0001749723us-gaap:AdditionalPaidInCapitalMember2022-03-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
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| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2022March 31, 2023
OR
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| ¨ | 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 x No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| | | | | |
Large accelerated filer x | Accelerated filer ¨ |
Non-accelerated filer ¨ | Smaller reporting company ☐ |
| Emerging growth company ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| Class A common stock | | “NFE” | | Nasdaq Global Select Market |
As of August 2, 2022,May 1, 2023, the registrant had 207,556,249205,030,155 shares of Class A common stock outstanding.
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:
| | | | | |
| ADO | automotive diesel oil |
| |
| Bcf/yr | billion cubic feet per year |
| |
| 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 |
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| CERCLA | Comprehensive Environmental Response, Compensation and Liability Act |
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| CWA | Clean Water Act |
| |
| DOE | U.S. Department of Energy |
| |
| DOT | U.S. Department of Transportation |
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| EPA | U.S. Environmental Protection Agency |
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| FTA countries | countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas |
| |
| GAAP | generally accepted accounting principles in the United States |
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| GHG | greenhouse gases |
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| GSA | gas sales agreement |
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| 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 |
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| 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 |
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| MMBtu | one million Btus, which corresponds to approximately 12.1 gallons of LNG |
| |
| mtpa | metric tons per year |
| |
| MW | megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt |
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| NGA | Natural Gas Act of 1938, as amended |
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| 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 |
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| OPA | Oil Pollution Act |
| |
| | | | | |
| OUR | Office of Utilities Regulation (Jamaica) |
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| PHMSA | Pipeline and Hazardous Materials Safety Administration |
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| PPA | power purchase agreement |
| |
| SSA | steam supply agreement |
| |
| TBtu | one trillion Btus, which corresponds to approximately 12,100,000 gallons of LNG |
CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS
This Quarterly Report contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Quarterly Report other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance or our projected business results. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “projects,” “targets,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements are necessarily estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:
•our limited operating history;
•the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us;
•construction and operational risks related to our facilities and assets, including cost overruns and delays;
•failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
•complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;
•delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
•failure to maintain sufficient working capital for the development and operation of our business and assets;
•failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;
•failure to maintain sufficient working capital for the development and operation of our business and assets;
•failure to convert our customer pipeline into actual sales;
•lack of asset, geographic or customer diversification, including loss of one or more of our customers;
•competition from third parties in our business;
•failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
•cyclical or other changes in the demand for and price of LNG and natural gas;
•inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;
•inability to successfully develop and implement our technological solutions;
•inability to service our debt and comply with our covenant restrictions;
•inability to obtain additional financing to effect our strategy;
•inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits, including with respect to the Mergers (as defined below);benefits;
•economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;
•weather events or other natural or manmade disasters or phenomena;
•the extent of the global COVID-19 pandemic or any other major health and safety incident;
•increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;
•the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A shares; and
•other risks described in the “Risk Factors” section of this Quarterly Report.
All forward-looking statements speak only as of the date of this Quarterly Report. When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in our Annual Report on Form 10-K for the year ended December 31, 20212022 (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.
PART I
FINANCIAL INFORMATION
Item 1. Financial Statements.
New Fortress Energy Inc.
Condensed Consolidated Balance Sheets
As of June 30, 2022March 31, 2023 and December 31, 20212022
(Unaudited, in thousands of U.S. dollars, except share amounts)
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Assets | Assets | | | | Assets | | | |
| Current assets | Current assets | | Current assets | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 138,329 | | | $ | 187,509 | | Cash and cash equivalents | $ | 296,860 | | | $ | 675,492 | |
| Restricted cash | Restricted cash | 71,602 | | | 68,561 | | Restricted cash | 325,298 | | | 165,396 | |
| Receivables, net of allowances of $164 and $164, respectively | 313,457 | | | 208,499 | | |
| Receivables, net of allowances of $748 and $884, respectively | | Receivables, net of allowances of $748 and $884, respectively | 353,192 | | | 280,313 | |
| Inventory | Inventory | 72,152 | | | 37,182 | | Inventory | 76,536 | | | 39,070 | |
| Prepaid expenses and other current assets, net | Prepaid expenses and other current assets, net | 141,092 | | | 83,115 | | Prepaid expenses and other current assets, net | 102,251 | | | 226,883 | |
| Total current assets | Total current assets | 736,632 | | | 584,866 | | Total current assets | 1,154,137 | | | 1,387,154 | |
| | Restricted cash | 7,960 | | | 7,960 | | |
| | Construction in progress | Construction in progress | 1,401,468 | | | 1,043,883 | | Construction in progress | 3,357,434 | | | 2,418,608 | |
| Property, plant and equipment, net | Property, plant and equipment, net | 2,156,431 | | | 2,137,936 | | Property, plant and equipment, net | 2,094,417 | | | 2,116,727 | |
| Equity method investments | Equity method investments | 939,738 | | | 1,182,013 | | Equity method investments | 136,300 | | | 392,306 | |
| Right-of-use assets | Right-of-use assets | 407,689 | | | 309,663 | | Right-of-use assets | 477,757 | | | 377,877 | |
| Intangible assets, net | Intangible assets, net | 121,088 | | | 142,944 | | Intangible assets, net | 80,312 | | | 85,897 | |
| Finance leases, net | 600,885 | | | 602,675 | | |
| | Goodwill | Goodwill | 778,488 | | | 760,135 | | Goodwill | 776,760 | | | 776,760 | |
| Deferred tax assets, net | Deferred tax assets, net | 5,628 | | | 5,999 | | Deferred tax assets, net | 8,074 | | | 8,074 | |
| Other non-current assets, net | Other non-current assets, net | 95,369 | | | 98,418 | | Other non-current assets, net | 138,555 | | | 141,679 | |
| Total assets | Total assets | $ | 7,251,376 | | | $ | 6,876,492 | | Total assets | $ | 8,223,746 | | | $ | 7,705,082 | |
| | Liabilities | Liabilities | | Liabilities | |
| Current liabilities | Current liabilities | | Current liabilities | |
| Current portion of long-term debt | Current portion of long-term debt | $ | 99,756 | | | $ | 97,251 | | Current portion of long-term debt | $ | 277,035 | | | $ | 64,820 | |
| Accounts payable | Accounts payable | 111,436 | | | 68,085 | | Accounts payable | 310,272 | | | 80,387 | |
| Accrued liabilities | Accrued liabilities | 236,535 | | | 244,025 | | Accrued liabilities | 602,928 | | | 1,162,412 | |
| Current lease liabilities | Current lease liabilities | 53,983 | | | 47,114 | | Current lease liabilities | 106,666 | | | 48,741 | |
| Other current liabilities | Other current liabilities | 94,286 | | | 106,036 | | Other current liabilities | 99,275 | | | 52,878 | |
| Total current liabilities | Total current liabilities | 595,996 | | | 562,511 | | Total current liabilities | 1,396,176 | | | 1,409,238 | |
| | Long-term debt | Long-term debt | 4,051,756 | | | 3,757,879 | | Long-term debt | 4,951,545 | | | 4,476,865 | |
| Non-current lease liabilities | Non-current lease liabilities | 329,972 | | | 234,060 | | Non-current lease liabilities | 349,621 | | | 302,121 | |
| Deferred tax liabilities, net | Deferred tax liabilities, net | 140,289 | | | 269,513 | | Deferred tax liabilities, net | 26,455 | | | 25,989 | |
| Other long-term liabilities | Other long-term liabilities | 60,835 | | | 58,475 | | Other long-term liabilities | 50,623 | | | 49,010 | |
| Total liabilities | Total liabilities | 5,178,848 | | | 4,882,438 | | Total liabilities | 6,774,420 | | | 6,263,223 | |
| | Commitments and contingencies (Note 21) | 0 | | 0 | |
| Commitments and contingencies (Note 19) | | Commitments and contingencies (Note 19) | |
| | Stockholders’ equity | Stockholders’ equity | | Stockholders’ equity | |
Class A common stock, $0.01 par value, 750.0 million shares authorized, 207.6 million issued and outstanding as of June 30, 2022; 206.9 million issued and outstanding as of December 31, 2021 | 2,076 | | | 2,069 | | |
| Class A common stock, $0.01 par value, 750 million shares authorized, 204.7 million issued and outstanding as of March 31, 2023; 208.8 million issued and outstanding as of December 31, 2022 | | Class A common stock, $0.01 par value, 750 million shares authorized, 204.7 million issued and outstanding as of March 31, 2023; 208.8 million issued and outstanding as of December 31, 2022 | 2,047 | | | 2,088 | |
| Additional paid-in capital | Additional paid-in capital | 1,868,618 | | | 1,923,990 | | Additional paid-in capital | 1,047,541 | | | 1,170,254 | |
| Accumulated deficit | (63,895) | | | (132,399) | | |
| Accumulated other comprehensive income (loss) | 78,232 | | | (2,085) | | |
| Retained earnings | | Retained earnings | 191,819 | | | 62,080 | |
| Accumulated other comprehensive income | | Accumulated other comprehensive income | 57,344 | | | 55,398 | |
| Total stockholders’ equity attributable to NFE | Total stockholders’ equity attributable to NFE | 1,885,031 | | | 1,791,575 | | Total stockholders’ equity attributable to NFE | 1,298,751 | | | 1,289,820 | |
| Non-controlling interest | Non-controlling interest | 187,497 | | | 202,479 | | Non-controlling interest | 150,575 | | | 152,039 | |
| Total stockholders’ equity | Total stockholders’ equity | 2,072,528 | | | 1,994,054 | | Total stockholders’ equity | 1,449,326 | | | 1,441,859 | |
| Total liabilities and stockholders’ equity | Total liabilities and stockholders’ equity | $ | 7,251,376 | | | $ | 6,876,492 | | Total liabilities and stockholders’ equity | $ | 8,223,746 | | | $ | 7,705,082 | |
The accompanying notes are an integral part of these condensed consolidated financial statements.
New Fortress Energy Inc.
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
For the three and six months ended June 30,March 31, 2023 and 2022 and 2021
Unaudited, in thousands of U.S. dollars, except share and per share amounts) | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| Revenues | Revenues | | | | | | | | Revenues | | | | |
| Operating revenue | Operating revenue | $ | 497,240 | | | $ | 102,836 | | | $ | 897,315 | | | $ | 194,032 | | Operating revenue | $ | 501,688 | | | $ | 400,075 | | |
| Vessel charter revenue | Vessel charter revenue | 75,134 | | | 64,561 | | | 167,554 | | | 64,561 | | Vessel charter revenue | 76,524 | | | 92,420 | | |
| Other revenue | Other revenue | 12,481 | | | 56,442 | | | 25,104 | | | 110,930 | | Other revenue | 919 | | | 12,623 | | |
| Total revenues | Total revenues | 584,855 | | | 223,839 | | | 1,089,973 | | | 369,523 | | Total revenues | 579,131 | | | 505,118 | | |
| | Operating expenses | Operating expenses | | Operating expenses | | |
| Cost of sales | 272,401 | | | 101,430 | | | 480,699 | | | 198,101 | | |
| Cost of sales (exclusive of depreciation and amortization shown separately below) | | Cost of sales (exclusive of depreciation and amortization shown separately below) | 184,938 | | | 208,298 | | |
| Vessel operating expenses | Vessel operating expenses | 18,628 | | | 15,400 | | | 41,592 | | | 15,400 | | Vessel operating expenses | 13,291 | | | 22,964 | | |
| Operations and maintenance | Operations and maintenance | 20,490 | | | 18,565 | | | 43,658 | | | 34,816 | | Operations and maintenance | 26,671 | | | 23,168 | | |
| Selling, general and administrative | Selling, general and administrative | 50,310 | | | 44,536 | | | 98,351 | | | 78,152 | | Selling, general and administrative | 52,138 | | | 48,041 | | |
| Transaction and integration costs | Transaction and integration costs | 4,866 | | | 29,152 | | | 6,767 | | | 40,716 | | Transaction and integration costs | 494 | | | 1,901 | | |
| | Depreciation and amortization | Depreciation and amortization | 36,356 | | | 26,997 | | | 70,646 | | | 36,886 | | Depreciation and amortization | 34,375 | | | 34,290 | | |
| Asset impairment expense | 48,109 | | | — | | | 48,109 | | | — | | |
| | Total operating expenses | Total operating expenses | 451,160 | | | 236,080 | | | 789,822 | | | 404,071 | | Total operating expenses | 311,907 | | | 338,662 | | |
| Operating income (loss) | 133,695 | | | (12,241) | | | 300,151 | | | (34,548) | | |
| Operating income | | Operating income | 267,224 | | | 166,456 | | |
| Interest expense | Interest expense | 47,840 | | | 31,482 | | | 92,756 | | | 50,162 | | Interest expense | 71,673 | | | 44,916 | | |
| Other (income), net | (22,102) | | | (7,457) | | | (41,827) | | | (8,058) | | |
| Other expense (income), net | | Other expense (income), net | 25,005 | | | (19,725) | | |
| | Net income (loss) before (loss) income from equity method investments and income taxes | 107,957 | | | (36,266) | | | 249,222 | | | (76,652) | | |
| (Loss) income from equity method investments | (372,927) | | | 38,941 | | | (322,692) | | | 38,941 | | |
| Tax (benefit) provision | (86,539) | | | 4,409 | | | (136,220) | | | 3,532 | | |
| Net (loss) income | (178,431) | | | (1,734) | | | 62,750 | | | (41,243) | | |
| Income before income from equity method investments and income taxes | | Income before income from equity method investments and income taxes | 170,546 | | | 141,265 | | |
| Income from equity method investments | | Income from equity method investments | 9,980 | | | 50,235 | | |
| Tax provision (benefit) | | Tax provision (benefit) | 28,960 | | | (49,681) | | |
| Net income | | Net income | 151,566 | | | 241,181 | | |
| Net income attributable to non-controlling interest | Net income attributable to non-controlling interest | 8,666 | | | (4,310) | | | 5,754 | | | (2,704) | | Net income attributable to non-controlling interest | (1,360) | | | (2,912) | | |
| Net loss attributable to stockholders | $ | (169,765) | | | $ | (6,044) | | | $ | 68,504 | | | $ | (43,947) | | |
| Net income attributable to stockholders | | Net income attributable to stockholders | $ | 150,206 | | | $ | 238,269 | | |
| | Net (loss) income per share – basic | $ | (0.81) | | | $ | (0.03) | | | $ | 0.33 | | | $ | (0.23) | | |
| Net (loss) income per share – diluted | $ | (0.81) | | | $ | (0.03) | | | $ | 0.33 | | | $ | (0.23) | | |
| Net income per share – basic | | Net income per share – basic | $ | 0.72 | | | $ | 1.14 | | |
| Net income per share – diluted | | Net income per share – diluted | $ | 0.71 | | | $ | 1.13 | | |
| | Weighted average number of shares outstanding – basic | Weighted average number of shares outstanding – basic | 209,669,188 | | | 202,331,304 | | | 209,797,133 | | | 189,885,473 | | Weighted average number of shares outstanding – basic | 208,707,385 | | | 209,928,070 | | |
| Weighted average number of shares outstanding – diluted | Weighted average number of shares outstanding – diluted | 209,669,188 | | | 202,331,304 | | | 209,810,647 | | | 189,885,473 | | Weighted average number of shares outstanding – diluted | 209,325,619 | | | 210,082,295 | | |
| | Other comprehensive income (loss): | | |
| Net (loss) income | $ | (178,431) | | | $ | (1,734) | | | $ | 62,750 | | | $ | (41,243) | | |
| Other comprehensive income: | | Other comprehensive income: | | |
| Net income | | Net income | $ | 151,566 | | | $ | 241,181 | | |
| Currency translation adjustment | Currency translation adjustment | (39,703) | | | 101,690 | | | 81,127 | | | 100,693 | | Currency translation adjustment | 2,141 | | | 120,830 | | |
| Comprehensive (loss) income | (218,134) | | | 99,956 | | | 143,877 | | | 59,450 | | |
| Comprehensive income | | Comprehensive income | 153,707 | | | 362,011 | | |
| Comprehensive income attributable to non-controlling interest | Comprehensive income attributable to non-controlling interest | 9,812 | | | (4,637) | | | 4,944 | | | (2,157) | | Comprehensive income attributable to non-controlling interest | (1,555) | | | (4,868) | | |
| Comprehensive (loss) income attributable to stockholders | $ | (208,322) | | | $ | 95,319 | | | $ | 148,821 | | | $ | 57,293 | | |
| Comprehensive income attributable to stockholders | | Comprehensive income attributable to stockholders | $ | 152,152 | | | $ | 357,143 | | |
The accompanying notes are an integral part of these condensed consolidated financial statements.
New Fortress Energy Inc.
Condensed Consolidated Statements of Changes in Stockholders’ Equity
For the three and six months ended June 30,March 31, 2023 and 2022 and 2021
(Unaudited, in thousands of U.S. dollars, except share amounts)
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| | | | | | | Class A common stock | | Additional
paid-in
capital | | Retained earnings (accumulated
deficit) | | Accumulated other
comprehensive
(loss) income | | Non-
controlling
interest | | Total
stockholders’ equity |
| | | | | | | | | Shares | | Amount |
| Balance as of December 31, 2021 | | | | | | | | | 206,863,242 | | | $ | 2,069 | | | $ | 1,923,990 | | | $ | (132,399) | | | $ | (2,085) | | | $ | 202,479 | | | $ | 1,994,054 | |
| Net income | | | | | | | | | — | | | — | | | — | | | 238,269 | | | — | | | 2,912 | | | 241,181 | |
| Other comprehensive income | | | | | | | | | — | | | — | | | — | | | — | | | 118,874 | | | 1,956 | | | 120,830 | |
| Share-based compensation expense | | | | | | | | | — | | | — | | | 880 | | | — | | | — | | | — | | | 880 | |
| Issuance of shares for vested RSUs | | | | | | | | | 1,121,255 | | | 7 | | | — | | | — | | | — | | | — | | | 7 | |
| Shares withheld from employees related to share-based compensation, at cost | | | | | | | | | (442,146) | | | — | | | (15,274) | | | — | | | — | | | — | | | (15,274) | |
| Dividends | | | | | | | | | — | | | — | | | (20,754) | | | — | | | — | | | (3,019) | | | (23,773) | |
| Balance as of March 31, 2022 | | | | | | | | | 207,542,351 | | | $ | 2,076 | | | $ | 1,888,842 | | | $ | 105,870 | | | $ | 116,789 | | | $ | 204,328 | | | $ | 2,317,905 | |
| Net income (loss) | | | | | | | | | — | | | — | | | — | | | (169,765) | | | — | | | (8,666) | | | (178,431) | |
| Other comprehensive loss | | | | | | | | | — | | | — | | | — | | | — | | | (38,557) | | | (1,146) | | | (39,703) | |
| Share-based compensation expense | | | | | | | | | — | | | — | | | 358 | | | — | | | — | | | — | | | 358 | |
| | | | | | | | | | | | | | | | | | | | | |
| Issuance of shares for vested RSUs | | | | | | | | | 13,898 | | | — | | | — | | | — | | | — | | | — | | | — | |
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| Dividends | | | | | | | | | — | | | — | | | (20,582) | | | — | | | — | | | (7,019) | | | (27,601) | |
| Balance as of June 30, 2022 | | | | | | | | | 207,556,249 | | | $ | 2,076 | | | $ | 1,868,618 | | | $ | (63,895) | | | $ | 78,232 | | | $ | 187,497 | | | $ | 2,072,528 | |
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| | | | | | | Class A common stock | | Additional
paid-in
capital | | Retained earnings | | Accumulated other
comprehensive
income | | Non-
controlling
interest | | Total
stockholders’ equity |
| | | | | | | | | Shares | | Amount |
| Balance as of December 31, 2022 | | | | | | | | | 208,770,088 | | | $ | 2,088 | | | $ | 1,170,254 | | | $ | 62,080 | | | $ | 55,398 | | | $ | 152,039 | | | $ | 1,441,859 | |
| Net income | | | | | | | | | — | | | — | | | — | | | 150,206 | | | — | | | 1,360 | | | 151,566 | |
| Other comprehensive income | | | | | | | | | — | | | — | | | — | | | — | | | 1,946 | | | 195 | | | 2,141 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Cancellation of shares | | | | | | | | | (4,100,000) | | | (41) | | | (122,713) | | | — | | | — | | | — | | | (122,754) | |
| Dividends | | | | | | | | | — | | | — | | | — | | | (20,467) | | | — | | | (3,019) | | | (23,486) | |
| Balance as of March 31, 2023 | | | | | | | | | 204,670,088 | | | $ | 2,047 | | | $ | 1,047,541 | | | $ | 191,819 | | | $ | 57,344 | | | $ | 150,575 | | | $ | 1,449,326 | |
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | Class A common stock | | Additional
paid-in
capital | | Accumulated
deficit | | Accumulated other
comprehensive
(loss) income | | Non-
controlling
interest | | Total
stockholders’
equity | | | | Class A common stock | | Additional
paid-in
capital | | Retained earnings (Accumulated
deficit) | | Accumulated other
comprehensive
(loss) income | | Non-
controlling
interest | | Total
stockholders’
equity |
| | | Shares | | Amount | | | | Non-
controlling
interest | | Total
stockholders’
equity | Shares | | Amount |
| Balance as of December 31, 2020 | | | 174,622,862 | | | $ | 1,746 | | | $ | 594,534 | | | $ | (229,503) | | | $ | 182 | | | $ | 8,127 | | | $ | 375,086 | | |
| Balance as of December 31, 2021 | | Balance as of December 31, 2021 | | | 206,863,242 | | | $ | 2,069 | | | $ | 1,923,990 | | | $ | (132,399) | | | $ | (2,085) | | | $ | 202,479 | | | $ | 1,994,054 | |
| | Net loss | | | — | | | — | | | — | | | (37,903) | | | — | | | (1,606) | | | (39,509) | | |
| Net income | | Net income | | | — | | | — | | | — | | | 238,269 | | | — | | | 2,912 | | | 241,181 | |
| Other comprehensive loss | Other comprehensive loss | | | — | | | — | | | — | | | — | | | (123) | | | (874) | | | (997) | | Other comprehensive loss | | | — | | | — | | | — | | | — | | | 118,874 | | | 1,956 | | | 120,830 | |
| Share-based compensation expense | Share-based compensation expense | | | — | | | — | | | 1,770 | | | — | | | — | | | — | | | 1,770 | | Share-based compensation expense | | | — | | | — | | | 880 | | | — | | | — | | | — | | | 880 | |
| Issuance of shares for vested RSUs | Issuance of shares for vested RSUs | | | 1,335,787 | | | — | | | — | | | — | | | — | | | — | | | — | | Issuance of shares for vested RSUs | | | 1,121,255 | | | 7 | | | — | | | — | | | — | | | — | | | 7 | |
| Shares withheld from employees related to share-based compensation, at cost | Shares withheld from employees related to share-based compensation, at cost | | | (638,235) | | | — | | | (27,571) | | | — | | | — | | | — | | | (27,571) | | Shares withheld from employees related to share-based compensation, at cost | | | (442,146) | | | — | | | (15,274) | | | — | | | — | | | — | | | (15,274) | |
| Dividends | Dividends | | | — | | | — | | | (17,598) | | | — | | | — | | | — | | | (17,598) | | Dividends | | | — | | | — | | | (20,754) | | | — | | | — | | | (3,019) | | | (23,773) | |
| 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 | | |
| Balance as of March 31, 2022 | | Balance as of March 31, 2022 | | | 207,542,351 | | | $ | 2,076 | | | $ | 1,888,842 | | | $ | 105,870 | | | $ | 116,789 | | | $ | 204,328 | | | $ | 2,317,905 | |
| |
The accompanying notes are an integral part of these condensed consolidated financial statements.
New Fortress Energy Inc.
Condensed Consolidated Statements of Cash Flows
For the sixthree months ended June 30,March 31, 2023 and 2022 and 2021
(Unaudited, in thousands of U.S. dollars)
| | | Six Months Ended June 30, | | Three Months Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities | Cash flows from operating activities | | | | Cash flows from operating activities | | | |
| Net income (loss) | $ | 62,750 | | | $ | (41,243) | | |
| Net income | | Net income | $ | 151,566 | | | $ | 241,181 | |
| Adjustments for: | Adjustments for: | | Adjustments for: | |
| Amortization of deferred financing costs and debt guarantee, net | 2,383 | | | (6,290) | | |
| | Depreciation and amortization | Depreciation and amortization | 71,172 | | | 37,462 | | Depreciation and amortization | 34,608 | | | 34,852 | |
| Loss (earnings) of equity method investees | 322,692 | | | (38,941) | | |
| Drydocking expenditure | (12,439) | | | — | | |
| (Earnings) of equity method investees | | (Earnings) of equity method investees | (9,980) | | | (50,235) | |
| | Dividends received from equity method investees | Dividends received from equity method investees | 14,859 | | | 7,386 | | Dividends received from equity method investees | 5,830 | | | 7,609 | |
| Sales-type lease payments received in excess of interest income | 1,426 | | | 2,388 | | |
| | Change in market value of derivatives | Change in market value of derivatives | (9,798) | | | (7,073) | | Change in market value of derivatives | 3,330 | | | (24,855) | |
| Deferred taxes | Deferred taxes | (178,109) | | | 2,447 | | Deferred taxes | — | | | (58,769) | |
| Change in value of investment of equity securities | 1,090 | | | (88) | | |
| Share-based compensation | 1,238 | | | 3,383 | | |
| Asset impairment expense | 48,109 | | | — | | |
| | (Earnings) recognized from vessels chartered to third parties transferred to Energos | | (Earnings) recognized from vessels chartered to third parties transferred to Energos | (31,954) | | | — | |
| Loss on the disposal of equity method investment | | Loss on the disposal of equity method investment | 37,401 | | | — | |
| Other | Other | 671 | | | 275 | | Other | (2,090) | | | 2,847 | |
| Changes in operating assets and liabilities, net of acquisitions: | | |
| (Increase) in receivables | (123,843) | | | (38,018) | | |
| Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
| Decrease (increase) in receivables | | Decrease (increase) in receivables | 28,136 | | | (58,462) | |
| (Increase) in inventories | (Increase) in inventories | (35,167) | | | (35,458) | | (Increase) in inventories | (2,271) | | | (18,617) | |
| (Increase) Decrease in other assets | (58,949) | | | 3,679 | | |
| (Increase) in other assets | | (Increase) in other assets | (27,966) | | | (15,440) | |
| Decrease in right-of-use assets | Decrease in right-of-use assets | 35,265 | | | 2,072 | | Decrease in right-of-use assets | 13,336 | | | 17,016 | |
| Increase in accounts payable/accrued liabilities | 71,603 | | | 24,732 | | |
| Increase (Decrease) in amounts due to affiliates | 1,238 | | | (2,919) | | |
| (Decrease) Increase in lease liabilities | (31,352) | | | 133 | | |
| Decrease in other liabilities | (13,906) | | | (25,279) | | |
| Net cash provided by (used in) operating activities | 170,933 | | | (111,352) | | |
| (Decrease) increase in accounts payable/accrued liabilities | | (Decrease) increase in accounts payable/accrued liabilities | (43,400) | | | 68,520 | |
| (Decrease) increase in amounts due to affiliates | | (Decrease) increase in amounts due to affiliates | (2,519) | | | 2,035 | |
| (Decrease) in lease liabilities | | (Decrease) in lease liabilities | (9,709) | | | (11,773) | |
| Increase (decrease) in other liabilities | | Increase (decrease) in other liabilities | 55,822 | | | (21,527) | |
| Net cash provided by operating activities | | Net cash provided by operating activities | 200,140 | | | 114,382 | |
| | Cash flows from investing activities | Cash flows from investing activities | | Cash flows from investing activities | |
| Capital expenditures | Capital expenditures | (441,708) | | | (235,324) | | Capital expenditures | (563,268) | | | (189,221) | |
| 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 | — | | | (750) | | |
| Net cash (used in) investing activities | (441,708) | | | (1,830,933) | | |
| Sale of equity method investment | | Sale of equity method investment | 100,000 | | | — | |
| | Net cash used in investing activities | | Net cash used in investing activities | (463,268) | | | (189,221) | |
| | Cash flows from financing activities | Cash flows from financing activities | | Cash flows from financing activities | |
| Proceeds from borrowings of debt | Proceeds from borrowings of debt | 437,917 | | | 1,652,500 | | Proceeds from borrowings of debt | 700,000 | | | 200,836 | |
| Payment of deferred financing costs | Payment of deferred financing costs | (4,805) | | | (20,989) | | Payment of deferred financing costs | (5,903) | | | (3,504) | |
| Repayment of debt | Repayment of debt | (146,030) | | | (15,864) | | Repayment of debt | (1,080) | | | (123,669) | |
| Payments related to tax withholdings for share-based compensation | Payments related to tax withholdings for share-based compensation | (13,054) | | | (29,717) | | Payments related to tax withholdings for share-based compensation | — | | | (13,054) | |
| Payment of dividends | Payment of dividends | (47,374) | | | (41,346) | | Payment of dividends | (649,796) | | | (23,773) | |
| Net cash provided by financing activities | Net cash provided by financing activities | 226,654 | | | 1,544,584 | | Net cash provided by financing activities | 43,221 | | | 36,836 | |
| Effect of exchange rate changes on cash, cash equivalents and restricted cash | (2,018) | | | (1,317) | | |
| Impact of changes in foreign exchange rates on cash and cash equivalents | | Impact of changes in foreign exchange rates on cash and cash equivalents | 948 | | | 12,979 | |
| Net (decrease) in cash, cash equivalents and restricted cash | Net (decrease) in cash, cash equivalents and restricted cash | (46,139) | | | (399,018) | | Net (decrease) in cash, cash equivalents and restricted cash | (218,959) | | | (25,024) | |
| Cash, cash equivalents and restricted cash – beginning of period | Cash, cash equivalents and restricted cash – beginning of period | 264,030 | | | 629,336 | | Cash, cash equivalents and restricted cash – beginning of period | 855,083 | | | 264,030 | |
| Cash, cash equivalents and restricted cash – end of period | Cash, cash equivalents and restricted cash – end of period | $ | 217,891 | | | $ | 230,318 | | Cash, cash equivalents and restricted cash – end of period | $ | 636,124 | | | $ | 239,006 | |
| | | Supplemental disclosure of non-cash investing and financing activities: | Supplemental disclosure of non-cash investing and financing activities: | | 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 | Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions | $ | 5,302 | | | $ | 85,513 | | Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions | $ | 348,737 | | | $ | 19,838 | |
| Liabilities associated with consideration paid for entities acquired in asset acquisitions | — | | | 9,959 | | |
| Consideration paid in shares for business combinations | — | | | 1,400,784 | | |
| Principal payments on financing obligation to Energos by third party charterers | | Principal payments on financing obligation to Energos by third party charterers | (11,648) | | | — | |
| Shares received in Hilli Exchange | | Shares received in Hilli Exchange | $ | (122,754) | | | $ | — | |
The following table identifies the balance sheet line-items included in Cash and cash equivalents, Current restricted cash, and Non-current restricted cash presented in the Condensed Consolidated Statement of Cash Flows:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2023 | | 2022 |
| Cash and cash equivalents | $ | 296,860 | | | $ | 156,173 | |
| Current restricted cash | 325,298 | | | 74,873 | |
| Non-current restricted cash | — | | | 7,960 | |
| Cash and cash equivalents classified as held for sale | 13,966 | | | — | |
| Cash, cash equivalents and restricted cash – end of period | $ | 636,124 | | | $ | 239,006 | |
Cash and cash equivalents includes $13,966 which has been classified as assets held for sale and included in Other non-current assets on the condensed consolidated balance sheets.
The accompanying notes are an integral part of these condensed consolidated financial statements.
1. Organization
New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. The Company owns and operates natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, MexicoBrazil and Brazil.Mexico. The Company also has marine operations with vessels operating under time charters and in the spot market globally.
The Company currently conducts its business through 2two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business.
2. Basis of presentation
The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 20212022 (the "Annual Report"). Certain prior year amounts have been reclassified to conform to current year presentation.
The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions, impacting the reported amounts of assets and liabilities, net earnings and disclosures of contingent assets and liabilities as of the date of the condensed consolidated financial statements. Actual results could be different from these estimates.
3. Adoption of new and revised standards
(a)New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2022:
The Company has reviewed recently issued accounting pronouncements and concluded that such pronouncements are either not applicable to the Company or no material impact is expected in the condensed consolidated financial statements as a result of future adoption.
(b)New and amended standards adopted by the Company:
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 amendments4. Revenue recognition
Operating revenue in the same period permitted. The adoption of this guidance in the first quarter of 2022 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 Energy Transition Ltd. (“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 "Hygo Merger"). The acquisition of Hygo expanded the Company’s footprint in South America with 3 gas-to-power
projects in Brazil’s large and fast-growing market. Assets acquired as a result of the Hygo Merger included a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), as well as a terminal and power plant under development in the State of Pará, Brazil (the “Barcarena Facility” and "Barcarena Power Plant," respectively), and a terminal under development on the southern coast of Brazil (the “Santa Catarina Facility”). In addition, the Company also acquired included 2 LNG carriers and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility.
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 determined it was the accounting acquirer of Hygo, which was accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction was 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. The final adjusted 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 | |
Construction in process | 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 | 275,410 | |
Other non-current liabilities | 21,520 | |
Total liabilities assumed: | 825,123 | |
Non-controlling interest | 38,306 | |
Net assets acquired: | 1,218,234 | |
Goodwill | $ | 762,550 | |
The fair value of Hygo’s non-controlling interest (“NCI”) as of April 15, 2021 was $38,306, including the fair value of the net assets of VIEs that Hygo has consolidated. These VIEs are SPVs (both defined below) 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 was $8,009, which approximated the gross contractual amount; no material amounts were expected to be uncollectible.
Goodwill was 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 workforce, that will allow the Company to rapidly develop and deploy LNG to power solutions. While the goodwill is not deductible for local tax purposes, it is treated as an amortizable expense for the U.S. global intangible low-taxed income ("GILTI") computation.
The Company’s results of operations for the six months ended June 30, 2022 include Hygo’s result of operations for the entire period. Revenue and net loss attributable to Hygo during the period was $49,391 and $179,826, respectively.
GMLP Merger
On April 15, 2021, the Company completed the acquisition of all of the outstanding common units, representing all voting interests, of Golar LNG Partners LP ("GMLP") in exchange for $3.55 in cash per common unit and for each of the outstanding membership interest of GMLP’s general partner (the "GMLP Merger, and collectively with the Hygo Merger,
the "Mergers"). 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.
As a result of the GMLP Merger, the Company acquired a fleet of 6 FSRUs and 4 LNG carriers, which are expected to help support the Company’s existing facilities and international business development pipeline. Acquired FSRUs are operating in Brazil, Indonesia and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market. Assets acquired also included an interest in a floating natural gas liquefaction vessel ("FLNG"), the Hilli Episeyo (the "Hilli"), 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 determined it is the accounting acquirer of GMLP, which was accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction was 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. The final adjusted 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 | 106,500 | |
Deferred tax assets, net | 963 | |
Other non-current assets | 4,400 | |
Total assets acquired: | $ | 1,604,990 | |
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 | 14,907 | |
Other non-current liabilities | 10,630 | |
Total liabilities assumed: | 277,629 | |
Non-controlling interest | 196,156 | |
Net assets to be acquired: | 1,131,205 | |
Goodwill | $ | 15,938 | |
The fair value of GMLP’s NCI as of April 15, 2021 was $196,156, 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 was $4,797, which approximated the gross contractual amount; no material amounts were 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 was $106,500 and the fair value of the unfavorable contracts was $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 were 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 income (loss) in the second quarter of 2021.
The Company’s results of operations for the six months ended June 30, 2022 include GMLP’s result of operations for the entire period. Revenue and net income attributable to GMLP during the period was $139,674 and $105,970, respectively.
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 June 30, | | Six Months Ended June 30, |
| 2021 | | 2021 |
| Revenue | $ | 239,554 | | | $ | 474,990 | |
| Net income (loss) | 4,438 | | | (48,746) | |
| Net income (loss) attributable to stockholders | 3,904 | | | (46,146) | |
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.
