UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
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| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the year ended December 31, 20202023
OR
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| o | 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)
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| Delaware | | 83-1482060 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
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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
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered
on which registered
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| Class A common stock | NFE | NASDAQNasdaq Global Select Market |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐x No ☒o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐o No ☒x
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 ☐o
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 ☐o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer ☐x | Accelerated filer ☒o |
Non-accelerated filer ☐o | 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. ☐o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b)404(b) of the Sarbanes-Oxley Act (15(15 U.S.C. 7262(b)7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒x
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐o No ☒x
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed as of June 30, 20202023 (the last business day of the registrant’s most recently completed second fiscal quarter), based on the closing price of the Class A sharescommon stock on the Nasdaq Global Select Market, was $417.4$2,776.0 million.
At March 15, 2021,February 26, 2024, the registrant had 175,958,649205,033,557 shares of Class A common stock outstanding.
Documents Incorporated by Reference::
Portions of the registrant’s definitive proxy statement for the registrant’s 20212024 annual meeting, to be filed within 120 days after the close of the registrant’s fiscal year, are incorporated by reference into Parts II and III of this Annual Report on Form 10-K.
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As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this Annual Report on Form 10-K (“Annual Report”), the terms listed below have the following meanings:
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| ADO | automotive diesel oil |
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| Bcf/yr | billion cubic feet per year |
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| 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 |
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| CAA | Clean Air Act |
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| CERCLA | Comprehensive Environmental Response, Compensation and Liability Act |
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| CWA | Clean Water Act |
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| DOE | U.S. Department of Energy |
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| 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 |
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| GAAP | generally accepted accounting principles in the United States |
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| GHG | greenhouse gases |
| GHG | greenhouse gases
| GSA | |
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 |
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| 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 LNG gallons |
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| mtpa | metric tons per year |
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| 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 |
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| 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 |
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| SSA | steam supply agreement |
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| TBtu | one trillion Btus, which corresponds to approximately 12,100,000 LNG gallons |
CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K for the year ended December 31, 20202023 (this “Annual Report”) contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Annual Report other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance or our projected business results. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “projects,” “targets,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements are necessarily estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:
our limited operating history;
loss of one or more•the results of our customers;subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us
inability•construction and operational risks related to procure LNG on a fixed-price basis, or otherwise to manage LNG price risks,our facilities and assets, including hedging arrangements;
the completion of construction on our LNG terminals, facilities, power plants or Liquefaction Facilities and the terms of our construction contracts for the completion of these assets;
cost overruns and delays in the completion of one or more of our LNG terminals, facilities, power plants or Liquefaction Facilities, as well as difficulties in obtaining sufficient financing to pay for such costs and delays;
our ability to obtain additional financing to effect our strategy;
Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all, and we, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending;
After the Proposed Mergers, we may be unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers;
•failure to produce or purchase sufficient amounts of LNG or natural gas at favorable prices to meet customer demand;
hurricanes or other natural or manmade disasters;
failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
operational, regulatory, environmental, political, legal and economic risks pertaining to the construction and operation of our facilities;
inability to contract with suppliers and tankers to facilitate the delivery of LNG on their chartered LNG tankers;
cyclical or other changes in the demand for and price of LNG and natural gas;
failure of natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
•delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
•failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;
•failure to maintain sufficient working capital for the development and operation of our business and assets;
•failure to convert our customer pipeline into actual sales;
•lack of asset, geographic or customer diversification, including loss of one or more of our customers;
•competition from third parties in our business;
•inability to re-financeprocure 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 outstanding indebtedness;technological solutions;
changes•inability to environmental andobtain additional financing to effect our strategy;
•inability to successfully complete mergers, sales, divestments or similar laws and governmental regulations that are adversetransactions related to our operations;businesses or assets or to integrate such businesses or assets and realize the anticipated benefits;
inability to enter into favorable agreements and obtain necessary regulatory approvals;•weather events or other natural or manmade disasters or phenomena;
the tax treatment of us•any future pandemic or of an investment in our Class A shares;
the completion of the Exchange Transactions (as defined below);
aany other major health and safety incident relating to our business;incident;
•increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;
risks related to the jurisdictions in which we do, or seek to do, business, particularly Florida, Jamaica, Brazil and the Caribbean; and
•other risks described in the “Risk Factors” section of this Annual Report.
All forward-looking statements speak only as of the date of this Annual 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 this Annual Report. 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.
Items 1 and 2. | Items 1 and 2. Business and Properties |
Unless the context otherwise requires, references in this Annual Report to the “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. When used in a historical context, “our,” “us,” “we” 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. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes.
Overview
We are a global integrated gas-to-powerenergy infrastructure company that seeksfounded to usehelp 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 satisfy the world’s large and growing power needs. Werapidly deliver targetedturnkey energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins.global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emission-free independent power providing companies.emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail below under “Toward“Sustainability—Toward a Carbon-FreeLow Carbon Future.”
We deliver targeted energy solutions by employing an integrated LNG supply and delivery model:
LNG and Natural Gas Supply and Liquefaction -– We supply LNG and natural gas to our own power plants and to our customers. We typically supply LNG and natural gas regasified from LNG to our customers typically by entering into long-term LNG supply contracts, which are generally based on an index such as Henry Hub plus an additional fee.a fixed fee component. We have successfully capitalized on current market conditions to secure long-termacquire our LNG contracts, which are also based on Henry Hub plus an additional fee, with attractive terms. In addition, we supply LNG to our customers from third party suppliers in open market purchases and long-term supply agreements; we also manufacture LNG fromat our existing liquefaction and storage facility in Miami, Florida (the “Miami Facility”).
Shipping -– We have long-term charters forlease, own or operate a fleet of seven regasification units (“FSRUs”) and 13 liquefied natural gas carriers (“LNGCs”) and floating storage and regasification units (“FSRUs”FSUs”). These assets transport LNGTen vessels are owned by our joint venture affiliate, Energos Infrastructure ("Energos"). We also charter vessels to and from ports to our downstream facilities and gasify LNG for ultimate delivery to our customers.
Facilities -– Through our network of current and planned downstream facilities and logistics assets, we are strategically positioned to deliver gas and power solutions to our customers seeking either to transition from environmentally dirtier distillate fuels such as automotive diesel oil (“ADO”) and heavy fuel oil (“HFO”) or to purchase natural gas to meet their current fuel needs.
Our Business Model
As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to shipping, logistics, facilities and conversion or development of natural gas-fired power generation. While historically,Historically, natural gas procurement or liquefaction, transportation, regasification and power generation projects have been financeddeveloped separately the segregation of such projectsand have required multilateral or traditional financing sources, which has inhibited the developmentintroduction of natural gas-fired power in many developing countries. In executing our business model, we have the capability to build or arrange any necessary infrastructure ourselves without reliance on multilateral financing sources or traditional project finance structures, so that we maintain our strategic flexibility.flexibility and optimize our portfolio.
We currently conduct our operations at the following facilities:
•our LNG storage and regasification facility at the Port of Montego Bay, Jamaica (the “Montego Bay Facility”),
•our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility” and,, together with the Montego Bay Facility, the “Jamaica Facilities”),
•our dual-fired combined heat and power ("CHP") facility in Clarendon, Jamaica (the "CHP Plant"),
•our landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”),
•our LNG receiving facility (the “La Paz Facility”) and gas-fired power plant (the "La Paz Power Plant") at the Port of Pichilingue in Baja California Sur, Mexico, and
•our Miami Facility.
In addition, we are currently developing facilities in Mexico,Brazil, Nicaragua, Ireland and Ireland,other locations, as described below in more detail. We are in active discussions with additional customers to develop projects in multiple regions around the world who 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 the terms of such contracts or that we will be able to achieve our target pricing or margins.
Our Facilities
Downstream, we have six facilities operational or under active development. Our facilities position us to acquire and supply LNG to customers in a number of attractive markets around the world.
We look to build facilities in locations where the need for LNGnatural gas is significant. We design and construct natural gas and power facilities to meet the supply and demand specifications of our current and potential future customers in an applicable region. In these markets, we first seek to identify and establish “beachhead” target markets for the sale of LNG, natural gas or natural gas-fired power. Wepower, and we then seek to convert and supply natural gas to additionalor power customers.under long-term downstream contracts. Finally, our goal is to expand within the market by supplyingand supply natural gas or power to additional industrial and transportation customers.
Our facilities position us to acquire and supply LNG to customers and natural gas-fired power in a number of attractive markets around the world. Downstream, we have thirteen facilities that are either operational or under active development. We currently have threefour operational LNG terminal facilities and four under active development, as well as two operational power plant facilities and three power plant facilities under active development, as described below. We design and construct facilities to meet the supply and demand specifications of our current and potential future customers in the applicable region. Our LNG facilities currently operating or under development are expected to be capable of receiving between 740,000 and 6up to one million gallons ofMMBtu from LNG (61,000 and 500,000 MMBtu) per day depending upon the needs of our customers and potential demand in the region.
Set forth below is additional detail regarding each such facility:of our LNG and power facilities:
Montego Bay, Jamaica -– Our Montego Bay Facility commenced commercial operations in October 2016. The Montego Bay Facility is capable of processing up to 740,000 gallons of60,000 MMBtu from LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage. It supplies natural gas to the 145 MW145MW power stationplant (the “Bogue Power Plant”) operated by Jamaica Public Service Company Limited (“JPS”) pursuant to a long-term contract for natural gas equivalent to approximately 310,000 gallons of25,000 MMBtu from LNG (25,600 MMBtu) per day. The Montego Bay Facility also supplies numerous on-island industrial users with natural gas or LNG pursuant to numerous offtake contracts of various durations, some of which contain take-or-pay provisions.durations. We have total aggregate contracted volumes of approximately 405,000 gallons of29,000 MMBtu from LNG (33,470 MMBtu) per day at our Montego Bay Facility with a weighted average remaining contract length of 15.316 years as of December 31, 2020.2023. We have the ability to service other potential customers with the excess capacity of the Montego Bay Facility, and we are seeking to enter into long-term contracts with new customers for such purposes. We deliver LNG to the Montego Bay Facility via small LNGCs.
Old Harbour, Jamaica -– Our Old Harbour Facility commenced commercial operations in June 2019. The Old Harbour Facility is an offshore facility with storage and regasification equipment provided via FSRU. The offshore design eliminates the need for onshore infrastructure and storage tanks. It is capable of processing approximately 6 million gallons ofup to 750,000 MMBtu from LNG (500,000 MMBtu) per day. The Old Harbour Facility is supplying gas to a new 190 MW Old Harbour190MW gas-fired power plant (the “Old Harbour Power Plant”) owned and operated by South Jamaica Power Company Limited (“SJPC”) pursuant to a long-term contract for natural gas equivalent to approximately 380,000 gallons of30,000 MMBtu from LNG (31,400 MMBtu) per day. day, and back-up ADO, for 20 years.
The Old Harbour Facility is also supplying gas to the dual-fired combined heat and power (“CHP”) facility in Clarendon, Jamaica (the “CHP Plant”) thatour 100MW CHP Plant, which we constructed, and which commenced commercial operations in March 2020. The CHP Plant is fueled by natural gas, with the ability to run on March 3, 2020. See “—Our Current Customers—JamalcoADO as a backup fuel source. We have executed a suite of agreements in connection with the CHP Plant.” Plant, including a 20-year agreement to supply steam to an alumina refinery joint venture between affiliates of Century Aluminum Company, and the Government of Jamaica, and we have a 20-year agreement to supply electricity to JPS.
We have total aggregate contracted volumes of approximately 760,000 gallons of58,000 MMBtu from LNG (62,810 MMBtu) per day at our Old Harbour Facility with ana weighted average contract length of 18.716 years as of December 31, 2020.2023. We have the ability to service other
potential customers with the excess capacity of the Old Harbour Facility, and we are seeking to enter into long-term contracts with new customers for such purposes. The Old Harbour Facility is an offshore facility with storage and regasification equipment provided via FSRU. The offshore design eliminates the need for expensive storage tanks and permanent, onshore infrastructure.
San Juan, Puerto Rico– Our San Juan Facility became fully operational in the third quarter ofJuly 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. We have leased the land under a long-term agreement. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. In addition, it supplies natural gas to Units 5 and 6 of theThe San Juan Combined Cycle Power Plant (the “San Juan Power Plant”), which are owned and operated byFacility is near the Puerto Rico Electric Power Authority a public instrumentality("PREPA") San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.
In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. ("Weston") for the governmentinstallation and operation of approximately 350MW of power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico (“PREPA”). We converted Units 5 and 6, which together have a capacity of 440 MW, to use natural gas as fuel and expect towell as the supply both Units 5 and 6 with approximately 26 TBtu of natural gas per year, which equals approximately 863,000 gallonsand ADO. Weston has been contracted by the U.S. Army Corps of LNG (70,000 MMBtu) per day.
Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 150MW of duel-fuel power generation using our gas supply in May 2023, and the remaining 200MW was commissioned in September 2023.
La Paz, Baja California Sur, Mexico - We were awarded a public tender to build, own and operate an LNG receiving facility (the “La Paz Facility”) on July 18, 2018.– Our La Paz Facility is currently under development and is expected to commence commercialcommenced operations in the secondfourth quarter of 2021. It is being designed as an LNG receiving facility located at the Port of Pichilingue in Baja California Sur, Mexico, wherereceiving LNG will be delivered via ISO containers on an offshore supply vehicle from a mothership moored nearby. The La Paz Facility is expected to supply approximately 270,000 gallonsnearby vessel. In March 2021, we entered into a gas sales agreement with CFEnergia ("CFE"), a subsidiary of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW ofFederal Electricity Commission(Comisión Federal de Electricidad), Mexico’s power supplied by gas-fired modular power units that we plan to develop, own and operate, which may be increased to approximately 350,000 gallons of LNG (29,000 MMBtu) per day for up to 135 MW of power. In addition, we were declared the winner of a bid with CFEnergiautility, for the supply of natural gas to power plants located at Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day and are in the processState of finalizing definitive agreements for this supply. Similarly,Baja California Sur ("CFE Plants"), and in the fourth quarter of 2022, we reached an agreement to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur. Under an amended gas sales agreement with CFE, we expect that we will useto sell approximately 38,000 MMBtu from LNG per day.
The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to facilitate135MW of power. We placed the supplyLa Paz Power Plant into service in the third quarter of approximately 200,000 gallons of LNG (16,500 MMBtu) per day to regional industrial users and hotels.
Puerto Sandino, Nicaragua -– We have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and under the terms of such agreement we expect to provide approximately 700,000 gallons of LNG (57,500 MMBtu) per day. We are designing and developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua, as well as an onshore regasification facility (the “Puerto Sandino Facility”). The Puerto Sandino Facility is expected to supply gas to aour new approximately 300 MW300MW natural gas-fired power plant in Puerto Sandino, Nicaragua (the “Nicaragua Power Plant”) that we will own and operate. We have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies. We expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.
Barcarena, Brazil – Our terminal in the State of Pará, Brazil (the “Barcarena Facility”) consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing over one million MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG. We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. We substantially completed our Barcarena Facility in 2022 and expect to commence operations, including delivery to the Alunorte Alumina Refinery in the first half of 2024.
The Barcarena Facility will also supply our new 630MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”). The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. Construction of the Barcarena Power Plant was greater than 43% complete as of December 31, 2023. We expect to complete the Barcarena Power Plant and begin delivering power to nine committed offtakers for 25 years beginning in 2025.
Shannon, Ireland - We haveIn the fourth quarter of 2023, we entered into an agreement to purchase allacquire a 1.6GW PPA in exchange for newly issued 5% NFE redeemable Series A Convertible Preferred Stock (the "Series A Convertible Preferred Stock"), closing of which remains subject to customary closing conditions, including regulatory approval for the transfer of the ownership interestsPPA (the “Barcarena PPA Exchange”). NFE has applied to transfer the 1.6 GW PPA to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build a power plant to supply the PPA using gas from the Barcarena Facility. We expect to begin delivering electricity under the acquired PPA in July 2026.
Santa Catarina, Brazil – Our facility in Santa Catarina, Brazil (the “Santa Catarina Facility” and, together with the Barcarena Facility, the "Brazil Facilities") is located on the southern coast of Brazil and consists of an FSRU with a project companyprocessing capacity of approximately 500,000 MMBtu from LNG per day and LNG storage capacity of up to 138,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that ownswill connect the rightsSanta Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations in the first half of 2024.
Shannon, Ireland – We intend to develop and operate an LNG facility and a CHP plant on the Shannon Estuary near Ballylongford, Ireland. We intend for this facility to include a storage facility with onshore regasification equipment and pipeline connection into the distribution system of Gas Networks Ireland, Ireland’s national gas network (the “Ireland Facility” and, together with the Jamaica Facilities, the San Juan Facility, the Brazil Facilities, the La Paz Facility and the Puerto Sandino Facility, our “LNG Facilities”) and a power plant on the Shannon Estuary, near Tarbert, Ireland (the “Ireland Power Plant” and, together with the CHP Plant, La Paz Power Plant, Nicaragua Power Plant, Barcarena Power Plant, the “Power Plants,” and together with the LNG Facilities, the “Facilities”). In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We are challenging this decision. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project.
ZeroParks - In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies.
Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the processwestern hemisphere and numerous petrochemical manufacturers, many of obtaining final planning permission fromwhich require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I and expect to commence operations on the Commission for Regulationfirst phase in the first half of Utilities in Ireland and we intend to begin construction of the Ireland Facility after2025. Additionally, we have obtained such permissionsecured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect our Beaumont Facility to be the largest green hydrogen plant in the United States.
LNG Supply
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 through 2029; 3) our Miami Facility; and 4) our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our 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 a binding contract for LNG volumes from a U.S. LNG facility with a 20-year term, that is expected to commence in 2027 and another 20 year contract with a separate U.S. facility, subject to that facility's FID, expected to commence in 2029. Finally, we plan to commence production from our own Fast LNG facilities in 2024. We plan to expand that capacity when additional Fast LNG units come online.
Geopolitical events have substantially impacted and may continue to impact the natural gas and LNG markets, which have experienced significant volatility in recent years. 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, we plan to further mitigate our exposure to variability in LNG prices, and our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream customers with volumes sufficient to support the development.terminals.
Our LNG Supply Contracts and Liquefaction Assets
In December 2018, the Company entered into a contract with Centrica LNG Company Limited (“Centrica”) for the purchase of 29 firm cargoes of 1.1 billion gallons of LNG (86.7 million MMBtu) scheduled for delivery between June 2019 and December 2021. In June 2020, we terminated our obligation to purchase any additional LNG cargoes for the remainder of 2020 in exchange for a one-time payment of $105 million, which has enabled us to purchase LNG in the open market at prices that are significantly lower than the price we were obligated to pay to Centrica to purchase LNG in 2020.
In 2020, the Company entered into four supply agreements for the purchase of approximately 415 TBtu of LNG between 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029.
We constructed the Miami Facility, which commenced full commercial operations in 2016, in under 12 months at a cost to build of approximately $70 million.2016. The Miami Facility has one liquefaction train with liquefaction production capacity of approximately 100,000 gallons of8,300 MMBtu from LNG (8,300 MMBtu) per day and was 97.5% dispatchable during 2020.day. The Miami Facility also has three LNG storage tanks with total capacity of approximately 1,000 cubic meters. The Miami Facility also includes two separate LNG transfer areas capable of serving both truck and rail. For the fiscal year ended December 31, 2020, we delivered approximately 35,000 gallons of
Fast LNG (2,900 MMBtu) per day from the Miami Facility pursuant to long-term, take-or-pay contracts.
We are currently evaluatingdeveloping multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the timingworld. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our first “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 other greenfield alternatives. Semi-permanently moored floating storage unit(s) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. We are also in discussions with CFE to utilize our FLNG design in an onshore application.
Fast LNG is anchored by key benefits over conventional liquefaction projects. In particular, we believe installing modular equipment in a shipyard will meaningfully expedite timelines. In addition, placing solutions offshore provides greater access to natural gas and optimized marine logistics.
Fast LNG solutions are also flexible from a commercial standpoint, as they can act as tolling facilities (where third parties are the offtaker of the LNG), manufacturing facilities (where we are the offtaker), or a combination of the two. This flexibility enables us to take advantage of numerous opportunities around the world and present the most optimal commercial arrangements for us and our counterparties.
Our initial Fast LNG unit was constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas and our new projects are being constructed there as well. The Kiewit facility specializes in the fabrication and integration of offshore projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. Our first Fast LNG unit has been deployed offshore in Altamira, Mexico, and we expect to deploy additional units over the next two years.
Our Shipping Assets
Our shipping assets include: Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are either leased to customers under long-term or spot arrangements or commercially operated by us. FSRUs provide offshore storage and regasification capabilities and are generally less costly and substantially faster to deploy compared to the construction and development of land-based LNG regasification and storage facilities. FSUs are floating storage assets, which often provide storage for LNG but are also capable of transporting LNG when required. LNGC's are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally.
Our shipping assets are included in our two operating segments, Ships and Terminals and Infrastructure. Vessels currently chartered to third parties are included in our Ships segment,and vessels we operate at our Facilities are included in our Terminals and Infrastructure segment. At the expiration of third-party charters of vessels owned by Energos, a natural gas liquefaction plant on landjoint venture that we have purchasedformed in 2022 and describe in more detail below, we charter these vessels for our own use through the periods described below in various capacities. We exclude these vessels from our Ships segment and include them in our Terminals and Infrastructure segment once we begin to use the vessels for our own operational purposes. We maintain flexibility to deploy vessels in our Terminals and Infrastructure segment as needed to operate our LNG supply chain and serve our downstream customers.
In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of 11 vessels, including six FSRUs, three FSUs and two LNGCs, to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. 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 of the Energos vessels, the terms of which will commence upon the expiration of each vessel’s existing third-party charter. As a result of this arrangement, when existing third-party charters expire between April 2023 and August 2027, those vessels will then be chartered to us by Energos for up to 20-year terms expiring between December 2027 and August 2042. In February 2024, we sold substantially all of our stake in Energos to our joint venture partner.
Set forth below are tables containing additional detail regarding each vessel in our operating segments:
Ships Segment:
| | | | | | | | | | | | | | | | | |
| Name | Type | Capacity (cubic meters of LNG) | Owner | Contract Type | Location |
| Energos Igloo | FSRU | 170,000 | | Energos | Lease | The Netherlands |
| Energos Eskimo | FSRU | 161,000 | | Energos | Lease | Kingdom of Jordan |
| Energos Maria | LNGC / FSU | 146,000 | | Energos | Lease | Various |
Mazo1 | LNGC / FSU | 137,000 | | 60% NFE / 40% CPC | Owned | Various |
| Nusantara Regas Satu | FSRU | 125,000 | | Energos | Lease | Indonesia |
1 In December 2023, we entered into an agreement to sell the vessel, Mazo, for $22.4 million; the sale closed in the Marcellus areafirst quarter of Pennsylvania (the “Pennsylvania Facility”,2024.
Terminals and together with the Miami Facility, the “Liquefaction Facilities”). In December 2019, PHMSA granted a special permitInfrastructure Segment:
| | | | | | | | | | | | | | | | | |
| Name | Type | Capacity (cubic meters of LNG) | Owner | Contract Type | Location |
| Orion Sea | LNGC / FSU | 174,000 | | JP Morgan | Lease | Various |
| Cobia LNG | LNGC / FSU | 174,000 | | Cheniere / TMS Cardiff Gas | Lease | Various |
| Hoegh Gallant | FSRU | 170,000 | | Hoegh LNG | Lease | Jamaica |
| Energos Celsius | FSRU | 161,000 | | Energos | Lease | Brazil |
| NFE Penguin | LNGC / FSU | 161,000 | | Energos | Lease | Mexico |
| Gaslog Singapore | LNGC / FSU | 155,000 | | Gaslog | Lease | Various |
| Energos Grand | LNGC / FSU | 146,000 | | Energos | Lease | Mexico |
| Energos Winter | FSRU | 138,000 | | Energos | Lease | Brazil |
| Energos Princess | LNGC / FSU | 138,000 | | Energos | Lease | Various |
| Energos Freeze | FSRU | 126,000 | | Energos | Lease | Various |
| Coral Encanto | LNGC / FSU | 30,000 | | Anthony Veder | Lease | Various |
| CNTIC Vpower Global | LNGC / FSU | 28,000 | | CNTIC Vpower Holdings | Lease | Various |
| Titan Unikum | LNGC / FSU | 12,000 | | Titan LNG | Lease | Various |
| Avenir Accolade | LNGC / FSU | 7,500 | | Avenir | Lease | Various |
| Coral Anthelia | LNGC / FSU | 6,500 | | Anthony Veder | Lease | Various |
We also lease, own and operate various operating service vessels, tugboats and other vessels to one ofsupport our subsidiaries to ship LNG by rail, which would allow us to transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels.
Our Current Customers
Our downstream customers are, and we expect future customers to be, a mix of power, transportation and industrial users of natural gas and LNG.LNG, as well as local power generation, distribution companies, including private and
governmental owned or controlled. We seek to substantially reduce our customers’ fuel costs while providing them with a cleaner-burning, more environmentally friendlyenvironmentally-friendly fuel source. We also intend to sell power and steam directly to some of our customers. In addition, we provide development services to some customers for the conversion or development of natural gas-fired power generation in connection with long-term agreements to supply natural gas or LNG to the customer.
