilize the capacity of its facilities; • Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil; • Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities; Risks Related to GMLP Business Activities • GMLP currently derives all of its revenue from a limited number of customers and will face substantial competition in the future; • GMLP’s equity investment in Golar Hilli LLC may not result in anticipated profitability or generate cash flow sufficient to justify its investment. In addition, this investment exposes GMLP to risks that may harm its business; • GMLP may experience operational problems with its vessels that reduce revenue and increase costs; • GMLP may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits; Risks Related to Ownership of Our Class A Common Stock • A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders; and • The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all. Risks Related to the Mergers We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers. The success of the Mergers will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which recently operated as independent companies, with our business and realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from each combination. If we are unable to achieve these objectives within the anticipated time frame, or at all, the anticipated benefits may not be realized fully, or at all, or may take longer to realize than expected and the value of our common stock may be harmed. Additionally, as a result of the Mergers, rating agencies may take negative actions against our credit ratings, which may increase our financing costs, including in connection with the financing of the Mergers. The Mergers involve the integration of Hygo and GMLP with our existing business, which is a complex, costly and time-consuming process. The integration of each of Hygo and GMLP into our business may result in material challenges, including, without limitation: 66 Table of Contents • managing a larger company; • attracting, motivating and retaining management personnel and other key employees; • the possibility of faulty assumptions underlying expectations regarding the integration process; • retaining existing business and operational relationships and attracting new business and operational relationships; • consolidating corporate and administrative infrastructures and eliminating duplicative operations; • coordinating geographically separate organizations; • unanticipated issues in integrating information technology, communications and other systems; and • unanticipated changes in federal or state laws or regulations. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built. We may not have discovered undisclosed liabilities or other issues of either Hygo or GMLP during our due diligence process, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo and GMLP. In the course of the due diligence review of each of Hygo and GMLP that we conducted prior to the consummation of each of the Mergers, we may not have discovered, or may have been unable to quantify, undisclosed liabilities or other issues of Hygo or GMLP and their respective subsidiaries. Moreover, we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo or GMLP, irrespective of whether such potential liabilities were discovered or not. Examples of such undisclosed or potential liabilities or other issues may include, but are not limited to, pending or threatened litigation, regulatory matters, tax liabilities, indemnification of obligations, undisclosed counterparty termination rights, or undisclosed letter of credit or guarantee requirements. Any such undisclosed or potential liabilities or other issues could have an adverse effect on our business, results of operations, financial condition and cash flows. We have incurred a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger and as a result of the consummation of the Mergers. As of December 31, 2020, we had approximately $1,250 million aggregate principal amount of indebtedness outstanding. As of September 30, 2021, we had approximately $3,890 million aggregate principal amount of indebtedness. On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. We may incur additional debt to fund our business and strategic initiatives. If we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase. In addition, in connection with both the Hygo Merger and the GMLP Merger, we assumed a significant amount of indebtedness, including guarantees and preferred shares. As such, we are now subject to additional restrictive debt covenants that may limit our ability to finance future operations and capital needs and to pursue business opportunities and activities. In addition, if we fail to comply with any of these restrictions, it could have a material adverse effect on us. Risks Related to Our Business We have not yet completed contracting, construction and commissioning of all of our Facilities and Liquefaction Facilities. There can be no assurance that our Facilities and Liquefaction Facilities will operate as expected, or at all. We have not yet entered into binding construction contracts, issued “final notice to proceed” or obtained all necessary environmental, regulatory, construction and zoning permissions for all of our Facilities (as defined herein) and Liquefaction Facilities. There can be no assurance that we will be able to enter into the contracts required for the development of our Facilities and Liquefaction Facilities on commercially favorable terms, if at all, or that we will be able to obtain all of the environmental, regulatory, construction and zoning permissions we need. For example, we will require agreements with ports proximate to our Liquefaction Facilities capable of handling the transload of LNG directly from our transportation assets to our occupying vessel. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate these assets as expected, or at all. Additionally, the construction of these kinds of facilities is inherently subject to the risks of cost overruns and delays. There can be no assurance that we will not need to make adjustments to our Facilities and Liquefaction Facilities as a result of the required testing or commissioning of each development, which could cause delays and be costly. Furthermore, if we do enter into the necessary contracts and obtain regulatory approvals for the construction and operation of the Liquefaction Facilities, there can be no assurance that such operations will allow us to successfully export LNG to our Facilities, or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations. If we are unable to construct, commission and operate all of our Facilities and Liquefaction Facilities as expected, or, when and if constructed, they do not accomplish our goals, or if we experience delays or cost overruns in construction, our business, operating results, cash flows and liquidity could be materially and adversely affected. Expenses related to our pursuit of contracts and regulatory approvals related to our Facilities and Liquefaction Facilities still under development may be significant and will be incurred by us regardless of whether these assets are ultimately constructed and operational. 