Adjustments for non-recurring items increased pro forma net income by $25,887 and $37,450 for the three and six months ended June 30, 2021, respectively. 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.
Asset acquisitions
On January 12, 2021, the Company acquired 100% of the outstanding shares of CH4 Energia Ltda. (“CH4”), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to 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 long-term 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.
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 included 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 long-term 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.
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
Lessor VIEs
The Company assumed sale leaseback arrangements for 4 vessels as part of the Mergers, one of which was terminated in 2021. As part of these financings, the vessel was sold to a single asset entity wholly owned by the lending bank (a special purpose vehicle or "SPV") and then leased back. While the Company does not hold an equity investment in these lending entities, these entities are variable interest entities ("VIEs"), and the Company has a variable interest in these lending 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. Therefore, the Company consolidates these lending entities; as NFE has no equity interest in these VIEs, all equity attributable to these VIEs is included in non-controlling interest in the consolidated financial statements. Transactions between NFE's wholly-owned subsidiaries and these VIEs are eliminated in consolidation, including sale leaseback transactions.
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.
As of June 30, 2022, the Penguin and Celsius were 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 June 30, 2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Vessel | End of lease term | | Date of next
repurchase
option | | Repurchase price
at next repurchase
option date | | Repurchase
obligation at end of
lease term |
| | | | | | | |
| Nanook | September 2030 | | September 2022 | | $ | 193,066 | | | $ | 94,179 | |
| Penguin | December 2025 | | December 2022 | | 84,668 | | | 63,040 | |
| Celsius | March 2027 | | March 2023 | | 86,456 | | | 45,000 | |
A summary of payment obligations under the bareboat charters with the lessor VIEs as of June 30, 2022, are shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vessel | Remaining 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027+ |
| | | | | | | | | | | |
| Nanook | $ | 12,015 | | | $ | 23,426 | | | $ | 22,698 | | | $ | 21,910 | | | $ | 21,152 | | | $ | 72,595 | |
| Penguin | 6,600 | | | 12,889 | | | 12,379 | | | 8,973 | | | — | | | — | |
| Celsius | 8,504 | | | 61,640 | | | 15,722 | | | 14,976 | | | 13,424 | | | — | |
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 June 30, 2022 are as follows:
| | | | | | | | | | | | | | | | | | | |
| | | Nanook | | Penguin | | Celsius |
| Assets | | | | | | | |
| Restricted cash | | | $ | 14,660 | | | $ | 6,023 | | | $ | 27,983 | |
| Liabilities | | | | | | | |
| Long-term interest bearing debt - current portion | | | $ | — | | | $ | 18,828 | | | $ | 6,085 | |
| Long-term interest bearing debt - non-current portion | | | 187,403 | | | 66,513 | | | 102,793 | |
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 $2,357 and $4,371 for the three and six months ended June 30, 2022.
For the period subsequent to the completion of the Mergers in 2021, the most significant impact of the lessor VIEs operations on the Company’s condensed consolidated statement of operations is a reduction to interest expense of $6,635. 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 premium of $9,707 was recognized as a reduction to interest expense incurred of $3,072.
The most significant impact of the lessor VIEs cash flows on the condensed consolidated statements of cash flows is net cash provided by (used in) financing activities of $8,337 and $(15,823) for the six months ended June 30, 2022 and 2021, respectively. In the second quarter of 2022, COSCO declared a dividend of $4,000, which will be paid in a subsequent period. The declared dividend is recognized as a change to non-controlling interest in the condensed consolidated financial statements.
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 June 30, 2022 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 $382,269 and the outstanding portion of the Hilli Leaseback (defined below) which have been guaranteed by the Company.
PT Golar Indonesia (“PTGI”)
The Company acquired all of the voting stock and controls all of the economic interests in PTGI pursuant to a shareholders’ agreement with the other shareholder of PTGI, PT Pesona Sentra Utama (“PT Pesona”), as part of the acquisition of GMLP. PT Pesona holds the remaining 51% interest in the issued share capital of PTGI and provides agency and local representation services for the Company with respect to NR Satu. PTGI is the owner and operator of NR Satu.
The Company determined that PTGI is a VIE, and the Company is the primary beneficiary of PTGI. Thus, PTGI has been consolidated into the financial statements.
Trade creditors of PTGI have no recourse to the Company's general credit. PTGI paid no dividends to PT Persona during the period after the Mergers.
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, and the sale of LNG cargos. Included in operating revenue for the three months ended March 31, 2023 are LNG cargo sales to customers of $309,030 and $594,201$349,361, of which $169,500 was recognized for a cancellation fee received from a customer to cancel a future delivery. LNG cargo sales for the three and six months ended June 30,March 31, 2022 were , respectively, and $7,211 for the three and six months ended June 30, 2021. $285,171.
Other revenue includes revenue for development services as well as interest income from the Company’s finance leases.
Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of June 30, 2022March 31, 2023 and December 31, 2021,2022, receivables related to revenue from contracts with customers totaled $295,334$196,256 and $192,533,$280,382, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $164$748 and $164,$884, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases which are accounted for outside the scope of ASC 606, and receivables associated with reimbursable costs.costs and the realized gain of a commodity swap of $146,112.
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. TheContract liabilities associated with performance obligations that are expected to be satisfied during the next 12 months andare classified within Other current liabilities on the condensed consolidated balance sheets; when the performance obligation is expected to be satisfied in a
period after 12 months from the balance sheet date, the contract liabilities are classified within Other currentlong-term 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 June 30, 2022March 31, 2023 and December 31, 20212022 are detailed below:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Contract assets, net - current | Contract assets, net - current | $ | 7,766 | | | $ | 7,462 | | Contract assets, net - current | $ | 8,247 | | | $ | 8,083 | |
| Contract assets, net - non-current | Contract assets, net - non-current | 32,763 | | | 36,757 | | Contract assets, net - non-current | 26,538 | | | 28,651 | |
| Total contract assets, net | Total contract assets, net | $ | 40,529 | | | $ | 44,219 | | Total contract assets, net | $ | 34,785 | | | $ | 36,734 | |
| | Contract liabilities | Contract liabilities | $ | 11,201 | | | $ | 2,951 | | Contract liabilities | $ | 36,020 | | | $ | 12,748 | |
| | Revenue recognized in the year from: | Revenue recognized in the year from: | | Revenue recognized in the year from: | |
| Amounts included in contract liabilities at the beginning of the year | Amounts included in contract liabilities at the beginning of the year | $ | 2,951 | | | $ | 8,028 | | Amounts included in contract liabilities at the beginning of the year | $ | 6,809 | | | $ | 2,951 | |
Contract assets are presented net of expected credit losses of $442$376 and $442$401 as of June 30, 2022March 31, 2023 and December 31, 2021,2022, respectively. As of June 30, 2022March 31, 2023 and December 31, 2021,2022, contract assets was comprised of $40,215$34,563 and $43,839$36,483 of unbilled receivables, respectively, thatwhich represent unconditional rights to payment only subject to the passage of time.time, and the reduction to contract assets in the first quarter of 2023 was primarily due to the invoicing of unbilled receivables.
Contract liabilities increased in the first quarter of 2023 due to upfront payments received under the Company's contracts in Puerto Rico to provide temporary power and to operate and maintain PREPA's power generation assets. These payments will be recognized as revenue over the expected term of these contracts.
The Company has recognized costs to fulfill a contractcontracts with a significant customer,customers, which primarily consist of expenses required to enhance resources to deliver under agreements with these customers. These costs can include set-up and mobilization costs incurred ahead of the agreement withservice period, and such costs will be recognized on a straight-line basis over the customer.expected terms of the agreements. As of June 30, 2022,March 31, 2023, the Company has capitalized $10,679$11,632 of which $604$2,010 of these costs is presented within OtherPrepaid expenses and other current assets, net and $10,075$9,622 is presented within Other non-current assets, net on the condensed consolidated balance sheets. As of December 31, 2021,2022, the Company had capitalized $10,981,$10,377, of which $604 of these costs was presented within OtherPrepaid expenses and other current assets, net and $10,377$9,773 was presented within Other non-current assets, net 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 | Period | Revenue | Period | Revenue |
| Remainder of 2022 | $ | 138,274 | | |
| 2023 | 520,335 | | |
| Remainder of 2023 | | Remainder of 2023 | $ | 667,782 | |
| 2024 | 2024 | 516,660 | | 2024 | 1,183,908 | |
| 2025 | 2025 | 507,868 | | 2025 | 770,982 | |
| 2026 | 2026 | 505,729 | | 2026 | 501,753 | |
| 2027 | | 2027 | 498,876 | |
| Thereafter | Thereafter | 8,141,219 | | Thereafter | 7,943,959 | |
| Total | Total | $ | 10,330,085 | | Total | $ | 11,567,260 | |
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 14.12 Property, plant and equipment, net." Vessels included in the Energos Formation Transaction (defined below), including those vessels chartered to third parties, continue to be recognized on the condensed consolidated balance sheet. The following is the carrying amount of property, plant and equipmentthese vessels that isare leased to customersthird parties under operating leases:leases is as follows:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Property, plant and equipment | Property, plant and equipment | $ | 1,276,061 | | | $ | 1,274,234 | | Property, plant and equipment | $ | 896,719 | | | $ | 1,292,957 | |
| Accumulated depreciation | Accumulated depreciation | (55,477) | | | (31,849) | | Accumulated depreciation | (91,385) | | | (80,233) | |
| Property, plant and equipment, net | Property, plant and equipment, net | $ | 1,220,584 | | | $ | 1,242,385 | | Property, plant and equipment, net | $ | 805,334 | | | $ | 1,212,724 | |
The components of lease income from vessel operating leases for the three and six months ended June 30,March 31, 2023 and 2022 and June 30, 2021 were as follows:are shown below. As the Company has not recognized the sale of all of the vessels included in the Energos Formation Transaction, the operating lease income for the three months ended March 31, 2023 includes revenue of $76,524 from third-party charters of vessels included in the Energos Formation Transaction.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| Operating lease income | Operating lease income | $ | 71,682 | | | $ | 62,026 | | | $ | 151,904 | | | $ | 62,026 | | Operating lease income | $ | 76,524 | | | $ | 80,222 | | |
| Variable lease income | Variable lease income | 668 | | | 1,370 | | | 11,232 | | | 1,370 | | Variable lease income | — | | | 10,564 | | |
| Total operating lease income | Total operating lease income | $ | 72,350 | | | $ | 63,396 | | | $ | 163,136 | | | $ | 63,396 | | Total operating lease income | $ | 76,524 | | | $ | 90,786 | | |
The Company’sPrior to the completion of the Energos Formation Transaction, the Company's charter of the Nanook to CELSE (defined below) and certain equipment leases provided in connection with the supply of natural gas or LNG arewas accounted for as a finance leases.
Thelease, and the Company recognized interest income of $11,545 and $23,126$11,581 for the three and six months ended June 30,March 31, 2022 respectively, and $9,681related to this finance lease. The Company also recognized revenue of $1,634 for the three and six months ended June 30, 2021 related to the finance lease of the Nanook, which is included within Other revenue in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized revenue of $2,784 and $4,418 for the three and six months ended June 30,March 31, 2022 respectively, and $1,165 for the three and six months ended June 30, 2021 related to the operation and services agreement and variable charter revenue within Vessel charter revenue in the condensed consolidated statements of operations and comprehensive income (loss).income. The Company recognized the sale of the net investment in the finance lease of the Nanook as part of the Energos Formation Transaction.
As of June 30, 2022, there were outstanding balances due from CELSE of $6,968, of which $4,538 is recognized in Receivables, net and a loan to CELSE of $2,430 was recognized in Prepaid expenses and other current assets, net on the condensed consolidated balance sheets. As of December 31, 2021, there were outstanding balances due from CELSE of $6,428 of which $4,371 was recognized in Receivables, net and a loan to CELSE of $2,057 was recognized in Prepaid expenses and other current assets, net on the condensed consolidated balance sheets. CELSE is an affiliate dueSubsequent to the equity method investment held in CELSE’s parent, CELSEPAR,Energos Formation Transaction, all cash receipts on vessel charters, including the finance lease of the Nanook, will be received by Energos. As such, there are no future cash receipts from operating leases, and as such, these transactions and balancesthe future cash receipts from other finance leases are related party in nature.
The following table shows the expected future lease paymentsnot significant as of June 30, 2022, for the remainder of 2022 through 2026 and thereafter:
| | | | | | | | | | | |
| Future cash receipts |
| Financing Leases | | Operating Leases |
| Remainder of 2022 | $ | 25,248 | | | $ | 137,089 | |
| 2023 | 50,616 | | | 147,375 | |
| 2024 | 51,442 | | | 104,148 | |
| 2025 | 51,876 | | | 25,961 | |
| 2026 | 52,147 | | | — | |
| Thereafter | 1,051,956 | | | — | |
| Total minimum lease receivable | $ | 1,283,285 | | | $ | 414,573 | |
| Unguaranteed residual value | 107,000 | | | |
| Gross investment in sales-type lease | $ | 1,390,285 | | | |
| Less: Unearned interest income | 783,693 | | | |
| Less: Current expected credit losses | 1,551 | | | |
| Net investment in leased asset | $ | 605,041 | | | |
| | | |
| Current portion of net investment in leased asset | $ | 4,156 | | | |
| Non-current portion of net investment in leased asset | 600,885 | | | |
7.5. Leases, as lessee
The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the right-of-use ("ROU") asset and lease liability.
The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or right-of-useROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.
As of June 30, 2022March 31, 2023 and December 31, 2021, right-of-use2022, ROU assets, current lease liabilities and non-current lease liabilities consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Operating right-of-use-assets | Operating right-of-use-assets | $ | 384,938 | | | $ | 285,751 | | Operating right-of-use-assets | $ | 407,553 | | | $ | 355,883 | |
Finance right-of-use-assets | Finance right-of-use-assets | 22,751 | | | 23,912 | | Finance right-of-use-assets | 70,204 | | | 21,994 | |
| Total right-of-use assets | Total right-of-use assets | $ | 407,689 | | | $ | 309,663 | | Total right-of-use assets | $ | 477,757 | | | $ | 377,877 | |
| | Current lease liabilities: | Current lease liabilities: | | Current lease liabilities: | |
| Operating lease liabilities | Operating lease liabilities | $ | 50,156 | | | $ | 43,395 | | Operating lease liabilities | $ | 77,692 | | | $ | 44,371 | |
| Finance lease liabilities | Finance lease liabilities | 3,827 | | | 3,719 | | Finance lease liabilities | 28,974 | | | 4,370 | |
| Total current lease liabilities | Total current lease liabilities | $ | 53,983 | | | $ | 47,114 | | Total current lease liabilities | $ | 106,666 | | | $ | 48,741 | |
| Non-current lease liabilities: | Non-current lease liabilities: | | | | Non-current lease liabilities: | | | |
| Operating lease liabilities | Operating lease liabilities | $ | 316,919 | | | $ | 219,189 | | Operating lease liabilities | $ | 313,822 | | | $ | 290,899 | |
| Finance lease liabilities | Finance lease liabilities | 13,053 | | | 14,871 | | Finance lease liabilities | 35,799 | | | 11,222 | |
| Total non-current lease liabilities | Total non-current lease liabilities | $ | 329,972 | | | $ | 234,060 | | Total non-current lease liabilities | $ | 349,621 | | | $ | 302,121 | |
(1) Finance lease ROU assets are recorded net of accumulated amortization of $3,923 and $2,134 as of March 31, 2023 and December 31, 2022, respectively.
For the three and six months ended June 30,March 31, 2023 and 2022, and 2021, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive income (loss) werewas as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Fixed lease cost | $ | 20,413 | | | $ | 9,036 | | | $ | 38,913 | | | $ | 20,781 | |
| Variable lease cost | 466 | | | 503 | | | 936 | | | 1,196 | |
| Short-term lease cost | 1,897 | | | 1,507 | | | 6,122 | | | 2,229 | |
| | | | | | | |
| Lease cost - Cost of sales | $ | 20,112 | | | $ | 8,993 | | | $ | 41,015 | | | $ | 20,029 | |
| Lease cost - Operations and maintenance | 844 | | | 549 | | | 1,609 | | | 1,106 | |
| Lease cost - Selling, general and administrative | 1,820 | | | 1,504 | | | 3,347 | | | 3,071 | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| Fixed lease cost | $ | 16,368 | | | $ | 18,500 | | | | | |
| Variable lease cost | 597 | | | 470 | | | | | |
| Short-term lease cost | 3,549 | | | 4,225 | | | | | |
| | | | | | | |
| Lease cost - Cost of sales | $ | 15,754 | | | $ | 20,903 | | | | | |
| Lease cost - Operations and maintenance | 2,841 | | | 765 | | | | | |
| Lease cost - Selling, general and administrative | 1,919 | | | 1,527 | | | | | |
For the three months ended June 30,March 31, 2023 and 2022, and 2021, the Company has capitalized $2,973$4,256 and $2,313$8,242 of lease costs, respectively, forrespectively. Capitalized costs include of vessels and port space used during the commissioning of development projects in addition to short-termprojects. 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. For the six months ended June 30, 2022 and 2021, the Company has capitalized $11,215 and $3,512 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 quarterThe Company has leases of 2021, leases forturbines, 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 six months ended June 30,March 31, 2023 and 2022, the Company recognizedCompany’s finance interest expense related to finance leases of $218 and $447 respectively, which is included withinamortization recorded in Interest expense net inand Depreciation and amortization, respectively, within the condensed consolidated statements of operations and comprehensive income (loss). For the three and six months ended June 30, 2022, the Company recognized amortization of the right-of-use asset related to finance leases of $380 and $759, respectively, which are included within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss).
For the three and six months ended June 30, 2021, the Company recognized interest expense related to finance leases of $50, which is included within Interest expense, net in the condensed consolidated statements of operations and comprehensive income (loss). For the three and six months ended June 30, 2021, the Company recognized amortization of the right-of-use asset related to finance leases of $61, respectively, which are included within Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss).
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| Interest expense related to finance leases | $ | 468 | | | $ | 229 | | | | | |
| Amortization of right-of-use asset related to finance leases | 1,789 | | | 379 | | | | | |
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 sixthree months ended June 30, 2022March 31, 2023 and 2021:2022:
| | | Six Months Ended June 30, | | Three Months Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Operating cash outflows for operating lease liabilities | Operating cash outflows for operating lease liabilities | $ | 52,254 | | | $ | 18,354 | | Operating cash outflows for operating lease liabilities | $ | 24,849 | | | $ | 27,122 | |
| Financing cash outflows for finance lease liabilities | Financing cash outflows for finance lease liabilities | 2,554 | | | 654 | | Financing cash outflows for finance lease liabilities | 372 | | | 1,308 | |
| Right-of-use assets obtained in exchange for new operating lease liabilities | Right-of-use assets obtained in exchange for new operating lease liabilities | 134,075 | | | 3,706 | | Right-of-use assets obtained in exchange for new operating lease liabilities | 65,040 | | | 127,451 | |
| Right-of-use assets obtained in exchange for new finance lease liabilities | Right-of-use assets obtained in exchange for new finance lease liabilities | — | | | 8,663 | | Right-of-use assets obtained in exchange for new finance lease liabilities | 49,999 | | | — | |
The future payments due under operating and finance leases as of June 30, 2022March 31, 2023 are as follows:
| | | Operating Leases | | Financing Leases | | Operating Leases | | Financing Leases |
| Due remainder of 2022 | $ | 41,104 | | | $ | 2,359 | | |
| 2023 | 73,754 | | | 4,362 | | |
| Due remainder of 2023 | | Due remainder of 2023 | $ | 79,564 | | | $ | 25,406 | |
| 2024 | 2024 | 67,601 | | | 4,381 | | 2024 | 102,863 | | | 29,997 | |
| 2025 | 2025 | 59,144 | | | 4,381 | | 2025 | 66,893 | | | 11,867 | |
| 2026 | 2026 | 51,161 | | | 2,625 | | 2026 | 51,925 | | | 3,041 | |
| 2027 | | 2027 | 51,464 | | | 436 | |
| Thereafter | Thereafter | 236,512 | | | 1,029 | | Thereafter | 184,056 | | | 941 | |
| Total lease payments | Total lease payments | $ | 529,276 | | | $ | 19,137 | | Total lease payments | $ | 536,765 | | | $ | 71,688 | |
| Less: effects of discounting | Less: effects of discounting | 162,201 | | | 2,257 | | Less: effects of discounting | 145,251 | | | 6,915 | |
| Present value of lease liabilities | Present value of lease liabilities | $ | 367,075 | | | $ | 16,880 | | Present value of lease liabilities | $ | 391,514 | | | $ | 64,773 | |
| | Current lease liability | Current lease liability | $ | 50,156 | | | $ | 3,827 | | Current lease liability | $ | 77,692 | | | $ | 28,974 | |
| Non-current lease liability | Non-current lease liability | 316,919 | | | 13,053 | | Non-current lease liability | 313,822 | | | 35,799 | |
As of June 30, 2022,March 31, 2023, the weighted-averageweighted average remaining lease term for operating leases was 8.57.2 years and finance leases was 4.72.6 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 June 30, 2022both March 31, 2023 and December 31, 20212022 was 8.5% and 8.7% , respectively.. The weighted average discount rate associated with finance leases as of both June 30, 2022March 31, 2023 was 8.3% and as of December 31, 20212022 was 5.1%.
8.6. Financial instruments
Commodity risk management
The Company has utilized commodity swap transactions to manage exposure to changes in market pricing of natural gas or LNG. Realized and unrealized gains and losses on these transactions have been recognized in Cost of sales in the condensed consolidated statements of operations and comprehensive income.
During the fourth quarter of 2022, the Company entered into a commodity swap transaction to swap market pricing exposure for approximately 6.8 TBtus for a fixed price of $40.55 per MMBtu. The swap settled during the first quarter of 2023 resulting in a gain of $41,315 recognized as a reduction to Cost of sales in the condensed consolidated statements of operations and comprehensive income. The gain was comprised of a realized gain of $146,112 and the reversal of the unrealized gain of $104,797 recognized in the fourth quarter of 2022.
In January 2023, the Company entered into a commodity swap transaction. Mark-to-market losses of $5,730 on this instrument have been recognized in Cost of sales in the condensed consolidated statements of operations and comprehensive income.
Interest rate and currency risk management
In connection withThe Company was party to an interest rate swap, and in 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 hedgesfirst quarter of 2023, 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 support repayment of the Brazilian Real-denominated Debenture Loan.
During the second quarter of 2022, the Company entered into 2 foreign currency contingent, non-deliverable forwards to manage foreign currency impacts of the anticipated sale of its interest in CELSEPAR and CEBARRA; see discussion of the Sergipe Sale (all defined below) in Note 12. The forwards are designed to protect the Company's expected proceeds from currency translation loss.
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 June 30, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Instrument | | Notional Amount
(in thousands) | | Maturity Dates | | Fixed
Interest Rate | | Forward Foreign
Exchange Rate |
| Interest rate swap: Receiving floating, pay fixed | | $ | 339,750 | | | March 2026 | | 2.86% | | N/A |
| Cross currency interest rate swap - Debenture Loan, due 2024 | | R$ 198,600 | | September 2024 | | 5.90% | | 5.424 |
| Foreign currency forward purchase | | R$ 2,700,000 | | February 2023 | | N/A | | Based on settlement date |
The mark-to-market gain or loss on the interest rate and foreign currency swapsswap and other derivative instruments that are not designated as hedges for accounting purposesintended to mitigate commodity risk are reported in Other expense (income), net in the condensed consolidated statements of operations and comprehensive income (loss).income.
Fair value
Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:
•Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.
•Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.
•Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.
The valuation techniques that may be used to measure fair value are as follows:
•Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
•Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.
•Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The Company uses the market approach when valuing investment in equity securities which is recorded in Other non-current assets on the condensed consolidated balancesbalance sheets as of June 30,March 31, 2023 and December 31, 2022.
The Company uses the income approach when valuing the following financial instruments:
◦Interest rate swap and cross-currency- The Company did not have any interest rate swaps outstanding as of March 31, 2023. As of December 31, 2022, the Company had an interest rate swap arethat was recorded within Other non-current assets, net on the condensed consolidated balance sheets as of June 30, 2022.sheets.
◦Foreign currency forward purchase – The liability and asset associated with the foreign currency forward purchase iscommodity swaps are recorded within Other current liabilities and Prepaid expenses and other current assets on the condensed consolidated balance sheets as of June 30, 2022.March 31, 2023 and December 31, 2022, respectively.
◦Contingent consideration derivative liability –represents consideration due to the sellers in asset acquisitions when certain contingent events occur. The liability associated with these derivative liabilities is recorded within Other current liabilities and Other long-term liabilities on the condensed consolidated balance sheets as of June 30,March 31, 2023 and December 31, 2022.
The fair value of certain derivative instruments, including interest ratecommodity swaps foreign currency forwards, and cross-currency interest rate swaps. is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties. The Company estimates fair value of the contingent consideration derivative liabilities and the 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 events occurring.
The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of June 30, 2022March 31, 2023 and December 31, 2021:2022:
| | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| June 30, 2022 | | | | | | | | | |
| Assets | | |
| Investment in equity securities | | $ | 10,105 | | | $ | — | | | $ | 7,678 | | | $ | 17,783 | | |
| Cross-currency interest rate swap | | — | | | 2,801 | | | — | | | 2,801 | | |
| Interest rate swap | | — | | | 1,912 | | | — | | | 1,912 | | |
| Foreign currency forward purchase | | — | | | — | | | 17,471 | | | 17,471 | | |
| | Liabilities | | |
| Contingent consideration derivative liabilities | | $ | — | | | $ | — | | | $ | 47,887 | | | $ | 47,887 | | |
| | December 31, 2021 | | |
| March 31, 2023 | | March 31, 2023 | | | | | | | | |
| Assets | Assets | | Assets | |
| Investment in equity securities | Investment in equity securities | | $ | 11,195 | | | $ | — | | | $ | 7,678 | | | $ | 18,873 | | Investment in equity securities | | $ | 12,653 | | | $ | — | | | $ | 7,678 | | | $ | 20,331 | |
| | | | Liabilities | | Liabilities | |
| Commodity swap | | Commodity swap | | $ | — | | | $ | 5,730 | | | $ | — | | | $ | 5,730 | |
| Contingent consideration derivative liabilities | | Contingent consideration derivative liabilities | | — | | | — | | | 44,374 | | | 44,374 | |
| | December 31, 2022 | | December 31, 2022 | |
| Assets | | Assets | |
| Investment in equity securities | | Investment in equity securities | | $ | 10,128 | | | $ | — | | | $ | 7,678 | | | $ | 17,806 | |
| Interest rate swap | | Interest rate swap | | — | | | 11,650 | | | — | | | 11,650 | |
| Commodity swap | | Commodity swap | | — | | | 104,797 | | | — | | | 104,797 | |
| | Liabilities | Liabilities | | Liabilities | |
| Contingent consideration derivative liabilities | Contingent consideration derivative liabilities | | $ | — | | | $ | — | | | $ | 48,849 | | | $ | 48,849 | | Contingent consideration derivative liabilities | | $ | — | | | $ | — | | | $ | 46,619 | | | $ | 46,619 | |
| Cross-currency interest rate swap | | — | | | 2,167 | | | — | | | 2,167 | | |
| Interest rate swap | | — | | | 19,762 | | | — | | | 19,762 | | |
|
The Company believes the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value as of June 30, 2022March 31, 2023 and December 31, 20212022 and are classified as Level 1 within the fair value hierarchy.
The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, including the contingent consideration derivative liabilities, equity agreement, and foreign currency forward purchase.liabilities. These adjustments have been recorded within Other expense (income), net in the condensed consolidated statements of operations and comprehensive income (loss) for the three and six months ended June 30, 2022March 31, 2023 and 2021:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Contingent consideration derivative liabilities - Fair value adjustment - loss (gain) | | $ | 1,385 | | | $ | (288) | | | $ | 984 | | | $ | (713) | |
| | | | | | | | |
| | | | | | | | |
| Foreign currency forward purchase - (gain) | | (17,471) | | | — | | | (17,471) | | | — | |
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| Contingent consideration derivative liabilities - Fair value adjustment - gain | | $ | (3,013) | | | $ | (446) | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
During the sixthree months ended June 30,March 31, 2023 and 2022, and 2021, the Company had no settlements of the equity agreement or derivative liabilitiesother financial instruments or any transfers in or out of Level 3 in the fair value hierarchy.
Under the Company’s interest rate swap, the Company is required to provide cash collateral, and as of June 30, 2022 and December 31, 2021, $2,500 and $12,500, respectively, of cash collateral is presented as restricted cash on the condensed consolidated balance sheets. The interest rate swap has a credit arrangement which requires the Company to provide cash collateral when the market value of the instrument falls below a specified threshold, up to $12,500.
9.7. Restricted cash
As of June 30, 2022March 31, 2023 and December 31, 2021,2022, restricted cash consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Cash held by lessor VIEs | $ | 48,666 | | | $ | 35,651 | | |
| Cash restricted under the terms of loan agreements | | Cash restricted under the terms of loan agreements | $ | 85,819 | | | $ | 124,085 | |
| Collateral for letters of credit and performance bonds | Collateral for letters of credit and performance bonds | 27,639 | | | 27,614 | | Collateral for letters of credit and performance bonds | 239,479 | | | 41,392 | |
| Collateral for interest rate swaps | Collateral for interest rate swaps | 2,500 | | | 12,500 | | Collateral for interest rate swaps | — | | | 2,500 | |
| Other restricted cash | 757 | | | 756 | | |
| | Total restricted cash | Total restricted cash | $ | 79,562 | | | $ | 76,521 | | Total restricted cash | $ | 325,298 | | | $ | 167,977 | |
| | Current restricted cash | Current restricted cash | $ | 71,602 | | | $ | 68,561 | | Current restricted cash | $ | 325,298 | | | $ | 165,396 | |
| Non-current restricted cash | Non-current restricted cash | 7,960 | | | 7,960 | | Non-current restricted cash | — | | | 2,581 | |
As of March 31, 2023, the balance presented as collateral for letters of credit and performance bonds increased as the Company has posted cash does not include minimum consolidated cash balancescollateral of $30,000 required$203,000 to support a letter of credit which will be utilized to facilitate the purchase of turbines that is expected to be maintained as partcompleted in the second quarter of 2023. A portion of these turbines will be utilized to support the financial covenants for sale and leaseback financings andCompany's contract to generate temporary power in Puerto Rico.
Uses of cash proceeds under the VesselBarcarena Term Loan Facility that(see Note 17) are restricted to certain payments to construct the Barcarena Power Plant. Non-current restricted cash is includedpresented in Cash and cash equivalentsOther non-current assets, net on the condensed consolidated balance sheets assheets.
8. Inventory
As of June 30, 2022March 31, 2023 and December 31, 2021.
10. Inventory
As of June 30, 2022, and December 31, 2021, inventory consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| LNG and natural gas inventory | LNG and natural gas inventory | $ | 38,161 | | | $ | 16,815 | | LNG and natural gas inventory | $ | 50,038 | | | $ | 15,398 | |
| Automotive diesel oil inventory | Automotive diesel oil inventory | 8,443 | | | 4,789 | | Automotive diesel oil inventory | 9,270 | | | 8,164 | |
| Bunker fuel, materials, supplies and other | Bunker fuel, materials, supplies and other | 25,548 | | | 15,578 | | Bunker fuel, materials, supplies and other | 17,228 | | | 15,508 | |
| Total inventory | Total inventory | $ | 72,152 | | | $ | 37,182 | | Total inventory | $ | 76,536 | | | $ | 39,070 | |
Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).income. No adjustments were recorded during the sixthree months ended June 30, 2022March 31, 2023 and 2021.2022.
11.9. Prepaid expenses and other current assets
As of June 30, 2022March 31, 2023 and December 31, 2021,2022, prepaid expenses and other current assets consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Prepaid expenses | Prepaid expenses | $ | 55,972 | | | $ | 19,951 | | Prepaid expenses | $ | 24,701 | | | $ | 56,380 | |
| Recoverable taxes | Recoverable taxes | 34,517 | | | 33,053 | | Recoverable taxes | 47,989 | | | 37,504 | |
| Derivative assets | 17,471 | | | — | | |
| Commodity swap | | Commodity swap | — | | | 104,797 | |
| Due from affiliates | Due from affiliates | 3,362 | | | 3,299 | | Due from affiliates | 890 | | | 698 | |
| Other current assets | Other current assets | 29,770 | | | 26,812 | | Other current assets | 28,671 | | | 27,504 | |
| Total prepaid expenses and other current assets, net | Total prepaid expenses and other current assets, net | $ | 141,092 | | | $ | 83,115 | | Total prepaid expenses and other current assets, net | $ | 102,251 | | | $ | 226,883 | |
Prepaid expenses includes $33,404included $4,821 and $11$34,882 of prepaid LNG inventory as of June 30, 2022March 31, 2023 and December 31, 2021,2022, respectively. Other current assets as of June 30, 2022March 31, 2023 and December 31, 20212022 primarily consists of deposits, as well as the current portion of contract assets (Note 6) and finance leases (Note 6)4).
12.10. 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:
| | | | | | | |
| June 30, 2022March 31, 2023 | | |
Equity method investments as of December 31, 20212022 | $ | 1,182,013392,306 | | | |
| | | |
| Dividends | (14,858)(5,830) | | | |
| Equity in earnings of investees | 22,7559,980 | | | |
| | | |
Other-than-temporary impairmentSale of equity method investments | (345,447)(260,156) | | | |
Foreign currency translation adjustment | 95,275 | | |
Equity method investments as of June 30, 2022March 31, 2023 | $ | 939,738136,300 | | | |
The carrying amountamounts of the Company's equity method investments as of June 30,March 31, 2023 and December 31, 2022 is as follows:are:
| | | | | |
| June 30, 2022 |
Hilli LLC | $ | 382,269 | |
CELSEPAR | 557,469 | |
Total | $ | 939,738 | |
| | | | | | | | | | | |
| | | |
| March 31, 2023 | | December 31, 2022 |
| Hilli LLC | $ | — | | | $ | 260,000 | |
| Energos | 136,300 | | | 132,306 | |
| Total | $ | 136,300 | | | $ | 392,306 | |
As of June 30, 2022 andMarch 31, 2023, the carrying value of the Company’s equity method investments was less than its proportionate share of the underlying net assets of its investees by $1,548. At December 31, 2021,2022, the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $423,684 and $792,995, respectively,$16,976, 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.
On May 31, 2022, LNG Power Limited (“LNG Power”), an indirect subsidiary of NFE and direct owner of the CELSEPAR investment, and certain Ebrasil sellers as owners of CELSEPAR (together with LNG Power, the “Sergipe Sellers”), Eneva S.A., as purchaser ("Eneva") and Eletricidade do Brasil S.A. -- Ebrasil, entered into a Share Purchase Agreement (“SPA”) pursuant to which Eneva has agreed to acquire all of the outstanding shares of (a) CELSEPAR and (b) Centrais Elétricas Barra dos Coqueiros S.A. ("CEBARRA"), which owns 1.7 GW of expansion rights adjacent to the Sergipe Power Plant, for a purchase price of R$6.10 billion in cash (approximately $1.17 billion using the exchange rate as of June 30, 2022) (the “Sergipe Sale”).
The purchase price payable by Eneva accrues interest at a rate of CDI + 1% from December 31, 2021 until the date of the Closing (as defined below) and is subject to certain customary adjustments, including for the amount of any leakage that has occurred from December 31, 2021 to the date of the Closing, including (a) making distributions or payments to or for the benefit of Sergipe Sellers and their affiliates and assuming or incurring liabilities for the benefit of Sergipe Sellers or their affiliates, and (b) certain fees and expenses incurred by CELSEPAR and CEBARRA in connection with the Sergipe Sale. LNG Power also entered into a foreign currency forward associated to mitigate foreign currency risk to the expected proceeds from the transaction and will settle at the same time as Closing.