We seek to enter into long-term take-or-pay contracts to deliver natural gas or LNG. Pricing for any particular customer depends on the size of the customer, purchased volume, the customer’s credit profile, the complexity of the delivery and the infrastructure required to deliver it.
A limited numberWe continue to have significant concentrations in revenue. Revenue from two customers constituted 47% of total revenue in 2023; no other customers currently represent a large percentagecomprised more than 10% of our income.revenue. For the twelve monthsyear ended December 31, 2020,2022, revenue from two significant customers constituted 42% of our total revenue. For the year ended December 31, 2021, revenue from three significant customers constituted 88%48% of our total revenues.
We have several contracts with government affiliatedgovernment-affiliated entities in the countries in which we operate. In Jamaica, including contractswe have gas sales agreements with JPS and SJPC, (as defined belowwhich have remaining terms of approximately 15 and collectively, the “Jamaica GSAs”) and16 years, respectively, with a governmental instrumentality in Puerto Rico, PREPA.mutual options to extend, subject to certain conditions. The Jamaica GSAsgas sales agreements represent approximately 50% of Jamaica’s installed power capacity and sales of approximately 955,000 gallons of79,000 MMBtu from LNG (79,000 MMBtu) per day at full commercial operations. The Jamaica GSAs have remaining terms of approximately 18.3 years, with mutual options to extend, subject to certain conditions. The aggregate minimum quantities we are required to deliver, and our counterparties are required to purchase, under the Jamaica GSAsgas sales agreements initially, total approximately 56,20056,000 MMBtu per day. Additionally,
In Puerto Rico, we have entered into a Fuel Salefuel sale and Purchase Agreementpurchase agreement with PREPA, underpursuant to which we expect PREPA to purchase 863,000 gallons ofapproximately 68,000 MMBtu from LNG (70,000 MMBtu) per day.
Bogue Power Plant
We have executed a 22-year agreement to supply JPS’s 145 MW Bogue power plant (the “Bogue Power Plant”)day in Montego Bay, Jamaica with natural gas. The Bogue Power Plant has been converted to run on natural gas as well as ADO as backup fuel.
Old Harbour Power Plant
We have executed an agreement to supply SJPC’s Old Harbour Power Plant in Old Harbour, Jamaica with natural gas and back-up ADO for 20 years. The Old Harbour Power Plant is an approximately 190 MW capacity dual fuel plant owned by SJPC.
Jamalco CHP Plant
We have executed a suite of agreements, including a 20-year SSA to supply a joint venture between General Alumina Jamaica (“GAJ”), a subsidiary of Noble Group, and Clarendon Alumina Production Limited, an entity owned by the Government of Jamaica, with a focus on bauxite mining and alumina production in Jamaica (“Jamalco”) with steam for use in its alumina refinery operations and a 20-year PPA to supply electricity to JPS. The CHP Plant is a 150 MW capacity combined heat and power plant and is fueled by natural gasconnection with the ability to run on ADO as a backup fuel source.
PREPA San Juan Power Plant
On March 5, 2019, we entered into an agreement with PREPA, under which we convertedoperation of both Units 5 and 6 of the PREPA San Juan Power Plant to usePlant. Additionally, starting in 2023 and continuing through the 10-year contractual term, Genera operates and maintains PREPA's thermal generation assets. We receive an annual management fee and are eligible for performance-based incentive fees.
In Mexico, we have entered into a gas sales agreement with CFEnergia for the supply of natural gas which togetherto CFE Plants. In Nicaragua, we have a capacity of 440 MW, and we are supplying natural gas fuel to Units 5 and 6. The natural gas supply agreement has an initial natural gas supply term of 5 years from the beginning of commercial operations of the Units on natural gas and has three separate 5-year extensions that are exercisable at PREPA’s option. We have supplied natural gas for the commissioning of Units 5 and 6 since April 2020.
Nicaragua Power Plant
On February 13, 2020, we entered into a 25-year power purchase agreement to supply electricity towith Nicaragua’s electricity distribution companies, andsome of which are wholly or partially owned or controlled by governmental entities. In Brazil, we are in the process of constructing a natural gas-fired power plant with a capacity of approximately 300 MW.
Industrial End-User Sales
We have entered into multiple long-term contracts to sell LNG directly to industrial end-users in Jamaica, Puerto Rico and Mexico. To fulfill the requirements of our end-user customers, we transport LNG through our Facilities (either from our Liquefaction Facilities in the United States or from third parties in market purchases) and deliver such LNG directly to customers’ facilities.
Recent Developments: Hygo and GMLP Acquisitions
Hygo Acquisition
On January 13, 2021, we and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Hygo Merger Agreement”) with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), pursuant to which, on the terms and subject to conditions set forth in the Hygo Merger Agreement, Hygo Merger Sub will be merged with and into Hygo (the “Hygo Merger”), whereupon the separate corporate existence of Hygo Merger Sub shall cease and Hygo shall continue as the surviving company in the Hygo Merger. As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.
The Hygo Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions.
Upon completion of the acquisition of Hygo, we expect to acquire Hygo’s network of existing and development stage marine LNG import facilities, its ownership of interests in existing and development stage large-scale power plants backed by high quality offtakers, and the downstream distribution of LNG from its terminals via marine and onshore logistics to major demand centers in Brazil, each as described in more detail below. In addition, we expect to acquire Hygo’s vessel fleet, which consists of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Facility (as defined herein), and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which may be converted into FSRUs.
Sergipe Facility and Sergipe Power Plant. Hygo’s facility located near Aracaju, the state capital of Sergipe, Brazil (the “Sergipe Facility”), commenced commercial operations in March 2020 and is a key component in Brazil’s first private-sector LNG-to-power project. The Sergipe Facility is operated by Centrais Elétricas de Sergipe S.A. (“CELSE”), an entity wholly owned by Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), a 50/50 joint venture between Hygo and Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. The facility’s assets consist of (i) Hygo’s FSRU, the Golar Nanook, which is under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”), (ii) specialized mooring infrastructure and (iii) a dedicated 8 kilometer pipeline which connects to the adjacent Sergipe Power Plant. The Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The terminal is expected to utilize approximately 230,000 MMBtu/d (30% of the terminal’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant at full dispatch.
The Sergipe Power Plant, a 1.5 GW combined cycle power plant (the “Sergipe Power Plant”), receives natural gas from the Sergipe Facility through a dedicated 8 kilometer pipeline. Owned by CELSE, the Sergipe Power Plant is the largest natural gas-fired thermal power station in South America and was built to provide electricity on demand throughout the region, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region. Following its bid award in a government power auction in April 2015, CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant is delivering power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years. Hygo anticipates generating incremental earnings through selling merchant power from the Sergipe Power Plant. The sales would be made through CELSE. Hygo can choose to produce merchant power at the Sergipe Power Plant in any period in which power is not being produced pursuant to the PPAs, and sell the power into the electricity grid at spot prices, subject to local regulatory approval.
Hygo also owns 37.5% of Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), a joint venture with Ebrasil, which owns expansion rights with respect to the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for up to 3.2 GW of power generation, including the capacity of the Sergipe Power Plant. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. Hygo recently entered into a purchase agreement pursuant to which it will indirectly acquire an additional 37.5% interest in CEBARRA; such acquisition is subject to customary closing conditions including receipt of certain regulatory approvals.
Barcarena Facility and Barcarena Power Plant. Hygo is developing a facility in the State of Pará, Brazil (the “Barcarena Facility”). Hygo anticipates that the Barcarena Facility will be anchored by several large-scale industrial and power customer contracts, including a contract with Centrais Elétricas Barcarena S.A. (“CELBA”), a 50/50 joint venture between Hygo and Evolution Power Partners S.A. (“Evolution”). Hygo recently entered into a purchase agreement pursuant to which it will purchase the remaining 50% interest in CELBA from Evolution; such acquisition is subject to customary closing conditions, including receipt of certain regulatory approvals. The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to utilize approximately 92,000 MMBtu/d (12% of the facility’s maximum regasification capacity) to service the Barcarena Power Plant upon commencement of operations.
In October 2019, CELBA 2, Hygo’s joint venture with CELBA, Brazilian Energy Participações S.A. and OAK Participações Ltda. was awarded multiple 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant to be located in Pará, Brazil and to be supplied by the Barcarena Facility (the “Barcarena Power Plant”). The Barcarena Power Plant will utilize LNG sourced and processed at the Barcarena Facility for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019.
Santa Catarina Facility and Pipeline. Hygo is finalizing the process of securing key regulatory and environmental licenses to develop a facility on the southern coast of Brazil, near Santa Catarina (the “Santa Catarina Facility”) that is intended to consist of an FSRU with a processing capacity of approximately 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. In addition to the Santa Catarina Facility, Hygo is developing a 31 kilometer, 20 inch pipeline that will connect the Facility to the existing inland Transportadora Brasiliera Boliva (“TBG”) pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline is subject to final investment decision.
Partnership with BR Distribuidora. During the first quarter of 2020, Hygo entered into a strategic partnership with Petrobras Distribuidora S.A. (“BR Distribuidora”), Brazil’s leading fuel distribution company, to serve as its exclusive provider of LNG for use in Brazil’s transportation and industrial sectors. Using BR Distribuidora’s 94 distribution centers and 7,600+ fuel stations across Brazil, Hygo expects to leverage its existing infrastructure and LNG supply chain expertise to increase the accessibility of LNG to downstream end-users using a combination of marine and onshore solutions.
On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in the city of Ipojuca, State of Pernambuco, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.(“Pecém”) and Energética Camaçari Muricy II S.A (“Muricy”) from BR Distribuidora, CCETC Brasil Holding Ltda. and Enatec Engenharia Ltda. These companies collectively hold certain 15-yearvarious power purchase agreements totaling 288 MW for the development of the thermoelectric power plants Pecém II and Camaçari Muricy II, in the State of Bahia, Brazil.
Following closing of our acquisition of Pecém and Muricy, we will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil.
GMLP Acquisition
On January 13, 2021, we entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “GMLP Merger Agreement”) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and our wholly-owned subsidiary (“GMLP Merger Sub”) and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and our wholly-owned subsidiary (“GP Buyer”), pursuant to which, on the terms and subject to the conditions thereof, GMLP Merger Sub will be merged with and into GMLP (the “GMLP Merger” and, together with the Hygo Merger, the “Proposed Mergers”) and GMLP shall continue its existence as the surviving company in the GMLP Merger.
At the effective time of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediately prior to the GMLP Effective Time will automatically be converted into the right to receive $3.55 in cash. At the GMLP Effective Time, each of the incentivelocal distribution rights of GMLP will be canceled and cease to exist, and no consideration shall be delivered in respect thereof. Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof. Each outstanding unit representing a general partner interest of GMLP that is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time. Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP.
The GMLP Merger Agreement may be terminated by NFE or GMLP (which, in the case of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021, and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million.
The GMLP Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals, the approval of the GMLP Merger Agreement by the majority of the holders of GMLP common units and other customary closing conditions.
Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs (the Golar Spirit, the Golar Winter, the Golar Freeze, the NR Satu, the Golar Igloo, and the Golar Eskimo), four LNG carriers (the Golar Mazo, the Methane Princess, the Golar Grand, and the Golar Maria) and an interest in a floating liquefaction vessel, the Hilli Episevo (the “Hilli”), which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, eachcompanies, some of which are expected to help support our existing facilities and international project pipeline. GMLP currently owns 50% of the common units of Golar Hilli LLC which owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Hilli is the world’s first converted FLNG vessel. The majority of the FSRUs in GMLP’s fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters. GMLP’s uncontracted vessels are available for short term employment in the spot market.
Financing Commitments
In connection with entering into the each of the Hygo Merger Agreement and the GMLP Merger Agreement, on January 13, 2021 and January 20, 2021, we obtained financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If drawn, the proceeds of such committed financing are expected to be made available under a senior secured bridge term loan facility in an aggregate principal amount of $1.5 billion and a revolving credit facility in an aggregate principal amount of $200 million.
wholly or partially owned or controlled by governmental entities.Competition
In marketing LNG and natural gas, we compete for sales of LNG and natural gas primarily with LNG distribution companies who focus on sales of LNG without our integrated approach which includes development services and power. We also compete with a variety of natural gas marketers who may have affiliated distribution partners, including:
•major integrated marketers whose advantages include large amounts of capital and the ability to offer a wide range of services and market numerous products other than natural gas;
•producer marketers who sell natural gas they produce or which is produced by an affiliated company;
•small geographically focused marketers who focus their marketing on the geographic area in which their affiliated distributor operates; and
•aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.
Despite these competitors, we do not expect to experience significant competition for our LNG logistics services with respect to the Facilities to the extent we have entered into fixed GSAs or other long-term agreements we serve through the Facilities. If and when we have to replace our agreements with our counterparties, we may compete with other then-existing LNG logistics companies for these customers.