67 Table of Contents We may not be able to convert our anticipated LNG pipeline into binding contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate. We are actively pursuing a significant number of new LNG contracts with multiple counterparties in multiple jurisdictions. Potential sales contracts may differ meaningfully depending on various factors, including, but not limited to: whether the potential customer is a government entity or a private party; whether the contract process is done pursuant to a public bidding process or a bilateral negotiation; the infrastructure and permits needed for a particular project; customer timing requirements and applicable laws. Moreover, counterparties commemorate their commitment to purchase LNG in various degrees of formality ranging from traditional contracts to less formal arrangements. Given the variety of sales processes and counterparty acknowledgements of the LNG volumes they will purchase, we sometimes identify potential sales volumes as being either “Committed” or “In Discussion.” “Committed” volumes generally refer to the volumes that management expects to be sold under binding contracts, non-binding letters of intent or memorandums of understanding. “In Discussion” volumes generally refer to volumes that management is actively bidding on, responding to a request for proposals for or is actively negotiating. Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect. We may never sign a binding agreement to sell LNG to the counterparty, or we may sell much less LNG than we estimate. Accordingly, we cannot assure you that Committed or In Discussion volumes will result in actual sales, and such volumes should not be used to predict the company’s future results. We may experience time delays, unforeseen expenses and other complications while developing our projects. These complications can delay the commencement of revenue-generating activities, reduce the amount of revenue we earn and increase our development costs. Development projects, including our Facilities, Liquefaction Facilities, power plants, and related infrastructure are often developed in multiple stages involving commercial and governmental negotiations, site planning, due diligence, permit requests, environmental impact studies, permit applications and review, marine logistics planning and transportation and end-user delivery logistics. Projects of this type are subject to a number of risks that may lead to delay, increased costs and decreased economic attractiveness. These risks are often increased in foreign jurisdictions, where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project. A primary focus of our business is the development of projects in foreign jurisdictions, including in locations where we have no prior development experience, and we expect to continue expanding into new jurisdictions in the future, including with our expansion by way of the Mergers. We may experience delays, unforeseen expenses or other obstacles as we develop projects in new jurisdictions that could cause the projects we are developing to take longer and be more expensive than our initial estimates. While we plan our projects carefully and attempt to complete them according to timelines and budgets that we believe are feasible, we have experienced time delays and cost overruns in some projects that we have developed previously and may experience similar issues with future projects given the inherent complexity and unpredictability of developing infrastructure projects. For example, we previously expected to commence operations of our San Juan Facility and the converted Units 5 and 6 of the San Juan Power Plant (as defined herein) in San Juan, Puerto Rico in the third quarter of 2019. However, due in part to the earthquakes that occurred near Puerto Rico in January 2020 and third-party delays, we began supplying natural gas to Units 5 and 6 in the second quarter of 2020. Delays in the development beyond our estimated timelines, or amendments or change orders to the construction contracts we have entered into and will enter into in the future, could increase the cost of completion beyond the amounts that we estimate. Increased costs could require us to obtain additional sources of financing to continue development on our estimated development timeline or to fund our operations during such development. Any delay in completion of a Facility could cause a delay in the receipt of revenues estimated therefrom or cause a loss of one or more customers in the event of significant delays. As a result of any one of these factors, any significant development delay, whatever the cause, could have a material adverse effect on our business, operating results, cash flows and liquidity. 68 Table of Contents Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors. Our business strategy relies upon our future ability to successfully market natural gas to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the U.S., Jamaica, Mexico, Puerto Rico, Ireland, Nicaragua, Brazil and other countries where we do not currently operate. Our strategy assumes that we will be able to expand our operations into other countries, including countries in the Caribbean and Africa, enter into long-term GSAs and/or PPAs with end-users, acquire and transport LNG at attractive prices, develop infrastructure, including the Pennsylvania Facility (as defined herein), as well as other future projects, into efficient and profitable operations in a timely and cost-effective way, obtain approvals from all relevant federal, state and local authorities, as needed, for the construction and operation of these projects and other relevant approvals and obtain long-term capital appreciation and liquidity with respect to such investments. We cannot assure you if or when we will enter into contracts for the sale of LNG and/or natural gas, the price at which we will be able to sell such LNG and/or natural gas or our costs for such LNG and/or natural gas. Thus, there can be no assurance that we will achieve our target pricing, costs or margins. Our strategy may also be affected by future governmental laws and regulations. Our strategy also assumes that we will be able to enter into strategic relationships with energy end-users, power utilities, LNG providers, shipping companies, infrastructure developers, financing counterparties and other partners. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control. Additionally, in furtherance of our business strategy, we may acquire operating businesses or other assets in the future. Any such acquisitions would be subject to significant risks and contingencies, including the risk of integration, and we may not be able to realize the benefits of any such acquisitions. Additionally, our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our business. Any one or more of the following factors may have a material adverse effect on our ability to implement our strategy and achieve our targets: • inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts; • failure to develop cost-effective logistics solutions; • failure to manage expanding operations in the projected time frame; • inability to structure innovative and profitable energy-related transactions as part of our sales and trading operations and to optimally price and manage position, performance and counterparty risks; • inability, or failure, of any customer or contract counterparty to perform their contractual obligations to us (for further discussion of counterparty risk, see “– Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all.”); • inability to develop infrastructure, including our Facilities and Liquefaction Facilities, as well as other future projects, in a timely and cost-effective manner; • inability to attract and retain personnel in a timely and cost-effective manner; • failure of investments in technology and machinery, such as liquefaction technology or LNG tank truck technology, to perform as expected; • increases in competition which could increase our costs and undermine our profits; • inability to source LNG and/or natural gas in sufficient quantities and/or at economically attractive prices; • failure to anticipate and adapt to new trends in the energy sector in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, Brazil and elsewhere; • increases in operating costs, including the need for capital improvements, insurance premiums, general taxes, real estate taxes and utilities, affecting our profit margins; • inability to raise significant additional debt and equity capital in the future to implement our strategy as well as to operate and expand our business; • general economic, political and business conditions in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, Brazil and in the other geographic areas in which we intend to operate; • the severity and duration of world health events, including the recent COVID-19 pandemic and related economic and political impacts on our or our customers’ or suppliers’ operations and financial status; • inflation, depreciation of the currencies of the countries in which we operate and fluctuations in interest rates; • failure to win new bids or contracts on the terms, size and within the time frame we need to execute our business strategy; • failure to obtain approvals from governmental regulators and relevant local authorities for the construction and operation of potential future projects and other relevant approvals; • uncertainty regarding the timing, pace and extent of an economic recovery in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas; or • existing and future governmental laws and regulations. 69 Table of Contents If we experience any of these failures, such failure may adversely affect our financial condition, results of operations and ability to execute our business strategy. Our Fast LNG strategy is innovative and thus not yet proven. We may not be able to realize the time and cost savings we expect to achieve with our Fast LNG strategy. We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants. We are in the process of designing and constructing our first Fast LNG solution. The Fast LNG technology may take more time and money to construct than we currently estimate. We may not be able to successful construct our Fast LNG solution, and even if we succeed in constructing the technology, we may ultimately not be able to realize the time and cost savings we currently expect to achieve from this strategy. Any such failure could negatively affect both the timing and costs of some future projects, impair our ability to reduce our future LNG costs and negatively affect our financial results. When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project . A key part of our business strategy is to attract new customers by agreeing to finance and develop new facilities, power plants, liquefaction facilities and related infrastructure in order to win new customer contracts for the supply of natural gas, LNG or power. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell natural gas, LNG or power and generate fees from customers in the future. When we develop large projects such as facilities, power plants and large liquefaction facilities, our required capital expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain. If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects. We have a limited operating history, which may not be sufficient to evaluate our business and prospects. We have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the value of our Class A common stock. We commenced operations on February 25, 2014, and we had net losses of approximately $78.2 million in 2018, $204.3 million in 2019 and $264.0 million in 2020. Our strategy may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner. We cannot give you any assurance that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate. Our limited operating history also means that we continue to develop and implement various policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We will need to continue to build our team to develop and implement our strategies. We will continue to incur significant capital and operating expenditures while we develop infrastructure for our supply chain, including for the completion of our Facilities and Liquefaction Facilities under construction, as well as other future projects. We will need to invest significant amounts of additional capital to implement our strategy. We have not yet completed constructing all of our Facilities and Liquefaction Facilities and our strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under our customer contracts in relation to the incurrence of project and operating expenses. Our ability to generate any positive operating cash flow and achieve profitability in the future is dependent on, among other things, our ability to develop an efficient supply chain (which may be impacted by the COVID-19 pandemic) and successfully and timely complete necessary infrastructure, including our Facilities and Liquefaction Facilities under construction, and fulfill our gas delivery obligations under our customer contracts. 