Under the SPA, the closing of the Sergipe Sale (the “Closing”) will occur on the later of (a) October 3, 2022 and (b) the 10th business day after all conditions to Closing have been satisfied or waived, or as otherwise agreed to among the parties. The conditions to Closing include receipt of all required regulatory approvals, receipt of certain specified material third-party consents and the approval of the Sergipe Sale by Eneva’s shareholders. The Sergipe Sale may be terminated under certain circumstances, including, among others, (a) by either Eneva or Sergipe Sellers if Closing has not occurred on or before the date that is 270 days from the execution date of the SPA, (b) automatically if the Sergipe Sale is not approved by
Eneva’s shareholders. The SPA further provides that, (i) upon termination of the SPA under certain circumstances, Eneva will be required to pay Sergipe Sellers a reverse termination fee equal to R$300 million and (ii) upon termination of the SPA under certain other circumstances, Sergipe Sellers will be required to pay Eneva a termination fee equal to R$250 million.
In connection with the Sergipe Sale, the Company has recognized an other than temporary impairment ("OTTI") of the investment in CELSEPAR of $345,447, and this loss has been recognized in loss (income)Income from equity method investments in the condensed consolidated statements of operations and comprehensive income (loss). Nonrecurring, Level 2 inputs were used to estimateover the fair valueremaining estimated useful lives of the investment for the purpose of recognizing the OTTI. Upon closing, the Company expects to recognize transaction costs associated with the sale of CELSEPAR.underlying assets.
Hilli LLC
On March 15, 2023, the Company completed a transaction with Golar LNG Limited for the sale of the Company's investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100,000 in cash (the "Hilli Exchange"). In the fourth quarter of 2022, the Company recognized an other-than-temporary impairment on the investment in Hilli LLC of $118,558; this impairment was recognized in Loss from equity method investments in the consolidated statements of operations and comprehensive income. Upon completion of the Hilli Exchange, a loss on disposal of $37,401 was recognized in Other expense (income), net in the condensed consolidated statements of operations and comprehensive income. As a result of the Hilli Exchange, the Company no longer has an ownership interest in the Hilli. NFE shares received from GLNG were cancelled upon closing of the Hilli Exchange.
The Company acquiredhad guaranteed 50% of the outstanding principal and interest amounts payable by Hilli Common UnitsCorp., a direct subsidiary of Hilli LLC. The Company had also guaranteed letters of credit issued by a financial institution in the event of Hilli Corp.’s underperformance or non-performance under the liquefaction tolling agreement with its customer. In conjunction with the Hilli Exchange, the Company is no longer a guarantor under these arrangements, and the remaining guarantee liability of $2,286 was derecognized as parta reduction to Selling, general and administrative in the condensed consolidated statements of operations in the three months ended March 31, 2023.
Energos
On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), completed a sales and financing transaction resulting in cash proceeds of approximately $1.85 billion. This sales and financing transaction comprised (1) the formation of a limited liability company doing business as Energos Infrastructure ("Energos"), (2) the sale for cash of eight vessels, along with these vessels' owning and operating entities to the Purchaser, (3) the contribution of acquired vessel owning entities to Energos by the Purchaser and (4) the Company's contribution of threevessels, along with each vessels' owning and operating entities, to Energos in exchange for equity in Energos (the “Energos Formation Transaction”).
As a result of the GMLP Merger. 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 provideEnergos Formation Transaction, the Company owns an approximately 20% equity interest in Energos, with the remaining interest owned by the Purchaser. The Company's equity investment provides certain rights, including representation on the board of directors, which give the Company significant influence over Hilli LLC. The Hillithe operations of Energos, and as such, the investment has been accounted for under the equity method; this investment is currently operating underincluded within the Ships segment. Energos is also an 8-year liquefaction tolling agreement (“LTA”)affiliate, and all transactions with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures.Energos are transactions with an affiliate.
Within 60 days after the end of each quarter, GLNG, the managing member of Hilli LLC, determines the amount of Hilli LLC’s available cash and appropriate reserves, and Hilli LLC makes a distributionDue to the unitholderstiming and availability of Hilli LLCfinancial information of Energos, the Company recognizes its proportional share of the available cash, subject to such reserves. Hilli LLC makes distributions when declared by GLNG, provided that no distributions may be madeincome or loss from the equity method investment on the Hilli Common Units unless current and accumulated Series A Distributions and Series B Distributions have been paid.
The Company is required to reimburse other investors in Hilli LLC or may receive reimbursements from other investors in Hilli LLC for 50%a financial reporting lag of the amount, if any, by which certain operating expenses and withholding taxes of Hilli LLC are above or below an annual threshold. Duringone fiscal quarter. For the three and six months ended June 30, 2022, operating expense reimbursements did not significantly impact distributions made by Hilli LLC.March 31, 2023, the Company has recognized earnings from Energos of $3,994.
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 post construction financing for the Hilli in the amount of $960 million. Under the Hilli Leaseback, Hilli Corp will pay to Fortune 40 consecutive equal quarterly repayments of 1.375% of the construction cost, plus interest based on LIBOR plus a margin of 4.15%.
11. Construction in progress
The Company’s construction in progress activity during the sixthree months ended June 30, 2022March 31, 2023 is detailed below:
| | | | | | | |
| June 30, 2022March 31, 2023 | | |
Balance at beginningConstruction in progress as of periodDecember 31, 2022 | $ | 1,043,8832,418,608 | | | |
| | | |
| Additions | 437,539931,823 | | | |
Asset impairment expense | (48,109) | | |
| Impact of currency translation adjustment | 18,9938,387 | | | |
| Transferred to property, plant and equipment, net | (50,838)(1,384) | | | |
Balance at endConstruction in progress as of periodMarch 31, 2023 | $ | 1,401,4683,357,434 | | | |
Interest expense of $29,495$50,976 and $9,310,$13,137, inclusive of amortized debt issuance costs, was capitalized for the sixthree months ended June 30,March 31, 2023 and 2022, and 2021, respectively.
The Company’sCompany has significant development activities are primarily in Latin America as well as the development of the Company's Fast LNG floating liquefaction solution, and the completion of such development isdevelopments are subject to risks related toof successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.
The assets of CEBARRACompany's development activities for the three months ended March 31, 2023 were primarily consist offocused on Fast LNG; additions to construction in progress and in conjunction with the Sergipe Sale, the assets of CEBARRA meet the criteria to be presented as held for sale. These assets were measured at fair value, less costs to sell, upon classification to held for sale, and the Company recognized an impairment loss of $48,109 in Asset impairment expensein the condensed consolidated statementsfirst quarter of operations and comprehensive income (loss) in the Terminals and Infrastructure Segment. The fair value2023 of assets that are held for sale are not significant and have not presented separately as held for sale on the condensed consolidated balance sheets. Nonrecurring, Level 2 inputs$767,607 were used to estimate the fair value of the investment for the purpose of recognizing the asset impairment. As of June 30, 2022, no other indicators of impairment have been identified.develop Fast LNG projects.
14.12. Property, plant and equipment, net
As of June 30, 2022March 31, 2023 and December 31, 2021,2022, the Company’s property, plant and equipment, net consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Vessels | Vessels | $ | 1,510,730 | | | $ | 1,461,211 | | Vessels | $ | 1,518,839 | | | $ | 1,518,839 | |
| Terminal and power plant equipment | Terminal and power plant equipment | 216,662 | | | 206,889 | | Terminal and power plant equipment | 218,572 | | | 218,296 | |
| CHP facilities | CHP facilities | 123,605 | | | 122,777 | | CHP facilities | 125,015 | | | 123,897 | |
| Gas terminals | Gas terminals | 169,715 | | | 167,614 | | Gas terminals | 177,780 | | | 177,780 | |
| ISO containers and other equipment | ISO containers and other equipment | 138,070 | | | 134,775 | | ISO containers and other equipment | 134,924 | | | 134,324 | |
| LNG liquefaction facilities | LNG liquefaction facilities | 63,316 | | | 63,213 | | LNG liquefaction facilities | 63,316 | | | 63,316 | |
| Gas pipelines | Gas pipelines | 65,850 | | | 58,987 | | Gas pipelines | 66,319 | | | 65,985 | |
| Land | Land | 53,866 | | | 55,008 | | Land | 53,737 | | | 52,995 | |
| Leasehold improvements | Leasehold improvements | 9,377 | | | 9,377 | | Leasehold improvements | 10,252 | | | 9,377 | |
| Accumulated depreciation | Accumulated depreciation | (194,760) | | | (141,915) | | Accumulated depreciation | (274,337) | | | (248,082) | |
| Total property, plant and equipment, net | Total property, plant and equipment, net | $ | 2,156,431 | | | $ | 2,137,936 | | Total property, plant and equipment, net | $ | 2,094,417 | | | $ | 2,116,727 | |
The book value of the vessels that was recognized due to the failed sale leaseback in the Energos Formation Transaction as of March 31, 2023 and December 31, 2022 was $1,315,661 and $1,328,553, respectively.
Depreciation expense for the three months ended June 30,March 31, 2023 and 2022 totaled $26,000 and 2021 totaled $25,958 and $21,299,$26,109, respectively, of which $228$231 and $307,$563, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss). Depreciation expense for the six months ended June 30, 2022 and 2021 totaled $52,067 and $31,141, respectively, of which $527 and $576, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).
Capitalized drydocking costs of $18,854 and $5,914 are included in the vessel cost for June 30, 2022 and December 31, 2021, respectively, which are depreciated from the completion of drydocking until the next expected drydocking.
15.13. Goodwill and intangible assets
Goodwill
The following table summarizes the changes in the carrying amount of goodwill was $776,760 as of both June 30, 2022March 31, 2023 and December 31, 2021, all of which was included within the Terminals and Infrastructure segment.2022
| | | | | |
| Goodwill |
Balance as of December 31, 2021
| $ | 760,135 | |
Adjustment | 18,353 | | |
Balance as of June 30, 2022
| $ | 778,488 | |
| | | |
| | | |
| | | |
Intangible assets
The following table summarizestables summarize the composition of intangible assets as of June 30, 2022March 31, 2023 and December 31, 2021:2022:
| | | June 30, 2022 | | March 31, 2023 |
| | Gross Carrying
Amount | | Accumulated
Amortization | | Currency Translation
Adjustment | | Net Carrying
Amount | | Weighted
Average Life | | Gross Carrying
Amount | | Accumulated
Amortization | | Currency Translation
Adjustment | | Net Carrying
Amount | | Weighted
Average Life |
| Definite-lived intangible assets | Definite-lived intangible assets | | | | | | | | | | Definite-lived intangible assets | | | | | | | | | |
| Favorable vessel charter contracts | Favorable vessel charter contracts | $ | 106,500 | | | $ | (46,185) | | | $ | — | | | $ | 60,315 | | | 3 | Favorable vessel charter contracts | $ | 106,500 | | | $ | (71,098) | | | $ | — | | | $ | 35,402 | | | 3 |
| Permits and development rights | Permits and development rights | 48,217 | | | (3,543) | | | (2,959) | | | 41,715 | | | 38 | Permits and development rights | 48,217 | | | (4,452) | | | (1,234) | | | 42,531 | | | 38 |
| Acquired power purchase agreements | 16,585 | | | (1,347) | | | 1,447 | | | 16,685 | | | 17 | |
| | Easements | Easements | 1,556 | | | (269) | | | — | | | 1,287 | | | 30 | Easements | 1,556 | | | (307) | | | — | | | 1,249 | | | 30 |
| | Indefinite-lived intangible assets | Indefinite-lived intangible assets | | Indefinite-lived intangible assets | |
| Easements | Easements | 1,191 | | | — | | | (105) | | | 1,086 | | | n/a | Easements | 1,191 | | | — | | | (61) | | | 1,130 | | | n/a |
| Total intangible assets | Total intangible assets | $ | 174,049 | | | $ | (51,344) | | | $ | (1,617) | | | $ | 121,088 | | | Total intangible assets | $ | 157,464 | | | $ | (75,857) | | | $ | (1,295) | | | $ | 80,312 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 |
| Gross Carrying
Amount | | Accumulated
Amortization | | Currency Translation
Adjustment | | Net Carrying
Amount | | Weighted
Average Life |
| Definite-lived intangible assets | | | | | | | | | |
| Favorable vessel charter contracts | $ | 106,500 | | | $ | (27,074) | | | $ | — | | | $ | 79,426 | | | 3 |
| Permits and development rights | 48,217 | | | (3,311) | | | (119) | | | 44,787 | | | 38 |
| Acquired power purchase agreements | 16,585 | | | (750) | | | 406 | | | 16,241 | | | 17 |
| Easements | 1,556 | | | (243) | | | — | | | 1,313 | | | 30 |
| | | | | | | | | |
| Indefinite-lived intangible assets | | | | | | | | | |
| Easements | 1,191 | | | — | | | (14) | | | 1,177 | | | n/a |
| Total intangible assets | $ | 174,049 | | | $ | (31,378) | | | $ | 273 | | | $ | 142,944 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 |
| Gross Carrying
Amount | | Accumulated
Amortization | | Currency Translation
Adjustment | | Net Carrying
Amount | | Weighted
Average Life |
| Definite-lived intangible assets | | | | | | | | | |
| Favorable vessel charter contracts | $ | 106,500 | | | $ | (64,836) | | | $ | — | | | $ | 41,664 | | | 3 |
| Permits and development rights | 48,217 | | | (4,115) | | | (2,239) | | | 41,863 | | | 38 |
| Easements | 1,556 | | | (294) | | | — | | | 1,262 | | | 30 |
| | | | | | | | | |
| Indefinite-lived intangible assets | | | | | | | | | |
| Easements | 1,191 | | | — | | | (83) | | | 1,108 | | | n/a |
| Total intangible assets | $ | 157,464 | | | $ | (69,245) | | | $ | (2,322) | | | $ | 85,897 | | | |
Amortization expense for the three months ended June 30,March 31, 2023 and 2022 was $6,796 and 2021 was $9,959 and $5,925,$8,343, respectively. Amortization expense for the sixthree months ended June 30,March 31, 2022 and 2021 was $18,302 and $6,220, respectively. Amortization expense is inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed inliabilities.
Intangible assets associated with the Mergers.acquired power purchase agreements have been classified as held for sale as of March 31, 2023 and December 31, 2022; no impairment loss was recognized upon classification as held for sale (See Note 14).
16.14. Other non-current assets, net
As of June 30, 2022March 31, 2023 and December 31, 2021, other2022, Other non-current assets consisted of the following:
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Contract assets, net (Note 6) | $ | 32,763 | | | $ | 36,757 | |
| Investments in equity securities (Note 8) | 17,783 | | | 18,873 | |
| Cost to fulfill (Note 6) | 10,075 | | | 10,377 | |
| Upfront payments to customers | 9,453 | | | 9,748 | |
| Other | 25,295 | | | 22,663 | |
| Total other non-current assets, net | $ | 95,369 | | | $ | 98,418 | |
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| Assets held for sale | $ | 45,652 | | | $ | 40,685 | |
| Contract assets, net (Note 4) | 26,538 | | | 28,651 | |
| Investments in equity securities (Note 6) | 20,331 | | | 17,806 | |
| Cost to fulfill (Note 4) | 9,622 | | | 9,773 | |
| Upfront payments to customers | 9,010 | | | 9,158 | |
| Other | 27,402 | | | 35,606 | |
| Total other non-current assets, net | $ | 138,555 | | | $ | 141,679 | |
The Company recognized an unrealized loss of $898 and unrealized gain of $88gains / (losses) on its investments in equity securities of $2,525 and $(192) for the three months ended June 30,March 31, 2023 and 2022, and 2021, respectively, within Other expense (income), net in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized an unrealized loss on its investments in equity securities of $1,090 and $49 for the six months ended June 30, 2022 and 2021, respectively, within Other (income), net in the condensed consolidated statements of operations and comprehensive income (loss).income. Investments in equity securities include investments without a readily determinable fair value of $7,678 as of June 30, 2022March 31, 2023 and December 31, 2021.
Upfront payments to customers consist of amounts the Company has paid in relation to 2two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own. Other non-current assets includes deferred financing costs related to the Revolving Facility.
Assets held for sale
All assets and liabilities of Pecém and Muricy were classified as held for sale as of March 31, 2023 and December 31, 2022. The estimated fair value of these entities based on the consideration in the agreement was in excess of the carrying value, and no impairment loss was recognized upon classification as held for sale. The assets and liabilities held for sale have not been classified as a separate financial statement line item on the condensed consolidated balance sheets and are presented as Other non-current assets and Other long-term liabilities. Liabilities held for sale of $24,151 and $23,543 are presented as other long-term liabilities as of March 31, 2023 and December 31, 2022, respectively. Assets held for sale include a cash balance of $13,966 and $11,614 as of March 31, 2023 and December 31, 2022, respectively, which have been included in the ending cash and cash equivalents on the condensed consolidated statement of cash flows.
15. Accrued liabilities
As of June 30, 2022March 31, 2023 and December 31, 2021,2022, accrued liabilities consisted of the following:
| | | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| Accrued development costs | Accrued development costs | $ | 64,428 | | | $ | 101,177 | | Accrued development costs | $ | 507,503 | | | $ | 364,157 | |
| Accrued vessel operating and drydocking expenses | 10,870 | | | 12,767 | | |
| Accrued interest | Accrued interest | 62,629 | | | 61,630 | | Accrued interest | 12,106 | | | 51,994 | |
| Accrued bonuses | Accrued bonuses | 14,160 | | | 27,591 | | Accrued bonuses | 12,063 | | | 37,739 | |
| | Accrued dividend | | Accrued dividend | — | | | 626,310 | |
| Other accrued expenses | Other accrued expenses | 84,448 | | | 40,860 | | Other accrued expenses | 71,256 | | | 82,212 | |
| Total accrued liabilities | Total accrued liabilities | $ | 236,535 | | | $ | 244,025 | | Total accrued liabilities | $ | 602,928 | | | $ | 1,162,412 | |
As of June 30,March 31, 2023 and December 31, 2022, the balance presented as other accrued expenses includes accruals of $44,353$11,304 and $45,511, respectively, for inventory purchases completed inprior to the second quarterend of 2022.the period.
18.16. Other current liabilities
As of June 30, 2022March 31, 2023 and December 31, 20212022, other current liabilities consisted of the following:
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Derivative liabilities | $ | 19,442 | | | $ | 41,815 | |
| Deferred revenue | 30,515 | | | 28,662 | |
| Income tax payable | 19,452 | | | 8,881 | |
| | | |
| Due to affiliates | 10,326 | | | 9,088 | |
| Other current liabilities | 14,551 | | | 17,590 | |
| Total other current liabilities | $ | 94,286 | | | $ | 106,036 | |
Deferred revenue includes contract liabilities and prepayments received from lessees under charter agreements. Other current liabilities includes the value of unfavorable contracts assumed in the Mergers. | | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| Derivative liabilities | $ | 23,925 | | | $ | 19,458 | |
| Contract liabilities (Note 4) | 36,020 | | | 12,748 | |
| Income tax payable | 26,592 | | | 6,261 | |
| | | |
| Due to affiliates | 4,980 | | | 7,499 | |
| Other current liabilities | 7,758 | | | 6,912 | |
| Total other current liabilities | $ | 99,275 | | | $ | 52,878 | |
19.17. Debt
As of June 30, 2022March 31, 2023 and December 31, 2021,2022, debt consisted of the following:
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Senior Secured Notes, due September 2025 | $ | 1,242,255 | | | $ | 1,241,196 | |
| Senior Secured Notes, due September 2026 | 1,479,528 | | | 1,477,512 | |
| Vessel Term Loan Facility, due September 2024 | 379,474 | | | 408,991 | |
| Debenture Loan, due September 2024 | 37,851 | | | 40,665 | |
| South Power 2029 Bonds, due May 2029 | 215,782 | | | 96,820 | |
| Revolving Facility | 415,000 | | | 200,000 | |
| Subtotal (excluding lessor VIE loans) | 3,769,890 | | | 3,465,184 | |
| CCBFL VIE loan: | | | |
| Golar Nanook SPV facility, due September 2030 | 187,403 | | | 186,638 | |
| COSCO VIE loan: | | | |
| Golar Penguin SPV facility, due December 2025 | 85,341 | | | 90,035 | |
| AVIC VIE loan: | | | |
| Golar Celsius SPV facility, due May 2027 | 108,878 | | | 113,273 | |
| Total debt | $ | 4,151,512 | | | $ | 3,855,130 | |
| Current portion of long-term debt | $ | 99,756 | | | $ | 97,251 | |
| Long-term debt | 4,051,756 | | | 3,757,879 | |
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| Senior Secured Notes, due September 2025 | $ | 1,243,914 | | | $ | 1,243,351 | |
| Senior Secured Notes, due September 2026 | 1,482,722 | | | 1,481,639 | |
| Vessel Financing Obligation, due August 2042 | 1,388,535 | | | 1,406,091 | |
| South Power 2029 Bonds, due May 2029 | 216,373 | | | 216,177 | |
| Barcarena Term Loan, due February 2024 | 197,036 | | | 194,427 | |
| Revolving Facility | 700,000 | | | — | |
| Total debt | $ | 5,228,580 | | | $ | 4,541,685 | |
| Current portion of long-term debt | $ | 277,035 | | | $ | 64,820 | |
| Long-term debt | 4,951,545 | | | 4,476,865 | |
Long-term debt is recorded at amortized cost on the condensed consolidated balance sheets. The fair value of the Company's long-term debt is
$3,987,845$5,086,118 and
$3,910,425$4,327,311 as of
June 30, 2022March 31, 2023 and December 31,
2021,2022, respectively, and is classified as Level 2 within the fair value hierarchy.
Our outstanding debt as of June 30, 2022 is repayable as follows:
| | | | | |
| June 30, 2022 |
| Due remainder of 2022 | $ | 44,361 | |
| 2023 | 132,614 | |
| 2024 | 323,781 | |
| 2025 | 1,330,232 | |
| 2026 | 1,949,555 | |
| Thereafter | 410,483 | |
| Total debt | $ | 4,191,026 | |
| Less: fair value adjustments to assumed debt obligations | (779) | |
| Less: deferred finance charges | (38,735) | |
| Total debt, net deferred finance charges | $ | 4,151,512 | |
The terms of the Company's debt instruments have been described in the Annual Report. There have been no significantReport on Form 10-K. Significant changes to the Company's outstanding debt other thanare described below.
South Power 2029 Bonds
In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000. The CHP Facility was secured by a mortgage over the lease of the site on which the Company’s combined heat and power plant in Clarendon, Jamaica (“CHP Plant”) is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285,000 in South Power 2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. During the six months ended June 30, 2022, the Company issued $121,845, of South Power 2029 Bonds for a total amount outstanding of $221,845 as of June 30, 2022.
The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.
South Power will be required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provides for customary events of default, prepayment and cure provisions.
In conjunction with obtaining the CHP Facility, the Company incurred $3,243 in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional third-party fees associated with such lenders of $258 were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the condensed consolidated balance sheets. As of June 30, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $6,063 and $3,180, respectively.
Revolving Facility
In April 2021, the Company entered into a $200,000 senior secured revolving credit 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). In February and May 2022, the Revolving Facility was amended to increase the borrowing capacity by $115,000 and $125,000, respectively, for a total capacityborrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of $440,000. Letters of credit issued under the $100,000 letter of credit sub-facility may be used for general corporate purposes.Revolving Facility. The Revolving Facility will maturematures in 2026,2025, with the potential for the Company to extend the maturity date once in a one-year increment.
Borrowings under the Revolving Facility bear interest at a rate equal to Secured Overnight Financing Rate ("SOFR") plus 0.15% 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 SOFR plus 0.15% 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% SOFR floor. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.
The obligations underIn 2022, the Revolving Facility are guaranteedwas amended twice to increase the borrowing capacity by certaina total of $240,000, and in February 2023, the Company entered into an amendment which increased the borrowing capacity by $301,700, for a total capacity of $741,700. The amendments did not impact the interest rate or term of the Company's subsidiaries, in addition to other collateral.Revolving Facility, and no deferred costs were written off.
The Company incurred $5,398 in origination, structuring and other fees, associated with entry into the Revolving Facility.Facility, which includes additional fees to expand the facility in 2022. During the first quarter of 2023, the Company incurred an additional $4,965 in fees in relation to the 2023 amendment. These costs have been capitalized within Other non-current assets on the condensed consolidated balance sheets. As of June 30, 2022March 31, 2023 and December 31, 20212022, total remaining unamortized deferred financing costs for the Revolving Facility was $5,023$9,560 and $3,807,$5,172, respectively.
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 June 30, 2022, the Company was in compliance with all covenants under debt and lease agreements.
Financial covenants under GMLP's Vessel Term Loan Facility include requirements that GMLP and the borrowing subsidiary 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 million, each as defined in the Vessel Term Loan Facility. GMLP was in compliance with these covenants as of June 30, 2022. Obligationsobligations under the Vessel Term LoanRevolving Facility are guaranteed by GMLP and certain of GMLP'sthe Company's subsidiaries. Lenders have been granted a security interest covering 3 floating storage and regasification vessels and 4 LNG carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of June 30, 2022, the aggregate net book value of the three floating storage and regasification vessels and four LNG carriers pledged as security was approximately $660,825.
The Company is also required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023.2023 and onwards. The Company was in compliance with all covenants as of June 30, 2022.March 31, 2023.
Interest Expenseexpense
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 six months ended June 30,March 31, 2023 and 2022 and 2021 consisted of the following:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| Interest per contractual rates | Interest per contractual rates | $ | 60,662 | | | $ | 46,471 | | | $ | 116,011 | | | $ | 67,305 | | Interest per contractual rates | $ | 64,259 | | | $ | 55,349 | | |
| Interest expense on Vessel Financing Obligation | | Interest expense on Vessel Financing Obligation | 54,330 | | | — | | |
| Amortization of debt issuance costs, premiums and discounts | Amortization of debt issuance costs, premiums and discounts | 3,318 | | | (8,370) | | | 5,793 | | | (7,883) | | Amortization of debt issuance costs, premiums and discounts | 3,592 | | | 2,475 | | |
| Interest expense incurred on finance lease obligations | Interest expense incurred on finance lease obligations | 218 | | | 50 | | | 447 | | | 50 | | Interest expense incurred on finance lease obligations | 468 | | | 229 | | |
| Total interest costs | Total interest costs | $ | 64,198 | | | $ | 38,151 | | | $ | 122,251 | | | $ | 59,472 | | Total interest costs | $ | 122,649 | | | $ | 58,053 | | |
| Capitalized interest | Capitalized interest | 16,358 | | | 6,669 | | | 29,495 | | | 9,310 | | Capitalized interest | 50,976 | | | 13,137 | | |
| Total interest expense | Total interest expense | $ | 47,840 | | | $ | 31,482 | | | $ | 92,756 | | | $ | 50,162 | | Total interest expense | $ | 71,673 | | | $ | 44,916 | | |
20.18. Income taxesTaxes
The effective tax rate for the three months ended June 30, 2022 March 31, 2023 was 32.7%,16.0% compared to 164.8%(25.9)% for the three months ended June 30, 2021.March 31, 2022. The total tax benefitprovision for the three months ended June 30, 2022March 31, 2023 was $86,539,$28,960 compared to a provision
benefit of $49,681 for the three months ended June 30, 2021. TheMarch 31, 2022. Our prior year benefit and effective tax rate for the six months ended June 30, 2022 was 185.4%, compared to (9.4)% for the six months ended June 30, 2021. The total tax benefit for the six months ended June 30, 2022 was $136,220, compared to a provision of $3,532 for the six months ended June 30, 2021. The calculation of the effective tax rate for the period after the Mergers includes income from equity method investments.
The decrease to the effective tax rate for the three and six months ended June 30, 2022 resulted principally fromprimarily driven by significant discrete items, including the remeasurement of a deferred income tax liability in conjunction with an internal reorganization and tax benefit associated with the OTTI impairment of the investmentreorganization. The Company has not recognized any significant discrete items in CELSEPAR. In the first quarter of 2022, the Company’s equity method investment in CELSEPAR was distributed to a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil, and this reorganization resulted in a discrete tax benefit of $76,460. Additionally, in the second quarter of 2022, the Company recognized additional discrete benefits of $100,627, primarily due to OTTI, asset impairment expense and the impacts of changes in foreign currency exchange rates. This increase in tax benefit for the three and six months ended June 30, 2022 was offset in part by an increase in pretax income for certain profitable operations, including GMLP and Hygo, which resulted in income tax expense for the three and six months ended June 30, 2022.
During the second quarter of 2021, the Company assumed a liability for tax contingencies in the Mergers primarily related to potential tax obligations for payments under certain charter agreements for acquired vessels; this liability is included in Other long-term liabilities on the condensed consolidated balance sheets. As of June 30, 2022 and December 31, 2021, the Company has recognized a liability for these uncertain tax positions of $12,441 and $12,474, respectively. In addition to the liabilities for unrecognized income tax benefits assumed in the Mergers, the Company assumed liabilities related to potential employment tax obligations that are accounted for under ASC 450.
21.19. 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. 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 $3,200 (IDR 48.4 billion). The Company appealed 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 through 2017 assessing additional tax of approximately $6,900 (JOD 4.90 million). 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.
22.20. Earnings per share
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Numerator: | | | | | | | |
| Net (loss) income | $ | (178,431) | | | $ | (1,734) | | | $ | 62,750 | | | $ | (41,243) | |
| Net (income) attributable to non-controlling interests | 8,666 | | | (4,310) | | | 5,754 | | | (2,704) | |
| Net income (loss) attributable to Class A common stock | $ | (169,765) | | | $ | (6,044) | | | $ | 68,504 | | | $ | (43,947) | |
| | | | | | | |
| Denominator: | | | | | | | |
| Weighted-average shares - basic | 209,669,188 | | | 202,331,304 | | | 209,797,133 | | | 189,885,473 | |
| Net (loss) income per share - basic | $ | (0.81) | | | $ | (0.03) | | | $ | 0.33 | | | $ | (0.23) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
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| | | | | | | |
| Weighted-average shares - diluted | 209,669,188 | | | 202,331,304 | | | 209,810,647 | | | 189,885,473 | |
| Net (loss) income per share - diluted | $ | (0.81) | | | $ | (0.03) | | | $ | 0.33 | | | $ | (0.23) | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| Numerator: | | | | | | | |
| Net income | $ | 151,566 | | | $ | 241,181 | | | | | |
| Net loss attributable to non-controlling interests | (1,360) | | | (2,912) | | | | | |
| Net income attributable to Class A common stock | $ | 150,206 | | | $ | 238,269 | | | | | |
| | | | | | | |
| Denominator: | | | | | | | |
| Weighted-average shares - basic | 208,707,385 | | | 209,928,070 | | | | | |
| Net income per share - basic | $ | 0.72 | | | $ | 1.14 | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
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| Weighted-average shares - diluted | 209,325,619 | | | 210,082,295 | | | | | |
| Net income per share - diluted | $ | 0.71 | | | $ | 1.13 | | | | | |
The following table presents potentially dilutive securities excluded from the computation of diluted net income per share for the periods presented because its effects would have been anti-dilutive.
| | | | | | | | | | | |
| June 30, 2022 | | June 30, 2021 |
| Unvested RSUs | 30,486 | | | 695,279 | |
| Shannon Equity Agreement shares | 475,755 | | | 543,096 | |
| Total | 506,241 | | | 1,238,375 | |
| | | | | | | | | | | |
| March 31, 2023 | | March 31, 2022 |
| | | |
Equity Agreement shares (1) | — | | | 472,084 | |
| Total | — | | | 472,084 | |
(1) Represents Class A common stock that would be issued in relation to an agreement to issue shares executed in conjunction with a prior year asset acquisition.
In connection with the dividend policy update in the fourth quarter of 2022, the Board declared a dividend of $626,310 representing $3.00 per Class A share, which was paid in January 2023. The Company also declared and paid dividends of $20,754$20,467 and $20,582$20,754 during the firstthree months ended March 31, 2023 and second quarters of 2022, respectively, representing $0.10 per Class A share. The Company declared dividends of $17,598 and $20,736 and paid $17,657 and $20,670 during the first and second quarters of 2021, respectively, representing $0.10 per Class A share. The Company's dividend payment during the first quarter of 2021 included dividends that were accrued in prior periods.
During each of the first three months ended March 31, 2023 and second quarters of 2022 and in the second quarter of 2021, subsequent to the Mergers,, the Company paid a dividenddividends of $3,019 each quarterto holders of GMLP’s Golar LNG Partners LP's ("GMLP") 8.75% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). As these equity interests have been issued by one of the Company’s consolidated subsidiary,subsidiaries, the value of the Series A Preferred Units is recognized as non-controlling interest in the condensed consolidated financial statements.
23.21. Share-based compensation
The Company has granted Performance Share Units (“PSUs”("PSUs")
During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition under the New Fortress Energy Inc. 2019 Omnibus Incentive Plan (the "2019 Plan").Plan. Vesting is determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. During the fourth quarterAs of 2021,March 31, 2023, the Company determined that the 2020 Grant will vest at a multiple of two, resulting in the recognition of all compensation cost associated with this award. As of June 30, 2022, the Company determined that it was not probable that the
performance condition required for the
2021 GrantPSUs granted in the fourth quarter of 2022 ("2022 Grant") to vest would be achieved, and as such, no compensation expense
has beenwas recognized for this award.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| PSUs Granted | | Units Granted | | Range of Vesting | | Units Vested / Probable of Vesting | | Unrecognized Compensation Cost(1) | | Weighted Average
Remaining Vesting
Period |
| Q1 2020 ("2020 Grant") | | 1,109,777 | | 0 to 2,219,554 | | 2,105,522 | | $ | — | | | 0.00 years |
| Q1 2021 ("2021 Grant") | | 400,507 | | 0 to 801,014 | | — | | 30,709 | | | 0.50 years |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| PSUs Granted | | Units Granted | | Range of Vesting | | Units Vested / Probable of Vesting | | Unrecognized Compensation Cost(1) | | Weighted Average
Remaining Vesting
Period |
| 2022 Grant | | 742,073 | | 0 to 1,484,146 | | — | | 62,015 | | | 0.75 years |
(1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest.
Restricted Stock Units ("RSUs")
The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the 2019 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 six months ended June 30, 2022:
| | | | | | | | | | | |
| Restricted Stock
Units | | Weighted-average
grant date fair
value per share |
| Non-vested RSUs as of December 31, 2021 | 676,338 | | | $ | 13.49 | |
| Granted | 12,196 | | | $ | 29.89 | |
| Vested | (658,048) | | | $ | 13.78 | |
| Forfeited | — | | | $ | — | |
| Non-vested RSUs as of June 30, 2022 | 30,486 | | | $ | 14.47 | |
The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three and six months ended June 30, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Operations and maintenance | $ | — | | | $ | 212 | | | $ | 4 | | | $ | 434 | |
| Selling, general and administrative | 358 | | | 1,401 | | | 1,234 | | | 2,949 | |
| Total share-based compensation expense | $ | 358 | | | $ | 1,613 | | | $ | 1,238 | | | $ | 3,383 | |
For both the three and six months ended June 30, 2022, no cumulative compensation expense recognized for forfeited RSU awards was reversed. For both the three and six months ended June 30, 2021, cumulative compensation expense
recognized for forfeited RSU awards of $57 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 June 30, 2022, the Company had 30,486 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $158. The non-vested RSUs have weighted-average remaining vesting period of 0.51 years as of June 30, 2022.