There are no other liquefaction facilities currently in operation in Southern Florida.Table of ContentsIn purchasing LNG, we will compete for supplies of LNG with:
•large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;
•oil and gas producers who sell or control LNG derived from their international oil and gas properties; and
•purchasers located in other countries where prevailing market prices can be substantially different from those in the United States.
Government Regulation
Our LNG infrastructure is,business and operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws, as well as foreign regulations and laws. These laws require, among other things, consultations with appropriate federal, state and other agencies and that we obtain, maintain and comply with applicable permits, approvals and other authorizations for the siting and conduct of our business. These regulatory requirements increase our costs of operations and construction, and failure to comply with such laws could result in consequences such as substantial penalties and/or the issuance of administrative orders to cease or restrict operations until we are in compliance.
DOE Export
The DOEDepartment of Energy (“DOE”) issued orders authorizing us, through our subsidiary, American LNG Marketing LLC or its designee, to export up to a combined total of the equivalent of 60,000 mtpa (approximately 3.02 Bcf/yr) of domestically produced LNG by tanker from the Miami Facility to FTAFree Trade Agreement (“FTA”) countries for a 20-year term and to non-FTA countries for a 20-year term under contracts with terms of two years or longer. The 20-year term of the authorizations commenced on February 5, 2016, the date of first export from the Miami Facility. The DOE has also authorized American LNG Marketing LLC or its designee to export LNG from the Miami Facility to FTA and non-FTA countries under short-term (less than two years) agreements or on a spot cargo basis. Any LNG exported under the short-term authorization would be counted toward the quantity authorized under the long-term authorizations. These authorizations from the DOE are only applicable to exports of LNG produced at our Miami Facility, and exports of LNG from a liquefaction facility other than the Miami Facility (such as the Pennsylvania Facility) to FTA and/or non-FTA countries will require us to obtain new authorizations from the DOE.
The DOE issued an order authorizing us, through our subsidiary, NFEnergía LLC, to import LNG from various international sources by vessel at our San Juan Facility up to a total volume equivalent to 80 Bcf of natural gas over the two-year period beginning March 26, 2020.2020 which we did in 2022 and will start the process of renewing it again in 2024. NFEnergía LLC must renew its authorization every two years. Imports of LNG are deemed to be consistent with the public interest under Section 3(c)3 of the Natural Gas Act (“NGA”) and applications for such imports must be granted without modification or delay.
The Federal Energy Regulatory Commission (“FERC”) regulates the siting, construction and operation of “LNG terminals” under NGA Section 3(e).3. In consultation with our outside counsel and, where appropriate, FERC staff, we have designed and constructed our U.S. facilities so that they do not meet the statutory definition of an “LNG terminal” as interpreted by FERC pursuant to its case law. On June 18, 2020, we received an order fromMarch 19, 2021, as upheld on rehearing on July 15, 2021, FERC which asked us to explain whydetermined that our San Juan Facility is not subject to FERC’s jurisdiction. Because we do not believe thatits jurisdiction and 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 jurisdictional,in the public interest. The FERC orders were affirmed by the United States Court of the Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we provided our replyfiled an application for authorization to operate the San Juan Facility, which remains pending.
On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC onorders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 20, 202031, 2023, FERC issued an order stating that it would not
take action to prevent the construction and requested that FERC act expeditiously. The matter was raised during a FERC open meeting heldoperation of the pipeline and interconnect and on January 19, 2021 but was not resolved, is on30, 2024, FERC reaffirmed the agenda duringorder allowing the FERC open meetingconstruction and operation to be held on March 18, 2021, and remains pending. We do not know if or when FERC will respond to our reply, or the outcome of any such response.
continue.PipelinesPipeline and Hazardous Materials Safety Administration
Many LNG facilities are also subject to regulation by the DOT,Department of Transportation (“DOT”), through PHMSA; PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of “pipeline facilities,” which PHMSA has defined to include certain LNG facilities that liquefy, store, transfer or vaporize natural gas transported by pipeline in interstate or foreign commerce. PHMSA has promulgated detailed, comprehensive regulations governing LNG facilities under its jurisdiction at Title 49, Part 193 of the United States Code of Federal Regulations. These regulations address LNG facility siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. Variances from these regulations may require obtaining a special permit from PHMSA, the issuance of which is subject to public notice and comment and consultation with other federal agencies, which could result in delays, perhaps substantial in length, to the construction of our facilities where such variances are needed; additionally, PHMSA may condition, revoke, suspend or modify the special permits it issues.
In December 2019, PHMSA granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to shiptransport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. . This special permit expired on November 30, 2021, at which time our subsidiary applied for its renewal. On April 24, 2023, PHMSA issued a decision denying this special permit renewal request. On July 24, 2020, PHMSA issued a final rule authorizing the nationwide transportation of LNG by rail in DOT–113C120W specification rail tank cars, subject to all applicable requirements and certain additional operational controls. The appeal period for the special permit has expired, althoughexpired. However, in November 2021, PHMSA issued a proposed rule to rescind the final rule authorizing nationwide transportation. In September 2023, DOT promulgated a rule that suspends authorization of LNG transportation will likelyby rail pending the earlier of either completion of a rulemaking evaluating potential modifications to requirements governing tank car transportation of LNG under the Hazardous Materials Regulations at 49 C.F.R. Parts 171-180 or by June 30, 2025, whichever is earlier. We have the ability to transport LNG from our Pennsylvania Facility via truck, and this logistical solution is available to us should we be challenged.
unable to transport by rail.Environmental Regulation
Our LNG infrastructure and operations are subject to various international, federal, state and local laws and regulations as well as foreign laws and regulations relating to the protection of the environment, natural resources and human health. These laws and regulations may require the installation of controls on emissions and structures to prevent or mitigate any potential harm to human health and the environment or require certain protocols to be in place for mitigating or responding to accidental or intentional incidents at certain facilities. These laws and regulations may also lead to substantial penalties for noncompliance and substantial liabilities for incidents arising out of the operation of our facilities. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.
Other local laws and regulations, including local zoning laws, critical infrastructure regulations and fire protection codes, may also affect where and how we operate.
The costs of compliance with these requirements are not expected to have a material adverse effect on our business, financial condition or results of operations.
Environmental Regulation in Mexico
Mexican law comprehensively regulates all aspects of the receipt, delivery, importation, exportation, storage commercialization, liquefaction, and re-vaporizationregasification of LNG as well as the generation and transmission of electricity in Mexico. Various federal agencies in Mexico regulate these activities including, among others, Ministry of Energy, Ministry of the Navy, the Department of Environment and Natural Resources, DepartmentMinistry of Infrastructure, Communication and Transportation, the Energy Regulatory Commission, and the Agency for Safety, Energy & Environment, which issues permits for all activities associatedperformed by or in connection with the use of fossil fuels.Mexican hydrocarbon sector. State and local agencies also regulate these activities, issuing permits and authorizing the use of property for such purposes. In order to be able to obtain various permits for construction and operations under Mexican law, the project must first complete environmental and social impact analysesassessments according to the requirements of Mexican law. Each such impact analysisassessment is subject to further
evaluation and appeal. Moreover, all hydrocarbon projects must include an environmental risk assessment, which derives from a thorough risk analysis before each different stage, in order to identify potential design and operational hazards. Mexican law allows the governmental entities and, in certain cases, individuals to pursue claims against violators of environmental laws or permits issued pursuant to such laws.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 being challenged as unconstitutional, and a judge recently awarded a temporary injunction halting the implementation of the amendment. However, if the amendment is enforced against us, it could negatively affect our plant's dispatch and our revenue and results of operations.
Environmental Regulation in Jamaica
Our operations in Jamaica are governed by various environmental laws and regulations. These laws and regulations are largely implemented through the National Environment and Planning Agency and cover discharges of pollutants, regulation of air emissions, discharges and treatment of wastewater, storage of fuels, and responses to industrial emergencies involving hazardous materials. The level of environmental regulation in Jamaica has increased in recent years, and the enforcement of environmental laws is becoming more stringent. Compliance has not had a material adverse effect on our business, operations, or financial condition.condition, but we cannot assure you that this will be the case in the future. Jamaica is also in the process of developing a law to govern the receipt, storage, processing and distribution of natural gas, as well as requirements for the licensing, construction, and operation of natural gas facilities and transportation.
Environmental Regulation in Nicaragua
The regulation of activities with the potential to impact the environment in Nicaragua are largely regulated by the Natural Resource and Environment Ministry. Nicaragua regulates many areas of environmental protection. In order to obtain various permits for operations, a project must complete environmental and social impact analyses according to Nicaraguan law. While Nicaragua does not currently have any legislation specifically addressing the receipt, handling, and distribution of natural gas, such laws may be passed in the future.
Environmental Regulation in Ireland
LNG deliveries, storage, regasificationThe operation of the facilities will be regulated via additional licenses and use are extensively regulated in Ireland. Ireland regulates these operations at a national and local level through organic legislation and an array of permits. Ireland’s National Planning Board isconsents including from the primary regulator for planning and construction, while the Irish Environmental Protection Agency issues industrial emissions licenses that regulate environmental(EPA); the Commission for Regulation of Utilities (CRU); the Health and operational permitting. Safety regulation in Ireland is regulated pursuantAuthority (HSA); and the Local Planning Authority (Kerry Co. Council (KCC)). Additionally, the Shannon Foynes Port Company (SFPC) has statutory jurisdiction over marine activities. The LNG Terminal and Power Plant will also have to operate within the Controlprovisions of Major Accidents regime, which sets out various safety criteria that an LNG facility must meet.a number of codes, such as the EirGrid Transmission Network Grid Code, Single Electricity Market Trading and Settlement Code and GNI Code of Operations. We are in the process of applying for all these necessary permits, licenses and consents to build and complete the Ireland Facility.
The issuance of many of these permits willmay be subject to administrative or judicial challenges, including by non-governmental groups that act on behalf of citizens. For example, in September 2018, an Irish non-governmental organization filed a judicial challenge to the extension of a planning permission associated with our Ireland Facility. In a February 2019 written decision arising out of this judicial challenge, Ireland’s High Court referred several questions relating to the extensions to the European Court of Justice. In February 2020, the European Parliament voted to retain a group of energy infrastructure projects as eligible for EU funding, including the Ireland Facility and broader Shannon LNG project. However, this decision may face further challenges and while this judicial review proceeds, we intend to file for a new planning permission that, if approved, would replace the permission whose extension is currently under challenge. We intend to begin construction of the Ireland Facility after we have obtained a replacement planning permission (or, if earlier, received a favorable resolution to the challenge to the extension of our existing permission) and secured contracts with downstream customers for volumes that are sufficient to support the development.development of the Ireland Facility.
Environmental Regulation in Brazil
Our operations in Brazil are governed by various environmental laws and regulations. These laws and regulations cover social and environmental impacts, air emissions, discharges and treatment of residues, and emergency response, among others. According to Brazilian environmental legislation, the environmental licensing for energy generation activities must follow three stages: a Preliminary License that authorizes the design of the project and the location of the enterprise, an Installation License that authorizes the start of the implementation activities and, an Operating License, which authorizes the actual start of the activity. At each stage, specific environmental plans and studies are required to assess and mitigate the impacts on the environment. In addition, other authorizations may be required by environmental authorities on a local (municipal), state and federal level, including, but not limited to, permits to suppress vegetation, authorization for fauna management, and permission to address and/or otherwise mitigate impacts on affected communities, and others.
Environmental Regulation in Puerto Rico
Our operations in Puerto Rico are subject to various Puerto Rico laws and regulations relating to the protection of the environment, natural resources and human health. Puerto Rico has enacted a number of different statutes and regulations in order to implement the requirements of federal environmental laws on operations on the island. Environmental statutes and regulations are largely implemented by the Puerto Rico Department of Environment and Natural Resources. As part of its
operations, our San Juan Facility is required to comply with Clean Water Act requirements for stormwater and Clean Air Act requirements for facility emission sources. These laws and their related regulations require permits for the operation of the facilities and the implementation of mitigation measures to address environmental impacts of facility operations. Additionally, our operations in Puerto Rico are subject to regulation by the Department of Transportation and Public Works (“DTOP”). DTOP has been delegated authority from DOT to regulate both the distribution of natural gas through road transportation and facilities that operate natural gas pipelines. All deliveries of LNG by truck in Puerto Rico are subject to federal requirements for the ISO containers that hold the LNG and for the transport of the LNG by truck. Any expansion or increased stringency of these requirements may increase compliance costs for our operations in Puerto Rico.
U.S. and International Maritime Regulations of LNG Vessels
The International Maritime Organization (“IMO”) is the United Nations agency that provides international regulations governing shipping and international maritime trade. The requirements contained in the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”) promulgated by the IMO govern the shipping of our LNG cargoescargos and the operations of any vessels we use in our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies.
Vessels that transport gas, including LNGCs, are also subject to regulation under various international programs such as the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (the “IGC Code”) published by the IMO. The IGC Code provides a standard for the safe carriage of LNG and certain other liquid gases by prescribing the design and construction standards of vessels involved in such carriage, and includes specific air emissions limits, including on sulfur oxide and nitrogen oxide emissions from ship exhausts.