70 Table of Contents Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms. We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in specific markets, or the opportunistic sale of one of our non-core assets. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Quarterly Report for more information on our outstanding indebtedness. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan and our business, financial condition or results of operations may be materially adversely affected. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. Our ability to raise additional capital will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to the COVID-19 pandemic, our progress in executing our business strategy and other factors, many of which are beyond our control. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Additional debt financing, if available, may subject us to restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. If we are unable to comply with our existing covenants or any additional covenants and service our debt, we may lose control of our business and be forced to reduce or delay planned investments or capital expenditures, sell assets, restructure our operations or submit to foreclosure proceedings, all of which could result in a material adverse effect upon our business. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also historically have relied, and in the future will likely rely, on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms. We may not be profitable for an indeterminate period of time. We have a limited operating history and did not commence revenue-generating activities until 2016, and we have not achieved profitability for any annual period or for the six months ended June 30, 2021. We have made and will continue to make significant initial investments to complete construction and begin operations of each of our Facilities, power plants and Liquefaction Facilities, and we will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects, including in connection with the Mergers. We also expect to incur significant expenses in connection with the launch and growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. We will need to raise significant additional debt capital to achieve our goals. We may not be able to achieve profitability, and if we do, we cannot assure you that we would be able to sustain such profitability in the future. Our failure to achieve or sustain profitability would have a material adverse effect on our business. Our business is heavily dependent upon our international operations, particularly in Jamaica, Puerto Rico and Brazil, and any disruption to those operations would adversely affect us. Our operations in Jamaica began in October 2016, when our Montego Bay Facility commenced commercial operations, and continue to grow, and our San Juan Facility became fully operational in the third quarter of 2020. Jamaica, Puerto Rico and Brazil are subject to acts of terrorism or sabotage and natural disasters, in particular hurricanes, extreme weather conditions, crime and similar other risks which may negatively impact our operations in the region. We may also be affected by trade restrictions, such as tariffs or other trade controls. Additionally, tourism is a significant driver of economic activity in the Caribbean and Brazil. As a result, tourism directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in the Caribbean and Brazil are primarily driven by the economic condition of the tourists’ home country or territory, the condition of their destination, and the availability, affordability and desirability of air travel and cruises. Additionally, unexpected factors could reduce tourism at any time, including local or global economic recessions, terrorism, travel restrictions, pandemics, severe weather or natural disasters. If we are unable to continue to leverage on the skills and experience of our international workforce and members of management with experience in the jurisdictions in which we operate to manage such risks, we may be unable to provide LNG at an attractive price and our business could be materially affected. 71 Table of Contents Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results. A limited number of customers currently represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. At least in the short term, we expect that a substantial majority of our sales will continue to arise from a concentrated number of customers, such as power utilities, railroad companies and industrial end-users. We expect the substantial majority of our revenue for the near future to be from customers in the Caribbean, the Sergipe Facility and the Sergipe Power Plant and as a result, are subject to any risks specific to those customers and the jurisdictions and markets in which they operate. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition. If we lose any of our charterers and are unable to re-deploy the related vessel for an extended period of time, we will not receive any revenues from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, under the sale and leaseback arrangement in respect of the Golar Eskimo, if the time charter pursuant to which the Golar Eskimo is operating is terminated, the owner of the Golar Eskimo (which is a wholly-owned subsidiary of China Merchants Bank Leasing) will have the right to require us to purchase the vessel from it unless we are able to place such vessel under a suitable replacement charter within 24 months of the termination. We may not have, or be able to obtain, sufficient funds to make these accelerated payments or prepayments or be able to purchase the Golar Eskimo. In such a situation, the loss of a charterer could have a material adverse effect on our business, results of operations and financial condition. Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all. Our current results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon performance by JPS (as defined herein), SJPC (as defined herein) and PREPA (as defined herein), which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant (as defined herein), with us, and Jamalco (as defined herein), which has entered into a long-term SSA with us. While certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts are substantially in excess of such minimum volume commitments. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. In assessing customer credit risk, we use various procedures including background checks which we perform on our potential customers before we enter into a long-term contract with them. As part of the background check, we assess a potential customer’s credit profile and financial position, which can include their operating results, liquidity and outstanding debt, and certain macroeconomic factors regarding the region(s) in which they operate. These procedures help us to appropriately assess customer credit risk on a case-by-case basis, but these procedures may not be effective in assessing credit risk in all instances. As part of our business strategy, we intend to target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Additionally, we may face difficulties in enforcing our contractual rights against contractual counterparties that have not submitted to the jurisdiction of U.S. courts. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. The COVID-19 pandemic could adversely impact our customers through decreased demand for power due to decreased economic activity and tourism, or through the adverse economic impact of the pandemic on their power customers. The impact of the COVID-19 pandemic, including governmental and other third -party responses thereto, on our customers could enhance the risk of nonpayment by such customers under our contracts, which would negatively affect our business, results of operations and financial condition. 72 Table of Contents In particular, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, our ability to operate the CHP Plant is dependent on our ability to enforce the related lease. General Alumina Jamaica Limited (“GAJ”), one of the lessors, is a subsidiary of Noble Group, which completed a financial restructuring in 2018. If GAJ is involved in a bankruptcy or similar proceeding, such proceeding could negatively impact our ability to enforce the lease. If we are unable to enforce the lease due to the bankruptcy of GAJ or for any other reason, we could be unable to operate the CHP Plant or to execute on our contracts related thereto, which could negatively affect our business, results of operations and financial condition. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from the Federal Emergency Management Agency or other sources. PREPA’s contracting practices in connection with restoration and repair of PREPA’s electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. In the event that PREPA does not have or does not obtain the funds necessary to satisfy obligations to us under our agreement with PREPA or terminates our agreement prior to the end of the agreed term, our financial condition, results of operations and cash flows could be materially and adversely affected. If any of these customers fails to perform its obligations under its contract for the reasons listed above or for any other reason, our ability to provide products or services and our ability to collect payment could be negatively impacted, which could materially adversely affect our operating results, cash flow and liquidity, even if we were ultimately successful in seeking damages from such customer for a breach of contract. Our contracts with our customers are subject to termination under certain circumstances. Our contracts with our customers contain various termination rights. For example, each of our long-term customer contracts, including the contracts with JPS, SJPC, Jamalco and PREPA, contain various termination rights allowing our customers to terminate the contract, including, without limitation: • upon the occurrence of certain events of force majeure; • if we fail to make available specified scheduled cargo quantities; • the occurrence of certain uncured payment defaults; • the occurrence of an insolvency event; • the occurrence of certain uncured, material breaches; and • if we fail to commence commercial operations or achieve financial close within the agreed timeframes. We may not be able to replace these contracts on desirable terms, or at all, if they are terminated. Contracts that we enter into in the future may contain similar provisions. If any of our current or future contracts are terminated, such termination could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors: • additions to competitive regasification capacity in North America, Brazil, Europe, Asia and other markets, which could divert LNG or natural gas from our business; • imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States; • insufficient or oversupply of natural gas liquefaction or export capacity worldwide; • insufficient LNG tanker capacity; • weather conditions and natural disasters; • reduced demand and lower prices for natural gas; • increased natural gas production deliverable by pipelines, which could suppress demand for LNG; • decreased oil and natural gas exploration activities, including shut-ins and possible proration, which have begun and may continue to decrease the production of natural gas; • cost improvements that allow competitors to offer LNG regasification services at reduced prices; • changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas; • changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas; 73 Table of Contents • political conditions in natural gas producing regions; • adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and • cyclical trends in general business and economic conditions that cause changes in the demand for natural gas. Adverse trends or developments affecting any of these factors, including the timing of the impact of these factors in relation to our purchases and sales of natural gas and LNG could result in increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. The COVID-19 pandemic and certain actions by the Organization of the Petroleum Exporting Countries (“OPEC”) related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long -term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows. For example, among other reasons and because spot market LNG prices in the second quarter of 2020 were significantly lower than the price at which we had previously contracted to purchase LNG, we terminated our contractual obligation to purchase LNG for the remainder of 2020 in order to purchase LNG at lower prices on the spot market during that period in exchange for a one-time payment of $105 million. There can be no assurance we will achieve our target cost or pricing goals. In particular, because we have not currently procured fixed-price, long-term LNG supply to meet all future customer demand, increases in LNG prices and/or shortages of LNG supply could adversely affect our profitability. Additionally, we intend to rely on long-term, largely fixed-price contracts for the feedgas that we need in order to manufacture and sell our LNG. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control. Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations. We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we ma