24.22. Related party transactions
Management services
The Company is majority owned by Messrs. Edens, (our chief executive officer and chairman of ourthe Board of Directors)Directors, and Nardone, (onemember of our Directors) whothe Board of Directors, are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $1,144$1,345 and $1,794$1,515 for the three months ended June 30,March 31, 2023 and 2022, and 2021, respectively, and totaled $2,659 and $3,721 for the six months ended June 30, 2022 and 2021, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive income (loss).income. As of June 30, 2022March 31, 2023 and December 31, 2021, $7,8962022, $1,377 and $5,700$4,629 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 $1,125$771 and $1,340$1,022 for the three months ended June 30,March 31, 2023 and 2022, and 2021, respectively, and $2,147 and $2,949 for the six months ended June 30, 2022 and 2021, respectively. As of June 30, 2022March 31, 2023 and December 31, 2021, $1,2482022, $771 and $944$416 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 and $103 during the three months ended June 30,March 31, 2023 and 2022, and 2021, respectively, and $206 and $229 during the six months ended June 30, 2022 and 2021, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive income (loss). The Company has amounts due to FECI of $23 and $0 as of March 31, 2023 and December 31, 2022, respectively. As of June 30, 2022March 31, 2023 and December 31, 2021,2022, the Company has recorded a lease liability of $3,329$3,341 and $3,314,$3,340, respectively, within Non-currentNon-current lease liabilities on the condensed consolidated balance sheet.sheets.
DevTech investment
In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest iswas 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. Subsequent to the restructuring of the consulting agreement, the Company recognized approximately $119$105 and $217$98 in expense within Selling, general and administrative for the three and six months ended June 30,March 31, 2023 and 2022, respectively. As of June 30, 2022March 31, 2023 and December 31, 2021, $2172022, $105 and $88 was$80 were due to DevTech, respectively.
Fortress affiliated entities
The Company provides certain administrative services to related parties including Fortress affiliated entities. ThereNo costs are no costs incurred for such administrative services by the Company as the Company is fully reimbursed for all costs incurred. Beginning in the fourth quarter of 2020, theThe Company began subleasinghas subleased a portion of office space and related administrative services to an affiliateaffiliates of an entityentities managed by Fortress. ForFortress, and for the three months ended June 30,March 31, 2023 and 2022, $192 and 2021, $201 and $241$195 of rent and office related expenses were incurred by this affiliate,these affiliates, respectively. For the six months ended June 30,As of March 31, 2023 and December 31, 2022, $892 and 2021, $396 and $394 of$700, respectively, were due from all Fortress affiliated entities.
rent and office related expenses were incurred by this affiliate, respectively. As of June 30, 2022 and December 31, 2021, $937 and $1,241 were due from all Fortress affiliated entities, 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 $582$589 and $674$600 for the three months ended June 30,March 31, 2023 and 2022, and 2021, respectively, and $1,182 and $1,477 for the six months ended June 30, 2022 and 2021, respectively. As of June 30, 2022March 31, 2023 and December 31, 2021, $1,1822022, $3,043 and $2,444$2,455 were duedue to Fortress affiliated entities, respectively.
Agency agreement with PT Pesona Sentra Utama (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 $189 and $126 for the three months ended June 30, 2022 and 2021, respectively, and $$380 and $126 for the six months ended June 30, 2022 and 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. As of June 30, 2022, Company has guaranteed $339,750 under the Partnership Guarantee.
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 June 30, 2022, the fair value of debt guarantees after amortization of $4,779 and $0, has been presented within Other current liabilities and Other long-term liabilities, respectively, on the condensed consolidated balance sheet. As of June 30, 2022, the Company was in compliance with the covenants and ratios for both Hilli guarantees.
25.23. Segments
As of June 30, 2022,March 31, 2023, the Company operates in 2two 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 vesselsVessels that are utilized in the Company’s terminal or logistics operations are included in this segment.
Terminals and Infrastructure Operating Margin included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% investment in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”); the Company disposed of this investment in the fourth quarter of 2022.
Terminal and Infrastructure segment includes realized gains and losses from the settlement of derivative transactions entered into as economic hedges to reduce market risks associated with commodity prices.
•Ships includes 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; 6 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. NaN of theFive FSRUs and five LNG carriers acquired in the Mergers are included in this segment. The Company’s investment in Hilli LLCEnergos is also included in the Ships segment.
Ships Operating Margin included our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC prior to the disposition of this investment in first quarter of 2023.
The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value. 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 Segment 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.
The table below presents segment information for the three and six months ended June 30, 2022March 31, 2023 and 2021:2022:
| | | Three Months Ended June 30, 2022 | | Three Months Ended March 31, 2023 |
| (in thousands of $) | (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total
Segment | | Consolidation and Other(3) | | Consolidated | (in thousands of $) | Terminals and
Infrastructure | | Ships | | Total
Segment | | Consolidation and Other(4) | | Consolidated |
| Statement of operations: | Statement of operations: | | Statement of operations: | | | | | | | | | |
| Total revenues | Total revenues | $ | 543,455 | | | $ | 111,024 | | | $ | 654,479 | | | $ | (69,624) | | | $ | 584,855 | | Total revenues | $ | 502,608 | | | $ | 97,917 | | | $ | 600,525 | | | $ | (21,394) | | | $ | 579,131 | |
| Cost of sales | 271,948 | | | — | | | 271,948 | | | 453 | | | 272,401 | | |
Cost of sales(1) (3) | | Cost of sales(1) (3) | 73,798 | | | — | | | 73,798 | | | 111,140 | | | 184,938 | |
| Vessel operating expenses | Vessel operating expenses | 4,255 | | | 21,288 | | | 25,543 | | | (6,915) | | | 18,628 | | Vessel operating expenses | — | | | 19,239 | | | 19,239 | | | (5,948) | | | 13,291 | |
| Operations and maintenance | Operations and maintenance | 29,540 | | | — | | | 29,540 | | | (9,050) | | | 20,490 | | Operations and maintenance | 26,671 | | | — | | | 26,671 | | | — | | | 26,671 | |
| Segment Operating Margin | Segment Operating Margin | $ | 237,712 | | | $ | 89,736 | | | $ | 327,448 | | | $ | (54,112) | | | $ | 273,336 | | Segment Operating Margin | $ | 402,139 | | | $ | 78,678 | | | $ | 480,817 | | | $ | (126,586) | | | $ | 354,231 | |
| Balance sheet: | Balance sheet: | | Balance sheet: | |
Total assets(4) | Total assets(4) | $ | 5,189,044 | | | $ | 2,062,332 | | | $ | 7,251,376 | | | $ | — | | | $ | 7,251,376 | | Total assets(4) | $ | 6,584,603 | | | $ | 1,639,143 | | | $ | 8,223,746 | | | $ | — | | | $ | 8,223,746 | |
| Other segmental financial information: | Other segmental financial information: | | Other segmental financial information: | |
Capital expenditures(5)(2) | Capital expenditures(5)(2) | $ | 242,808 | | | $ | 11,148 | | | $ | 253,956 | | | $ | — | | | $ | 253,956 | | Capital expenditures(5)(2) | $ | 931,823 | | | $ | — | | | $ | 931,823 | | | $ | — | | | $ | 931,823 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 |
| (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total
Segment | | Consolidation and Other(3) | | Consolidated |
| Statement of operations: | | | | | | | | | |
| Total revenues | $ | 1,023,804 | | | $ | 225,966 | | | $ | 1,249,770 | | | $ | (159,797) | | | $ | 1,089,973 | |
| Cost of sales | 507,480 | | | — | | | 507,480 | | | (26,781) | | | 480,699 | |
| Vessel operating expenses | 7,747 | | | 47,230 | | | 54,977 | | | (13,385) | | | 41,592 | |
| Operations and maintenance | 59,782 | | | — | | | 59,782 | | | (16,124) | | | 43,658 | |
| Segment Operating Margin | $ | 448,795 | | | $ | 178,736 | | | $ | 627,531 | | | $ | (103,507) | | | $ | 524,024 | |
| Balance sheet: | | | | | | | | | |
Total assets(4) | $ | 5,189,044 | | | $ | 2,062,332 | | | $ | 7,251,376 | | | $ | — | | | $ | 7,251,376 | |
| Other segmental financial information: | | | | | | | | | |
Capital expenditures(4)(5) | $ | 439,198 | | | $ | 14,437 | | | $ | 453,635 | | | $ | — | | | $ | 453,635 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 |
| (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Statement of operations: | | | | | | | | | |
| Total revenues | $ | 181,548 | | | $ | 95,762 | | | $ | 277,310 | | | $ | (53,471) | | | $ | 223,839 | |
| Cost of sales | 103,451 | | | — | | | 103,451 | | | (2,021) | | | 101,430 | |
| Vessel operating expenses | — | | | 20,175 | | | 20,175 | | | (4,775) | | | 15,400 | |
| Operations and maintenance | 23,644 | | | — | | | 23,644 | | | (5,079) | | | 18,565 | |
| Segment Operating Margin | $ | 54,453 | | | $ | 75,587 | | | $ | 130,040 | | | $ | (41,596) | | | $ | 88,444 | |
| Balance sheet: | | | | | | | | | |
Total assets(4) | $ | 1,917,701 | | | $ | 4,474,374 | | | $ | 6,392,075 | | | $ | — | | | $ | 6,392,075 | |
| Other segmental financial information: | | | | | | | | | |
Capital expenditures(4)(5) | $ | 210,790 | | | $ | 1,400 | | | $ | 212,190 | | | $ | — | | | $ | 212,190 | |
| | | Six Months Ended June 30, 2021 | | Three Months Ended March 31, 2022 |
| (in thousands of $) | (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated | (in thousands of $) | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Statement of operations: | Statement of operations: | | Statement of operations: | | | | | | | | | |
| Total revenues | Total revenues | $ | 327,232 | | | $ | 95,762 | | | $ | 422,994 | | | $ | (53,471) | | | $ | 369,523 | | Total revenues | $ | 480,349 | | | $ | 114,942 | | | $ | 595,291 | | | $ | (90,173) | | | $ | 505,118 | |
Cost of sales | Cost of sales | 200,122 | | | — | | | 200,122 | | | (2,021) | | | 198,101 | | Cost of sales | 235,532 | | | — | | | 235,532 | | | (27,234) | | | 208,298 | |
| Vessel operating expenses | Vessel operating expenses | — | | | 20,175 | | | 20,175 | | | (4,775) | | | 15,400 | | Vessel operating expenses | 3,492 | | | 25,942 | | | 29,434 | | | (6,470) | | | 22,964 | |
| Operations and maintenance | Operations and maintenance | 39,895 | | | — | | | 39,895 | | | (5,079) | | | 34,816 | | Operations and maintenance | 30,242 | | | — | | | 30,242 | | | (7,074) | | | 23,168 | |
| Segment Operating Margin | Segment Operating Margin | $ | 87,215 | | | $ | 75,587 | | | $ | 162,802 | | | $ | (41,596) | | | $ | 121,206 | | Segment Operating Margin | $ | 211,083 | | | $ | 89,000 | | | $ | 300,083 | | | $ | (49,395) | | | $ | 250,688 | |
| Balance sheet: | Balance sheet: | | Balance sheet: | |
Total assets(4) | Total assets(4) | $ | 1,917,701 | | | $ | 4,474,374 | | | $ | 6,392,075 | | | $ | — | | | $ | 6,392,075 | | Total assets(4) | $ | 5,291,601 | | | $ | 2,074,207 | | | $ | 7,365,808 | | | $ | — | | | $ | 7,365,808 | |
| Other segmental financial information: | Other segmental financial information: | | Other segmental financial information: | |
Capital expenditures(5)(2) | Capital expenditures(5)(2) | $ | 316,551 | | | $ | 1,400 | | | $ | 317,951 | | | $ | — | | | $ | 317,951 | | Capital expenditures(5)(2) | $ | 196,390 | | | $ | 3,289 | | | $ | 199,679 | | | $ | — | | | $ | 199,679 | |
(1) Terminals and Infrastructure includesCost of sales in the Company’s effective sharesegment measure only includes realized gains and losses on derivative transactions that are an economic hedge of revenues, expensesour commodity purchases and operating margin attributablesales, and in the first quarter of 2023, realized gains of $146,112 were recognized as a reduction to 50% ownershipCost of CELSEPAR. The losses attributablesales in the segment measure.
Unrealized changes in the mark-to-market value of derivative transactions of $111,140 reconcile Cost of sales in the segment measure to the investmentCost of $389,996 and $353,315 for the three and six months ended June 30, 2022, respectively, and earnings attributable to the investment of $28,447 for the three and six months ended June 30, 2021 are reported in (Loss) income from equity method investmentssales in the condensed consolidated statements of operations and comprehensive income (loss).income.
(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 $17,069 and $30,623 for the three and six months ended June 30, 2022, respectively, and $10,494 for the three and six months ended June 30, 2021 are reported in (Loss) income from equity method investments in the condensed consolidated statements of operations and comprehensive income (loss).
(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in the 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.
(3) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income.
(4) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR and the common units of Hilli LLC in the segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.
Consolidated Segment Operating Margin is defined as net (loss) income, adjusted for selling,Selling, general and administrative expenses, transactionTransaction and integration costs, depreciationDepreciation and amortization, asset impairmentInterest expense, interestOther expense other (income), (loss) incomenet, Income from equity method investments and taxTax provision (benefit) provision.
The following table reconciles Net income (loss) income, the most comparable financial statement measure, to Consolidated Segment Operating Margin:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended March 31, | | |
| (in thousands of $) | (in thousands of $) | 2022 | | 2021 | | 2022 | | 2021 | (in thousands of $) | 2023 | | 2022 | | |
| Net (loss) income | $ | (178,431) | | | $ | (1,734) | | | $ | 62,750 | | | $ | (41,243) | | |
| Net income | | Net income | $ | 151,566 | | | $ | 241,181 | | | |
| Add: | Add: | | Add: | | |
| Selling, general and administrative | Selling, general and administrative | 50,310 | | | 44,536 | | | 98,351 | | | 78,152 | | Selling, general and administrative | 52,138 | | | 48,041 | | | |
| Transaction and integration costs | Transaction and integration costs | 4,866 | | | 29,152 | | | 6,767 | | | 40,716 | | Transaction and integration costs | 494 | | | 1,901 | | | |
| | Depreciation and amortization | Depreciation and amortization | 36,356 | | | 26,997 | | | 70,646 | | | 36,886 | | Depreciation and amortization | 34,375 | | | 34,290 | | | |
| Asset impairment expense | 48,109 | | | — | | | 48,109 | | | — | | |
| | Interest expense | Interest expense | 47,840 | | | 31,482 | | | 92,756 | | | 50,162 | | Interest expense | 71,673 | | | 44,916 | | | |
| Other (income), net | (22,102) | | | (7,457) | | | (41,827) | | | (8,058) | | |
| Other expense (income), net | | Other expense (income), net | 25,005 | | | (19,725) | | | |
| | Tax (benefit) provision | (86,539) | | | 4,409 | | | (136,220) | | | 3,532 | | |
| Loss (Income) from equity method investments | 372,927 | | | (38,941) | | | 322,692 | | | (38,941) | | |
| Tax provision (benefit) | | Tax provision (benefit) | 28,960 | | | (49,681) | | | |
| (Income) from equity method investments | | (Income) from equity method investments | (9,980) | | | (50,235) | | | |
| Consolidated Segment Operating Margin | Consolidated Segment Operating Margin | $ | 273,336 | | | $ | 88,444 | | | $ | 524,024 | | | $ | 121,206 | | Consolidated Segment Operating Margin | $ | 354,231 | | | $ | 250,688 | | | |
26. Subsequent events
Vessel Financing Transaction
On July 2, 2022, certain affiliates of NFE (collectively, the “Sellers”) and a separate affiliate of NFE acting as contributor (the “Contributor”, together with the Sellers, the “NFE Vessel Group”) entered into an Equity Purchase and Contribution Agreement (the “Purchase Agreement”) with AP Neptune Holdings Ltd. (“Purchaser”), which is affiliated with certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc. (the “Purchaser Group”), pursuant to which (1) the Contributor and the Purchaser formed a joint venture (the “JV”), (2) the Sellers agreed to sell to the Purchaser 8 vessels, (3) the Purchaser will contribute the 8 vessels to the JV and (4) the Contributor will contribute 3 additional vessels to the JV. In connection with the transaction, the Nanook SPV facility, Penguin SPV facility, Celsius SPV facility and Vessel Term Loan Facility are expected to be extinguished. The cash purchase price for the transaction is subject to customary purchase price adjustments, and after giving effect to the repayment of existing debt, net cash proceeds to NFE are expected to be approximately $1.1 billion (the "Vessel Financing Transaction").
In connection with the transaction, certain affiliates of NFE will enter into long-term time charter agreements for a period up to 20 years in respect of 10 of the 11 vessels, the terms of which will commence upon the expiration of each vessel's existing charter.
The Purchase Agreement contains customary representations, warranties and covenants by each of the NFE Vessel Group, the Contributor and the Purchaser Group. Closing of the transactions contemplated by the Purchase Agreement is subject to customary conditions, including the absence of a material adverse effect, but is not subject to any regulatory or financing condition or contingency. Closing is expected to occur in the third quarter of 2022.
The Purchase Agreement contains termination rights for each of the NFE Vessel Group and the Purchaser Group, including for the material uncured breach of either the NFE Vessel Group or the Purchaser Group and for the failure to consummate the transactions by December 30, 2022. Upon termination of the Purchase Agreement under specified circumstances, the Purchaser Group would owe to the NFE Vessel Group a termination fee of approximately $80 million.
A&R LC Facility
On July 27, 2022, NFE and certain subsidiaries of NFE, acting as Guarantors, entered into an Amendment and Restatement to the Uncommitted Letter of Credit and Reimbursement Agreement (“LC Facility”, and as amended and restated, the “A&R LC Facility”), with certain financial institutions for the provision of letters of credit to NFE and its subsidiaries. The A&R LC Facility was increased to an initial amount of $250,000, as may be increased by an additional principal amount of up to $100,000, subject to satisfaction of certain conditions. The A&R LC Facility has a term of one year with the potential for the Company to extend the maturity date.
The A&R LC Facility provides for the issuance of letters of credit, and the letters of credit will be used to provide credit support for the Company's commercial agreements in the ordinary course of business, including LNG purchases or development expenditures.
The obligations under the A&R LC Facility are guaranteed, jointly and severally, by certain of the Company's subsidiaries. The obligations are senior secured obligations, secured on a first-priority basis by liens on the collateral, subject to permitted liens and certain other exceptions. The security interest of the secured parties under the A&R LC Facility in the collateral ranks pari passu with the security interest of the holders of the Company’s existing 2025 Notes, the Company’s existing 2026 Notes and the Company’s Revolving Facility, and an equal priority intercreditor agreement governs the treatment of such collateral.
The letters of credit bear interest at a rate equal to (i) a base rate equal to the higher of the rate last quoted by The Wall Street Journal as the “Prime Rate” and a rate tied to the Federal Reserve Bank of New York, plus 0.50%, plus (ii) an applicable margin of 2.25%.
The A&R LC Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The affirmative covenants include, among other things, delivery of financial statements, compliance certificates and notices, payment of taxes and other obligations, conduct of business and maintenance of existence, compliance with applicable laws and regulations, maintenance of properties and insurance, maintenance of books and records and provision of guarantees and collateral.
The negative covenants include limitations on restricted payments, dividends and other payment restrictions affecting subsidiaries, indebtedness, asset sales, transactions with affiliates, liens, mergers, consolidation or sale of all or substantially all assets, and maintenance of a total debt to capitalization ratio and a total first lien debt to adjusted EBITDA ratio (which latter covenant shall be tested only if the Company is required to test under the Company’s Revolving Facility). The A&R LC Facility also contains usual and customary events of default (subject to grace periods), including non-payment of principal, interest, fees and other amounts; material breach of a representation or warranty; covenant defaults, acceleration of other material debt; material judgments; bankruptcy or insolvency; ERISA-related defaults; impairment of security or guarantees; and change of control.
Vessel Term Loan Facility Upsize
On August 3, 2022, the Company exercised the accordion feature under the Vessel Term Loan Facility, drawing $115,000. The Company expects to repay all amounts outstanding under the Vessel Term Loan Facility, including this additional principal draw, in conjunction with closing the Vessel Financing Transaction in the third quarter of 2022.
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, 20212022 (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.millions.
Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like 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. Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to the completion of Mergers, New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries.
Overview
We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets.markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emission-free independent power providing companies.emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Carbon-FreeVery-Low Carbon Future.”
On April 15, 2021, we completed the acquisitions of Hygo (the "Hygo Merger" and GMLP (the "GMLP Merger,"and collectively with the Hygo Merger, the “Mergers”) As a result of the Hygo Merger, we acquired a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), as well as a terminal and power plant under development in the State of Pará, Brazil (the “Barcarena Facility” and "Barcarena Power Plant," respectively), a terminal under development on the southern coast of Brazil (the “Santa Catarina Facility”) and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. As a result of the Mergers, we acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (the “Hilli”), each of which are expected to help support our existing facilities and international project pipeline. Acquired FSRUs are operating in Brazil, Indonesia 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, ourOur 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 vesselsStarting in the third quarter of 2023, we expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG."The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as the cost to operate our vessels that are utilized in our terminal or logistics operations are included in this segment.operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply and
acquired and leased fleet. The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, including our interest in the Sergipe Power Plant.
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.arrangements. The Company’s investment in Hilli LLC, owner and operator of the Hilli,Energos (defined below) is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.
Our Current Operations – Terminals and Infrastructure
Our management team has successfully employed our strategy to secure long-term contracts with significant customers, 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”), and Comisión Federal de Electricidad (“CFE”), a subsidiary of Federal
Electricity Commission (Comisión Federal de Electricidad), Mexico’s power utility, 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 liquefaction facility in Dade County, Florida ("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”) in addition to supplying our customers through long-term LNG contracts.
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 Plantpower plant in Montego Bay, Jamaica.Jamaica ("Bogue Power Plant"). Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 61,000 MMBtu of LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.
Old Harbour Facility
The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term PPA.agreement. 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 deliveragreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico. We have delivered natural
La Paz Facility
In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu of LNG per day to our 100MW gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020.
SergipeLa Paz Power Plant and Sergipe Facility
As partmay be increased to approximately 29,000 MMBtu 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 1.5GW combined cycle power plant, receives natural gas from the Sergipe Facility through a dedicated 8-kilometer pipeline. The Sergipe Power Plant is one of the largest natural gas-fired thermal power stations in Latin America and was built to provide electricity on demand throughout the Brazilian electric integrated system, particularly during dry seasons when hydropower is unable to meet the growing demandLNG per day for electricity in the country. 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 own expansion rights with respect to the Sergipe Power Plant, which are owned by Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), a joint venture with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., of which we own a 75% interest. These rights include 190 acres of land and regulatory permits for two new power generation projects of 1.7GW in the aggregate. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions.
The Sergipe Facility is capable of processing up to 790,000 MMBtu per day135MW of power.
In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and storing up to 170,000 cubic meters of LNG and supplies approximately 230,000 MMBtu per day (30% of the Sergipe Facility’s maximum regasification capacity)extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the Sergipe Power Plant, at full dispatch. In June 2022, we announced the sale of the Sergipe Facility and our interest in the SergipeLa Paz Power Plant to Eneva S.A. See "Recent Developments"CFE and are in the process of finalizing long-form agreements to commemorate all binding terms. The gas sales and power plant sale agreements are subject to execution of the long-form final agreements and certain conditions precedent, and we expect to execute the long-form final agreements in the second quarter of 2023.
Miami Facility
Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.
Our LNG Supply and Cargo Sales
NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts expected to commence in 2027; 3) our Miami Facility; and 4) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in
2026 and 2027. Finally, we plan to commence our own Fast LNG production in the third quarter of 2023, when our first FLNG facility is expected to begin operation, and we plan to expand that capacity when additional units come online over the next two years.
The recent geopolitical events in Europe have substantially impacted the natural gas and LNG markets with unprecedented price increases and volatility. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production from FLNG facilities expected to commence in the third quarter of 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.
Our Current Operations – Ships
Our Ships segment includes six FSRUs and five LNG carriers, which are leased to customers under long-term or spot arrangements, including a 25-yeararrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and describe in more detail below, we plan to charter of Nanook with CELSE. As these charter arrangements expire, we expect to use these vessels infor our terminal operationsown use. We exclude these vessels from our Ships segment and reflect such vesselsinclude them in our Terminals and Infrastructure segment. segment once we begin to use the vessels for our own operational purposes. One acquired LNG carrier and one acquired FSRU are currently utilized in our terminal operations, and the results of operations of these vessels are reflected in the Terminals and Infrastructure segment.
In JulyAugust 2022, we announcedcompleted a financing transaction with an affiliate of Apollo Global Management, Inc. collateralized by our vessels. See "Recent Developments"
The Company’svessels (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, and we have accounted for the investment in Hilli LLC, ownerEnergos as an equity method investment. In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for periods of up to 20 years in respect of ten vessels, the terms of which commence upon the expiration of each vessel's existing charter. These charters prevent the recognition of a sale of these vessels to Energos, and operatoras such, proceeds associated with these vessels have been treated as failed sale leasebacks. These vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and we have recognized this failed sale leaseback financing as debt.
Certain vessels included in the Energos Formation Transaction are currently chartered to third parties under operating leases. As we have not recognized the sale of these vessels and proceeds received under the Energos Formation Transaction are collateralized by the cash flows from these charters, revenue generated from these operating leases continues to be recognized as Vessel charter revenue; costs of operating the vessels is included in Vessel operating expenses over the terms of the third-party charters. Cash flows from these third-party charters are included as part of debt service for the sale leaseback financing debt, and we will recognize additional financing costs within Interest expense, net.
We did not enter into a charter agreement to leaseback the Nanook, which was sold to Energos as part of the Energos Formation Transaction. After closing this transaction, we no longer recognize revenue from the sales-type lease of the HilliNanook, is also included in and 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 liquefactionrelated operating 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.agreement.
Our Development Projects
La Paz Facility
In July 2021, we began commercial operations at the PortOur projects currently under development include our development of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu of LNG per day to our 100MW of power supplied by gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu of LNG per day for up to 135MW of power. We are exploring a potential sale of the La Paz Power Plant; we do not plan to recognize a loss on the sale.
Puerto Sandino Facility
We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”). We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu of LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement.
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 per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to third-party industrial and power customers as well as a new 605MW combined cycle thermal power plant to be located in Pará, Brazil which we own (the “Barcarena Power Plant”), which is supported by multiple 25-year power purchase agreement to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025.
Santa Catarina Facility
The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are also developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day.
Sri Lanka Facility
We may develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, in Colombo, Sri Lanka, where 310 MW of power is operational today and an additional 700 MW is scheduled to be built.
Ireland Facility
We intend to develop and operate an LNG facility (the “Ireland Facility”) and power plant on the Shannon Estuary, near Tarbert, Ireland. We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland, and we intend to begin construction of the Ireland Facility after we have obtained the necessary consents and secured contracts with downstream customers with volumes sufficient to support the development.
Fast LNG
We are currently developing a series of modular floating liquefaction facilities to provide a source of low-cost supply of LNG forto customers around the world through our growing customer base. The “Fast LNG” design pairs advancementsFast LNG technologies; our LNG terminal facility in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a much lower costPuerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and faster deployment schedule than today’s floating liquefaction vessels. Semi-permanently moored FSU(s) will serve aspower plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG storage alongsideterminal located on the floating liquefaction infrastructure, which can be deployed anywhere there is abundantsouthern coast of Brazil ("Santa Catarina Terminal"); and stranded natural gas.
Other Projects
our LNG terminal (“Ireland Facility”) and power plant in Ireland. We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target pricingrevenue or margins.results of operations.
The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-
consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.
We describe each of our current development projects below.
Fast LNG
We are currently developing multiple modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing offshore liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. The “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than land-based alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.
We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.
Altamira
In the first quarter of 2023, we executed an agreement, which include conditions to effectiveness that have not been satisfied, with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million tons per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. We expect to deploy this FLNG unit to Altamira in the third quarter of 2023.
Louisiana
In particular,addition, we are currentlyplan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.
Lakach
Also, in discussionsthe fourth quarter of 2022, we finalized agreements, which include conditions to effectiveness that have not been satisfied, with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. If the parties form a partnership,agreements become effective, NFE expects towould invest in the continued development of the Lakach field over a two-year period by completing seven offshore wells and to deploy a 1.4 MTPA Fast LNG unit to liquefy the majority of the produced natural gas. Remaining natural gas and associated condensate volumes are expected towould be utilized by Pemex in Mexico's onshore domestic market.
Recent Developments
Sergipe SalePuerto Sandino Facility
On May 31, 2022, LNG Power Limited (“LNG Power”),We are developing an indirect subsidiaryoffshore facility consisting of NFEan FSRU and direct owner of the CELSEPAR investment, associated infrastructure, including mooring and certain Ebrasil sellers as owners of CELSEPAR (together with LNG Power, the “Sergipe Sellers”), Eneva S.A., as purchaser ("Eneva") and Eletricidade do Brasil S.A. -- Ebrasil,offshore pipelines, in Puerto Sandino, Nicaragua. We have entered into a Share Purchase Agreement (“SPA”) pursuant25-year PPA with Nicaragua’s electricity distribution companies, and we expect to which Eneva has agreedutilize approximately 57,500 MMBtu from LNG per day to acquire all of the outstanding shares of CELSEPAR and CEBARRA for a purchase price of R$6.10 billion in cash (approximately $1.17 billion using the exchange rate as of June 30, 2022) (the “Sergipe Sale”).
The purchase price payable by Eneva accrues interest at a rate of CDI + 1% from the December 31, 2021 until the date of the Closing (as defined below) and is subject to certain customary adjustments, including for the amount of any leakage that has occurred from December 31, 2021provide natural gas to the date of the Closing, including (a) making distributions or payments to or for the benefit of Sergipe Sellers and their affiliates and assuming or incurring liabilities for the benefit of Sergipe Sellers or their affiliates, and (b) certain fees and expenses incurred by CELSEPAR and CEBARRAPuerto Sandino Power Plant in connection with the Sergipe Sale. LNG Power also entered into25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a foreign currency forward associatedmarket that is underserved. We expect to mitigate foreign currency risk to the expected proceeds from the transaction and will settle at the same time as Closing.complete this optimization in 2024.
Barcarena Facility
UnderWe have financed the SPA, the closingdevelopment of the Sergipe Sale (the “Closing”)Barcarena Power Plant pursuant to a financing agreement. For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in our Annual Report.
Santa Catarina Facility
The Santa Catarina Facility will occurbe located on the latersouthern coast of (a) October 3, 2022Brazil and (b)will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the 10th business daySanta Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations by the end of 2023.
Ireland Facility
We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland. While the specific timing for receiving the required permits is unknown, we have undertaken pre-development work that will allow us to complete the terminal in approximately 9-15 months after all conditions to Closing have been satisfied or waived, orreceiving the required permits. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as otherwise agreed to among the parties. The conditions to Closing include receipt of all required regulatory approvals, receipt of certain specified material third-party consents and the approvalpart of the Sergipe Saleauction process operated by Eneva’s shareholders.Ireland’s Transmission System Operator. The Sergipe Sale maypower plant is required to be terminated under certain circumstances, including, among others, (a)operational by either Eneva or Sergipe Sellers if Closing has not occurred on or beforeOctober 2026.
Recent Developments
On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the date that is 270 days from the execution datesale of the SPA, (b) automatically ifCompany's investment in the Sergipe Sale is not approved by Eneva’s shareholders. The SPA further provides that, (i) upon terminationcommon units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). In the SPA under certain circumstances, Eneva will be required to pay the Sergipe Sellersfourth quarter of 2022, we recognized a reverse termination fee equal to R$300 million and (ii) upon termination of the SPA under certain other circumstances, the Sergipe Sellers will be required to pay Eneva a termination fee equal to R$250 million.
In connection with the Sergipe Sale, we have recognized an other than temporary impairment ofloss on the investment in CELSEPARthe Hilli of $345,447, and$118.6 million; this loss has beenwas recognized in loss (income)Loss from equity method investments in the condensed consolidated statements of operations and comprehensive income (loss)income. Upon completion of the Hilli Exchange, we recognized an additional loss on disposal of $37.4 million, which was included in Other expense (income), net. As a result of the Hilli Exchange we no longer have an ownership interest in the Hilli. UponNFE shares received from GLNG were cancelled upon the closing we expect to recognize transaction costs associatedof the Hilli Exchange.
In the first quarter of 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-Year contract for the operation and maintenance of PREPA’s thermal generation assets with the salegoal of CELSEPAR.
The assetsreducing costs and improving reliability of CEBARRA primarily consist of constructionpower generation in progress,Puerto Rico. We will receive an annual management fee and in conjunction withbe eligible for performance-based incentive fees, beginning after the Sergipe Sale,service period under the assets of CEBARRA meet the criteria to be represented as held for sale and stated at fair value. These assets were reviewed for impairment upon classification to held for sale, and the Company recognized an impairment loss of $48,109in Asset impairment expense in the condensed consolidated statements of operations and comprehensive income (loss).
Vessel Financing Transaction
On July 2, 2022, certain affiliates of NFE (collectively, the “Vessel Sellers”) and a separate affiliate of NFE acting as contributor (the “Contributor”, together with the Vessel Sellers, the “NFE Vessel Group”) entered into an Equity Purchase and Contribution Agreement (the “Purchase Agreement”) with AP Neptune Holdings Ltd. (“Purchaser”),contract commences, which is affiliated with certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc. (the “Purchaser Group”), pursuant to which (1) the Contributor and the Purchaser formed a joint venture (the “JV”), (2) the Vessel Sellers agreed to sell to the Purchaser eight vessels, (3) the Purchaser will contribute the eight vessels to the JV and (4) the Contributor will contribute three additional vessels to the JV. In connection with the transaction, the Nanook SPV facility, Penguin SPV facility, Celsius SPV facility and Vessel Term Loan Facility are expected to be extinguished. The cash purchase price for the transaction is subject to customary purchase price adjustments, and after giving effect to the repayment of existing debt, we expect to receive net cash proceeds of approximately $1.1 billion (the "Vessel Financing Transaction").
In connection with the transaction, certain of our affiliates will enter into long-term time charter agreements for a period up to 20 years in respect of ten of the eleven vessels, the terms of which will commence upon the expiration of each vessel's existing charter.
The Purchase Agreement contains customary representations, warranties and covenants by each of the NFE Vessel Group, the Contributor and the Purchaser Group. Closing of the transactions contemplated by the Purchase Agreement is subject to customary conditions, including the absence of a material adverse effect, but is not subject to any regulatory or financing condition or contingency. Closing is expected to occur in the third quarter of 2022.2023.
In February 2023, our senior secured revolving credit facility (the "Revolving Facility") was amended to increase the facility size by $301.7 million to $741.7 million. The Purchase Agreement contains termination rightsinterest rate for eachborrowings under the Revolving Facility based on the current usage of the NFE Vessel Group and the Purchaser Group, including for the material uncured breach of either the NFE Vessel Group or the Purchaser Group and for the failure to consummate the transactions by December 30, 2022. Upon termination of the Purchase Agreement under specified circumstances, the Purchaser Group would owefacility has not changed. No changes were made to the NFE Vessel Group a termination fee of approximately $80 million.
Cargo Sales
Since August 2021, LNG prices have increased materially, and global events, such as Russia’s invasion of Ukraine, have generated further energy pricing volatility. 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 increasematurity date or covenants. Also, in market pricing of LNG, we have optimized our supply portfolio to sell a portion of these cargos in the market, and these sales have positively impacted our results for the first half of 2022.
COVID-19 Pandemic
We continue2023, our uncommitted letter of credit and reimbursement agreement was upsized to closely monitor the impact$325 million; no changes to interest rates or other terms were made as part 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.
this amendment
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.
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. From the beginning of 2020 to June 30, 2022, we have incurred approximately $2.4 million to date for safety measures introduced into our operations and other responses to the COVID-19 pandemic.
We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects, charter or terminal operations from the COVID-19 pandemic; however, there are important uncertainties including the scope, severity and duration of the pandemic and resurgences of COVID-19 variants, 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 the Federal Energy Regulatory Commission ("FERC"), which asked for an explanation asus 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 was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC has denied all requests for rehearing andin an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. ToIn order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.
Results of Operations – Three Months Ended June 30, 2022March 31, 2023 compared to Three Months Ended MarchDecember 31, 2022 and SixThree Months Ended June 30,March 31, 2022 compared to Six Months Ended June 30, 2021
Segment performancePerformance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements.We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.
Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income/(loss) from operations, net income/(loss), cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions to facilitate measuring and achieving optimal financial performance of our current operations overall. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and thenot to rely on any single financial measure to evaluate our business.