We contract with leading vessel providers in the LNG industry and look to them to ensure that each of our chartered vessels is in compliance with applicable international and in-country requirements. Nevertheless, the IMO continues to review and introduce new regulations and it is impossible towe cannot with any certainty predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.
Import and Export Control Laws and RegulationsOneWe 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 between 2018 and 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the governments of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S. European, U.K. and other 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. 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 subsidiaries, Atlantic Distribution Holdings SRL, has enteredinternational business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a partnership framework agreement (the “PFA”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.
Anti-corruption Laws and Regulations
We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), with DevTech Environment Limited (“DevTech”). We have partnered with DevTechthe U.K. Bribery Act and local anti-bribery laws, which generally prohibit companies and their intermediaries from making improper payments to pursue strategic investment opportunitiesforeign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently operate present heightened risks for FCPA issues, such as Nicaragua,
Jamaica, Brazil and Mexico. Furthermore, our strategy has been, and continues to be, dependent in part on our ability to expand our operations in additional emerging markets, including in Latin America, Asia and Africa. Efforts to expand our operations in these markets could expose us to additional risks related to energy, transportationanti-corruption laws and infrastructure projectsregulations. Although we have adopted policies and procedures that are designed to assist us, our officers, directors, employees and other intermediaries in Jamaicacomplying with the FCPA and other anti-corruption laws and regulations, developing and implementing policies and procedures is a total projected costcomplex endeavor, particularly given the high level of development, constructioncomplexity of these laws and regulations. There is no assurance that these policies and procedures have or acquisition of no more than $5 million per project.
Pursuant to the termswill work effectively all of the PFA, whentime or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our officers, directors, employees and other intermediaries with respect to our business or any businesses that we make an investment related to services provided by DevTech, DevTech will receive 10% of the equity capitalmay acquire, particularly in the new investment in exchange for a capital contribution in that proportion. In addition, DevTech will receive profits interests entitling DevTech to 5% of all future distributions once the parties have received a return on the investment equal to their capital contributions. Certain of our subsidiaries have entered into a suite of agreements pursuant to which DevTech became a part owner of our subsidiary NFE North Distribution Limited and received economic interests substantially equivalent to those set forth in the PFA.
high risk jurisdictions.Suppliers and Working Capital
We expect to continue to supply our downstream customers with LNG and natural gas sourced from a combination of long-term, LNG contracts with attractive terms, purchases on the open market, and from our Miami Facility, and when completed, our Fast LNG solutions and Pennsylvania Facility.
Due to the nature of our business, we currently carry significant amounts of LNG inventory to meet delivery requirements of customers and assure ourselves of a continuous allotment of goods from suppliers.
Our operations can be affected by seasonal weather, which can temporarily affect our revenues, the delivery of LNG and the construction of our facilities.Facilities. For example, activity in the Caribbean is often lower during the North Atlantic hurricane season of June through November, and following a hurricane, activity may decrease further as there may be business interruptions as a result of damage or destruction to our facilitiesFacilities or the countries in which we operate. The Brazilian electric integrated system is largely dependent on hydro-generated power, which is affected during dry seasons, requiring other sources of power, such as natural gas-fired thermal power station, to dispatch more or less based on the amount of the rainfall during any period. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. In addition, severe winterSevere weather in the Northeast United Statescountries where our Facilities are located may impact the construction of our Pennsylvania Facility and affect the delivery of feedgas to the facility or LNG to and from ports in the region, among other things. Severe weather in Ireland, the Caribbean, Central America or Southern or Western Africa may also delay completion of our Facilities under development and related infrastructure.
our Facilities and affect the markets in which we operate. We are also 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.Our Insurance Coverage
We maintain customary insurance coverage for our business and operations. Our domestic insurance related to property, equipment, automobile, general liability and workers’ compensation is provided through policies customary for the business and exposures presented, subject to deductibles typical in the industry. Internationally, we also maintain insurance, including policies related to property, equipment, automobile, marine, pollution liability, general liability and the portion of workers’ compensation not covered under a governmental program.
We maintain property insurance, including named windstorm and flood, related to the operation of the Miami Facility, San Juan Facility, the La Paz Facility, and the Jamaica Facilities and builders risk insurance at our Facilities under development.
We had 231677 NFE full-time employees and 713 Genera full-time employees as of December 31, 2020.2023. We depend upon our skilled workforce to manage, operate and plan for our business. Recruitment and retention of talent accrossacross our company enables growth and innovation accrossacross a multitude of corporate initiatives, and this is one of our top priorities.
Our Human Resources team oversees human capital management, including talent attraction and retention, compensation and bonuses, employee relations, employee engagement and training and development in the various countries in which we operate.
Diversity and Inclusion
Our employees are critical to the success of our business. We value the diversity of our workplace and are committed to maintaining culture where our employees feel valued, welcomed and can thrive. We are subject to various federal, state
and local laws related to labor and employment, including matters related to workplace discrimination, harassment and unlawful retaliation in the jurisdictions in which we operate. We have developed and published our Code of Business Conduct, which sets out a guideline in connection with these matters and reflects our high expectations for an ethical workplace where employees are treated with dignity and respect. Because labor and employment laws and regulations can differ among the jurisdictions in which we operate, our Code of Business Conduct operates as a guideline for practices, but does not cover every legal aspect in each of our locations.We are advancing our commitments to diversity and inclusion through the following actions, among others:
•collecting and analyzing diversity data;
•conducting harassment trainings; and
•expanding employee benefits to include additional health programs such as mental health support and medical concierge services.
Employee Health, Safety and Wellness
We are subject to various health, safety, and environmental laws and regulations in the jurisdictions in which we operate. We have developed and published a Health, Safety, Security and Environment (HSSE) Strategic Framework, which sets out a guideline in connection with risk management, education/training, emergency response, incident management, performance measurement and other key programmatic drivers. Because health, safety, and environmental laws and regulations can differ among the jurisdictions in which we operate, our HSSE Strategic Framework operates as a guideline for practices, but is not binding or required. We also have developed and published a contractor safety management handbook for our contractors.
For the year ended December 31, 2023, we achieved zero employee recordable incidents, lost time incidents or fatalities across our operating sites.
Property
We lease space for our offices in New York, New York, Miami, FloridaHouston, Texas, Rio de Janeiro, Brazil, Mexico City, Mexico and San Juan, Puerto Rico, and in other regions in which we operate. We own the properties on which our Pennsylvania Facility will be located. Additionally, the properties on which our Facilities, including the CHP Plant and Miami Facility are located are generally subject to long-term leases and rights-of-way. Our leased properties are subject to various lease terms and expirations.
Sustainability
Since our founding in 2014, sustainability has been at the core of our mission and vision. We believe that a sustainable future built on positive energy is the way forward. To advance both our business model and the interests of our stakeholders— including our people, shareholders and investors, partners, the communities we serve, and the wider public—we have established four key sustainability goals: (i) protect and preserve the environment, (ii) empower people worldwide, (iii) invest in communities, and (iv) become a leading provider of very-low-carbon energy. Our sustainability initiatives and investments under each of these goals are highlighted below.Formation TransactionsProtect and StructurePreserve the Environment
NFE was formedWe are committed to our goal to protect and preserve the environment, and we progress this goal by providing cleaner energy solutions around the world. With our projects, we strive to reduce carbon emissions and increase energy efficiency. By helping our customers convert from traditional fuels such as oil or coal to LNG as their energy source, we seek to reduce air-polluting emissions of nitrogen oxide (NOx), carbon dioxide (CO2), sulfur oxide (SOx), and fine particulate matter, among others. Moreover, we believe that the use of LNG as a Delaware limited liability companycomplement to renewable power options is helping the transition to a sustainably-sourced energy future.
Empower People Worldwide
We are committed to our goal to provide access to affordable, reliable, cleaner energy. To that end, we help our customers customize and implement LNG energy solutions designed to lower their energy costs, reduce their environmental footprint, and improve their energy efficiency, either by converting their existing power generation to LNG or by building brand-new gas-fired facilities. In addition, we seek to provide a reliable supply of LNG to our customers, wherever located, through our established, integrated LNG logistics chain.
Invest in Communities
We are committed to our goal to improve lives and support people, especially in the communities where we operate. For example, through our New Fortress Energy Holdings on August 6, 2018. NFE’s initial public offering closed on February 4, 2019 (the “IPO”). On August 7, 2020,Foundation, we seek to strengthen our communities by (i) investing in education to help support the Company converted New Fortress Energy LLC (“NFE LLC”) fromnext generation of leaders; (ii) providing industry training programs to help create and sustain a Delaware limited liability companywell-equipped workforce; and (iii) giving financially to a Delaware corporation named New Fortress Energy Inc. (the “Conversion”). Sincecommunity causes that enhance quality of life, including reducing poverty, hunger, and inequities. For the IPO, NFE LLC had been a corporationyear-ended December 31, 2022, we:
•Created 226 jobs with local hires accounting for U.S. federal tax purposes,89% of new and converting NFE LLC from a limited liability companyreplacement hires in non-U.S. operating locations;
•Awarded 284 scholarships across five universities in Jamaica and Puerto Rico and covered tuition and exam fees for 100 students in Jamaica;
•Engaged 167 engineering students in tours, internships, and webinars, educating them in LNG and marine transport technology;
•Provided school supplies for 3,237 students in countries where we have operational or development projects;
•Provided medical and dental exams to a corporation had no effect on540 children across Jamaica and Brazil;
•Donated food and supplies to 900 families across our operational boundaries for the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately priorholidays; and
•Provided water, food, and supplies to the Conversion were converted into one issued600 families affected by natural disasters in Brazil and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of the Company (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity.
On June 3, 2020, the Company entered into a mutual agreement (the “Mutual Agreement”) with the members holding the majority voting interest in New Fortress Energy Holdings (“Exchanging Members”) and NFE Sub LLC, a wholly-owned subsidiary of NFE. Pursuant to the Mutual Agreement, the Exchanging Members agreed to deliver a block redemption notice in accordance with the Amended and Restated Limited Liability Company Agreement of NFI LLC (the “NFI LLCA”) with respect to all of the NFI LLC Units, together with an equal number of Class B shares of NFE, that such Exchanging Members indirectly own as members of New Fortress Energy Holdings. Pursuant to the Mutual Agreement, NFE agreed to exercise the Call Right (as defined in the NFI LLCA), pursuant to which NFE would acquire such NFI LLC Units and such Class B shares in exchange for Class A shares of NFE (the “Exchange Transactions”). The Exchange Transactions were completed on June 10, 2020. In connection with the closing of the Exchange Transactions, NFE issued 144,342,572 Class A shares in exchange for an equal number of NFI LLC Units, together with an equal number of Class B shares of NFE. Following the completion of the Exchange Transactions, NFE owns all of the NFI LLC Units directly or indirectly and no Class B shares remain outstanding.
Toward a Carbon-FreeLow Carbon Future
As we work to reduce greenhouse gas (GHG) emissions for our customers around the world, our long-term goal isgoals are to reach net zero carbon emissions by 2030 for Scope 1 and 2 emissions for our initial Facilities and be one of the world’s leading providers of carbon-freelow-carbon energy. Today, weWe believe that natural gas remains the mosta cost-effective and environmentally-friendly complement for intermittent renewable energy, aiding the growth of these technologies. Over time, we believe that low-cost hydrogen will play an increasingly significant role as a carbon-free fuelin the decarbonization of hard to support renewablesabate corners of the global economy supporting renewable development and displace fossil fuels across power, transportation and industrial markets. Wedisplacing fossil. To that end, we formed a division, which we call Zero,ZeroParks, to evaluate promising technologies and pursue initiatives that will position us to capitalize on this emerging industry. As partThe U.S. government is in the process of our hydrogen initiative,seeking comment and feedback on the initial guidance issued by the U.S. Treasury Department in October 2020, we announced our intention to partnerconnection 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.
Within Zero, we are building two businesses that will look to develop commercially viable pathways to scale low-cost, emissions-free hydrogen. Zero Blue will focus on innovative technologies that are capable of capturing and sequestering nearly all carbon emissions while producing low-cost hydrogen from carbon-based resources like natural gas and coal.
Zero Green will aim to use innovative, cost-effective water-splitting technologies powered by renewable energy to produce emissions-free hydrogen. We made our first hydrogen-related investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost greenproposed hydrogen production technology.tax credits. The outcome of this consultation process, and the ultimate form of any related legislation, remains uncertain.
We are required to file or furnish any annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The SEC maintains an internet website that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC, including this Annual Report, at www.sec.gov.
We also make available free of charge through our website, www.newfortressenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K,8- K, and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report.