The tables below present our segment information for the three months ended June 30,March 31, 2023, December 31, 2022 and March 31, 2022, and for the six months ended June 30, 2022 and June 30, 2021:2022:
| | | Three Months Ended June 30, 2022 | | Three Months Ended March 31, 2023 |
| (in thousands of $) | (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated | (in thousands of $) | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | Total revenues | $ | 543,455 | | | $ | 111,024 | | | $ | 654,479 | | | $ | (69,624) | | | $ | 584,855 | | Total revenues | $ | 502,608 | | | $ | 97,917 | | | $ | 600,525 | | | $ | (21,394) | | | $ | 579,131 | |
Cost of sales | Cost of sales | 271,948 | | | — | | | 271,948 | | | 453 | | | 272,401 | | Cost of sales | 73,798 | | | — | | | 73,798 | | | 111,140 | | | 184,938 | |
Vessel operating expenses | Vessel operating expenses | 4,255 | | | 21,288 | | | 25,543 | | | (6,915) | | | 18,628 | | Vessel operating expenses | — | | | 19,239 | | | 19,239 | | | (5,948) | | | 13,291 | |
Operations and maintenance | Operations and maintenance | 29,540 | | | — | | | 29,540 | | | (9,050) | | | 20,490 | | Operations and maintenance | 26,671 | | | — | | | 26,671 | | | — | | | 26,671 | |
| Segment Operating Margin | Segment Operating Margin | $ | 237,712 | | | $ | 89,736 | | | $ | 327,448 | | | $ | (54,112) | | | $ | 273,336 | | Segment Operating Margin | $ | 402,139 | | | $ | 78,678 | | | $ | 480,817 | | | $ | (126,586) | | | $ | 354,231 | |
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| Three Months Ended March 31, 2022 |
| (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | $ | 480,349 | | | $ | 114,942 | | | $ | 595,291 | | | $ | (90,173) | | | $ | 505,118 | |
| Cost of sales | 235,532 | | | — | | | 235,532 | | | (27,234) | | | 208,298 | |
| Vessel operating expenses | 3,492 | | | 25,942 | | | 29,434 | | | (6,470) | | | 22,964 | |
| Operations and maintenance | 30,242 | | | — | | | 30,242 | | | (7,074) | | | 23,168 | |
| Segment Operating Margin | $ | 211,083 | | | $ | 89,000 | | | $ | 300,083 | | | $ | (49,395) | | | $ | 250,688 | |
| | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 |
| (in thousands of $) | | | | | | | | | | Consolidated |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Gross margin (GAAP) | | | | | | | | | | $ | 319,856 | |
| Depreciation and amortization | | | | | | | | | | 34,375 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 354,231 | |
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| Three Months Ended December 31, 2022 |
| (in thousands of $) | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | $ | 457,324 | | | $ | 106,990 | | | $ | 564,314 | | | $ | (17,945) | | | $ | 546,369 | |
Cost of sales(2) | 232,436 | | | — | | | 232,436 | | | (96,537) | | | 135,899 | |
Vessel operating expenses(4) | — | | | 19,515 | | | 19,515 | | | (6,729) | | | 12,786 | |
Operations and maintenance(4) | 28,931 | | | — | | | 28,931 | | | — | | | 28,931 | |
| Segment Operating Margin | $ | 195,957 | | | $ | 87,475 | | | $ | 283,432 | | | $ | 85,321 | | | $ | 368,753 | |
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| Three Months Ended December 31, 2022 |
| (in thousands of $) | | | | | | | | | | Consolidated |
| | | | | | | | | | |
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| | | | | | | | | | |
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| | | | | | | | | | |
| Gross margin (GAAP) | | | | | | | | | | $ | 332,552 | |
| Depreciation and amortization | | | | | | | | | | 36,201 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 368,753 | |
| | | Six Months Ended June 30, 2022 | | Three Months Ended March 31, 2022 |
| (in thousands of $) | (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated | (in thousands of $) | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | Total revenues | $ | 1,023,804 | | | $ | 225,966 | | | $ | 1,249,770 | | | $ | (159,797) | | | $ | 1,089,973 | | Total revenues | $ | 480,349 | | | $ | 114,942 | | | $ | 595,291 | | | $ | (90,173) | | | $ | 505,118 | |
Cost of sales | Cost of sales | 507,480 | | | — | | | 507,480 | | | (26,781) | | | 480,699 | | Cost of sales | 235,532 | | | — | | | 235,532 | | | (27,234) | | | 208,298 | |
Vessel operating expenses | Vessel operating expenses | 7,747 | | | 47,230 | | | 54,977 | | | (13,385) | | | 41,592 | | Vessel operating expenses | 3,492 | | | 25,942 | | | 29,434 | | | (6,470) | | | 22,964 | |
Operations and maintenance | Operations and maintenance | 59,782 | | | — | | | 59,782 | | | (16,124) | | | 43,658 | | Operations and maintenance | 30,242 | | | — | | | 30,242 | | | (7,074) | | | 23,168 | |
| Segment Operating Margin | Segment Operating Margin | $ | 448,795 | | | $ | 178,736 | | | $ | 627,531 | | | $ | (103,507) | | | $ | 524,024 | | Segment Operating Margin | $ | 211,083 | | | $ | 89,000 | | | $ | 300,083 | | | $ | (49,395) | | | $ | 250,688 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 |
| (in thousands of $) | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | $ | 327,232 | | | $ | 95,762 | | | $ | 422,994 | | | $ | (53,471) | | | $ | 369,523 | |
| Cost of sales | 200,122 | | | — | | | 200,122 | | | (2,021) | | | 198,101 | |
| Vessel operating expenses | — | | | 20,175 | | | 20,175 | | | (4,775) | | | 15,400 | |
| Operations and maintenance | 39,895 | | | — | | | 39,895 | | | (5,079) | | | 34,816 | |
| Segment Operating Margin | $ | 87,215 | | | $ | 75,587 | | | $ | 162,802 | | | $ | (41,596) | | | $ | 121,206 | |
| | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2022 |
| (in thousands of $) | | | | | | | | | | Consolidated |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Gross margin (GAAP) | | | | | | | | | | $ | 216,398 | |
| Depreciation and amortization | | | | | | | | | | 34,290 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 250,688 | |
(1) TerminalsCost of sales in our segment measure only includes realized gains and Infrastructure includeslosses on derivative transactions that are economic hedges of our commodity purchases and sales, and in the first quarter of 2023, realized gains of $146.1 million were recognized as a reduction to Cost of sales in the segment measure.
For the three months ended March 31, 2023, December 31, 2022 and March 31, 2022, unrealized changes in the mark-to-market value of derivative transactions of $111.1 million, $96.4 million and $2.5 million, respectively, reconcile Cost of sales in the segment measure to Cost of sales in our condensed consolidated statements of operations and comprehensive income.
(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income.
(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR. The lossesCentrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and earnings attributablethe common units of Hilli LLC in the segment measure, prior to the investment of $389,996 and $36,680 for the three months ended June 30, 2022 and March 31, 2022, respectively, are reported in (Loss) income from equity methoddisposition to these investments, in the condensed consolidated statements of operations and comprehensive income (loss). In the six months ended June 30, 2022 and 2021, the losses and earnings attributable to the investment were $353,315 and $28,447, respectively.
(2) Ships includes our effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $17,069 and $13,555 for the three months ended June 30, 2022 and March 31, 2022, respectively, are reported in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). For the six months ended June 30, 2022 and 2021, the earnings attributable to the investment were $30,623 and $10,494, respectively.
(3) Consolidation and Other adjust for the inclusion of our 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) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.
Terminals and Infrastructure Segment
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended, | | |
| (in thousands of $) | June 30, 2022 | | March 31, 2022 | | Change | | | | | | | | | | |
| Total revenues | $ | 543,455 | | | $ | 480,349 | | | $ | 63,106 | | | | | | | | | | | |
| Cost of sales | 271,948 | | | 235,532 | | | 36,416 | | | | | | | | | | | |
| Vessel operating expenses | 4,255 | | | 3,492 | | | 763 | | | | | | | | | | | |
| Operations and maintenance | 29,540 | | | 30,242 | | | (702) | | | | | | | | | | | |
| Segment Operating Margin | $ | 237,712 | | | $ | 211,083 | | | $ | 26,629 | | | | | | | | | | | |
| | | Six Months Ended, | | Three Months Ended | |
| (in thousands of $) | (in thousands of $) | June 30, 2022 | | June 30, 2021 | | Change | (in thousands of $) | March 31, 2023 | | December 31, 2022 | | Change | | March 31, 2022 | | Change | |
| Total revenues | Total revenues | $ | 1,023,804 | | | $ | 327,232 | | | $ | 696,572 | | Total revenues | $ | 502,608 | | | $ | 457,324 | | | $ | 45,284 | | | $ | 480,349 | | | $ | 22,259 | | |
| Cost of sales | 507,480 | | | 200,122 | | | 307,358 | | |
| Cost of sales (exclusive of depreciation and amortization) | | Cost of sales (exclusive of depreciation and amortization) | 73,798 | | | 232,436 | | | (158,638) | | | 235,532 | | | (161,734) | | |
| Vessel operating expenses | Vessel operating expenses | 7,747 | | | — | | | 7,747 | | Vessel operating expenses | — | | | — | | | — | | | 3,492 | | | (3,492) | | |
| Operations and maintenance | Operations and maintenance | 59,782 | | | 39,895 | | | 19,887 | | Operations and maintenance | 26,671 | | | 28,931 | | | (2,260) | | | 30,242 | | | (3,571) | | |
| Segment Operating Margin | Segment Operating Margin | $ | 448,795 | | | $ | 87,215 | | | $ | 361,580 | | Segment Operating Margin | $ | 402,139 | | | $ | 195,957 | | | $ | 206,182 | | | $ | 211,083 | | | $ | 191,056 | | |
Total revenue
Total revenue for the Terminals and Infrastructure Segment increased $63,106by $45.3 million for the three months ended June 30,March 31, 2023 as compared to the three months ended December 31, 2022, and total revenue for the Terminals and
Infrastructure Segment increased by $22.3 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. The increase wasincreases were primarily driven by increased revenue from LNG cargo sales to third parties and increasesvolumes delivered to our downstream terminal customers, partially offset by decreases to the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment.
The increase in revenue in the first quarter of 2023 when compared to the fourth quarter of 2022 was primarily attributable to the following:
•Revenue from cargo sales was $309,030 for the three months ended June 30, 2022 and $285,171$349.4 million for the three months ended March 31, 2022. Our revenue has been positively impacted by increases2023, of which $169.5 million was recognized for a cancellation fee received from a customer to cancel a future delivery, increasing from $231.1 million for the Henry Hub index during 2022, and the impact was more pronouncedthree months ended December 31, 2022.
•Volumes delivered to downstream terminal customers increased from 11.0 TBtus in the second quarter. fourth quarter of 2022 to 12.1 TBtu in the first quarter of 2023, primarily as a result of increased consumption by the San Juan Power Plant, which was under maintenance for a portion of the fourth quarter of 2022.
•The average Henry Hub index pricing used to invoice our downstream customers increaseddecreased by 45% for the three months ended June 30, 2022March 31, 2023 as compared to the three months ended MarchDecember 31, 2022.
TotalThe increase in revenue forin the Terminals and Infrastructure Segment increased $696,572 for the six months ended June 30, 2022 asfirst quarter of 2023 when compared to the six months ended June 30, 2021. The increasefirst quarter of 2022 was primarily driven by increased revenue from LNG cargo sales to third parties, additional revenue from our investment in CELSEPAR and increasesattributable to the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. following:
•Revenue from cargos sales was $594,201$349.4 million for the six months ended June 30, 2022 as compared to $7,211 for the six months ended June 30, 2021 as we did not have any significant cargo sales transactions in the first and second quarters of 2021. Our acquisition of our investment in CELSEPAR in the Mergers occurred on April 15, 2021, and as such, we have recognized additional revenue in the six months ended June 30, 2022 as compared to the six months ended June 30, 2021. Finally, the average Henry Hub index pricing used to invoice our customers increased by 119% for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021.
The following tables summarize the volumes delivered, exclusive of LNG cargo volumes sold to third parties, in the three months ended June 30, 2022 as compared to the three months ended March 31, 2022, as well as the six months ended June 30, 20222023 of which $169.5 million was recognized for a cancellation fee received from a customer to cancel a future delivery, as compared to the six months ended June 30, 2021:
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| (in TBtu) | June 30, 2022 | | March 31, 2022 | | Change | | | | |
| Old Harbour Facility | 4.1 | | | 3.0 | | | 1.1 | | | | | |
| Montego Bay Facility | 1.7 | | | 0.5 | | | 1.2 | | | | | |
| San Juan Facility | 3.0 | | | 1.1 | | | 1.9 | | | | | |
| Other | 0.5 | | | 1.7 | | | (1.2) | | | | | |
| Total volumes delivered in the current period | 9.3 | | | 6.3 | | | 3.0 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended |
| (in TBtu) | June 30, 2022 | | June 30, 2021 | | Change | | | | |
| Old Harbour Facility | 7.1 | | | 9.4 | | | (2.3) | | | | | |
| Montego Bay Facility | 2.2 | | | 4.1 | | | (1.9) | | | | | |
| San Juan Facility | 4.1 | | | 7.7 | | | (3.6) | | | | | |
| Other | 2.2 | | | 0.6 | | | 1.6 | | | | | |
| Total volumes delivered in the current period | 15.6 | | | 21.8 | | | (6.2) | | | | | |
Additional details of the change in volumes by location are as follows:
•Volumes delivered at the Old Harbour Facility increased$285.2 million for the three months ended June 30, 2022 as compared to the three months ended March 31, 2022 due to an increase in2022.
•For the three months ended March 31, 2023, volumes delivered at the Old Harbour Power Plant. Decreased consumption at the CHP Plant also drove volume decreases at the Old Harbour Facility for the six months ended June 30, 2022to downstream customers were 12.1 TBtu as compared to 6.3 TBtu for the sixthree months ended June 30, 2021.
•March 31, 2022. During the first quarter of 2022, no volumes were consumed by the Bogue Power Plant leading to the significant decrease in volumes delivered at the Montego Bay Facility, due to the port authority at the Port of Montego Bay where our facility resides requiring a reconfiguration and partial relocation of our assets. This reconfiguration was completed inAdditionally, maintenance activities lowered consumption at both our CHP Plant and the second quarter of 2022, and at that time, we recommenced deliveries to the Bogue Power Plant.
•The San Juan Power Plant completed additional maintenance activities in the first quarter of 2022, leading2022; these facilities were not impacted by significant maintenance downtime in the current quarter.
•The average Henry Hub index pricing used to lower consumption of natural gas. The increase in volumes delivered at the San Juan Facilityinvoice our downstream customers decreased by 31% for the three months ended June 30, 2022 andMarch 31, 2023 as compared to the decreasethree months ended March 31, 2022.
Additionally, after the completion of the sale of our investment in CELSEPAR in the six months ended June 30,fourth quarter of 2022, were due to these additional maintenance activities.
Subsequent to the acquisition of our interest in the Sergipe Facility as part of the Mergers, ourwe no longer recognize revenue from this investment. Our share of revenue from our investment in CELSEPAR was $43,576 for the three months ended June 30, 2022 and $63,389$63.4 million for the three months ended March 31, 2022, which was primarily comprised of fixed capacity payments received under CELSE'srelated PPAs. As hydrology conditions have continued to improve in the second quarter of 2022, the Sergipe Power Plant was not dispatched in the second quarter of 2022, reducing revenue from our share of our investment in CELSEPAR. Our share of revenue from our investment in CELSEPAR was $106,965 for the six months ended June 30, 2022 as compared to $31,769 for the six months ended June 30, 2021, which represents our share of revenue for the period after the Merger. The increase was due the investment impacting our results for the full six months of 2022 as opposed to less than a full quarter of 2021 and revenue earned from dispatch of the Sergipe Power Plant in the first quarter of 2022.
Cost of sales
Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.
Cost of sales increased $36,416decreased by $158.6 million for the three months ended June 30, 2022March 31, 2023 as compared to the three months ended MarchDecember 31, 2022.2022, which was attributable to the following:
•The increase was primarily due to higherDecreased cost and volume of LNG cargo sales in the market. We recognized $115,432 during the three months ended June 30, 2022 to acquire cargos sold to third parties, as compared to $86,462 for the three months ended March 31, 2022. Due to the significant increase in market pricing of LNG in the second half of 2021 and continued increase in the first half of 2022, we have optimized our supply portfolio to sell a portion of our committed cargos in the market. LNG cargo sales in the market increased by 0.5 TBtus for the three months ended June 30, 2022. The weighted-average cost of LNG from the sale of a portion of our cargos also increased from $8.81 per MMBtu for the three months ended March 31, 2022 to $11.23 per MMBtu for the three months ended June 30, 2022.
•Cost of LNG purchased from third parties for sale to our downstream customers of $43.5 million. Volumes delivered to our downstream customers increased $33,376by approximately 10% in the current quarter; however,
our cost to deliver these volumes decreased significantly to $7.23 per MMBtu for the three months ended June 30,March 31, 2023 from $10.95 per MMBtu for the three months ended December 31, 2022.
Cost of sales decreased by $161.7 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022, which was attributable to the following:
•Realized gain of $146.1 million from the settlement of a commodity swap transaction, entered into as an economic hedge to reduce the market risks associated with commodity prices, was included as reduction of cost of sales in the first quarter of 2023. For segment performance measures, unrealized mark to market gains and losses are excluded until settled. We had no settlements of commodity derivative transactions in the first quarter of 2022.
•We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $21.4 million in the first quarter of 2023 due to increased volumes delivered; we delivered 92% more volumes to our downstream terminal customers in the current period as compared to the three months ended March 31, 2022. The increaseWhile we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was primarily attributablesubstantially lower, decreasing to a 48% increase in volumes delivered compared to$7.23 per MMBtu for the three months ended March 31, 2022, and a slight increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased2023 from $9.49 per MMBtu for the three months ended March 31, 2022 to $9.78 per MMBtu2022.
•Cost of sales for the three months ended June 30, 2022.
•During the second quarterMarch 31, 2022 included $24.7 million of 2022, the Sergipe Power Plant was dispatched substantially less than in the first quarter of 2022 due to improved hydrology conditions in Brazil. Ourour share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel thea power plant was $1,794 for the three months ended June 30, 2022, as compared to $24,742 for the three months ended March 31, 2022.owned by CELSEPAR.
Cost of sales increased $307,358 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021.
•We recognized cost to acquire LNG cargos sold to third parties and our share of cost of sales from our investment in CELSEPAR during the first and second quarters of 2022, totaling $228,429. We did not have any significant cargo sale transactions in the first half of 2021, and the acquisition of our investment in CELSEPAR in the
Mergers occurred subsequent to March 31, 2021. Accordingly, the increased costs of sales was primarily driven by these transactions.
•Cost of LNG purchased from third parties for sale to our customers increased $18,100 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021. We delivered 10% less volumes to our terminal customers in the current period as compared to the six months ended June 30, 2021. Our cost of LNG was significantly higher in the current period, and as such, the increase of cost of sales to deliver to our terminal customers did not fully correspond with the decrease in volumes. The weighted-average cost of LNG purchased from third parties increased from $6.37 per MMBtu for the six months ended June 30, 2021 to $9.66 per MMBtu for the six months ended June 30, 2022.
•We incurred additional costs associated with the required reconfiguration and partial relocation of our assets at the Port of Montego Bay of $22,165 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2022.
•Vessel costs increased $39,544 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021 due to additional vessels used in our expanded operations.
The weighted-average cost of our LNG inventory balance to be used in our operations as of June 30, 2022March 31, 2023 and December 31, 20212022 was $12.32$10.45 per MMBtu and $9.51$10.42 per MMBtu, respectively.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, and these costs are typically included in the Ships segment.
Vessel operating expenses was substantially flat for Once we begin to use a vessel in our terminal operations, the three months ended June 30, 2022 as comparedcosts of the vessel begin to be included in the Terminals and Infrastructure segment. For the three months ended March 31, 2022.
Vessel2022, we incurred $3.5 million of vessel operating expenses increased $7,747 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021 due to vessels includedin this segment; we did not incur vessel operating costs in this segment that are being chartered to third parties during periods when the vessels are not being used in our downstream terminal operations.three months ended March 31, 2023 and December 31, 2022.
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 was substantially flatdecreased $2.3 million for the three months ended June 30,March 31, 2023 as compared to the three months ended December 31, 2022. The decrease was primarily attributable to unplanned maintenance costs incurred in the fourth quarter of 2022 at the CHP Plant that did not recur in the first quarter of 2023.
Operations and maintenance decreased $3.6 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022.
Operations and maintenance increased $19,887 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021.
•The increase for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021decrease was primarily attributable to higher logistics costs associated with our ISO container distribution system. In the the six months ended June 30, 2022, we continued to source LNG from our Miami Facility to service industrial end users in Jamaica due to the reconfiguration and partial relocation of our assets at the Port of Montego Bay, and we incurred additional costs to distribute LNG to customers via our ISO container distribution system.
•Additionally, Operations and maintenance increased $11,045 due to the inclusion of our share of Operations and maintenance from our investment in CELSEPAR from $5,079of $7.1 million for the sixthree months ended June 30, 2021 to $16,124 forMarch 31, 2022. There is no such activity in the six months ended June 30, 2022, which representsfirst quarter of 2023 as we sold our investment in CELESPAR in the fourth quarter of 2022. The decrease was partially offset by additional vessel operating costs for the period after the Merger. These costs are primarily related to the operationincluded in Operations and services agreement for the maintenance as these vessels support our terminal operations.Nanook, insurance costs and costs for connecting to the transmission system.
Ships Segment
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| Three Months Ended, | | |
| (in thousands of $) | March 31, 2023 | | December 31, 2022 | | Change | | March 31, 2022 | | Change | | | | | | | | | | |
| Total revenues | $ | 97,917 | | | $ | 106,990 | | | $ | (9,073) | | | $ | 114,942 | | | $ | (17,025) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Vessel operating expenses | 19,239 | | | 19,515 | | | (276) | | | 25,942 | | | (6,703) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Segment Operating Margin | $ | 78,678 | | | $ | 87,475 | | | $ | (8,797) | | | $ | 89,000 | | | $ | (10,322) | | | | | | | | | | | |
Ships Segment
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| Three Months Ended, | | |
| (in thousands of $) | June 30, 2022 | | March 31, 2022 | | Change | | | | | | | | | | |
| Total revenues | $ | 111,024 | | | $ | 114,942 | | | $ | (3,918) | | | | | | | | | | | |
| Cost of sales | — | | | — | | | — | | | | | | | | | | | |
| Vessel operating expenses | 21,288 | | | 25,942 | | | (4,654) | | | | | | | | | | | |
| Operations and maintenance | — | | | — | | | — | | | | | | | | | | | |
| Segment Operating Margin | $ | 89,736 | | | $ | 89,000 | | | $ | 736 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Six Months Ended, |
| (in thousands of $) | June 30, 2022 | | June 30, 2021 | | Change |
| Total revenues | $ | 225,966 | | | $ | 95,762 | | | $ | 130,204 | |
| Cost of sales | — | | | — | | | — | |
| Vessel operating expenses | 47,230 | | | 20,175 | | | 27,055 | |
| Operations and maintenance | — | | | — | | | — | |
| Segment Operating Margin | $ | 178,736 | | | $ | 75,587 | | | $ | 103,149 | |
Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. We havePrior to the completion of the Energos Formation Transaction, we also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of
the Nanook. We includeincluded the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements representrepresented our ongoing ordinary businessbusiness operations.
AtDuring the completionfirst quarter of the Mergers, five of the2023, four FSRUs and twofour LNG carriers were on hireleased to customers under long-term charter agreements, and one LNG carriers, the Grand, was operating in theor spot market. In the third quarter, 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 from the third quarter of 2021 onward.arrangements. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels.
Total revenue
Total revenue for the Ships segment decreased $3,918$9.1 million for the three months ended June 30, 2022March 31, 2023 as compared to the three months ended December 31, 2022. One of our vessel charters was renewed at the beginning of 2023 at a lower rate; additionally the charters for two vessels concluded in the first quarter of 2023, lowering vessel revenue. We plan to utilize these vessels in our operations following conversion and other upgrades starting later in 2023.
Total revenue for the Ships segment decreased $17.0 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. The decrease in revenue was primarily driven by lower revenue as athe result of one FSRU being off-hirethe sale of the Nanook as part of the vessel transitions between charters; the new charter is expected to commence priorEnergos Formation Transaction; we recognized revenue of $13.2 million related to the endNanook in the first quarter of 2022. The decrease was partially offset by improved results from oneOne of our vessel charters was renewed at the beginning of 2023 at a lower rate; additionally the charters for two vessels concluded in the first quarter of 2023, lowering vessel revenue. We plan to utilize these vessels in the Cool Pool.
Total revenue for the Ships segment increased $130,204 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021. We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021,our operations following conversion and the increaseother upgrades starting later in revenue is due to the inclusion of the Ships segment in our results of operations for a full six months as opposed to less than a full quarter in the prior year comparable period.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli.prior to the Hilli Exchange discussed above. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.
Vessel operating expenses decreased $4,654$6.7 million for the three months ended June 30, 2022March 31, 2023 as compared to the three months ended March 31, 2022, primarily2022. We incurred lower vessel operating costs due to customs claimsvessels that are currently not under charter and are not in Jordan where oneservice due to drydocking or to complete other improvements to the vessels. Certain of our FSRUs operates recognized in the first quarterLNGCs are being converted to operate as an FSRU or FSU or are currently out of 2022 that did not recur in the second quarter of 2022.
Vessel operating expenses increased $27,055 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021.We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021, and the increase in vessel operating expenses is due to the inclusion of the Ships segment in our results of operations for a full six months as opposed to less than a full quarter in the prior year comparable period.
Other operating results
| | | Three Months Ended, | | Six Months Ended, | | | Three Months Ended, | |
| (in thousands of $) | (in thousands of $) | June 30, 2022 | | March 31, 2022 | | Change | | June 30, 2022 | | June 30, 2021 | | Change | | (in thousands of $) | March 31, 2023 | | December 31, 2022 | | Change | | | March 31, 2022 | | Change | |
| Selling, general and administrative | Selling, general and administrative | $ | 50,310 | | | $ | 48,041 | | | $ | 2,269 | | | $ | 98,351 | | | $ | 78,152 | | | $ | 20,199 | | | Selling, general and administrative | $ | 52,138 | | | $ | 70,099 | | | $ | (17,961) | | | | $ | 48,041 | | | $ | 4,097 | | |
| Transaction and integration costs | Transaction and integration costs | 4,866 | | | 1,901 | | | 2,965 | | | 6,767 | | | 40,716 | | | (33,949) | | | Transaction and integration costs | 494 | | | 9,409 | | | (8,915) | | | | 1,901 | | | (1,407) | | |
| Depreciation and amortization | Depreciation and amortization | 36,356 | | | 34,290 | | | 2,066 | | | 70,646 | | | 36,886 | | | 33,760 | | | Depreciation and amortization | 34,375 | | | 36,201 | | | (1,826) | | | | 34,290 | | | 85 | | |
| Asset impairment expense | Asset impairment expense | 48,109 | | | — | | | 48,109 | | | 48,109 | | | — | | | 48,109 | | | Asset impairment expense | — | | | 2,550 | | | (2,550) | | | | — | | | — | | |
| Total operating expenses | Total operating expenses | 139,641 | | | 84,232 | | | 55,409 | | | 223,873 | | | 155,754 | | | 68,119 | | | Total operating expenses | 87,007 | | | 118,259 | | | (31,252) | | | | 84,232 | | | 2,775 | | |
| Operating income (loss) | 133,695 | | | 166,456 | | | (32,761) | | | 300,151 | | | (34,548) | | | 334,699 | | | |
| Operating income | | Operating income | 267,224 | | | 250,494 | | | 16,730 | | | | 166,456 | | | 100,768 | | |
| Interest expense | Interest expense | 47,840 | | | 44,916 | | | 2,924 | | | 92,756 | | | 50,162 | | | 42,594 | | | Interest expense | 71,673 | | | 80,517 | | | (8,844) | | | | 44,916 | | | 26,757 | | |
| Other (income), net | (22,102) | | | (19,725) | | | (2,377) | | | (41,827) | | | (8,058) | | | (33,769) | | | |
| Other expense (income), net | | Other expense (income), net | 25,005 | | | (16,431) | | | 41,436 | | | | (19,725) | | | 44,730 | | |
| | Net income (loss) before income from equity method investments and income taxes | 107,957 | | | 141,265 | | | (33,308) | | | 249,222 | | | (76,652) | | | 325,874 | | | |
| (Loss) income from equity method investments | (372,927) | | | 50,235 | | | (423,162) | | | (322,692) | | | 38,941 | | | (361,633) | | | |
| Tax (benefit) provision | (86,539) | | | (49,681) | | | (36,858) | | | (136,220) | | | 3,532 | | | (139,752) | | | |
| Net (loss) income | $ | (178,431) | | | $ | 241,181 | | | $ | (419,612) | | | $ | 62,750 | | | $ | (41,243) | | | $ | 103,993 | | | |
| Income before income from equity method investments and income taxes | | Income before income from equity method investments and income taxes | 170,546 | | | 186,408 | | | (15,862) | | | | 141,265 | | | 29,281 | | |
| Income (loss) from equity method investments | | Income (loss) from equity method investments | 9,980 | | | (117,793) | | | 127,773 | | | | 50,235 | | | (40,255) | | |
| Tax provision (benefit) | | Tax provision (benefit) | 28,960 | | | 2,810 | | | 26,150 | | | | (49,681) | | | 78,641 | | |
| Net income | | Net income | $ | 151,566 | | | $ | 65,805 | | | $ | 85,761 | | | | $ | 241,181 | | | $ | (89,615) | | |
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 $2,269by $4.1 million for the three months ended June 30, 2022,March 31, 2023 as compared to the three months ended March 31, 2022. The2022; the increase was primarily attributable to higher payroll costs, screening costs and professional fees due to the continued expansion of our operations as compared to the first quarter of 2022.
Selling, general and administrative increased $20,199 for the six months ended June 30, 2022, as compared to the six months ended June 30, 2021. The increase was primarily attributable to higher payroll and professional feescosts associated with the continued expansion of our operations.
Transaction and integration costs
For the three months ended June 30, 2022,March 31, 2023, we incurred $4,866$0.5 million for transaction and integration costs, as compared to $1,901$9.4 million for the three months ended December 31, 2022 and $1.9 million for the three months ended March 31, 2022. ForDuring the three months ended June 30,December 31, 2022, we incurred transactioncosts associated with the sale of our investment in CELSEPAR. Transaction and integration costs incurred in connectionthe first quarter of 2022 were primarily associated with our continued integrations of acquisitions completed in 2021.
Depreciation and amortization
Depreciation and amortization was relatively consistent for the Sergipe Sale, which consisted primarilyeach of financial advisory, legal accounting and consulting costs.
For the sixthree months ended June 30,March 31, 2023, December 31, 2022 and March 31, 2022. Throughout 2022 and the first quarter of 2023 we incurred $6,767 for transactionhave not placed significant assets into service, and integration costs, as compared to $40,716 for the six months ended June 30, 2021. For the six months ended June 30, 2021, we incurred in transactionsuch, our depreciation and integration costs in connection with the Sergipe Sale, which consisted primarily of financial advisory, legal accounting and consulting costs and to a lesser extent integration costs from the Mergers as the integration of GMLP and Hygoamortization expense has progressed since the acquisition date.been consistent.
Asset impairment expense
Depreciation and amortization
Depreciation and amortization increased $2,066 for the three months ended June 30, 2022 as compared to the three months ended March 31, 2022. For the three months ended June 30, 2022, we incurred higher amortization of favorable and unfavorable contracts and permits.
Depreciation and amortization increased $33,760 for the six months ended June 30, 2022 as compared to the six months ended June 30, 2021. 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 for a full six months as opposed to less than a full quarter in the prior year comparable period. We recognized $18,483 of incremental depreciation expense for the acquired vessels during the six months ended June 30, 2022.
•Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of an additional $11,815 for the six months ended June 30, 2022.
Asset impairment expense
As a result of the Hygo Merger, we recognized long-lived assets associated with the expansion of the Sergipe Power Plant.Plant owned by CELSEPAR. In connection with the secondsale of our investment in CELSEPAR in the fourth quarter of 2022, we recognized asset impairment expense of $48,109, as$2.6 million. We did not recognize any impairment expense in the fair valuefirst quarter of these assets was less than the carrying value and the asset group was held for sale.
Interest expense
Interest expense increaseddecreased by $2,924$8.8 million for the three months ended June 30, 2022March 31, 2023 as compared to the three months ended December 31, 2022. The decrease was primarily due to increases in capitalized interest, partially offset by increased interest expense due to borrowings under our expanded Revolving Credit Facility.
Interest expense increased by $26.8 million for the three months ended March 31, 2023, as compared to the three months ended March 31, 2022. The increase was primarily due an increase in total principal outstanding due to draws on the Revolving Facility (defined in our Annual Report) and borrowings under the South Power 2029 Bonds (defined below); principal balance on outstanding facilities was $4,191,026 as of June 30, 2022 as compared to total outstanding debt of $3,978,250 as of March 31, 2022.
Interest expense increased by $42,594 for the six months ended June 30, 2022, as compared to the six months ended June 30, 2021. The increase was primarily due to an increase in total principal outstanding due to draws on the Revolving Facility, borrowingsadditional principal balance outstanding, including obligations under the Vessel Term Loan Facility (defined in our Annual Report) and the South Power 2029 Bonds, all occurring after June 30, 2022;Energos Formation Transaction, under which we incur higher borrowing costs. The total principal balance on outstanding facilities was $4,191,026$5.3 billion as of June 30, 2022March 31, 2023 as compared to total outstanding debt of $3,527,297$4.0 billion as of June 30, 2021. Interest expense also increased due to debt assumed in the Mergers, which were completed on April 15, 2021.March 31, 2022.
Other expense (income), net
Other expense (income), net was $(22,102)$25.0 million, $(16.4) million and $(19,725)$(19.7) million for the three months ended June 30,March 31, 2023, December 31, 2022 and March 31, 2022, respectively.
Other (income), net was $(41,827) and $(8,058) for the six months ended June 30, 2022 and June 30, 2021, respectively. Other (income)expense recognized in the three monthsthree ended March 31, 2023 was primarily comprised of a $37.4 million loss on disposal of Hilli equity method investment in the Hilli Exchange. This loss was partially offset by interest income, foreign currency remeasurment gains and sixgains on investments in equity securities.
Other (income) expense, net recognized in the three months ended June 30,December 31, 2022 was primarily comprised of
a $20.4 million gain related to the following:
•Mark-to-market gains onsettlement of the foreign currency forward purchaseduring the fourth quarter of $17,4712022.
Income recognized in both the three and six months ended June 30, 2022.
•Additionally,March 31, 2022 was primarily comprised of changes in the fair value of the cross-currency interest rate swap and the interest rate swap acquired in connection with the Mergers offset by interest expense on the interest rate swap acquired in connection with the Mergers, resulted in incomederivatives of $2,213 and $24,270 for the three and six months ended June 30, 2022.$21.6 million.
Tax provision
We recognized a tax benefitprovision for the three months ended June 30, 2022March 31, 2023 of $86,539$29.0 million compared to a tax provision of $2.8 million for the three months ended December 31, 2022 and a tax benefit of $49,681$49.7 million for the three months ended March 31, 2022. We recognized aThe significant tax benefit for the six months ended June 30, 2022 of $136,220 compared to a tax provision of $3,532 for the six months ended June 30, 2021.
The tax benefits recognized in the three and six months ended June 30,first quarter of 2022 were was primarily driven by significant discrete items, including the remeasurement of a deferred income tax liability in conjunction with an internal reorganization and the impairment of our investment in CELSEPAR. Our equity method investment in CELSEPAR is now directly held by a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil resulting in areorganization. We have not recognized any significant discrete tax
benefit of $76,460 recognizeditems in the first quarter of 2022. Additionally, in the second quarter of 2022, we recognized an other-than-temporary impairment ("OTTI") on the value of this investment, resulting in a further discrete benefit of $100,627.This increase in tax benefit for the three and six months ended June 30, 2022 was partially offset by an increase in pretax income for certain profitable operations, including GMLP and Hygo.2023.
The Company has not recorded any material changes in liabilities for uncertain tax positions in the second quarter of 2022.
(Loss) incomeIncome (loss) from equity method investments
We recognized loss and income from our equity method investments in Hilliof $10.0 million and CELSEPAR of $372,927 and $50,235 for the three months ended June 30, 2022 and March 31, 2022, respectively. In connection with the Sergipe Sale, we recognized an other than temporary impairment of the investment in CELSEPAR of $345,447. Our share of earnings from CELSEPAR was also significantly impacted by a foreign currency remeasurement loss of $28,788 for the three months ended June 30, 2022 as a result of the remeasurement of the Nanook finance lease obligation, as compared to a remeasurement gain of $42,466$117.8 million for the three months ended March 31, 2022.
2023 and December 31, 2022, respectively. We recognized lossincome of $4.0 million from our investmentsequity method investment in Energos in the three months ended March 31, 2023 and $6.0 million of income from our investment in Hilli and CELSEPAR of $322,692 for the six months ended June 30, 2022. For the six months ended June 30, 2021, during the period afterprior to the completion of the Mergers, weHilli Exchange. The loss in the fourth quarter of 2022 was primarily the result of the other-than-temporary impairment of our investment in Hilli of $118.6 million.
We recognized income of $50.2 million from our equity method investments in Hilli and CELSEPAR of $38,941. In connection with the Sergipe Purchase and Sale, we recognized an other than temporary impairment of the investment in CELSEPAR of $345,447.three months ended March 31, 2022. Our share of earnings from CELSEPAR was significantly impacted byincluded a significant foreign currency remeasurement gain of $13,678 for$42.5 million. CELSEPAR was not included in our results of operations following the six months ended June 30, 2022 as a resultsale of the remeasurement of the Nanook finance lease obligation, as compared to a remeasurement gain of $25,776 during the period after the Mergers for the six months ended June 30, 2021.this investment in 2022.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:
•Our historical financial results do not reflect the recently announced Sergipe Sale and Vessel Financing Transaction. After the completion of the Sergipe Sale expected in the fourth quarter of 2022, we will no longer include the results of our equity method investment in CELSEPAR in our financial statements. For the three and six months ended June 30, 2022, we recognized losses of $389,996 and $353,315, respectively, in Loss (income) from equity method investments in our condensed consolidated statements of operations and comprehensive income (loss). The results of operations of the Sergipe Power Plant have also been included in our Terminal and Infrastructure segment results, contributing segment operation margin of $32,732 and $64,305 for the three and six months ended June 30, 2022, respectively. Finally, we recognized an other than temporary impairment on our investment in CELSEPAR in the second quarter of 2022 of $345,447, which would not recur after the Sergipe Sale is completed.
We expect to complete the Vessel Financing Transaction in the third quarter of 2022. Upon the completion of this transaction, the majority of proceeds received will be reflected as additional financing on our condensed consolidated balance sheet, increasing our interest expense in future periods.
•Our historical financial results do not reflect new LNG supply agreements, as well as our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 96%
98% of our LNG volumes from third parties for the sixthree months ended June 30, 2022.March 31, 2023. We have entered into LNG supply agreements at a price indexed to Henry Hub through 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. We have entered into supply agreements to secure supply of 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; pricing under these agreements is indexed to Henry Hub, resulting in expected pricing below our historical supply agreements. 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, We expect to deploy our first Fast LNG prices have increased materially. Due to this significant increase in market pricing of LNG, we have optimized our supply portfolio to sell a portion of our committed cargosunit in the market with delivery throughout 2022, and these cargo sales are expected to increase our 2022 revenues and resultsthird quarter of operations2023..
•Our historical financial results do not include significant projects that have recently been completed or are near completion or in development.completion. Our results of operations for the three and six months ended June 30, 2022March 31, 2023 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We recentlyhave placed a portion of our La Paz Facility into service, and in the fourth quarter of 2021, our revenue and results of operations beganhave begun to be impacted by our operations in Mexico. We have executed short-form agreements to extend and amend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and are in the process of finalizing long-form agreements to commemorate all binding terms. We are also continuing to develop of our La Paz Power Plant and our Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects. Our current results also exclude other developments, including the Barcarena Facility, Santa Catarina Facility and Ireland Facility.
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 and the reasonably foreseeable future. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, the completion of the Sergipe Sale, the completion of the Vessel Financing Transactioncash generated from certain sales and financing transactions and cash generated from operations.operations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. We have historically funded our developments through proceeds from our IPO, and debt and equity financing, most recently as follows (below terms definedasset sales and cash from operations, and these financing transactions have been described in detail in our Annual Report):
•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 February and May 2022, we amended the Revolving Facility to increase the borrowing capacity by $115,000 and $125,000, respectively, for a total capacity under the Revolving Facility of $440,000.
•In August 2021, we entered into the CHP Facility and initially drew $100,000, which may be increased to $285,000. In January 2022, we agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds (defined below). Through June 30, 2022, we have received proceeds of $221,845 from the issuance of South Power 2029 Bonds.
•In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility. 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 $2,057$4,414 million, with approximately $1,727$3,152 million having already been spent through June 30, 2022.March 31, 2023. This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and the Sri Lanka Facility.committed capital expenditures to support our grid stabilization project in Puerto Rico. We expect fully completed Fast LNG units to be ablecost between $800 million and $1 billion per unit. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to fund all suchconstruct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed projects with a combinationspending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flowsflow from operations, and proceeds from the South Power 2029 Bonds. We will also expect to fundborrowings under existing and future Fast LNG development with proceeds received from the Sergipe Sale and Vessel Financing Transaction.debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.
As of June 30, 2022,March 31, 2023, we have spent approximately $128$128.6 million to develop the Pennsylvania Facility. Approximately $22$22.5 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$106.1 million, has been capitalized, and to date, we have repurposed approximately $17$16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities.
On December 12, 2022, our Board of Directors approved an update to our dividend policy. In connection with the dividend policy update, the Board declared a dividend of $626.3 million, representing $3.00 per Class A share, which was
paid during the first quarter of 2023. Additionally, we declared and paid quarterly dividends totaling $20.8 million during the three months ended March 31, 2023, representing $0.10 per Class A share. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our Board of Directors may deem relevant.
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 DecemberMarch 31, 2021. There were no significant changes to our contractual obligations in the first half of 2022.2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of $) | Total | | Year 1 | | Years 2 to 3 | | Year 4 to 5 | | More than
5 years |
| Long-term debt obligations | $ | 4,936,353 | | | $ | 305,575 | | | $ | 878,471 | | | $ | 3,341,677 | | | $ | 410,630 | |
| Purchase obligations | 5,265,356 | | | 784,060 | | | 1,637,783 | | | 1,450,817 | | | 1,392,696 | |
| Lease obligations | 420,329 | | | 67,131 | | | 101,295 | | | 68,393 | | | 183,510 | |
| Total | $ | 10,622,038 | | | $ | 1,156,766 | | | $ | 2,617,549 | | | $ | 4,860,887 | | | $ | 1,986,836 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of $) | Total | | Less than Year 1 | | Years 2 to 3 | | Year 4 to 5 | | More than
5 years |
| Long-term debt obligations | $ | 7,468,642 | | | $ | 163,554 | | | $ | 2,757,933 | | | $ | 2,015,021 | | | $ | 2,532,134 | |
| Purchase obligations | 13,847,969 | | | 1,501,951 | | | 1,458,028 | | | 1,278,496 | | | 9,609,494 | |
| Lease obligations | 608,453 | | | 104,970 | | | 211,620 | | | 106,866 | | | 184,997 | |
| Total | $ | 21,925,064 | | | $ | 1,770,475 | | | $ | 4,427,581 | | | $ | 3,400,383 | | | $ | 12,326,625 | |
Long-term debt obligations
For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.”Debt” in our Annual Report. The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of DecemberMarch 31, 2021.2023.
Purchase obligations
We are 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. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. 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 DecemberMarch 31, 2021. We have secured supply of LNG for 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 have construction purchase commitments in connection with our development projects, including the La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility as well asand committed capital expenditures to support our Fast LNG solution.grid stabilization project in Puerto Rico. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.
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, gas turbines and a land lease.
As of December 31, 2021, we had seven vessels under time charter leases with remaining non-cancellable terms ranging from one month to ten 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 executed a lease for an LNG carrier that has not commenced as of December 31, 2021, which has a noncancelable terms of seven years and includes fixed payments of approximately $198,100; these payments are not included in the table above.
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 space shared with affiliated companies in New York, as well as offices in Miami, New Orleans, and Rio de Janeiro, which have lease terms between three to seven years.
Cash Flows
The following table summarizes the changes to our cash flows for the sixthree months ended June 30,March 31, 2023 and 2022, and June 30, 2021, respectively:
| | | Six Months Ended June 30, | | Three Months Ended March 31, |
| (in thousands of $) | (in thousands of $) | 2022 | | 2021 | | Change | (in thousands of $) | 2023 | | 2022 | | Change |
| Cash flows from: | Cash flows from: | | | | | | Cash flows from: | | | | | |
| Operating activities | Operating activities | $ | 170,933 | | | $ | (111,352) | | | $ | 282,285 | | Operating activities | $ | 200,140 | | | $ | 114,382 | | | $ | 85,758 | |
| Investing activities | Investing activities | (441,708) | | | (1,830,933) | | | 1,389,225 | | Investing activities | (463,268) | | | (189,221) | | | (274,047) | |
| Financing activities | Financing activities | 226,654 | | | 1,544,584 | | | (1,317,930) | | Financing activities | 43,221 | | | 36,836 | | | 6,385 | |
| Net (decrease) in cash, cash equivalents, and restricted cash | $ | (44,121) | | | $ | (397,701) | | | $ | 353,580 | | |
| Net decrease in cash, cash equivalents, and restricted cash | | Net decrease in cash, cash equivalents, and restricted cash | $ | (219,907) | | | $ | (38,003) | | | $ | (181,904) | |
Cash provided by (used in) operating activities
Our cash flow provided by (used in) operating activities was $170,933$200.1 million for the sixthree months ended June 30, 2022,March 31, 2023, which increased by $282,285$85.8 million from cash used inprovided by operating activities of $(111,352)$114.4 million for the sixthree months ended June 30, 2021.March 31, 2022. Our net income for the sixthree months ended June 30, 2022,March 31, 2023, when adjusted for non-cash items, increased by $366,338$36.1 million from the sixthree months ended June 30, 2021. ChangesMarch 31, 2022. The remaining increase for the first quarter of 2023 was driven by changes in working capital accounts, primarily increases in accounts payable and accrued liabilities, partially offset the additional net income in 2022.accounts.
Cash (used in)used in investing activities
Our cash flow (used in)used in investing activities was $(441,708)$463.3 million for the sixthree months ended June 30, 2022,March 31, 2023, which decreasedincreased by $1,389,225$274.0 million from cash used in investing activities of $(1,830,933)$189.2 million for the sixthree months ended June 30, 2021.March 31, 2022. Cash outflows for investing activities during the sixthree months ended June 30,March 31, 2023 were used primarily for continued development of our Fast LNG project. Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange.
Cash outflows for investing activities during the three months ended March 31, 2022 were used for continued development of our Fast LNG solution,project, Santa Catarina Facility, Barcarena Facility, as well as expenditures to complete our La Paz Facility and Puerto Sandino Facility.
Cash used for the Mergers, net of cash acquired was $1,586,042 for the six months ended June 30, 2021. Cash outflows for investing activities during the six months ended June 30, 2021 were also used for continued development of the Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution.
Cash provided by financing activities
Our cash flow provided by financing activities was $226,654$43.2 million for the sixthree months ended June 30, 2022,March 31, 2023, which decreasedincreased by $1,317,930$6.4 million from cash used inprovided by financing activities of $1,544,584$36.8 million for the sixthree months ended June 30, 2021. March 31, 2022. In December 2023, our Board of Directors approved and declared a dividend of $626.3 million, representing $3.00 per Class A share. such dividend payment was made in January 2023. Throughout the first quarter of 2023 we borrowed under our expanded Revolving Facility for total additional borrowings of $700.0 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project.
Cash provided by financing activities during the sixthree months ended June 30,March 31, 2022 was primarily due to proceeds from issuance of debt of $437,917,$200.8 million, offset by repayments of debt of $146,030$123.7 million and payment of dividends of $47,374.
Cash provided by financing activities during the six months ended June 30, 2021 was due to proceeds received from the borrowings under the 2026 Notes of $1,500,000 and the draw of $152,500 on the Revolving Facility. The proceeds received were further offset by financing fees paid in connection with the borrowings and dividends paid for the six months ended June 30, 2021.$23.8 million.
Long-Term Debt and Preferred Stock
The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below.
South Power 2029 Bonds
In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000. The CHP Facility was secured by a mortgage over the lease of the site on which our CHP Plant is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility andFebruary 2023, we entered into an agreementamendment of our Revolving Facility which increased the commitments by $301.7 million, for a total capacity of $741.7 million. The interest rate for borrowings under the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285,000 in South PowerRevolving Facility based
2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things,on the CHP Plant. Amounts outstanding at the timecurrent usage of the mutual rescission offacility has not changed, and no changes were made to the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. In the first and second quarters of 2022, South Power issued $121,845, of South Power 2029 Bonds for a total amount outstanding of $221,845 as of June 30, 2022.
The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repaymentmaturity date in May 2029. Interest payments on outstanding principal balances are due quarterly.Principal payments and interest payments on the South Power 2029 Bonds are guaranteed by NFE.
South Power will be required to comply with certain financial covenants as well as customary affirmative and negativeor covenants. The South Power 2029 Bonds also provides for customary events of default, prepayment and cure provisions.
In conjunction with obtaining the CHP Facility,amendment, we incurred $3,243an additional $5.0 million in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional fees associated with such lenders of $258 were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the condensed consolidated balance sheets. As of June 30, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $6,063 and $3,180, respectively.
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 June 30, 2022, the Company was in compliance with all covenants under debt and lease agreements.
Financial covenants under GMLP's Vessel Term Loan Facility include requirements that GMLP and the borrowing subsidiary 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 million, each as defined in the Vessel Term Loan Facility. GMLP was in compliance with these covenants as of June 30, 2022.
The Company is also required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023. The Company was in compliance with all covenants as of June 30, 2022.
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, and the debt obligations of these entities are not reported separately in our consolidated financial statements. The key terms of CELSEPAR's and Hilli LLC's debt obligations are summarized in our Annual Report.
In July 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. Standby letters of credit are guaranteed, jointly but not severally, by CELSE’s shareholders, NFE and Ebrasil. The working capital facility is in an aggregate amount of up to $200.0 million (or its equivalent in Brazilian reais). The facility has a term of 12 months, and was renewed for an additional 12-month period in July 2022 by mutual agreement of the parties. Amounts disbursed under the working capital facility accrue interest at a rate referenced to LIBOR+, and contractual margins. As of June 30, 2022, there were no standby letters of credit issued under this facility.
Off Balance Sheet Arrangements
As of June 30, 2022 and DecemberMarch 31, 2021, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.2023.
Critical Accounting Policies and Estimates
A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of June 30, 2022,March 31, 2023, there have been no significant changes to our critical accounting estimates since our Annual Report, except as noted below.
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances signal that the carrying value of the assets may not be recoverable based on indicators, such as the acceptance of a purchase price from a market participant which is lower than the asset carrying value. Equity method investments are assessed for an other than temporary loss impairment whenever factors such as an offered purchase price from a market participant is lower than the carrying value of the investment.
In the second quarter of 2022, we considered whether there was any indication of impairment of the equity method investment in CELSEPAR and the long-lived assets of CEBARRA due to the Sergipe Sale. NFE determined that there was an OTTI of the CELSEPAR equity method investment and an impairment of CEBARRA long-lived assets. The decline in fair value of these investments was driven by the impact of significant increases in risk-free rates to future cash flows, as well as the country specific risk premium observed in connection with where such investment is held, in the second quarter of 2022.
Our estimate of fair value used in the impairment assessments was based on the purchase price in the SPA, as adjusted by contractual adjustments expected to be made to this purchase price at Closing. Judgments used to estimate the fair value included the estimation of expected adjustment to the purchase price and the allocation of the purchase price between CELSEPAR and CEBARRA. Closing is expected in the fourth quarter of 2022, and the gain or loss recognized from the completion of the Sergipe Sale will be impacted by the timing of Closing, the foreign currency exchange rate in effect at Closing, the settlement of working capital and other balances.
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.Risk.
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 downstreamcustomers 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. In 2022, we entered into a commodity swap transaction as an economic hedge to reduce the risks associated with commodity prices which settled in the first quarter of 2023 resulting in a realized gain of $146.1 million. In January 2023, we entered into a commodity swap transaction and we recognized an unrealized loss of $5.0 million in the first quarter of 2023. We currently do not currently have anyother derivative arrangements to protect against fluctuations in commodity prices, butinstruments to mitigate the effect of fluctuations in LNG prices on our operations,operations; in the future we may enter into variousadditional derivative instruments.
Interest Rate Risk
The 2025 Notes, and 2026 Notes and South Power 2029 Bonds (each defined in our Annual Report) 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 and South Power 2029 Bonds 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 $82,000.$79.0 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 VesselBarcarena Term Loan Facility has a component based on LIBOR or other market indices should LIBOR become unavailable.the Secured Overnight Financing Rate ("SOFR"). A 100-basis point increase or decrease in the market interest rate would decrease or increase our annual interest expense by approximately $3,800.
As a result of the Mergers, we assumed the Debenture Loan (defined in our Annual Report) 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 indebtednesss.$2 million.
Foreign Currency Exchange Risk
After the completion of the Hygo Merger, we began toWe have more significant transactions, assets and liabilities denominated in Brazilian reais;reais, and our Brazilian subsidiaries and investments receive income and payspay 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.
We entered into a foreign currency forward associated with the sale of our CELSEPAR and CEBERRA operations. The forward is designed to mitigate foreign currency risk and the value of the forward is linked to the amount of proceeds expected to be received from the buyer and will settle upon close of the transaction.
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, butcurrencies. As we expect our international operations to continue to grow in the near term, w.e may enter into derivative or hedging transactions with third parties to manage our exposure to changes in foreign currency exchange risks as we expand our international operations.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15(b) of the Securities Exchange Act (defined below)of 1934, as amended ("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 June 30, 2022March 31, 2023. 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 June 30, 2022March 31, 2023 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
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 June 30, 2022March 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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.”
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;
Risks Related to Our Business
•We have a limited operating history, which may not be sufficient to evaluate our business and prospects
•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;prospects;
•Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors;
• We are subject to various construction risks;
• Operation of our infrastructure, facilities and vessels involves significant risks;
• We depend on third-party contractors, operators and suppliers;
• Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;
• We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation;
• Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction;
• 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;
• Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations;
• Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements;
• Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects;
• Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;
• We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate;
• Our contracts with our customers are subject to termination under certain circumstances;
• Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess;
• Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;
• 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;
• Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses;
• We may not be ableare dependent on third-party LNG suppliers and the development of our own portfolio is subject to purchase or receive physical delivery of LNG or natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPAsvarious risks and SSAs;assumptions;
• We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve;
• Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all;
• We have incurred, and may in the future incur, a significant amount of debt;
• 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 may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;
• Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate;
• We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect;affect us;
Risks Related to the Jurisdictions in Which We Operate
• We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate;
• Our financial condition and operating results may be adversely affected by foreign exchange fluctuations;•
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;
•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;
General Risks
◦•We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest;
◦•We may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;
•We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers; and
◦•A change in tax laws in any country in which we operate could adversely affect us.
Risks Related to the Mergers
We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers.
In 2021, we consummated the Mergers, which involve the integration of Hygo and GMLP with our existing business. The integration of these businesses is a complex, costly and time-consuming process. 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. The integration of each of Hygo and GMLP into our business may result in material challenges, including, without limitation:
•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.
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. 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.
Risks Related to Our Business
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. In 2021, weWe recognized income of $92.7 million.million in 2021 and $184.8 million in 2022. Our limited operating history also means that we continue to develop and implement our strategies, policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We cannot give you any assurance that our strategy will be successful or 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. Furthermore, in 2021, we consummated the Mergers, which involve the integration of Hygo and GMLP with our existing business. Our operating history prior to 2021 does not reflect the combination of these businesses and our limited operating history may not accurately reflect our business following consummation of the Mergers. The success of our business 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, failure of which could result in a material adverse effect upon our operations and business. See “—We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers.”
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. We achieved profitability for the first time in 2021. Several of our projects have not reached commercial operations and we will not receive any material increase in operating cash flows until a project is completed. Even if completed, we may construct facilities to capture anticipated future energy consumption growth in a region in which such growth does not materialize. For example, the purchase of the project company holding the rights to develop and operate the Ireland Facility (as defined herein) is subject to several contingencies, many of which are beyond our control and could cause us not to acquire the remaining interests of the project company or cause a delay in the construction of our Ireland Facility. 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, as well as all related infrastructure, and we will need to make significant additional investments to develop, improve and operate them. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects, including in connection with the Mergers and new technologies. We expect to incur significant expenses in connection with the growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel, as well as any technologies we develop. We will need to raise significant additional debt and equity funding to achieve our goals. We cannot assure you that we will 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 ability to implement our business strategy may be materially and adversely affected by many known and unknown factors.
Our business strategy relies on a variety of factors, including our ability to successfully market LNG, natural gas, steam, and power to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the countries where we operate, and expand our projects and operations to other
countries where we do not currently operate, and successfully integrate Hygo and GMLP into our business.among others. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control, including, among others:
• 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 strategic relationships;
• failure to obtain required governmental and regulatory approvals for the construction and operation of these projects and other relevant approvals;
• unfavorable laws and regulations, changes in laws or unfavorable interpretation or application of laws and regulations; and
• 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.
Furthermore, as part of our business strategy, we 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. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance.
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 ability to execute our business strategy and adversely affect our business, financial condition and results of operations.
We are subject to various construction risks.
We are involved in the development of complex small, medium and large-scale engineering and construction projects, including our facilities, liquefaction facilities, power plants, and related infrastructure, which 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. In addition to our facilities, these infrastructure projects can include the development and construction of facilities as part of our customer contracts. Projects of this type are subject to a number of risks including, among others:
•engineering, environmental or geological problems;
•shortages or delays in the delivery of equipment and supplies;
•government or regulatory approvals, permits or other authorizations;
•failure to meet technical specifications or adjustments being required based on testing or commissioning;
•construction accidents that could result in personal injury or loss of life;
•lack of adequate and qualified personnel to execute the project;
•weather interference; and
•potential labor shortages, work stoppages or labor union disputesdisputes.
Furthermore, because of the nature of our infrastructure, we are dependent on interconnection with transmission systems and other infrastructure projects of third parties, including our customers, and/or governmental entities. Such third-party projects can be greenfield or brownfield projects, including modifications to existing infrastructure or increases in capacity to existing facilities, among others, and are subject to various construction risks.risks and additional operational monitoring and balancing requirements that may impact the design of facilities to be constructed. Delays from such third parties or governmental entities could prevent connection to our projects and generate delays in our ability to develop our own projects.In addition, 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. These risks can be increased in 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.See “–Risks Related to the Jurisdictions in which weWhich We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.”
The occurrence of any one of these factors, whatever the cause, could result in unforeseen delays or cost overruns to our projects.Delays in the development beyond our estimated timelines, or amendments or change orders to our construction contracts, could result in increases to our development costs beyond our original estimates, which could
require us to obtain additional financing or funding and could make the project less profitable than originally estimated or possibly not profitable at all. Further, any such delays could cause a delay in our anticipated receipt of revenues, a loss of one or more customers in the event of significant delays, and our inability to meet milestones or conditions precedents in our customer contracts, which could lead to delay penalties and potentially a termination of agreements with our customers. We have experienced time delays and cost overruns in the construction and development of our projects as a result of the occurrence of various of the above factors, and no assurance can be given that we will not continue to experience in the future similar events, any of which could have a material adverse effect on our business, operating results, cash flows and liquidity.
Operation of our infrastructure, facilities and vessels involves significant risks.
Our existing infrastructure, facilities and vessels and expected future operations and businesses face operational risks, including, but not limited to, the following:
•performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;
•breakdowns or failures of equipment or shortages or delays in the delivery of supplies;
•operational errors by trucks, including trucking accidents while transporting natural gas, LNG or any other chemical or hazardous substance;
•risks related to operators and service providers of tankers or tug operators;tugs used in our operations;
•operational errors by us or any contracted facility, port or other operator of related third-party infrastructure;
•failure to maintain the required government or regulatory approvals, permits or other authorizations;
•accidents, fires, explosions or other events or catastrophes;
•lack of adequate and qualified personnel;
•potential labor shortages, work stoppages or labor union disputes;
•weather-related or natural disaster interruptions of operations;
•pollution, release of or exposure to toxic substances or environmental contamination affecting operation;
•inability, or failure, of any counterparty to any facility-related agreements to perform their contractual obligations;
•decreased demand by our customers, including as a result of the COVID-19 pandemic; and
•planned and unplanned power outages or failures to supply due to scheduled or unscheduled maintenance.
In particular, we are subject to risks related to the operation of power plants, liquefaction facilities, marine and other LNG operations with respect to our facilities, FSRUsfloating storage regasification units ("FSRU") and LNG carriers, which operations are complex and technically challenging and subject to mechanical and hazardous risks and problems. In particular, marine LNG operations are subject to a variety of risks, including, among others, marine disasters, piracy, bad weather, mechanical failures, environmental accidents, epidemics, grounding, fire, explosions and collisions, human error, and war and terrorism. An accident involving our cargoescargos or any of our chartered vessels could result in death or injury to persons, loss of property or environmental damage; delays in the delivery of cargo; loss of revenues; termination of charter contracts; governmental fines, penalties or restrictions on conducting business; higher insurance rates; and damage to our reputation and customer relationships generally. Any of these circumstances or events could increase our costs or lower our revenues. If our chartered vessels suffer damage as a result of such an incident, they may need to be repaired. 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 and result in higher than anticipated operating expenses or require additional capital expenditures. The loss of earnings while these vessels are being repaired would decrease our results of operations. If a vessel we charter were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage could have a material adverse effect on our reputation, our business, our results of operations and cash flows and weaken our financial condition. Our marineoffshore operating expenses depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond its control, such as the overall economic impacts caused by the global COVID-19 outbreak. FactorsOther factors, such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements, could also increase operating expenditures. Future increases to operational costs are likely to occur. If costs rise, they could materially and adversely affect our results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and results of operations.
We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, our facilities or assets.
We depend on third-party contractors, operators and suppliers.
We rely on third-party contractors, equipment manufacturers, suppliers and operators for the development, construction and operation of our projects and assets. We have not yet entered into binding contracts for the construction, development and operation of all of our facilities and assets, and we cannot assure you that we will be able to enter into the contracts required on commercially favorable terms, if at all, which could expose us to fluctuations in pricing and potential changes to our planned schedule. If we are unable to enter into favorable contracts, we may not be able to construct and operate these assets as expected, or at all. Furthermore, these agreements are the result of arms-length negotiations and subject to change.There can be no assurance that contractors and suppliers will perform their obligations successfully
under their agreements with us.If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. For example, each of our vessels is operated and maintained by GLNG or its affiliates pursuant to ship management agreements. Any failure by GLNG or its affiliates in the operation of our vessels could have an adverse effect on our maritime operations and could result in our failure to deliver LNG to our customers as required under our customer agreements. Although some agreements may provide for liquidated damages if the contractor or supplier fails to perform in the manner required with respect to its obligations, the events that trigger such liquidated damages may delay or impair the completion or operation of the facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment, including, among others, any covenants or obligations by us to pay liquidated damages or penalties under our agreements with our customers, development services, the supply of natural gas, LNG or steam and the supply of power, as well as increased expenses or reduced revenue. Such liquidated damages may also be subject to caps on liability, and we may not have full protection to seek payment from our contractors to compensate us for such payments and other consequences. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to its respective agreement. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If we are unable to construct and commission our facilities and assets as expected, or, when and if constructed, they do not accomplish our goals or performance expectations, or if we experience delays or cost overruns in design, construction, commissioning or operation, our business, operating results, cash flows and liquidity could be materially and adversely affected.
Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.
Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional or shale natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. Since August 2021, LNG prices have increased materially, and global events, such as the COVID-19 pandemic, Russia’s invasion of Ukraine and global inflationary pressures, have generated further energy pricing volatility, which can have an adverse effect on market pricing of LNG and global demand for our products, as well as our ability to remain competitive in the markets in which we operate. Potential expansion in the Caribbean, Latin America and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. In Brazil, hydroelectric power generation is the predominant source of electricity and LNG is one of several other energy sources used to supplement hydroelectric generation. The success of our operations is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to our customers at a lower cost than the cost to deliver other alternative energy sources.
Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean and Latin America, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean, Latin America and other countries where we operate or seek to operate. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to other markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil, nuclear, hydrogen, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets. As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy
sources could adversely affect our ability to deliver LNG or natural gas to our customers on a commercial basis, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation
Our business is highly regulated and subject to numerous governmental laws, rules, regulations and requires permits, authorizations and various governmental and agency approvals, in the various jurisdictions in which we operate, that impose various restrictions and obligations that may have material effects on our business and results of operations. Each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and extent of any changes in these laws, rules, regulations and permits may be unpredictable, have retroactive effects, and may have material effects on our business. Future legislation and regulations or changes in existing legislation and regulations, or interpretations thereof, such as those relating to thepower, natural gas or LNG operations, including exploration, development and production activities, liquefaction, storage,regasification or regasificationtransportation of LNG, or its transportationour products, could cause additional expenditures, restrictions and delays in connection with our operations as well as other future projects, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.
In addition, these rules and regulationregulations are subject to decision, administrationassessed, managed, administered and implementationenforced by various governmental agencies and bodies, which takewhose actions orand decisions thatcould adversely affect our business or operations. For example, in March 2021, an amendment to the Mexican Power Industry Law (Ley de la Industria Electrica) was published which would reduce the dispatch priority of privately-owned power plants compared to state-owned power plants in Mexico. The amendment is currently suspended by Mexican courts in response to various challenges by hundreds of industry participants. The Mexican government may not implement such amendment until all such challenges have been resolved by a final judgment or dismissed by the Mexican courts. Furthermore, the Mexican Supreme Court recently discussed the constitutionality of the law and issued a non-binding majority vote in favor of declaring it unconstitutional, with the required super-majority for a general unconstitutional declaration being short by one vote. The law therefore remains suspended by the various challenges and until all of those challenges have been resolved or the suspensions revoked. As another example, on May 4, 2021, an amendment to the Mexican Hydrocarbons Law (Ley de Hidrocarburos) was published which would negatively impact our permits in Mexico. However, it has been challenged as unconstitutional by several private parties, and the legal claims are pending resolutions by Mexican courts. If the amendment is enforced against us, it could negatively affect our permitting applications, our revenue and results of operations. If either amendment is enforced against us, it could negatively affect our plant’s dispatch and our revenue and results of operations. In addition, the Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the New Regulatory Framework (Lei do Novo Modelo do Setor Elétrico). Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed. It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our Brazilian business and operations. Due to the duration of the lawsuit, it is possible that the Brazilian Federal Supreme Court will not give retroactive effect to its decision, but rather preserve the validity of past acts
applying a judicial practice known as modulation of effects. Revised, reinterpreted or additional laws and regulations that delay our ability to obtain permits necessary to commence operations or that result in increased compliance costs or additional operating costs and restrictions could have an adverse effect on our business, the ability to expand our business, including into new markets, results of operations, financial condition, liquidity and prospects.
In the United States and Puerto Rico, approvals of the Department of Energy (“DOE”) under Section 3 of the NGA, as well as several other material governmental and regulatory permits, approvals and authorizations, including under the CAA and the CWA and their state analogues, may be required in order to construct and operate an LNG facility and export LNG. Permits, approvals and authorizations obtained from the DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional requirements may be imposed. Certain federal permitting processes may trigger the requirements of the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions that have the potential to significantly impact the environment. Compliance with NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challenges to the adequacy of the NEPA analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. On July 15, 2020, the White House Council on Environmental Quality issued a final rule revising its NEPA regulations. These regulations have taken legal effect, and although they have been challenged in court, they have not been stayed. The Council on Environmental Quality has announced that it is engaged in an ongoing and comprehensive review of the revised regulations and is assessing whether and how the Council may ultimately undertake a new rulemaking to revise the regulations. The impacts of any such future revisions that may be adopted are uncertain and indeterminable for the foreseeable future. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believeOn March 19, 2021, as upheld on rehearing on July 15, 2021, FERC determined that theour San Juan Facility is jurisdictional, we provided our replysubject to FERC on July 20, 2020,its jurisdiction 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 iswas 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. The FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19, 2021 and July 15, 2021 orders withwere affirmed by the United States Court of Appeals for the District of Columbia Circuit. No other party has sought review of FERC’s orders. While our petitions for review are pending, and inCircuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.
We may not comply with each of these requirements in the future, or at all times, including any changes to such laws and regulations or their interpretation. The failure to satisfy any applicable legal requirements may result in the suspension of our operations, the imposition of fines and/or remedial measures, suspension or termination of permits or other authorization, as well as potential administrative, civil and criminal penalties, which may significantly increase compliance costs and the need for additional capital expenditures.
Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.
The design, construction and operation of our infrastructure, facilities and businesses, including our FSRUs, FLNGsFLNG units and LNG carriers, the import and export of LNG, exploration and development activities, and the transportation of natural gas, among others, are highly regulated activities at the national, state and local levels and are subject to various approvals and permits. The process to obtain the permits, approvals and authorizations we need to conduct our business, and the interpretations of those rules, is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We may be unable to obtain such approvals on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations. Many of these permits, approvals and authorizations require public notice and comment
before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application. We may also be (and have been in select circumstances) subject to local opposition, including citizens groups or non-governmental organizations such as environmental groups, which may create delays and challenges in our permitting process and may attract negative publicity, which may create an adverse impact on our reputation. In addition, such rules change frequently and are often subject to discretionary interpretations, including administrative and judicial challenges by regulators, all of which may make compliance more difficult and may increase the length of time it takes to receive regulatory approval for our operations, particularly in countries where we operate, such as Mexico and Brazil. For example, in Mexico, we have obtained substantially all permits but are awaiting regasification and transmission permits for our power plant and permits necessary to operate our terminal. We do not knowIn connection with our application to the precise date whenU.S. Maritime Administration ("MARAD") related to our FLNG project off the coast of Louisiana, MARAD announced it had initially paused the statutory 356-day application review timeline on August 16, 2022 pending receipt of additional information, and restarted the timeline on October 28, 2022. MARAD issued a second stop notice on November 23, 2022 and on December 22, 2022, MARAD issued a third data request for supplemental information. Following review of NFE's response to the December 2022 data requests, MARAD extended the stop-clock on February 21, 2023 pending clarification of responses and receipt of additional information. No assurance can be given that we will be able to obtain approval of this application and receive the required permits, we needapprovals and authorizations from governmental and regulatory agencies related to commence full commercial operations.our project on a timely basis or at all. We intend to apply for an updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities. We cannot assure if or when we will receive this permit,these permits, which isare needed prior to commencing certain construction activities related to the facility. Any
administrative and judicial challenges can delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty. We cannot control the outcome of any review or approval process, including whether or when any such permits and authorizations will be obtained, the terms of their issuance, or possible appeals or other potential interventions by third parties that could interfere with our ability to obtain and maintain such permits and authorizations or the terms thereof. Furthermore, we are developing new technologies and operate in jurisdictions that may lack mature legal and regulatory systems and may experience legal instability, which may be subject to regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to our business and new technology, which can result in difficulties and instability in obtaining or securing required permits or authorizations. There is no assurance that we will obtain and maintain these permits and authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and we may not be able to complete our projects, start or continue our operations, recover our investment in our projects and may be subject to financial penalties or termination under our customer and other agreements, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
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, steam or power. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell our products and generate fees from customers in the future. When we develop these projects, 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.
Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.
We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working
capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.
Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements.
Our business strategy relies upon our ability to successfully market our products to our existing and new customers and enter into or replace our long-term supply and services agreements for the sale of natural gas, LNG, steam and power. If we contract with our customers on short-term contracts, our pricing can be subject to more fluctuations and less favorable terms, and our earnings are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require us to enter into contracts based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in its cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover its financing costs for related vessels. Our 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. 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 -partythird-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. 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, 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 otherfederal sources. Specifically, 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. Certain of our subsidiaries are counterparties to contracts with governmental entities, including PREPA. Although these contracts require payment and performance of certain obligations, we remain subject to the statutory limitations on enforcement of those contractual provisions that protect these governmental entities. In the event that PREPA or any applicable governmental counterparty does not have or does not obtain the funds necessary to satisfy their obligations to us under our agreement with PREPAagreements, or terminatesif they terminate our agreementagreements 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 current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The substantial majorityOur results of our anticipated revenue inoperations for the year ended December 31, 2022 will be dependent upon our assets and customers in Jamaica, Brazil and Puerto Rico. Our operations in Jamaica began in October 2016, whenthe three months ended March 31, 2023, include our Montego Bay Facility, commenced commercial operations, and continue to grow, and ourOld Harbour Facility, San Juan Facility, became fully operationalcertain industrial end-users and our Miami Facility. In addition, we placed a portion of our La Paz Facility into service in the third quarter2022, and our revenue and results of 2020. We commenced ouroperations have begun to be impacted by operations in BrazilMexico, including agreements with certain power generation facilities in 2021, followingBaja California Sur. Our results for 2022 exclude other developments, including our Puerto Sandino Facility, the Mergers, and have been operating in Brazil through our joint venture for the SergipeBarcarena Facility, Santa Catarina Facility and the Sergipe Power Plant.Ireland Facility. Jamaica, BrazilMexico and Puerto Rico have historically experienced economic volatility and the general condition and performance of their economies, over which we have no control, may affect our business, financial condition and results of operations. Jamaica, Mexico and 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. See “—Risks Related to the Jurisdictions in which weWhich We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.” 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 Brazilthese geographies and directly and indirectly affects local demand for our LNG and therefore
our results of operations. Trends in tourism in the Caribbean and Brazilthese geographies 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, including the COVID-19 pandemic, severe weather or natural disasters. Due to our current lack of asset and geographic diversification, an adverse development at our operating facilities, in Jamaica, Brazil or Puerto Rico, in the energy industry or in the economic conditions in Jamaica, Brazil or Puerto Rico,these geographies, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.
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 results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon a limited number of customers, including 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, and which 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. 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.The loss of any of these customers could have an adverse effect on our revenues and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. 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.
We may not be able to convert our anticipated customer pipeline into binding long-term 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 contracts for the sale of LNG, natural gas, steam, and power with multiple counterparties in multiple jurisdictions.Counterparties commemorate their purchasing commitments for these products in various degrees of formality ranging from traditional contracts to less formal arrangements, including non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responding to requests for proposals with potential customers. These agreements and any award following a request for proposals are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations.We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements. For example, we were unable to reach a definitive agreement with an affiliate of Eni s.p.a regarding a potential tolling arrangement. In addition, the effectiveness of our binding agreements can be subject to a number of conditions precedent that may not materialize, rendering such agreements non-effective.Moreover, while certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts may be 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 nominate in excess of such minimum quantities and to perform their obligations under their respective contracts. Given the variety of sales processes and counterparty acknowledgements of the 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 or awards under requests for proposals.“In “In Discussion” volumes generally refer to volumes related to potential customers that management is actively negotiating, responding to a request for proposals, or with respect to which management anticipates a request for proposals or competitive bid process to be announced based on discussions with potential customers. Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect.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’sCompany’s future results. We may never sign a binding agreement to sell our products to the counterparty, or we may sell much less volume than we estimate, which could result in our inability to generate the revenues and profits we anticipate, having a material adverse effect on our results of operations and financial condition.
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.
Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess.
A substantial majority of our revenue is dependent upon our LNG sales to third parties. We operate in the highly competitive industry for LNG and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, in the various markets in which we operate and many of which have been in operation longer than us. Various factors relating to competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all, including , among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for natural gas but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our liquefaction projects;
•increases in the cost to supply LNG feedstock to our facilities;
•decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, heavy fuel oil and automotive diesel oil (“ADO”);
•decreases in the price of LNG; and
•displacement of LNG or fossil fuels more broadly by alternate fuels or energy sources or technologies (including but not limited to nuclear, wind, solar, biofuels and batteries) in locations where access to these energy sources is not currently available or prevalent.
In addition, we may not be able to successfully execute on our strategy to supply our existing and future customers with LNG produced primarily at our own liquefaction facilities upon completion of the Pennsylvania Facility or through our Fast LNG solution. Various competitors have and are developing LNG facilities in other markets, which will compete with our LNG facilities, including our Fast LNG solution. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs, larger and more versatile fleets, and substantially greater financial, technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities and skilled employees. See “—We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.” The superior resources that some of these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects. We anticipate that an increasing number of marineoffshore transportation companies, including many with strong reputations and extensive resources and experience will enter the LNG transportation market and the FSRU market. This increased competition may cause greater price competition for our products. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a favorable basis, if at all, which would have a material adverse effect on our business, results of operations and financial condition.
Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.
Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional or shale natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. Since August 2021, LNG prices have increased materially, and global events, such as the COVID-19 pandemic, Russia’s invasion of Ukraine and global inflationary pressures, have generated further energy pricing volatility, which can have an adverse effect on market pricing of LNG and global demand for our products, as well as our ability to remain competitive in the markets in which we operate. Potential expansion in the Caribbean, Latin America and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. In Brazil, hydroelectric power generation is the predominant source of electricity and LNG is one of several other energy sources used to supplement hydroelectric generation. The success of our operations is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to our customers at a lower cost than the cost to deliver other alternative energy sources.
Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean and Latin America, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean, Latin America and other countries where we operate or seek to operate. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to other markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets. As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect our ability to deliver LNG or natural gas to our customers on a commercial basis, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
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.
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 may 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;
•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. Conversely, current market conditions have madeincreased LNG values to historically high relative to long term pricing benchmarks, whichlevels. The elevated market values could increase the economic incentives an LNG seller has given LNG sellers the potential ability to fail to deliver volumes, payLNG cargos to us if they can sell the same LNG cargos at a higher price to another buyer in the market after giving effect to any contractual penalty, but divertpenalties the seller would owe to us for failing to deliver. Our contracts may not require an LNG seller to more profitable markets.compensate us for the full current market value of an LNG cargo that we have purchased, and if so, we may not be contractually entitled to receive full economic indemnification upon an LNG seller’s failure to deliver an LNG cargo to us. Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no 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. 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. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.
Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.
Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas.
These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our facilities. If we were to incur a
material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows.
WeAny use of hedging arrangements may not be ableadversely affect our future operating results or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase or receive physical delivery of LNG or natural gas, we have entered and may in sufficient quantities and/the future enter into futures, swaps and option contracts traded or at economically attractivecleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when expected supply is less than the amount hedged, the counterparty to the hedging contract defaults on its contractual obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
We are dependent on third-party LNG suppliers and the development of our own portfolio is subject to satisfy our delivery obligations under the GSAs, PPAsvarious risks and SSAs.assumptions.
Under our GSAs, PPAs and SSAs, we are required to deliver to our customers specified amounts of LNG, natural gas, power and steam, respectively, at specified times and within certain specifications, all of which requires us to obtain sufficient amounts of LNG from third-party LNG suppliers or our own portfolio. We may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide a counterparty with the right to terminate its GSA, PPA or SSA, as applicable, or subject us to penalties and indemnification obligations under those agreements. While we have entered into supply agreements for the purchase of LNG between 20222023 and 2030, we may need to purchase significant additional LNG volumes to meet our delivery obligations to our downstream customers. Price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices. Failure to secure contracts for the purchase of a sufficient amount of LNG or at favorable prices could materially and adversely affect our business, operating results, cash flows and liquidity.
The development of our own portfolio of LNG is subject to various risks and assumptions. In particular, the estimation of proved gas reserves involves subjective judgements and determinations based on available geological, technical, contractual, and economic information. Estimates can change over time because of new information from production or drilling activities, changes in economic factors, such as oil and gas prices, alterations in the regulatory policies of host governments, or other events. Estimates also change to reflect acquisitions, divestments, new discoveries, extensions of existing fields and mines, and improved recovery techniques. Published proved gas reserves estimates could also be subject to correction because of errors in the application of rules and changes in guidance. Downward adjustments could indicate lower future production volumes and could also lead to impairment of assets. This could have a material adverse effect on our business, operating results, cash flows and liquidity.
Additionally, we are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase LNG on the spot market or receive a sufficient quantity of LNG in order to satisfy our delivery obligations under our GSAs, PPAs and SSAs or at favorable terms. Under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased, as our vessels maybe be too small for those obligations. Any such failure to purchase or receive delivery of LNG or natural gas in sufficient quantities could result in our failure to satisfy our obligations to our customers, which could lead to delaylosses, penalties, indemnification and potentially a termination of agreements with our customers. AnyFurthermore, we may seek to litigate any such failurebreaches by our third-party LNG suppliers and shippers. Such legal proceedings may involve claims for substantial amounts of money and we may not be successful in pursing such claims. Even if we are successful, any litigation may be costly and time-consuming. If any such proceedings were to sellresult in an unfavorable outcome, we may not be able to recover our inventorylosses (including lost profits) or any damages sustained from our agreements with our customers. See “—General Risks—We are and may be involved in legal proceedings and may experience unfavorable outcomes.” These actions could also expose us to adverse publicity, which might adversely affect our reputation and therefore, our results of natural gas or LNG at attractive pricesoperations. Further, if, it could materially and adversely affecthave an adverse effect on our business, operating results, cash flows and liquidity.liquidity, which could in turn materially and adversely affect our liquidity to make payments on our debt or comply with our financial ratios and other covenants. See “—We have incurred, and may in the future incur, a significant amount of debt.”
We may not be able to fully utilize the capacity of our FSRUs and other facilities.
Our FSRU facilities have significant excess capacity that is currently not dedicated to a particular anchor customer. Part of our business strategy is to utilize undedicated excess capacity of our FSRU facilities to serve additional downstream customers in the regions in which we operate. However, we have not secured, and we may be unable to secure, commitments for all of our excess capacity. Factors which could cause us to contract less than full capacity include difficulties in negotiations with potential counterparties and factors outside of our control such as the price of and demand for LNG. For example, the owner and operator of the Sergipe Facility, CELSE, has the right to utilize 100% of the capacity at the Sergipe Facility pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Facility, we would need to obtain the consent of CELSE and the senior lenders under CELSE’s financing arrangements. Failure to secure commitments for less than full capacity could impact our future revenues and materially adversely affect our business, financial condition and operating results.
LNG that is processed and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage.
LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. WeWhere we have chartered in, but subsequently not outchartered an FSRU, which in turn results in our being unable to transfer risk of loss or damage, we could bear the risk of loss or damage to all those volumes of LNG for the period of time during which those applicable volumes of LNG isare stored on an FSRU or isare dispatched to a pipeline. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at our facilities, which could materially and adversely affect our revenues, financial condition and results of operations.
The operation of our vessels is dependent on our ability to deploy our vessels to an NFE terminal or to long-term charters.
Our principal strategy for our FSRU and LNG carriers is to provide steady and reliable shipping, regasification and marineoffshore operations to NFE terminals and, to the extent favorable to our business, replace or enter into new long-term carrier time charters for our vessels. Most requirements for new LNG projects continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium
term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands. More frequent changes to vessel sizes, propulsion technology and emissions profile, together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the duration of long-term charters could also decrease over time. We may also face increased difficulty entering into long-term time charters upon the expiration or early termination of our contracts. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. If we lose any of our charterers and are unable to re-deploy the related vessel to a NFE terminal or into a new replacement contract 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, it is an event of default under the credit facilities related to all of our vessels if the time charter of any vessel related to any such credit facility is cancelled, rescinded or frustrated and we are unable to secure a suitable replacement charter, post additional security or make certain significant prepayments. Any event of default under GMLP’s credit facilities would result in acceleration of amounts due thereunder.
We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer.
In addition to our own fleet of vessels, we rely on third-party ocean-going tankers and freight carriers (for ISO containers) for the transportation of LNG and ship-to-ship kits to transfer LNG between ships. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers on favorable terms or at all, which may result in us not being able to meet our obligations. Our ability to enter into contracts or renew existing contracts will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of charter rates and contract provisions. Fluctuations in rates result from changes in the supply of and demand for capacity and changes in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demand are outside of our control and are highly unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.
Furthermore, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo carrying capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, emissions standards, maritime regulatory changes and other factors not within our control. The availability of the tankers could be delayed to the detriment of our LNG business and our customers because the construction and delivery of LNG tankers require significant capital and long construction lead times. Changes in ocean freight capacity, which are outside our control, could negatively
impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers.
The operation of ocean-going tankers and kits carries inherent risks. These risks include the possibility of natural disasters; mechanical failures; grounding, fire, explosions and collisions; piracy; human error; epidemics; and war and terrorism. We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. As a result, if our current equipment fails, is unavailable or insufficient to service our LNG purchases, production, or delivery commitments we may need to procure new equipment, which may not be readily available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Any of these results could have a material adverse effect on our business, financial condition and operating results.
Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings may decline.
Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to current and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a number of factors outside of our control. For example, driven in part by an increase in LNG production capacity, the market supply particularly of LNG carriers has been increasing. As of March 23, 2022, the LNG carrier order book totaled 187 vessels, including two FSRUs/FSUs. We believe that this and any future expansion of the global LNG carrier fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, the impact of which could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth. The LNG market is also closely connected to world natural gas prices and energy markets, which it cannot predict. A substantial or extended decline in demand for natural gas or LNG including as a result of the spread of COVID-19, could adversely affect our ability to
charter or re-charter our vessels at acceptable rates or to acquire and profitably operate new vessels. Accordingly, this could have a material adverse effect on our earnings, financial condition, operating results and prospects.
Vessel values may fluctuate substantially and, if these values are lower at a time when we are attempting to dispose of vessels, we may incur a loss.
Vessel values can fluctuate substantially over time due to a number of different factors, including:
•prevailing economic conditions in the natural gas and energy markets;
•a substantial or extended decline in demand for LNG;
•increases in the supply of vessel capacity without a commensurate increase in demand;
•the size and age of a vessel; and
•the cost of retrofitting, steel or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.
As our vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on our business and operations if we do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel would be significant.
During the period a vessel is subject to a charter, we will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, we may be unable to re-deploy the affected vessels at attractive rates or for our operations and, rather than continue to incur costs to maintain and finance them, we may seek to dispose of them. When vessel values are low, we may not be able to dispose of vessels at a reasonable price when we wish to sell vessels, and conversely, when vessel values are elevated, we may not be able to acquire additional vessels at attractive prices when we wish to acquire additional vessels, which could adversely affect our business, results of operations, cash flow, and financial condition.
The carrying values of our vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates and the cost of new build vessels. Our vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Although we did not recognize an impairment charge on any of its vessels for the year ended December 31, 2021,2022, we cannot assure you that we will not recognize impairment losses on our vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect our business, financial condition, or operating results.
Maritime claimants could arrest our vessels, which could interrupt our cash flow.
If we are in default on certain kinds of obligations related to our vessels, such as those to our lenders, crew members, suppliers of goods and services to our vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of our vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in our fleet for claims relating to another of our vessels. The arrest or attachment of one or more of our vessels could interrupt our cash flow and require us to pay to have the arrest lifted. Under some of our present charters, if the vessel is arrested or detained (for as few as 14 days in the case of one of our charters) as a result of a claim against us, we may be in default of our charter and the charterer may terminate the charter. This would negatively impact our revenues and cash flows.
We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve.
We analyze and seek to implement innovative and new technologies that complement our businesses to reduce our costs, achieve efficiencies for our business and our customers and advance our long-term goals, such as our ISO container distribution system, our Fast LNG solution and our green hydrogen project. The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. 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. See “—Our Fast LNG technology is a novel technology that is not yet proven and we may not be able to implement it as planned or at all.” We are also making investments to develop green hydrogen energy technologies as part of our long-term goal to become one of the world’s leading providers of carbon-free energy. In October 2020, we announced our intention to partner with Long Ridge Energy Terminal and GE Gas Power to transition a power plant to be capable of burning 100%
green hydrogen over the next decade, and we made our first hydrogen-related investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology. We continue to develop our ISO container distribution systems in the various markets where we operate. We expect to make additional investments in this field in the future. Because these technologies are innovative, we may be making investments in unproven business strategies and technologies with which we have limited or no prior development or operating experience. As an investor in these technologies, it is also possible that we could be exposed to claims and liabilities, expenses, regulatory challenges and other risks. We may not be able to successfully develop these technologies, and even if we succeed, we may ultimately not be able to realize the time, revenues and cost savings we currently expect to achieve from these strategies, which could adversely affect our financial results.
Technological innovation may impair the economic attractiveness of our projects.
The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although we plan to build out our delivery logistics chain in Northern Pennsylvania using proven technologies such as those currently in operation at our Miami Facility, we do not have any exclusive rights to any of these technologies. In addition, such technologies may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others, which could materially and adversely affect our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
Our Fast LNG technology is a novel technology that is not yet proven and we may not be able to implement it as planned or at all.
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.Our ability to create and maintain a competitive position in the natural gas liquefaction industry may be adversely affected by our inability to effectively implement our Fast LNG technology. We are in the processfinalizing construction of designing and constructing our first Fast LNG solution, and are therefore subject to construction risks, risks associated with third-party contracting and service providers, permitting and regulatory risks.See “—We are subject to various construction risks” and “—We depend on third-party contractors, operators and suppliers.”Because our Fast LNG technology is a new technology that has not been previously implemented, tested or proven, we are also exposed to unknown and unforeseen risks associated with the development of new technologies, including failure to meet design, and engineering, or performance specifications, incompatibility of systems, inability to contract or employ third parties with sufficient experience in technologies used or inability by contractors to perform their work, delays and schedule changes, high costs and expenses that may be subject to increase or difficult to anticipate, regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to the technology, and added difficulties in obtaining or securing required permits or authorizations, among others. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” The success and profitability of our Fast LNG technology is also dependent on the volatility of the price of natural gas and LNG compared to the related levels of capital spending required to implement the technology. Natural gas and LNG prices have at various times been and may become volatile due to one
or more of factors. Volatility or weakness in natural gas or LNG prices could render our LNG procured through Fast LNG too expensive for our customers, and we may not be able to obtain our anticipated return on our investment or make our technology profitable. In addition, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in jurisdictions withwhich could potentially expose us to increased political, economic, social and legal instability, a lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us toor additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. See “—Risks Related to the Jurisdictions in which weWhich We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.” Furthermore, as part of our business strategy for Fast LNG, we may enter into tolling agreements with third parties, including in developing countries, and these counterparties may have greater credit risk than typical. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. We may not be able to successfully develop, construct and implement our Fast LNG solution, and even if we succeed in developing and constructing the technology, we may ultimately not be able to realize the cost savings and revenues we currently expect to achieve from it, which could result in a material adverse effect upon our operations and business.
We have incurred, and may in the future incur, a significant amount of debt.
On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. As of December 31, 20212022 and June 30, 2022,March 31, 2023, we had approximately $3,896 million$4.5 billion and $4,191 million,
$5.3 billion, respectively, aggregate principal amount of indebtedness outstanding on a consolidated basis. In connection with the Mergers, we assumed a significant amount of indebtedness, including guarantees and preferred shares, and we incurred a significant amount of debt to pay a portion of the purchase price for the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses, and for general corporate purposes. The terms and conditions of our indebtedness including some of the indebtedness we assumed as part of the Mergers, include restrictive covenants that may limit our ability to operate our business, to incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities. If we fail to comply with any of these restrictions or are unable to pay our debt service when due, our debt could be accelerated or cross-accelerated, and we cannot assure you that we will have the ability to repay such accelerated debt. Any such default could also have adverse consequences to our status and reporting requirements, reducing our ability to quickly access the capital markets. Our ability to service our existing and any future debt will depend on our performance and operations, which is subject to factors that are beyond our control and compliance with covenants in the agreements governing such debt. 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, which could have a material adverse effect on our business, results of operation and financial condition.
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 and the reasonably foreseeable future. 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. 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. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Our ability to raise additional capital on acceptable terms 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, 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. Additional debt financing, if available, may subject us to increased restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. 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. 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, we may be unable to pay or refinance our indebtedness or to fund our other liquidity needs, and our financial condition or results of operations may be materially adversely affected.
Our current and any future sale and leaseback agreements contain or may contain restrictive covenants that may limit our liquidity and corporate activities.
Hygo’s sale and leaseback agreements for the Nanook, Penguin and Celsius contain, and any future sale and leaseback agreements we may enter into are expected to contain, customary covenants and event of default clauses, including specified financial ratios and financial covenants, including minimum consolidated leverage ratio and the minimum free liquidity covenants, as well as cross-default provisions and restrictive covenants and performance requirements that may affect our operational and financial flexibility. Such restrictions could affect, and in many respects limit or prohibit, among other things, Hygo’s or our ability to incur additional indebtedness, create liens, sell assets, or engage in mergers or acquisitions, as well as our ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities. A failure by Hygo to meet payment and other obligations, including the financial covenant requirements, could lead to defaults under other sale and leaseback agreements or any future sale and leaseback agreements. If we are not in compliance with our covenants and are not able to obtain covenant waivers or modifications, the current or future owners of our leased vessels, as appropriate, could retake possession of the vessels or require us to pay down our indebtedness or sell vessels in our fleet. We could lose our vessels if we default on our bareboat charters in connection with the sale and leaseback agreements, which would negatively affect our revenues, results of operations and financial condition. In addition, Hygo also assigns the shares in its subsidiaries which are the charterers of these vessels to the owners/lessors. There can be no assurance that such restrictions will not adversely affect our ability to finance future
operations or capital needs. As a result of these restrictions in current sale and leaseback agreements, or similar restrictions in future sale and leaseback agreements, we may need to seek permission from the owners of our leased vessels to engage in certain corporate actions. Their interests may be different from ours and we may not be able to obtain their permission when needed. This may prevent us from taking actions that we believe are in our best interest, which may adversely impact our revenues, results of operations and financial condition.
We have entered into, and may in the future enter into or modify existing, joint ventures that might restrict our operational and corporate flexibility or require credit support.
We have entered into, and may in the future enter, into joint venture arrangements with third parties in respect of our projects and assets. For example,In August 2022, we established Energos, as a joint venture platform with certain funds or investment vehicles managed by Apollo, for the Sergipe Facility and Sergipe Power Plant are partdevelopment of a 50/50 joint venture between Hygo and Ebrasil and our interest in the Hilli is the resultglobal marine infrastructure platform, of an acquisition by GMLP in July 2018 of 50% of the common units in Hilli LLC (the “Hilli Acquisition”), the disponent owner of Hilli Corp. (as defined herein), the owner of the Hilli, which represents the equivalent of 50% of the two liquefaction trains, out of a total of four, that have been contracted to Perenco Cameroon SA (“Perenco”) and Société Nationale Des Hydrocarbures (“SNH” and, together with Perenco, the “Customer”) pursuant to a Liquefaction Tolling Agreement (“LTA”) with an 8-year term.we own 20%. As we do not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Because we do not control all of the decisions of our joint ventures, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in its or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by our joint ventures. Additionally, as the joint ventures are separate legal entities, any right we may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities, trade creditors and any other third parties that require such subordination, such as lenders and other creditors).
Moreover, joint venture arrangements involve various risks and uncertainties, such as our commitment to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture. We have provided and may in the future provide guarantees or other forms of credit support to our joint ventures and/or affiliates. For example, in connection with the closing of the Hilli Acquisition, GMLP agreed to provide a several guarantee (the “GMLP Guarantee”) of 50% of the obligations of Hilli Corp, a wholly owned subsidiary of Hilli LLC, under a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Facility”), pursuant to a Deed of Amendment, Restatement and Accession relating to a guarantee between GLNG, Fortune and GMLP dated July 12, 2018. The Hilli Facility provided for post-construction financing for the Hilli in the amount of $960 million.These guarantees or credit support contain and can contain certain financial restrictions and other covenants that may restrict our business and financing activities. We backstop the GMLP guarantee of Hilli Corp’s debt under the Hiili Leaseback by separately guaranteeing GMLP’s performance. Failure by any of our joint ventures, (e.g., Hilli Corp), equity method investees and/or affiliate to service their debt requirements and comply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to an event of default under the related loan agreement. As a result, if our joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to repay the outstanding borrowings, the relevant lenders may foreclose their liens on the relevant assets or vessels securing the loans or seek repayment of the loan from us, or both. Either of these possibilities could have a material adverse effect on our business. Further, by virtue of our guarantees with respect to our joint ventures and/or affiliates, this may reduce our ability to gain future credit from certain lenders.
Any use of hedging arrangements may adversely affect our future operating results or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when expected supply is less than the amount hedged, the counterparty to the hedging contract defaults on its contractual obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
We have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or OTC options and swaps with other natural gas merchants and financial institutions. Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect the cost and availability of the swaps that we may use for hedging, including, without limitation, rules setting limits on the positions in certain contracts, rules regarding aggregation of positions, requirements to clear through specific derivatives clearing organizations and trading platforms, requirements for posting of margins, regulatory requirements on swaps market participants. Our counterparties that are also subject to the capital requirements set out by the Basel Committee on the Banking Supervision in 2011, commonly referred to as “Basel III,” may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Our subsidiaries and affiliates operating in Europe and the Caribbean may be subject to the European Market Infrastructure Regulation (“EMIR”) and the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants, which may impose increased regulatory obligations, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data, as well as requiring liquid collateral. These regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to forgo the use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.
We may incur impairments to long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business, or adverse actions by governmental entities, changes to regulation or legislation could lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions
based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our condensed consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.
Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate.
Weather events such as storms and related storm activity and collateral effects, or other disasters, accidents, catastrophes or similar events, natural or manmade, such as explosions, fires, seismic events, floods or accidents, could result in damage to our facilities, liquefaction facilities, or related infrastructure, interruption of our operations or our supply chain, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our marineonshore and coastaloffshore operations. Due to the nature of our operations, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology. In particular, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in locations that are subject to risks posed by hurricanes and similar severe weather conditions or natural disasters or other adverse events or conditions that could severely affect our infrastructure, resulting in damage or loss, contamination to the areas, and suspension of our operations. For example, our operations in coastal regions in southern Florida, the Caribbean, the Gulf of Mexico and Latin America are frequently exposed to natural hazards such as sea-level rise, coastal flooding, cyclones, extreme heat, hurricanes, and earthquakes. These climate risks can affect our operations, potentially even damaging or destroying our facilities, leading to production downgrades, costly delays, reduction in workforce productivity, and potential injury to our people. In addition, jurisdictions with increased political, economic, social and legal instability, lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us to additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. In addition, because of the location of some of our operations, we are subject to other natural phenomena, including earthquakes, such
as the one that occurred near Puerto Rico in January 2020, which resulted in a temporary delay of development of our Puerto Rico projects.projects, hurricanes and tropical storms. If one or more tankers, pipelines, facilities, liquefaction facilities, vessels, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our facilities, liquefaction facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe or similar event, our construction projects and our operations could be significantly interrupted, damaged or destroyed. These delays, interruptions and damages could involve substantial damage to people, property or the environment, and repairs could take a significant amount of time, particularly in the event of a major interruption or substantial damage. We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” The occurrence of a significant event, or the threat thereof, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental, social, health and safety laws and regulations could result in increased or more stringent compliance requirements, which may be difficult to comply with or result in additional costs and may otherwise lead to significant liabilities and reputational damage.
Our business is now and will in the future be subject to extensive national, federal, state, municipal and local laws, rules and regulations, in the United States and in the jurisdictions where we operate, relating to the environment, social, health and safety and hazardous substances. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG, natural gas and other substances; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA and the CWA, and analogous laws and regulations in the jurisdictions in which we operate, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities and vessels, and require us to obtain and maintain permits and provide governmental authorities with access to our facilities and vessels for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Changes or new environmental, social, health and safety laws and regulations could cause additional expenditures, restrictions and delays in our business and operations, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in
October 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance document was a “rule” subject to the Congressional Review Act (“CRA”). This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the CRA, potentially increasing the likelihood that laws and regulations applicable to our business will become subject to revised interpretations in the future that we cannot predict. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Any failure in environmental, social, health and safety performance from our operations may result in an event that causes personal harm or injury to our employees, other persons, and/or the environment, as well as the imposition of injunctive relief and/or penalties or fines for non-compliance with relevant regulatory requirements or litigation. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain permits and approvals, and otherwise jeopardize our reputation or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. As the owner and operator of our facilities and owner or charterorcharterer of our vessels, we may be liable, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment at or from our facilities and for any resulting damage to natural resources, which could result in substantial liabilities, fines and penalties, capital expenditures related to cleanup efforts and pollution control equipment, and restrictions or curtailment of our operations. Any such liabilities, fines and penalties that exceed the limits of our insurance coverage. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets.
Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associated with the processing, transportation, and use of fossil fuels and emission of GHGs. In the United States to date, no comprehensive climate change legislation has been implemented at
the federal level, although various individual states and state coalitions have adopted or considered adopting legislation, regulations or other regulatory initiatives, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement, effective February 19, 2021, and other countries where we operate or plan to operate, including Jamaica, Brazil, Ireland, Mexico, and Nicaragua, have signed or acceded to this agreement. However, the scope of future climate and GHG emissions-focused regulatory requirements, if any, remain uncertain. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States and worldwide. For example, based in part on the publicized climate plan and pledges by President Biden, there may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. For example, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve U.S. goals under the Paris Agreement.
Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.
The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs, and thereby reduce demand for or erode value for, the natural gas that we process and market. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. Furthermore, political, litigation, and financial risks may result in reduced natural gas production activities, increased liability for infrastructure damages as a result of climatic changes, or an
impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is subject to these regulations, none of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but regulators and governmental agencies in the jurisdictions in which we operate can impose similar siting, design, construction and operational requirements that can affect our projects, facilities, infrastructure and operations. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change. Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and management of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.
Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. Hydraulic fracturing activities can be regulated at the national, federal or local levels, with governmental agencies asserting authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Such authorities may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending
the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).
The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several jurisdictions have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition, some local jurisdictions have adopted or considered adopting land use restrictions, such as city or municipal ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.
Indigenous Communities.Communities. Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which states that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations, such as are required for our Brazilian operations, are consulted through appropriate procedures and through their representative institutions, particularly using the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for our operations, we are required to comply with the
requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: IBAMA, local environmental authorities in the National Congress (in specific cases),localities in which we operate, the Federal Public Prosecutor’s Office and the National Indian Foundation (Fundaç(Fundação Nacional do Índio or FUNAI)“FUNAI”) (for indigenous people) or Palmares Cultural Foundation (Fundaç(Fundação Cultural Palmares)Palmares) (for Quilombola communities).
Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact its operations. For example, in February 2020, the Interamerican Court of Human Rights (“IACtHR”) found that Argentina had not taken adequate steps, in law or action, to ensure the consulting of indigenous communities and obtaining those communities’ free prior and informed consent for a project impacting their territories. IACtHR further found that Argentina had thus violated the ACHR due to infringements on the indigenous communities’ rights to property, cultural identity, a healthy environment, and adequate food and water by failing to take effective measures to stop harmful, third-party activities on the indigenous communities’ traditional land. As a result, IACtHR ordered Argentina, among other things, to achieve the demarcation and grant of title to the indigenous communities over their territory and the removal of the third-partiesthird parties from the indigenous territory. We cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact our existing development agreements or negotiations for outstanding development agreements with indigenous communities in the areas in which we operate.
There are several indigenous communities that surround our operations in Brazil. Hygo hasCertain of our subsidiaries have entered into agreements with some of these communities that mainly provide for the use of their land for our operations, provide compensation for any potential adverse impact that our operations may indirectly cause to them, and negotiations with other such communities are ongoing. If we are not able to timely obtain the necessary authorizations or obtain them on favorable terms for our operations in areas where indigenous communities reside, our relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to our operations, we could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.
International Waters.Offshore operations. Our chartered vessels’ operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vesselswe operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, the handling and disposal of hazardous substances and wastes and the management of ballast water. The International Maritime Organization (“IMO”) International Convention for the Prevention of Pollution from Ships of 1973, as amended from time to time, and generally referred to as “MARPOL,” can affect operations of our chartered vessels. In addition, our chartered LNG vessels may become subject to the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the “HNS Convention”), adopted in 1996 and subsequently amended by a Protocol to the HNS Convention in April 2010. Other regulations include, but are not limited to, the designation of Emission Control Areas under MARPOL, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as amended from time to time, the International Convention on Civil Liability for Bunker Oil Pollution Damage, the IMO International Convention for the Safety of Life at Sea of 1974, as amended from time to time, the International Safety Management Code for the Safe Operations of Ships and for Pollution Prevention, the IMO International Convention on Load Lines of 1966, as amended from time to time and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004.
In particular, development of offshore operations of natural gas and LNG are subject to extensive environmental, industry, maritime and social regulations. For example, any development and future operation of the potential Lakach project, which would be developed as a deepwater natural gas field in Mexico, as well as the development of a new FLNG hub off the coast of Altamira, State of Tamaulipas, would be subject to regulation by Mexico’s Ministry of Energy (Secretaría de Energía) (“SENER”), Mexico's National Hydrocarbon Commission (“CNH”), the National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”), among other relevant Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidelines as the industry develops. Such regulations are subject to change, so it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. In addition, our operations in waters off the coast of Mexico are subject to regulation by ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also
relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidelines as the industry modernizes and adapts to market changes. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.
Moreover, the overall trends are towards more regulations and more stringent requirements which are likely to add to our costs of doing business. For example, IMO regulations, which became applicable on January 1, 2020, limit the sulfur content of fuel oil for ships to 0.5 weight percent starting January 1, 2020, thus increasing the cost of fuel and increasing expenses for us. Likewise, the European Union is considering extending its emissions trading scheme to maritime transport to reduce GHG emissions from vessels. We contract with industry leading vessel providers in the LNG market and look for them to take the lead in maintaining compliance with all such requirements, although the terms of our charter agreements may call for us to bear some or all of the associated costs. While we believe we are similarly situated with respect to other companies that charter vessels, we cannot assure you that these requirements will not have a material effect on our business.
Our chartered vessels operating in U.S. waters, now or in the future, will also be subject to various federal, state and local laws and regulations relating to protection of the environment, including the OPA, the CERCLA, the CWA and the CAA. In some cases, these laws and regulations require governmental permits and authorizations before conducting certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our chartered vessels’ operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, may increase our overall cost of business.
We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation.
We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Latin America, Europe and the other countries in which we seek to do business. We must also comply with trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. For example, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua and inbetween 2018 2019 and 2020,2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the government of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in Russia or connected to Russia, including sanctions specifically targeting the Russian oil and gas industry. Although we take precautions to comply with all such laws and regulations, violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to, (i) having to suspend our development or operations on a temporary or permanent basis, (ii) being unable to recuperate prior invested time and capital or being subject to lawsuits, or (iii) investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.
We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we
currently, or may in the future, operate may present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico or other countries in Latin America, Asia and Africa. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, it is highly challenging to adopt policies and procedures that ensure compliance in all respects with the FCPA, particularly in high-risk jurisdictions. Developing and implementing policies and procedures is a complex endeavor. There is no assurance that these policies and procedures will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire.