Additionally, we have made our annual Sustainability Report and environmental, social and governance (“ESG”) related documents available on our website, www.newfortressenergy.com, to provide more detailed information regarding our human capital programs and initiatives as well as our efforts to manage ESG issues. Item 1A. | Item 1A. Risk Factors |
An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below. If any of the following risks were to occur, the value of our Class A common stock could be materially adversely affected or our business, financial condition and results of operations could be materially adversely affected and thus indirectly cause the value of our Class A common stock to decline. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business and the value of our Class A common stock. As a result of any of these risks, known or unknown, you may lose all or part of your investment in our Class A common stock. The risks discussed below also include forward-looking statements, and actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement on Forward-Looking Statements”.
References to “NFE,Statements.” the “Company,” “we,” “us,” “our” and similar terms in this section refer to NFE Inc. and its subsidiaries, including, if the Hygo Merger has closed, Hygo and its subsidiaries, and including, if the GMLP Merger has closed, GMLP and its subsidiaries. References to “Hygo” and “GMLP”, respectively, in this section, refer to Hygo and GMLP and their respective subsidiaries prior to the applicable Proposed Merger, and refer to Hygo and GMLP and their respective subsidiaries, along with the Company and its subsidiaries, following the applicable Proposed Merger.
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 Proposed Mergers
Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all, and we, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending;
After the Proposed Mergers, we may be unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers;
We may not have discovered undisclosed liabilities of either Hygo or GMLP during our due diligence process;
We expect to incur a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger as a result of the consummation of the Proposed Mergers;
Risks Related to Our Business
•Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors;
•We have not yet completed contracting,are subject to various construction and commissioning for allrisks;
•Operation of our Facilitiesinfrastructure, facilities and Liquefaction Facilitiesvessels involves significant risks;
•We depend on third-party contractors, operators and there cansuppliers;
•Failure of LNG to be no assurancea 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 Facilities or Liquefaction Facilities will operate as expected or at all;customers do not fulfill their payment obligations to us following our capital investment in a project;
We may experience time delays, unforeseen expenses• Failure to maintain sufficient working capital could limit our growth and other complications while developingharm our projects;business, financial condition and results of operations;
We may not be profitable for• 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 indeterminate period of time;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 currentcontracts 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;
• 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;
•Any use of hedging arrangements may adversely affect our future operating results or liquidity;
• We are dependent on third-party LNG suppliers and the development of our own portfolio is subject to various risks and assumptions;
•LNG that is processed and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage;
•We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer;
•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;
•The operation of our vessels is dependent on our ability to generatedeploy our vessels to an NFE terminal or to long-term charters;
•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;
•Maritime claimants could arrest our vessels, which could interrupt our cash flow;
• 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;
•Technological innovation may impair the economic attractiveness of our projects;
• Our Fast LNG technology is substantiallynot 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 the entry into and performance by customers under long term contracts that weobtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms;
•We have entered into, or willand may in the future enter into or modify existing, joint ventures that might restrict our operational and corporate flexibility or require credit support;
•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;
•We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation;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 may incur impairments to long-lived assets;
• 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 near future;markets in which we operate or plan to operate;
Operation•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;
•Increasing transportation regulations may increase our costs and negatively impact our results of operations;
•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”);
•We may not own the land on which our LNG infrastructureprojects are located and are subject to leases, rights-of-ways, easements and other facilities that we may construct involves significant risks;property rights for our operations;
The operation of the CHP Plant•We could be negatively impacted by environmental, social, and any other power plants involves particular, significant risks;governance (“ESG”) and sustainability-related matters;
•Information technology failures and cyberattacks could affect us significantly;
•Our insurance may be insufficient to cover losses that may occur to our property or result from our operations;operations.
•Our success depends on key members of our management, the loss of any of whom could disrupt our business operations;
•We are unablemay experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to predict the extent to which the global COVID-19 pandemic will negatively adversely affectattract and retain qualified personnel, as well as our operations financial performance, or ability to achieve our strategic objectives, or our customers and suppliers;
We perform development or construction services from time to time which are subject to a variety of risks unique to these activities;
We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations to customers;
Failure of LNG to be a competitive source of energy in the markets in which we operatecomply with such labor laws, could adversely affect our expansion strategy;us;
•Our current lack of asset and geographic diversification;business could be affected adversely by labor disputes, strikes or work stoppages;
Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operation of our facilities could impede operations and construction;
Risks Related to the Jurisdictions in Which We Operate
•We are currently highly dependent uponsubject to the economic, political, social and other conditions and developments in the Caribbean, particularly Jamaica, Puerto Rico and the other jurisdictions in which we operate;
Risks Related to Hygo Business Activities
| • | Hygo’s Sergipe Facility has commenced commercial operations• Our financial condition and Hygo’s other planned facilities are in various stages of contracting, construction, permitting and commissioning;
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Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various factors;
Hygo may not be able to fully utilize the capacity of its facilities;
Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil;
Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities;
Risks Related to GMLP Business Activities
GMLP currently derives all of its revenue from a limited number of customers and will face substantial competition in the future;
GMLP’s equity investment in Golar Hilli LLC may not result in anticipated profitability or generate cash flow sufficient to justify its investment. In addition, this investment exposes GMLP to risks that may harm its business;
GMLP may experience operational problems with its vessels that reduce revenue and increase costs;
GMLPresults may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits;adversely affected by foreign exchange fluctuations;
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;
•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;
•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;
•Our Certificate of Incorporation and By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock;
•Our By-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents;
•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; and
Risks Related•The incurrence or issuance of debt which ranks senior to the Proposed Mergers
Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all. Failure to complete either of the Proposed Mergers could have material adverse effects on us.
On January 13, 2021, we signed the Hygo Merger Agreement and the GMLP Merger Agreement. We currently expect to close the Proposed Mergers in the first half of 2021, subject to customary closing conditions. Each of the Proposed Mergers is not conditioned on the other.
The completion of each of the Proposed Mergers is subject to a number of conditions, including (i) the receipt of all required regulatory approvals and third-party consents; (ii) the receipt of certain specified material third-party consents; (iii) the absence of any legal restraint issued by any court or governmental entity of competent jurisdiction preventing consummation of the transaction; (iv) the accuracy of each party’s representations and warranties, and (v) in the case of the Hygo Merger, the approval for listing on the NASDAQ Global Select Market (the “Nasdaq”) of the shares ofour Class A common stock upon our liquidation 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 be issued inour Class A common stock for the Hygo Merger.purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock;
There can be no assurance that the conditions to closing of the Proposed Mergers will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the Proposed Mergers. Under•We may issue preferred stock, the terms of which could adversely affect the Hygo Merger Agreement,voting power or value of our Class A common stock;
•Sales or issuances of our Class A common stock could adversely affect the Hygo Merger is requiredmarket 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;
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 close no later than July 12, 2021, subjectour businesses or assets in the future and we may fail to successfully complete such transaction or to realize the satisfactionexpected value;
•A change in tax laws in any country in which we operate could adversely affect us;
•We have been and may be involved in legal proceedings and may experience unfavorable outcomes;
•If we fail to develop or waivermaintain an effective system of certain closing conditions. Under the terms of the GMLP Merger Agreement, the GMLP Merger is requiredinternal controls, we may not be able to close no later than July 13, 2021, subject to the satisfactionaccurately report our financial results or waiver of certain closing conditions. Any delayprevent fraud. As a result, current and potential stockholders could lose confidence in closing or a failure to close of either of the Proposed Mergers could have a negative impact onour financial reporting, which would harm our business and the trading price of our Class A common stock.stock;
In addition, regulators may impose conditions, terms, obligations•If securities or restrictions in connection withindustry analysts do not publish research or reports about our business, if they adversely change their approval of or consent to either of the Proposed Mergers, and such conditions, terms, obligations or restrictions may delay completion of either of the Proposed Mergers, require us to take actions that materially alter our existing business or the proposed combined business, including divestitures or similar transactions, or impose additional material costs on or materially limit the revenues of the combined company following the completion of either of the Proposed Mergers. Regulators may impose such conditions, terms, obligations or restrictions, and, if imposed, such conditions, terms, obligations or restrictions may delay or lead to the abandonment of either of the Proposed Mergers.
By purchasingrecommendations regarding our Class A common stock youor if our operating results do not meet their expectations, our share price could decline; and
•We are investing in us on a stand-alone basisunable to predict the extent to which global pandemics and recognize that we may not consummate either or both of the Proposed Mergers or realize the expected benefits therefrom if we do. In the event we fail to consummate either or both Proposed Mergers, it is possible that we may have issued a significant number of additional shares of common stock and wehealth crises will not have acquired the revenue generating assets that will be required to produce the earnings and cash flow we anticipated. If either of the Proposed Mergers is not completed, our ongoing business may be materially adversely affected and, without realizing any of the benefits of having completed either of the Proposed Mergers, we will be subject to a number of risks, including the following:
the market price of our common stock could decline;
time and resources committed by our management to matters relating to the applicable Proposed Merger could otherwise have been devoted to pursuing other beneficial opportunities for our Company;
we may experience negative reactions from the financial markets or from our customers, employees, suppliers and regulators; and
we will be required to pay the costs relating to each the Proposed Mergers, such as legal, accounting and financial advisory fees, whether or not the Proposed Mergers are completed.
The materialization of any of these risks could adversely impact our ongoing business.
Similarly, delays in the completion of either of the Proposed Mergers could, among other things, result in additional transaction costs, loss of revenue or other negative effects associated with uncertainty about completion of the Proposed Mergers.
We, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending, which could adversely affect the business and operations of the combined Company.
In connection with the pendency of the Proposed Mergers, it is possible that some customers, suppliers and other persons with whom we, Hygo or GMLP have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with us, Hygo or GMLP, as the case may be, as a result of the Proposed Mergers, which could negatively affect our current or the combined Company’s future revenues, earnings and cash flows, regardless of whether the Proposed Mergers are completed.
Under the terms of each of the Merger Agreements, each of Hygo and GMLP is subject to certain restrictions on the conduct of its business prior to completing each of the Proposed Mergers, which may adversely affect its ability to execute certain of its business strategies, including the ability in certain cases to enter into or amend contracts, acquire or dispose of assets, incur indebtedness or fund capital expenditures. Such limitations could adversely affect Hygo’s or GMLP’s business and operations, prior to the completion of the applicable Proposed Merger.
Each of the risks described above may be exacerbated by delays or other adverse developments with respect to the completion of either of the Proposed Mergers.
Uncertainties associated with the Proposed Mergers may cause a loss of management personnel and other key employees, and we may have difficulty attracting and motivating management personnel and other key employees, which could adversely affect our future business and operations.
We are dependent on the experience and industry knowledge of our management personnel and other key employees to execute their business plans. Our success after the completion of the Proposed Mergers will depend in part uponfinancial performance, nor our ability to attract, motivate and retain key management personnel and other key employees. Prior to completion of the Proposed Mergers, current and prospective employees may experience uncertainty about their roles withinachieve our Company following the completion of the Proposed Mergers, which may have an adverse effect on our ability to attract, motivate or retain management personnel and other key employees. In addition, no assurance can be given that we will be able to attract, motivate or retain management personnel and other key employees to the same extent after the completion of the Proposed Mergers.
After the Proposed Mergers, we may bestrategic objectives. We are also unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers.
The success of the Proposed Mergers will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which currently operate 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 benefitspredict how a global pandemic may not be realized fully, or at all, or may take longer to realize than expected and the value of our common stock may be harmed. Additionally, as a result of the Proposed 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 Proposed Mergers.
The Proposed Mergers involve the integration of Hygo and GMLP with our existing business, which is a complex, costly and time-consuming process. The integration of each of Hygo and GMLP into our business may result in material challenges, including, without limitation:
the diversion of management’s attention from ongoing business concerns and performance shortfalls as a result of the devotion of management’s attention to the Proposed Mergers;
managing a larger Company;
maintaining employee morale and attracting and motivating and retaining management personnel and other key employees;
the possibility of faulty assumptions underlying expectations regarding the integration process;
retaining existing business and operational relationships and attracting new business and operational relationships;
consolidating corporate and administrative infrastructures and eliminating duplicative operations;
coordinating geographically separate organizations;
unanticipated issues in integrating information technology, communications and other systems;
unanticipated changes in federal or state laws or regulations; and
unforeseen expenses or delays associated with either of the Proposed Mergers.
Many of these factors will be outside of our control and any one of them could result in delays, increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially affect our financial position, results of operationscustomers and cash flows.
Unlike new builds, existing vessels typically do not carry warranties as to their condition. If we inspect existing vessels prior to purchase, such an inspection would normally not provide us with as much knowledge of a vessel’s condition as we would possess if it had been built for us and operated only by us during its life. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built. These costs could decrease our cash flow and reduce our liquidity and could have an adverse effect on our expected plans for growth.
We may not have discovered undisclosed liabilities or other issues of either Hygo or GMLP during our due diligence process.
In the course of the due diligence review of each of Hygo and GMLP that we conducted prior to the execution of each of the Merger Agreements, 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. Examples of such undisclosed liabilities or other issues may include, but are not limited to, pending or threatened litigation, regulatory matters, undisclosed counterparty termination rights, or undisclosed letter of credit or guarantee requirements. Any such undisclosed liabilities or other issues could have an adverse effect on our business, results of operations, financial condition and cash flows following the completion of the Proposed Mergers.
We expect to incur a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger and as a result of the consummation of the Proposed Mergers.
As of December 31, 2020 we had approximately $1,250 million aggregate principal amount of indebtedness outstanding. On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. We may incur additional debt to fund our business and strategic initiatives, and expect to incur additional debt to fund a portion of the purchase price for the GMLP Merger. On January 13, 2021, we obtained financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase.
In addition, in connection with both the Hygo Merger and the GMLP Merger, we will be assuming a significant amount of indebtedness, including guarantees and preferred shares. As such, we will be subject to additional restrictive debt covenants that may limit our ability to finance future operations and capital needs and to pursue business opportunities and activities. In addition, if we fail to comply with any of these restrictions, it could have a material adverse effect on us.
Risks Related to Our Business
We haveOur business strategy relies on a variety of factors, including our ability to successfully market LNG, natural gas, steam, and power to our customers, 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 yet completed contracting, constructioncurrently operate, among others. These assumptions are subject to significant economic, competitive, regulatory and commissioningoperational uncertainties, contingencies and risks, many of all ofwhich are beyond our Facilities and Liquefaction Facilities. There can be no assurance thatcontrol, including, among others:
•inability to achieve our Facilities and Liquefaction Facilities will operate as expected, or at all.
We have not yet entered into binding construction contracts, issued “final notice to proceed” or obtained all necessary environmental, regulatory, construction and zoning permissions for all of our Facilities (as defined herein) and Liquefaction Facilities. There can be no assurance that we will be able to enter into the contracts requiredtarget costs for the developmentpurchase, liquefaction and export of natural gas and/or LNG and our Facilities and Liquefaction Facilities on commercially favorable terms, if at all, or that we will be abletarget pricing for long-term contracts;
• failure to develop strategic relationships;
• failure to obtain all of the environmental, regulatory, constructionrequired governmental and zoning permissions we need. In particular, we will require agreements with ports proximate to our Liquefaction Facilities capable of handling the transload of LNG directly from our transportation assets to our occupying vessel. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate these assets as expected, or at all. Additionally, the construction of these kinds of facilities is inherently subject to the risks of cost overruns and delays. There can be no assurance that we will not need to make adjustments to our Facilities and Liquefaction Facilities as a result of the required testing or commissioning of each development, which could cause delays and be costly. Furthermore, if we do enter into the necessary contracts and obtain regulatory approvals for the construction and operation of 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 Liquefaction Facilities, theretiming, pace and extent of economic growth 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 no assuranceexpected that such operationsone or more of our assumptions will allow usprove to successfully export LNG to our Facilities, orbe incorrect and that we will succeed inface unanticipated events and circumstances that may adversely affect our goal of reducing the riskability to our operations of future LNG price variations. If we are unable to construct, commission and operate all of our Facilities and Liquefaction Facilities as expected, or, when and if constructed, they do not accomplish our goals, or if we experience delays or cost overruns in construction,execute our business operating results, cash flows and liquidity could be materiallystrategy and adversely affected. Expenses related toaffect our pursuitbusiness, financial condition and results of contracts and regulatory approvals related to our Facilities and Liquefaction Facilities still under development may be significant and will be incurred by us regardless of whether these assets are ultimately constructed and operational.
We may experience time delays, unforeseen expensesare subject to various construction risks.
We are involved in the development of complex small, medium and other complications while developing our projects. These complications can delay the commencement of revenue-generating activities, reduce the amount of revenue we earnlarge-scale engineering and increase our development costs.
Developmentconstruction projects, including our Facilities, Liquefaction Facilities,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 disputes.
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 and additional operational monitoring and balancing requirements that may leadimpact the design of facilities to delay, increased costsbe constructed. Delays from such third parties or governmental entities could prevent connection to our projects and decreased economic attractiveness.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 are oftencan be increased in foreign jurisdictions where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project.
A primary focus of our business is See “–Risks Related to the development of projectsJurisdictions in foreign jurisdictions, includingWhich We Operate—We are subject to the economic, political, social and other conditions in locations where we have no prior development experience, and we expect to continue expanding into newthe jurisdictions in which we operate.”
The occurrence of any one of these factors, whatever the future, including with our expansion by way of the Proposed Mergers.
Our inexperiencecause, could result in these jurisdictions creates a meaningful risk that we may experienceunforeseen delays unforeseen expenses or other obstacles that will cause the projects we are developing to take longer and be more expensive than our initial estimates.
While we plan our projects carefully and attempt to complete them according to timelines and budgets that we believe are feasible, we have experienced time delays and cost overruns in some projects that we have developed previously and may experience similar issues with future projects given the inherent complexity and unpredictability of developing infrastructureto our projects. For example, we previously expected to commence operations of our San Juan Facility and the converted Units 5 and 6 of the San Juan Power Plant (as defined herein) in San Juan, Puerto Rico in the third quarter of 2019. However, due in part to the earthquakes that occurred near Puerto Rico in January 2020 and third-party delays, we began supplying natural gas to Units 5 and 6 in the second quarter of 2020. Delays in the development beyond our estimated timelines, or amendments or change orders to theour construction contracts, we have entered into and will enter intocould result in the future, could increase the cost of completionincreases to our development costs beyond the amounts that we estimate. Increased costsour original estimates, which could require us to obtain additional sources of financing to continue development on ouror funding and could make the project less profitable than originally estimated development timeline or to fund our operations duringpossibly not profitable at all. Further, any such development. Any delay in completion of a Facilitydelays could cause a delay in theour anticipated receipt of revenues, estimated therefrom or cause a loss of one or more customers, 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 eventconstruction and development of significant delays. Asour 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 one of these factors, any significant development delay, whatever the cause,which could have a material adverse effect on our business, operating results, cash flows and liquidity.
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 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 operations;
•inability, or failure, of any counterparty to any facility-related agreements to perform their contractual obligations;
•decreased demand by our customers; 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, FSRU and LNG carriers, which operations are complex and technically challenging and subject to mechanical 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 cargos 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
Our ability to implementthese 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, strategy may beour results of operations and cash flows and weaken our financial condition. Our offshore 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 our control, such as the overall economic impacts caused by the global COVID-19 outbreak. Other 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 affected by many knownaffect 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 unknown factors.results of operations.
Our business strategy relies upon our future ability to successfully market natural gas to end-users, developWe depend on third-party contractors, operators and maintain cost-effective logistics in our supply chainsuppliers.
We rely on third-party contractors, equipment manufacturers, suppliers and construct, develop and operate energy-related infrastructure in the U.S., Jamaica, Mexico, Puerto Rico, Ireland, Nicaragua, Brazil and other countries where we do not currently operate. Our strategy assumes that we will be able to expand our operations into other countries, including countries in the Caribbean, enter into long-term GSAs and/or PPAs with end-users, acquire and transport LNG at attractive prices, develop infrastructure, including the Pennsylvania Facility (as defined herein), as well as other future projects, into efficient and profitable operations in a timely and cost-effective way, obtain approvals from all relevant federal, state and local authorities, as needed,operators for the development, construction and operation of theseour projects and other relevant approvals and obtain long-term capital appreciation and liquidity with respect to such investments.assets. We cannot assure you if or when we will enterhave not yet entered into binding contracts for the saleconstruction, development and operation of LNG and/or natural gas, the price at whichall of our facilities and assets, and we will be able to sell such LNG and/or natural gas or our costs for such LNG and/or natural gas. Thus, there can be no assurance that we will achieve our target pricing, costs or margins. Our strategy may also be affected by future governmental laws and regulations. Our strategy also assumescannot assure you that we will be able to enter into strategic relationshipsthe 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 energy end-users,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. 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, utilities, LNG providers, shipping companies, infrastructure developers, financing counterpartiesas well as increased expenses or reduced revenue. Such liquidated damages may also be subject to caps on liability, and we may not have full indemnification from our contractors to compensate us for such payments and other partners. These assumptionsconsequences. 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 their respective agreements. 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. LNG prices have increased materially in the past, including in August 2021 through the end of 2022, 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 have had and may in the future 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 the 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 power, natural gas or LNG operations, including exploration, development and production activities, liquefaction, regasification or transportation of our 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 regulations are assessed, managed, administered and enforced by various governmental agencies and bodies, whose actions and decisions could adversely affect our business or operations. 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. For example, in February 2024, the Biden Administration announced a temporary pause on pending approvals of LNG exports to non-FTA countries. While the duration of the pause remains unclear, any restrictions on or delays in approving natural gas exports could negatively impact our business in the future. 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. 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. On March 19, 2021, as upheld on rehearing on July 15, 2021, FERC determined that our San Juan Facility is subject to its jurisdiction and directed us to file an application for authorization to operate the San Juan Facility but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. 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, FLNG 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 significant economic, competitive, regulatoryvarious approvals and operational uncertainties, contingenciespermits. The process to obtain the permits, approvals and risks, manyauthorizations 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. Jurisdiction-specific employment, labor, and subcontracting laws may also affect contracting strategies and impact construction and operations. 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 beyondawaiting final approvals for our control. Additionally, in furtherancepower plant and permits necessary to operate our terminal. In connection with our application to the U.S. Maritime Administration ("MARAD") related to our FLNG project off the coast of Louisiana (as discussed further below), 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. In addition, jurisdiction-specific employment, labor, and subcontracting laws may also affect contracting strategies and impact construction and operations. No assurance can be given that we will be able to obtain approval of this application and receive the required permits, approvals and authorizations from governmental and regulatory agencies related to our business strategy,project on a timely basis or at all. 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. We cannot make any assurance as to if or when we may acquire operating businesseswill receive these permits, which are 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 assetspotential 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 the future. Any such acquisitions wouldjurisdictions that may lack mature legal and regulatory systems and may experience legal instability, which may be subject to significant risksregulatory and contingencies, including the risklegal challenges, instability or clarity of integration,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 realize the benefits of any such acquisitions.
Additionally,complete our strategyprojects, start or continue our operations, recover our investment in our projects and may evolve over time. Our future abilitybe subject to executefinancial penalties or termination under our business strategy is uncertain,customer and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our business. Any one or more of the following factors mayother agreements, which could have a material adverse effect on our ability to implement our strategy and achieve our targets:
inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts;
failure to develop cost-effective logistics solutions;
failure to manage expanding operations in the projected time frame;
inability to structure innovative and profitable energy-related transactions as part of our sales and trading operations and to optimally price and manage position, performance and counterparty risks;
inability, or failure, of any customer or contract counterparty to perform their contractual obligations to us (for further discussion of counterparty risk, see “— Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all.”);
inability to develop infrastructure, including our Facilities and Liquefaction Facilities, as well as other future projects, in a timely and cost-effective manner;
inability to attract and retain personnel in a timely and cost-effective manner;
failure of investments in technology and machinery, such as liquefaction technology or LNG tank truck technology, to perform as expected;
increases in competition which could increase our costs and undermine our profits;
inability to source LNG and/or natural gas in sufficient quantities and/or at economically attractive prices;
failure to anticipate and adapt to new trends in the energy sector in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, after the consummation of the Proposed Mergers, Brazil, and elsewhere;
increases in operating costs, including the need for capital improvements, insurance premiums, general taxes, real estate taxes and utilities, affecting our profit margins;
inability to raise significant additional debt and equity capital in the future to implement our strategy as well as to operate and expand our business;
general economic, political and business, conditions in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, Brazil and in the other geographic areas in which we intend to operate;
the severity and duration of world health events, including the recent COVID-19 pandemic and related economic and political impacts on our or our customers’ or suppliers’ operations and financial status;
inflation, depreciation of the currencies of the countries in which we operate and fluctuations in interest rates;
failure to win new bids or contracts on the terms, size and within the time frame we need to execute our business strategy;
failure to obtain approvals from governmental regulators and relevant local authorities for the construction and operation of potential future projects and other relevant approvals;
uncertainty regarding the timing, pace and extent of an economic recovery in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas; or
existing and future governmental laws and regulations.
If we experience any of these failures, such failure may adversely affect our financial condition, operating results, of operationsliquidity and ability to execute our business strategy.
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 natural gas, LNG or powerour products and generate fees from customers in the future. When we develop largethese projects, such as facilities, power plants and large liquefaction facilities, our required capital
expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain.
If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects.
We have a limited operating history,significant working capital requirements, primarily driven by the time difference between the time when we incur costs to build and/or purchase our Facilities and other projects and the time in which we receive revenues from customers after such Facilities and other projects are complete. We also experience timing date differences between the date we pay for natural gas and the payment dates 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 sufficientable to evaluatepursue 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 prospects.results of operations.