If we are not in compliance with trade and economic sanctions laws and anti-corruption laws and regulations, including the FCPA, we may be subject to costly and intrusive criminal and civil investigations as well significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, the imposition of an independent compliance monitor, as well as potential personnel change and disciplinary actions. In addition, non-compliance with such laws could constitute a breach of certain covenants in operational or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers. In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries. Violations of applicable import, export, trade and economic sanctions, and anti-corruption laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with these provisions in the future. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, liquidity and future business prospects. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.
Although we believe that we have been in compliance with all applicable sanctions, embargo and anti-corruption laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism, which could adversely affect our ability to access funding and liquidity, our financial condition and prospects.
Our Chartererscharterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.
None of our vessels have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism. When we charter our vessels to third parties we conduct comprehensive due diligence of the charterer and include prohibitions on the charterer calling on ports in countries subject to comprehensive U.S. sanctions or otherwise engaging in commerce with such countries. However, our vessels may be sub-chartered out to a sanctioned party or call on ports of a sanctioned nation on charterers’ instruction, and without our knowledge or consent. If our charterers or sub-charterers violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, those violations could in turn negatively affect our reputation and cause us to incur significant costs associated with responding to any investigation into such violations.
Increasing transportation regulations may increase our costs and negatively impact our results of operations.
We are developing a transportation system specifically dedicated to transporting LNG using ISO tank containers and trucks to our customers and facilities. This transportation system may include trucks that we or our affiliates own and operate. Any such operations would be subject to various trucking safety regulations in the various countries where we operate, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA��FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to state and/or local safety regulations that mirror federal regulations but also regulate the weight and size dimensions of loads. Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental
regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size. In addition to increased costs, fines and penalties, any non-compliance or violation of these regulations, could result in the suspension of our operations, which could have a material adverse effect on our business and consolidated results of operations and financial position.
Our chartered vessels operating in certain jurisdictions, including the United States, now or in the future, may be subject to cabotage laws, including the Merchant Marine Act of 1920, as amended (the “Jones Act”).
Certain activities related to our logistics and shipping operations may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions in which we operate. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act in the U.S., only vessels meeting specific national ownership and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade.” When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as fines or forfeiture of any vessels or their cargo, and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition.
We do not own the land on which our projects are located and are subject to leases, rights-of-ways, easements and other property rights for our operations.
We have obtained long-term leases and corresponding rights-of-way agreements and easements with respect to the land on which various of our projects are located, including the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the Miami Facility, the San Juan Facility and the CHP Plant are situated, facilities in Brazil such as the Garuva-Itapoa pipeline connecting the TBG pipeline to the Sao Francisco do Sul terminal, rights of way to the Petrobras/Transpetro OSPAR oil pipeline facilities, among others. In addition, our operations will require agreements with ports proximate to our facilities capable of handling the transload of LNG direct from our occupying vessel to our transportation assets. We do not own the land on which these facilities are located. As a result, we are subject to the possibility of increased costs to retain necessary land use rights as well as applicable law and regulations, including permits and authorizations from governmental agencies or third parties. If we were to lose these rights or be required to relocate, we would not be able to continue our operations at those sites and our business could be materially and adversely affected. For example, 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. 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 our assets as anticipated, or at all, which could negatively affect our business, results of operations and financial condition.
We could be negatively impacted by environmental, social, and governance (“ESG”) and sustainability-related matters.
Governments, investors, customers, employees and other stakeholders are increasingly focusing on corporate ESG practices and disclosures, and expectations in this area are rapidly evolving. We have announced, and may in the future announce, sustainability-focused goals, initiatives, investments and partnerships. These initiatives, aspirations, targets or objectives reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. Our efforts to accomplish and accurately report on these initiatives and goals present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and stock price.
In addition, the standards for tracking and reporting on ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period. Moreover, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals. In this regard, the criteria by which our ESG practices and disclosures are assessed may change due to the quickly evolving
landscape, which could result in greater expectations of us and cause us to undertake costly initiatives to satisfy such new criteria. The increasing attention to corporate ESG initiatives could also result in increased investigations and litigation or threats thereof. If we are unable to satisfy such new criteria, investors may conclude that our ESG and sustainability practices are inadequate. If we fail or are perceived to have failed to achieve previously announced initiatives or goals or to accurately disclose our progress on such initiatives or goals, our reputation, business, financial condition and results of operations could be adversely impacted.
Information technology failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected. We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities, liquefaction facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our network systems and storage and other business applications, and the systems and storage and other business applications maintained by our third-party providers, have been in the past, and may be in the future, subjected to attempts to gain unauthorized access to our network or information, malfeasance or other system disruptions.
Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, liquefaction facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.
Our current operations and future projects are subject to the inherent risks associated with construction of energy-related infrastructure, LNG, natural gas, power and maritime operations, shipping and transportation of hazardous substances, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, acts of aggression or terrorism, and other risks or hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the facilities, liquefaction facilities and assets or damage to persons and property. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not generally carry business interruption insurance or political risk insurance with respect to political disruption in the countries in which we operate and that may in the future experience significant political volatility. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses or delays to our development timelines, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Even if we choose to carry insurance for these events in the future, it may not be adequate to protect us from loss, which may include, for example, losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain. In addition, our insurance may be voidable by the insurers as a result of certain of our actions. Furthermore, we may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult or costly for us to obtain.
Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.
We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, some of our other executive officers and other key employees. Mr. Edens does not have an employment agreement with us. The loss of the services of Mr. Edens or one or more of our other key executives or employees could disrupt our operations and increase our exposure to the other risks described in this Item 1A. Risk Factors. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.
We are dependent upon the available labor pool of skilled employees for the construction and operation of our facilities and liquefaction facilities, as well as our FSRUs, FLNGs and LNG carriers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our infrastructure and assets and to provide our customers with the highest quality service. In addition, the tightening of the labor market due to the shortage of skilled employees may affect our ability to hire and retain
skilled employees, impair our operations and require us to pay increased wages. We are subject to labor laws in the jurisdictions in which we operate and hire our personnel, which can govern such matters as minimum wage, overtime, union relations, local content requirements and other working conditions. For example, Brazil and Indonesia, where some of our vessels operate, require we hire a certain portion of local personnel to crew our vessels. Any inability to attract and retain qualified local crew members could adversely affect our operations, business, results of operations and financial condition. Furthermore, should there be an outbreak of COVID-19 on our facilities or vessels, adequate staffing or crewing may not be available to fulfill the obligations under our contracts. Due to COVID-19, we could face (i) difficulty in finding healthy qualified replacement employees; (ii) local or international transport or quarantine restrictions limiting the ability to transfer infected employees from or to our facilities or vessels, and (iii) restrictions in availability of supplies needed for our projects due to disruptions to third-party suppliers or transportation alternatives. See “—General Risks—We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.” A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.
Our business could be affected adversely by labor disputes, strikes or work stoppages.
Some of our employees, particularly those in our Latin American operations, are represented by a labor union and are covered by collective bargaining agreements pursuant to applicable labor legislation. As a result, we are subject to the risk of labor disputes, strikes, work stoppages and other labor-relations matters. We could experience a disruption of our operations or higher ongoing labor costs, which could have a material adverse effect on our operating results and financial condition. Future negotiations with the unions or other certified bargaining representatives could divert management attention and disrupt operations, which may result in increased operating expenses and lower net income. Moreover, future agreements with unionized and non-unionized employees may be on terms that are note as attractive as our current agreements or comparable to agreements entered into by our competitors. Labor unions could also seek to organize some or all of our non-unionized workforce.
Risks Related to the Jurisdictions in Which We Operate
We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.
Our projects are located in Jamaica and the United States (including Puerto Rico), the Caribbean, Brazil, Mexico, Ireland, Nicaragua and other geographies and we have operations and derive revenues from additional markets. Furthermore, part of our strategy consists in seeking to expand our operations to other jurisdictions.As a result, our projects, operations, business, results of operations, financial condition and prospects are materially dependent upon economic, political, social and other conditions and developments in these jurisdictions. Some of these countries have experienced political, security, and social economic instability in the recent past and may experience instability in the future, including devaluation, depreciation,changes, sometimes frequent or marked, in energy policies or the personnel administering them, expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions or controls, currency exchange controls, inflation, economic downturns, political instability,fluctuations, royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of social unrest, terrorism, corruption and bribery. For example, in 2019, public demonstrations in Puerto Rico led to the governor’s resignation and the resulting political change interrupted the bidding process for the privatization of PREPA’s transmission and distribution systems. While our operations wereto date have not to date,been materially impacted by the demonstrations or political changes in Puerto Rico’s administration,Rico, any substantial disruption in our ability to perform our obligations under the Fuel Sale and Purchase Agreementany agreements with PREPA could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship with PREPA could change given PREPA’s award forprivatization of its transmission, distribution and distributionpower generation system. PREPA may seek to find alternative power sources or purchase substantially less natural gas from us than what we currently expect to sell to PREPA. Moreover,In addition, we cannot predict how local sentiment and support for our subsidiaries’ operations in Puerto Rico could change following the Sri Lankan government has experienced substantial disruption, which has delayed the developmentprivatization of Puerto Rico’s power generation systems. Should our facility in Colombo, Sri Lanka and may require usoperations face material local opposition, it could materially adversely affect our ability to postpone the project indefinitely.perform our obligations under our contracts or could materially adversely impact PREPA or any applicable governmental counterparty’s performance of its obligations to us. The governments in these jurisdictions differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. Governments may seek to impose controls on prices, exchange rates, local and foreign investment and international trade, restrict the ability of companies to dismiss employees, expropriate private sector assets and prohibit the remittance of profits to foreign investors. As our operations depend on governmental approval and regulatory decisions, we may be adversely affected by
changes in the political structure or government representatives in each of the countries in
which we operate. Any extreme levels of political instability resulting in changes of governments, internal conflict, unrest and violence, especially from terrorist organizations prevalent in the region, could lead to economic disruptions and shutdowns in industrial activities. In addition, these jurisdictions, particularly emerging countries, are subject to risk of contagion from the economic, political and social developments in other emerging countries and markets.
Furthermore, some of the regions in which we operate have been subject to significant levels of terrorist activity and social unrest, particularly in the shipping and maritime industries. Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. For example, the operations of Hilli Corp in Cameroon, which has experienced instability in its socio-political environment, under the LTA are subject to higher political and security risks than operations in other areas of the world. Tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries. See “—Our Charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.” We do not, nor do we intend to, maintain insurance (such as business interruption insurance or terrorism) against all of these risks and losses. Any claims covered by insurance will be subject to deductibles, which may be significant, and we may not be fully reimbursed for all the costs related to any losses created by such risks. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” As a result, the occurrence of any economic, political, social and other instability or adverse conditions or developments in the jurisdictions in which we operate, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.
While our condensed consolidated financial statements are presented in U.S. dollars, we generate revenues and incur operating expenses and indebtedness in local currencies in the countries where we operate, such as, among others, the euro, the Mexican peso and the Brazilian real. The amount of our revenues denominated in a particular currency in a particular country typically varies from the amount of expenses or indebtedness incurred by our operations in that country given that certain costs may be incurred in a currency different from the local currency of that country, such as the U.S. dollar. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars could result in potential losses and reductions in our margins resulting from currency fluctuations, which may impact our reported consolidated financial condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars and elect to intervene by implementing exchange rate regimes, including sudden devaluations, periodic mini devaluations, exchange controls, dual exchange rate markets and a floating exchange rate system. There can be no assurance that non-U.S. currencies will not be subject to volatility and depreciation or that the current exchange rate policies affecting these currencies will remain the same. For example, the Mexican peso and the Brazilian real have experienced significant fluctuations relative to the U.S. dollar in the past. We may choose not to hedge, or we may not be effective in efforts to hedge, this foreign currency risk. See “—Risks Related to our Business—Any use of hedging arrangements may adversely affect our future operating results or liquidity.” Depreciation or volatility of these currencies against the U.S. dollar could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.
Risks Related to Ownership of Our Class A Common Stock
The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.
The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:
•a shift in our investor base;
•our quarterly or annual earnings, or those of other comparable companies;
•actual or anticipated fluctuations in our operating results;
•changes in accounting standards, policies, guidance, interpretations or principles;
•announcements by us or our competitors of significant investments, acquisitions or dispositions;
•the failure of securities analysts to cover our Class A common stock;
•changes in earnings estimates by securities analysts or our ability to meet those estimates;
•the operating and share price performance of other comparable companies;
•overall market fluctuations;
•general economic conditions; and
•developments in the markets and market sectors in which we participate.
Stock markets in the United States have experienced extreme price and volume fluctuations. Market fluctuations, as well as general political and economic conditions such as acts of terrorism, prolonged economic uncertainty, a recession or interest rate or currency rate fluctuations, could adversely affect the market price of our Class A common stock. Furthermore, the market price of our common stock may fluctuate significantly following consummation of the Mergers if, among other things, the combined company is unable to achieve the expected growth in earnings, or if the operational cost savings estimates in connection with the integration of our, Hygo’s and GMLP’s businesses are not realized, or if the transaction costs relating to the Mergers are greater than expected, or if the financing relating to the transaction is on unfavorable terms. The market price also may decline if the combined company does not achieve the perceived benefits of the Mergers as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Mergers on the combined company’s financial position, results of operations or cash flows is not consistent with the expectations of financial or industry analysts. In addition, the results of operations of the combined company and the market price of our common stock after the completion of the Mergers may be affected by factors different from those currently affecting the independent results of operations of each of our, Hygo’s and GMLP’s and business.
We are a “controlled company” within the meaning of Nasdaq rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.
Affiliates of certain entities controlled by Wesley R. Edens, Randal A. Nardone and affiliates of Fortress Investment Group LLC (“Founder Entities”), together with affiliates of Energy Transition Holdings LLC, hold a majority of the voting power of our stock. In addition, pursuant to the Shareholders’ Agreement, dated as of February 4, 2019, by and among the Company and the respective parties thereto (the “Shareholders’ Agreement”), the Founder Entities currently have the right to nominate a majority of the members of our Board of Directors. Furthermore, the Shareholders’ Agreement provides that the parties thereto will use their respective reasonable efforts (including voting or causing to be voted all of the Company’s voting shares beneficially owned by each) to cause to be elected to the Board, and to cause to continue to be in office the director nominees selected by the Founder Entities. Affiliates of NFE SMRSEnergy Transition Holdings LLC are parties to the Shareholders’ Agreement and as of June 30, 2022March 31, 2023 hold approximately 16%12.5% of the voting power of our stock. As a result, we are a controlled company within the meaning of the Nasdaq corporate governance standards. Under Nasdaq rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:
•a majority of the board of directors consist of independent directors as defined under the rules of Nasdaq;
•the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
•the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
These requirements will not apply to us as long as we remain a controlled company. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. We intend to utilize some or all of these exemptions. Accordingly, our corporate governance may not afford the same protections as companies that are subject to all of the corporate governance requirements of Nasdaq.
A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders.
As of June 30, 2022,March 31, 2023, affiliates of the Founder Entities own an aggregate of approximately 87,136,768 shares of Class A common stock, representing 42.0%approximately 42.6% of our voting power. Aspower, and affiliates of June 30, 2022, Wesley R. Edens, Randal A. Nardone and Fortress Investment GroupEnergy Transition Holdings LLC, directly or indirectlyparty to the Shareholders' Agreement, own 47,540,925an aggregate of approximately 25,559,846 shares 26,196,526 shares and 13,399,317 shares, respectively, of our Class A common stock, representing 22.9%, 12.6% and 6.5%approximately 12.5% of the voting power of theour Class A common stock, respectively.stock. The beneficial ownership of greater than 50% of our voting stock means affiliates of the Founder Entities and Energy Transition Holdings LLC are able to control matters requiring stockholder approval, including the election of directors, changes to
our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of the affiliates of the Founder Entitiesthese parties with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders, including holders of the Class A common stock.
Given this concentrated ownership, the affiliates of the Founder Entities and Energy Transition Holdings LLC would have to approve any potential acquisition of us. The existence of a significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the concentration of stock ownership with affiliates of the Founder Entities and Energy Transition Holdings LLC may adversely affect the trading price of our securities, including our Class A common stock, to the extent investors perceive a disadvantage in owning securities of a company with a significant stockholder.
Furthermore, in connection with the Exchange Transactions (as defined herein), New Fortress Energy Holdings has assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition, our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.
Our Certificate of Incorporation and Bylaws,By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock.
Our Certificate of Incorporation and BylawsBy- Laws authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of stock constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third-partythird party to acquire us. In addition, some provisions of our Certificate of Incorporation and BylawsBy-Laws could make it more difficult for a third-partythird party to acquire control of us, even if the change of control would be beneficial to our security holders.securityholders. These provisions include:
•dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;
•providing that any vacancies may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (provided that vacancies that results from newly created directors requires a quorum);
•permitting special meetings of our stockholders to be called only by (i) the chairman of our board of directors, (ii) a majority of our board of directors, or (iii) a committee of our board of directors that has been duly designated by the board of directors and whose powers include the authority to call such meetings;
•prohibiting cumulative voting in the election of directors;
•establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of the stockholders; and
•providing that the board of directors is expressly authorized to adopt, or to alter or repeal our certain provisions of our organizational documents to the extent permitted by law.
Additionally, our Certificate of Incorporation provides that we have opted out of Section 203 of the Delaware General Corporation Law. However, our Certificate of Incorporation includes a similar provision, which, subject to certain exceptions, prohibits us from engaging in a business combination with an “interested stockholder,” unless the business combination is approved in a prescribed manner. Subject to certain exceptions, an “interested stockholder” means any person who, together with that person’s affiliates and associates, owns 15% or more of our outstanding voting stock or an affiliate or associate of ours who owned 15% or more of our outstanding voting stock at any time within the previous three years, but shall not include any person who acquired such stock from the Founder Entities or NFE SMRSEnergy Transition Holdings LLC (except in the context of a public offering) or any person whose ownership of stock in excess of 15% of our outstanding voting stock is the result of any action taken solely by us. Our Certificate of Incorporation provides that the Founder Entities and NFE SMRSEnergy Transition Holdings LLC and any of their respective direct or indirect transferees, and any group as to which such persons are a party, do not constitute “interested stockholders” for purposes of this provision.
Our BylawsBy-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our BylawsBy-Laws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or employees arising pursuant to any provision of our organizational documents or the Delaware General Corporation Law, or (iv) any action asserting a claim against us or any of our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in our stock will be deemed to have notice of, and consented to, the provisions described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it considers more likely to be favorable for disputes with us or our directors, officers, employees or agents,
which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our organizational documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, results of operations or prospects.
The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all.
The declaration and payment of dividends to holders of our Class A common stock will be at the discretion of our board of directors in accordance with applicable law after taking into account various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deem relevant. There can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all. Because we are a holding company and have no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries and our ability to receive distributions from our subsidiaries may be limited by the financing agreements to which they are subject.
The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation including any debt issued in connection with the financing of the Mergers and future issuances of equity or equity-related securities, which would dilute the holdings of our existing Class A common stockholders and may be senior to our Class A common stock for the purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock.
We have incurred and may in the future incur or issue debt including any debt issued in connection with the financing of the Mergers, or issue equity or equity-related securities to finance our operations, acquisitions or investments. Upon our liquidation, lenders and holders of our debt and holders of our preferred stock (if any) would receive a distribution of our available assets before Class A common stockholders. Any future incurrence or issuance of debt would increase our interest cost and could adversely affect our results of operations and cash flows. We are not required to offer any additional equity securities to existing Class A common stockholders on a preemptive basis. Therefore, additional issuances of Class A common stock, directly or through convertible or exchangeable securities (including limited partnership interests in our operating partnership), warrants or options, will dilute the holdings of our existing Class A common stockholders and such issuances, or the perception of such issuances, may reduce the market price of our Class A common stock. Any preferred stock issued by us would likely have a preference on distribution payments, periodically or upon liquidation, which could eliminate or otherwise limit our ability to make distributions to Class A common stockholders. Because our decision to incur or issue debt or issue equity or equity-related securities in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.
We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.
Our Certificate of Incorporation and BylawsBy-Laws authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock in respect of dividends and distributions, as our board of directors may
determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.
Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock.
Sales of substantial amounts of our Class A common stock in the public market, or the perception that such sales might occur, could adversely affect the market price of our Class A common stock. The issuance of our Class A common stock in connection with property, portfolio or business acquisitions or the exercise of outstanding options or otherwise could also have an adverse effect on the market price of our Class A common stock.
An active, liquid and orderly trading market for our Class A common stock may not be maintained and the price of our Class A common stock may fluctuate significantly.
Prior to January 2019, there was no public market for our Class A common stock. An active, liquid and orderly trading market for our Class A common stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock.
General Risks
We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest.
We conduct our business mainly through our operating subsidiaries and affiliates, including joint ventures and other special purpose entities, which are created specifically to participate in projects or manage a specific asset. Our ability to meet our financial obligations is therefore related in part to the cash flow and earnings of our subsidiaries and affiliates and the ability or willingness of these entities to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments, which are governed by various shareholder agreements, joint venture financing and operating arrangements. In addition, some of our operating subsidiaries, joint venture and special purpose entities are subject to restrictive covenants related to their indebtedness, including restrictions on dividend distributions. Any additional debt or other financing could include similar restrictions, which would limit their ability to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments. Similarly, we may fail to realize anticipated benefits of any joint venture or similar arrangement, which could adversely affect our financial condition and results of operation.
We may engage in mergers, sales and acquisitions, divestments, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value.
In furtherance of our business strategy, we may engage in mergers, purchases or sales, divestments, reorganizations or other similar transactions related to our businesses or assets in the future. Any such transactions may be subject to significant risks and contingencies, including the risk of integration, valuation and successful implementation, and we may not be able to realize the benefits of any such transactions. We may also engage in sales of our assets or sale and leaseback transactions that seek to monetize our assets and there is no guarantee that such sales of assets will be executed at the prices we desire or higher than the values we currently carry these assets at on our balance sheet. We do not know if we will be able to successfully complete any such transactions or whether we will be able to retain key personnel, suppliers or distributors. Our ability to successfully implement our strategy through such transactions depends upon our ability to identify, negotiate and complete suitable transactions and to obtain the required financing on terms acceptable to us. These efforts could be expensive and time consuming, disrupt our ongoing business and distract management. If we are unable to successfully complete our transactions, our business, financial condition, results of operations and prospects could be materially adversely affected.
We are unable to predict the extent to which the global pandemics and health crisis, such as the COVID-19 pandemic, will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.
The COVID-19 pandemic has caused, and is expected to continue to cause, economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil and other commodities. In addition, the pandemic has made, and any future global health crisis or pandemic could make, travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of the COVID-19any such crisis or pandemic and its economic consequences are uncertain, rapidly-changing and difficult to predict, the pandemic’sits impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains or could be uncertain and difficult to predict. Further, the ultimate impact of the COVID-19any such pandemic or crisis on our operations and financial performance depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the COVID-19 pandemic (including restrictions on travel and transport and workforce pressures); the impact of thesuch pandemic or crisis and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs, as well as
other monetary and financial policies enacted by governments (including monetary policy, taxation, exchange controls, interest rates, regulation of banking and financial services and other industries, government budgeting and public sector financing); the duration and severity of resurgences of COVIDany variants; general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery when the COVID-19 pandemic or crisis subsides. The COVID-19 pandemic has subjected ourOur operations, financial performance and financial condition have been subjected to the COVID-19 pandemic and could be subjected to a number of operational financial risks.risks in any such future pandemic or crisis. Although the services we provide are generally deemed essential, we may face negative impacts from increased operational challenges based on the need to protect employee health and safety, workplace disruptions and restrictions on the movement of people including our employees and subcontractors, and disruptions to supply chains related to raw materials and goods both at our own facilities, liquefaction facilities and at customers and suppliers. We may also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the operations and financial condition of our customers and potential customers, as well as the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.
A change in tax laws in any country in which we operate could adversely affect us.
Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.
We arehave been and may be involved in legal proceedings and may experience unfavorable outcomes.
We arehave been and may in the future be subject to material legal proceedings in the course of our business or otherwise, including, but not limited to, actions relating to contract disputes, business practices, intellectual property, real estate and leases, and other commercial, tax, regulatory and permitting matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time-consuming and expensive. Moreover, the process of litigating requires substantial time, which may distract our management. Even if we are successful, any litigation may be costly, and may approximate the cost of damages sought. These actions could also expose us to adverse publicity, which might adversely affect our reputation and therefore, our results of operations. Further, if any such proceedings were to result in an unfavorable outcome, it could have an adverse effect on our business, financial position and results of operations.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.
As a public company with stock listed on Nasdaq, we are subject to an extensive body of regulations, including certain provisions of the Sarbanes-Oxley Act, the Dodd-Frank Act, regulations of the SEC and Nasdaq requirements. Compliance with these rules and regulations increases our legal, accounting, compliance and other expenses. For example, as a result of becoming a public company, we added independent directors and created additional board committees. We entered into an administrative services agreement with FIG LLC, an affiliate of Fortress Investment Group (which currently employs Messrs. Edens, our chief executive officer and chairman of our Board of Directors, and Nardone, one of our Directors), in connection with the IPO, pursuant to which FIG LLC provides us with certain back-office services and charges us for selling, general and administrative expenses incurred to provide these services. In addition, we may incur additional costs associated with our public company reporting requirements and maintaining directors’ and officers’ liability insurance. It is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate, and the incremental costs may have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our share price could decline.
The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose viability in the financial markets, which in turn could cause our share price or trading volume to decline.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
(a) None.
(b) None.
(c) None.
Some of our operating subsidiaries, joint venture and special purpose entities are subject to restrictive covenants related to their indebtedness, including restrictions on dividend distributions. For information on our long-term debt obligations and debt and lease restrictions, see “—“Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt —“Debtand Preferred Stock —Debt and lease restrictions.”
Item 3. Defaults uponUpon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
Not applicable.
Item 6. Exhibits.
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Exhibit
Number | Description |
| Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, GMLP Merger Sub, GP Buyer, GMLP and the General Partner (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021). |
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| Transfer Agreement, dated as of January 13, 2021, by and among GP Buyer, GLNG and the General Partner (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021). |
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| Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, Hygo Merger Sub, Hygo and the Hygo Shareholders (incorporated by reference to Exhibit 2.3 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021). |
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| Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the SEC on November 9, 2018) |
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| Certificate of Amendment to Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the SEC on November 9, 2018) |
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| First Amended and Restated Limited Liability Company Agreement of New Fortress Energy LLC, dated February 4, 2019 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Certificate of Conversion of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). |
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| Certificate of Incorporation of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). |
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| Bylaws of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). |
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| Contribution Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Intermediate LLC, New Fortress Energy Holdings LLC, NFE Atlantic Holdings LLC and NFE Sub LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Amended and Restated Limited Liability Company Agreement of New Fortress Intermediate LLC, dated February 4, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| New Fortress Energy LLC 2019 Omnibus Incentive Plan (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8, (File No. 333-229507), filed with the SEC on February 4, 2019). |
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| Form of Director Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A, (File No. 333-228339), filed with the SEC on December 24, 2018). |
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| Restricted Share Unit Award Agreement under the Amended and Restated New Fortress Energy Inc. 2019 Omnibus Incentive Plan.Plan (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q, filed with the Commission on November 8, 2022). |
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| Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardone (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Administrative Services Agreement, dated February 4, 2019, by and between New Fortress Intermediate LLC and FIG LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790),filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Edens)(Guinta) (incorporated by reference to Exhibit 10.410.5 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Guinta)(Catterall) (incorporated by reference to Exhibit 10.510.7 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Catterall)(Grain) (incorporated by reference to Exhibit 10.710.8 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Grain)(Griffin) (incorporated by reference to Exhibit 10.810.9 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Griffin)(Mack) (incorporated by reference to Exhibit 10.910.10 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Mack)(Nardone) (incorporated by reference to Exhibit 10.1010.11 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Nardone)(Wanner) (incorporated by reference to Exhibit 10.1110.12 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Wanner)(Wilkinson) (incorporated by reference to Exhibit 10.1210.13 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the SEC on February 5, 2019). |
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| Indemnification Agreement (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).(Jay ). |
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| Amendment Agreement dated as February 11, 2019 to Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019). |
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| Second Amendment Agreement, dated as of March 13, 2019 to the Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, and as amended as of February 11, 2019, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019). |
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| Engineering, Procurement and Construction Agreement for the Marcellus LNG Production Facility I, dated January 8, 2019, by and between Bradford County Real Estate Partners LLC and Black & Veatch Construction, Inc. (incorporated by reference to Exhibit 10.17 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the SEC on January 25, 2019). |
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| Indemnification Agreement, dated as of March 17, 2019, by and between New Fortress Energy LLC and Yunyoung Shin (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019). |
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| Letter Agreement, dated as of December 3, 2019, by and between NFE Management LLC and Yunyoung Shin. (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2020). |
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| Letter Agreement, dated as of March 14, 2017, by and between NFE Management LLC and Christopher S. Guinta (incorporated by reference to Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Indenture, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020). |
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| Pledge and Security Agreement, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020). |
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| First Supplemental Indenture, dated December 17, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on December 18, 2020). |
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| Support Agreement,Second Supplemental Indenture, dated as of January 13,March 1, 2021, bybetween NFE US Holdings LLC, as Guaranteeing Subsidiary, and among NFE, GMLP, GLNG and the General PartnerU.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.110.21 to the Registrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the SEC on January 20, 2021)March 1, 2023). |
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| Third Supplemental Indenture, dated as of June 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Fourth Supplemental Indenture, dated as of September 13, 2021, between NFE Mexico Power Holdings Limited and NFE Mexico Terminal Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.23 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Fifth Supplemental Indenture, dated as of November 24, 2021, between NFE International Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.24 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Sixth Supplemental Indenture, dated as of March 23, 2022, between NFE UK Holdings Limited, NFE Global Holdings Limited and NFE Bermuda Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Seventh Supplemental Indenture, dated as of December 27, 2022, between NFE Andromeda Chartering LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Indenture, dated April 12, 2021, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021). |
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| Pledge and Security Agreement, dated April 12, 2021, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021). |
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| Shareholders’ Agreement,First Supplemental Indenture, dated as of April 15,June 11, 2021, bybetween Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and among theU.S. Bank Trust Company, GLNG, and StonepeakNational Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.110.29 to the Registrant’s CurrentAnnual Report on Form 8-K,10-K, filed with the SEC on April 21, 2021)March 1, 2023). |
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| Second Supplemental Indenture, dated as of September 13, 2021, between NFE Mexico Power Holdings Limited and NFE Mexico Terminal Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Third Supplemental Indenture, dated as of November 24, 2021, between NFE International Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.31 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Fourth Supplemental Indenture, dated as of March 23, 2022, between NFE UK Holdings Limited, NFE Global Holdings Limited and NFE Bermuda Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.32 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Fifth Supplemental Indenture, dated as of December 27, 2022, between NFE Andromeda Chartering LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.33 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc,. as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021). |
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| First amendment to Credit Agreement, dated as of July 16, 2021 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time partly thereto, the several lenders and issuing banks from time to time partly thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.30 to the Registrant’s QuarterlyAnnual Report on Form 10-K, filed with the SEC on March 1, 2022). |
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| Second Amendment to Credit Agreement, dated as of February 28, 2022 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.31 to the Registrant’s QuarterlyAnnual Report on Form 10-K, filed with the SEC on March 1, 2022). |
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| Third Amendment to Credit Agreement, dated as of May 4, 2022 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.32 to the Registrant’s QuarterlyAnnual Report on Form 10-Q, filed with the SEC on May 6, 2022). |
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| Fourth Amendment to Credit Agreement, dated as of February 7, 2023 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.38 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GLNG and certain other parties thereto (incorporated by reference to Exhibit 10.30 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). |
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| Indemnity Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and certain affiliates of Stonepeak (incorporated by reference to Exhibit 10.31 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). |
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| Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GMLP, GLNG and certain parties thereto (incorporated by reference to Exhibit 10.32 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). |
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| Tax Indemnification Agreement, dated as of April 15, 2021, by and between NFE International and GLNG (incorporated by reference to Exhibit 10.33 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). |
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| Facility Agreement, dated September 18, 2021, by and among Golar Partners Operating LLC as the Borrower, Golar LNG Partners LP and certain subsidiaries of the Borrower, with (i) Citibank N.A. and the lenders from time to time party thereto; (ii) Citigroup Global Markets Limited, Morgan Stanley Senior Funding, Inc. and HSBC Bank USA, N.A. as mandated lead arrangers; (iii) Goldman Sachs Bank USA as arranger; (iv) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as bookrunners; (v) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as co-ordinators, (vi) Citibank Europe Plc, UK Branch as agent and (vii) Citibank, N.A., London Branch as security agent (incorporated by reference to Exhibit 10.34 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 3, 2021). |
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| Share Purchase Agreement, dated as of May 31, 2022, by and among LNG Power Limited, Ebrasil Energia Ltda., the individual DC Energia Sellers set forth therein, collectively as Sellers, Eneva S.A., as Buyer, and Eletricidade do Brasil S.A. -Ebrasil, as guarantor for the obligations of the DC Energia Sellers.Sellers (incorporated by reference to Exhibit 10.38 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2022). |
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| Equity Purchase and Contribution Agreement, dated as of July 2, 2022, by and among Golar LNG Partners LP and Hygo Energy Transition Ltd., as Sellers, AP Neptune Holdings Ltd, as Purchaser, Floating Infrastructure Holdings LLC, as the Company, and Floating Infrastructure Intermediate LLC, as Holdco Pledgor, and Floating Infrastructure Holdings finance LLC, as Borrower, and New Fortress Energy Inc.(incorporated by reference to Exhibit 10.39 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2022). |
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| Second Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated July 27, 2022, by and among New Fortress Energy Inc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent, Natixis, New York Branch, as ULCA Collateral Agent, Natixis, New York Branch, and each of the other financial institutions party thereto, as Lenders and Issuing Banks.Banks (incorporated by reference to Exhibit 10.40 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2022). |
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| Incremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated February 6, 2023, by and among New Fortress Energy Inc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent and as Issuing Bank, Credit Agricole Corporate and Investment Bank, as Issuing Bank, and Sumitomo Mitsui Banking Corporation, as Issuing Bank (incorporated by reference to Exhibit 10.45 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023). |
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| Underwriting Agreement, dated December 14, 2022, by and among New Fortress Energy Inc., Energy Transition Holdings LLC and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on December 16, 2022). |
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| Certification by Chief Executive Officer pursuant to RuleRules 13a-14(a) and 15d-14(a) of the Exchange Act, Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| Certification by Chief Financial Officer pursuant to RuleRules 13a-14(a) and 15d-14(a) of the Exchange Act, Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| 101.INS* | Inline XBRL Instance Document |
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| 101.SCH* | Inline XBRL Schema Document |
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| 101.CAL* | Inline XBRL Calculation Linkbase Document |
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| 101.LAB* | Inline XBRL Label Linkbase Document |
1
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| 101.PRE* | Inline XBRL Presentation Linkbase Document |
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| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document |
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| 104* | Cover Page Interactive Data File, formatted in Inline XBRL and contained in Exhibit 101 |
* Filed as an exhibit to this Quarterly ReportReport.
** Furnished as an exhibit to this Quarterly ReportReport.
† Compensatory plan or arrangementarrangement.
# Portions of the exhibit (indicated by asterisks) have been omitted in compliance withpursuant to Item 601 (b)(10)(iv) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| NEW FORTRESS ENERGY INC. |
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Date: AugustMay 4, 20222023 | | |
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| By: | /s/ Wesley R. Edens |
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| Name: | Wesley R. Edens |
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| Title: | Chief Executive Officer and Chairman |
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| | (Principal Executive Officer) |
Date: AugustMay 4, 20222023 | | |
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| By: | /s/ Christopher S. Guinta |
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| Name: | Christopher S. Guinta |
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| Title: | Chief Financial Officer |
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| | (Principal Financial Officer) |
Date: AugustMay 4, 20222023 | | |
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| By: | /s/ Yunyoung Shin |
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| Name: | Yunyoung Shin |
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| Title: | Chief Accounting Officer |
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| | (Principal Accounting Officer) |