We have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the value of our Class A common stock. We commenced operations on February 25, 2014, and we had net losses of approximately $78.2 million in 2018, $204.3 million in 2019 and $264.0 million in 2020. Our strategy may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner. We cannot give you any assurance that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate. Our limited operating history also means that we continue to develop and implement various policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We will need to continue to build our team to develop and implement our strategies.
We will continue to incur significant capital and operating expenditures while we develop infrastructure for our supply chain, including for the completion of our Facilities and Liquefaction Facilities under construction, as well as other future projects. We will need to invest significant amounts of additional capital to implement our strategy. We have not yet completed constructing all of our Facilities and Liquefaction Facilities and our strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under our customer contracts in relation to the incurrence of project and operating expenses. Our ability to generate any positive operating cash flowrevenues is substantially dependent on our current and achieve profitabilityfuture 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 is dependent on, among other things, our ability to develop an efficient supply chain (which may be impacted by the COVID-19 pandemic) and successfully and timely complete necessary infrastructure, including our Facilities and Liquefaction Facilities under construction, and fulfill our gas delivery obligations under our customer contracts.
Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms.
We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in specific markets, or the opportunistic sale of one of our non-core assets. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan and our business, financial condition or results of operations may be materially adversely affected. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. Our ability to raise additional capital will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to the COVID-19 pandemic, our progress in executing our business strategy and other factors, many of which are beyond our control. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Additional debt financing, if available, may subjectrequire us to restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resourcesenter into contracts based on variable market prices, as opposed to service our obligations. If we are unable to comply with our existing covenants or any additional covenants and service our debt, we may lose control of our business and be forced to reduce or delay planned investments or capital expenditures, sell assets, restructure our operations or submit to foreclosure proceedings, all ofcontracts based on a fixed rate, which could result in a material adverse effect upondecrease in our business.
A variety of factors beyondcash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also historically have relied and in the future will likely rely on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.
We may not be profitable for an indeterminate period of time.
We have a limited operating history and did not commence revenue-generating activities until 2016, and did not achieve profitability as of December 31, 2020. We have made and will continue to make significant initial investments to complete construction and begin operations of each of our Facilities, power plants and Liquefaction Facilities, and we will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects, including in connection with the Proposed Mergers. We also expect to incur significant expenses in connection with the launch and growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. We will need to raise significant additional debt capital to achieve our goals.
We may not be able to achieve profitability, and if we do, we cannot assure you that we would be able to sustain such profitability in the future. vessels.Our failure to achieve or sustain profitability would have a material adverse effect on our business.
Our business is heavily dependent upon our international operations, particularly in Jamaica and Puerto Rico, and any disruption to those operations would adversely affect us.
Our operations in Jamaica began in October 2016, when our Montego Bay Facility commenced commercial operations, and continue to grow, and our San Juan Facility became fully operational in the third quarter of 2020. Jamaica and Puerto Rico are subject to acts of terrorism or sabotage and natural disasters, in particular hurricanes, extreme weather conditions, crime and similar other risks which may negatively impact our operations in the region. We may also be affected by trade restrictions, such as tariffs or other trade controls. Additionally, tourism is a significant driver of economic activity in the Caribbean. As a result, tourism directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in the Caribbean are primarily driven by the economic condition of the tourists’ home country or territory, the condition of their destination, and the availability, affordability and desirability of air travel and cruises. Additionally, unexpected factors could reduce tourism at any time, including local or global economic recessions, terrorism, travel restrictions, pandemics, severe weather or natural disasters. If we are unable to continue to leverage on the skills and experience of our international workforce and members of management with experience in the jurisdictions in which we operate to manage such risks, we may be unable to provide LNG at an attractive price and our business could be materially affected.
Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results.
A limited number of customers currently represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. At least in the short term, we expect that a substantial majority of our sales will continue to arise from a concentrated number of customers, such as power utilities, railroad companies and industrial end-users. We expect the substantial majority of our revenue for the near future to be from customers in the Caribbean, and assuming the consummation of the Proposed Merger, the Sergipe Terminal and the Sergipe Power Plant and as a result, are subject to any risks specific to those customers and the jurisdictions and markets in which they operate. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.
Assuming the consummation of the GMLP Merger and following such merger, if we lose any of our charterers and are unable to re-deploy the related vessel for an extended period of time, we will not receive any revenues from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, under the sale and leaseback arrangement in respect of the Golar Eskimo, if the time charter pursuant to which the Golar Eskimo is operating is terminated, the owner of the Golar Eskimo (which is a wholly-owned subsidiary of China Merchants Bank Leasing) will have the right to require us to purchase the vessel from it unless we are able to place such vessel under a suitable replacement charter within 24 months of the termination. We may not have, or be able to obtain, sufficient funds to make these accelerated payments or prepayments or be able to purchase the Golar Eskimo. In such a situation, the loss of a charterer could have a material adverse effect on our business, results of operations and financial condition.
Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all.
Our current results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon performance by JPS (as defined herein), SJPC (as defined herein) and PREPA (as defined herein), which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant (as defined herein), with us, and Jamalco (as defined herein), which has entered into a long-term SSA with us. While certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts are substantially in excess of such minimum volume commitments. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties.
Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. In assessing customer credit risk, we use various procedures including background checks which we perform on our potential customers before we enter into a long-term contract with them. As part of the background check, we assess a potential customer’s credit profile and financial position, which can include their operating results, liquidity and outstanding debt, and certain macroeconomic factors regarding the region(s) in which they operate. These procedures help us to appropriately assess customer credit risk on a case-by-case basis, but these procedures may not be effective in assessing credit risk in all instances. As part of our business strategy, we intend to target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Additionally, we may face difficulties in enforcing our contractual rights against contractual counterparties that have not submitted to the jurisdiction of U.S. courts. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. The COVID -19 pandemic could adversely impact our customers through decreased demand for power due to decreased economic activity and tourism, or through the adverse economic impact of thea pandemic, on their power customers. The impact of thesuch as COVID-19, pandemic, including governmental and other third-party responses thereto, on our customers could enhance the risk of nonpayment by such customers under our contracts, which would negatively affect our business, results of operations and financial condition.
In particular, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, our ability to operate the CHP Plant is dependent on our ability to enforce the related lease. General Alumina Jamaica Limited (“GAJ”), one of the lessors, is a subsidiary of Noble Group, which completed a financial restructuring in 2018. If GAJ is involved in a bankruptcy or similar proceeding, such proceeding could negatively impact our ability to enforce the lease. If we are unable to enforce the lease due to the bankruptcy of GAJ or for any other reason, we could be unable to operate the CHP Plant or to execute on our contracts related thereto, which could negatively affect our business, results of operations and financial condition. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from the Federal Emergency Management Agency or 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 results of operations for the year ended December 31, 2023, include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. In addition, we placed a portion of our La Paz Facility into service in the fourth quarter of 2021, and our revenue and results of operations have begun to be impacted by operations in Mexico, including agreements with certain power generation facilities in Baja California Sur. Our results for 2023 exclude other developments, including our Puerto Sandino Facility, the Barcarena Facility, Santa Catarina Facility and Ireland Facility. Jamaica, Mexico 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 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 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 these geographies and directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in these 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, severe weather or natural disasters. Due to our current lack of asset and geographic diversification, an adverse development at our operating facilities, in the energy industry or in the economic conditions in 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, SJPC, CFE and PREPA, 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, with us, and Jamalco, 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 responses 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. 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 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’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.
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, HFO and 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, hydrogen,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 offshore 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.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:
•additions to competitive regasification capacity in North America, Brazil, Europe, Asia and other markets, which could divert LNG or natural gas from our business;
•imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States;
•insufficient or oversupply of natural gas liquefaction or export capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions and natural disasters;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities, including shut-ins and possible proration, which have begun and may continue to decrease the production of natural gas;
•cost improvements that allow competitors to offer LNG regasification services at reduced prices;
•changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•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—in particular prior to our Pennsylvania Facility becoming operational—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 certainCertain actions by the Organization of the Petroleum Exporting Countries (“OPEC”("OPEC") related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long-term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows. For example, among other reasons and because spotConversely, as in recent years, market conditions may increase LNG pricesvalues to historically high levels. These elevated market values increase the economic incentives an LNG seller has to fail to deliver LNG cargos to us if they can sell the same LNG cargos at a higher price to another buyer in the second quartermarket after giving effect to any contractual penalties the seller would owe to us for failing to deliver. Our contracts may not require an LNG seller to compensate us for the full current market value of 2020 were significantly lower thanan 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 price at which we had previously contractedLNG 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 we terminatedor significantly increases our contractual obligation to purchasecosts for purchasing LNG, for the remainder of 2020 in order to purchase LNG at lower prices on the spot market during that period in exchange for a one-time payment of $105 million.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. Additionally, we intend to rely on long-term, largely fixed-price contracts for the feedgas that we need in order to manufacture and sell our LNG. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control.
Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.
We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.
Operation of our LNG infrastructure and other facilities that we may construct involves significant risks.
Our existing Facilities and Liquefaction Facilities and expected future facilities face operational risks, including, but not limited to, the following: performing below expected levels of efficiency, breakdowns or failures of equipment, operational errors by trucks, including trucking accidents while transporting natural gas, tankers or tug operators, operational errors by us or any contracted facility operator, labor disputes and weather-related or natural disaster interruptions of operations.
Any of these risks could disrupt our operations and increase our costs, which would adversely affect our business, operating results, cash flows and liquidity.
The operation of the CHP Plant and other power plants will involve particular, significant risks.
The operation of the CHP Plant and other power plants that we operate in the future will involve particular, significant risks, including, among others: failure to maintain the required power generation license(s) or other permits required to operate the power plants; pollution or environmental contamination affecting operation of the power plants; the inability, or failure, of any counterparty to any plant-related agreements to perform their contractual obligations to us including, but not limited to, the lessor’s obligations to us under the CHP Plant lease; decreased demand for power produced, including as a result of the COVID-19 pandemic; and planned and unplanned power outages due to maintenance, expansion and refurbishment. We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, the CHP Plant or other power plants. If the CHP Plant or other power plants are unable to generate or deliver power or steam, as applicable, to our customers, such customers may not be required to make payments under their respective agreements so long as the event continues. Certain customers may have the right to terminate those agreements for certain failures to generate or deliver power or steam, as applicable, and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. In addition, such termination may give rise to termination or other rights under related agreements including related leases. As a consequence, there may be reduced or no revenues from one or more of our power plants, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Global climate change may in the future increase the frequency and severity of weather events and the losses resulting therefrom, which could have a material adverse effect on the economies in the markets in which we operate or plan to operate in the future and therefore on our business.
Over the past several years, changing weather patterns and climatic conditions, such as global warming, have added to the unpredictability and frequency of natural disasters in certain parts of the world, including the markets in which we operate and intend to operate, and have created additional uncertainty as to future trends. There is a growing consensus today that climate change increases the frequency and severity of extreme weather events and, in recent years, the frequency of major weather events appears to have increased. We cannot predict whether or to what extent damage that may be caused by natural events, such as severe tropical storms and hurricanes, will affect our operations or the economies in our current or future market areas, but the increased frequency and severity of such weather events could increase the negative impacts to economic conditions in these regions and result in a decline in the value or the destruction of our liquefiers and downstream facilities or affect our ability to transmit LNG. In particular, if one of the regions in which our Facilities are operating or under development is impacted by such a natural catastrophe in the future, it could have a material adverse effect on our business. Further, the economies of such impacted areas may require significant time to recover and there is no assurance that a full recovery will occur. Even the threat of a severe weather event could impact our business, financial condition or the price of our Class A common stock.
Hurricanes or other natural or manmade disasters could result in an interruption of our operations, a delay in the completion of our infrastructure projects, higher construction costs or the deferral of the dates on which payments are due under our customer contracts, all of which could adversely affect us.
Storms and related storm activity and collateral effects, or other disasters such as explosions, fires, seismic events, floods or accidents, could result in damage to, or interruption of operations in our supply chain, including at our Facilities, Liquefaction Facilities, or related infrastructure, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our marine and coastal operations. Due to the concentration of our current and anticipated operations in Southern Florida and the Caribbean, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects. For example, the 2017 Atlantic hurricane season caused extensive and costly damage across Florida and the Caribbean, including Puerto Rico. In addition, earthquakes which occurred near Puerto Rico in January 2020 resulted in a temporary delay of development of our Puerto Rico projects. We are unable to predict with certainty the impact of future storms on our customers, our infrastructure or our operations.
If one or more tankers, pipelines, Facilities, Liquefaction Facilities, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our Facilities, Liquefaction Facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist or cyber-attack or event, our operations and construction projects could be delayed and our operations could be significantly interrupted. These delays and interruptions could involve significant damage to people, property or the environment, and repairs could take a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations or that causes us to make significant expenditures not covered by insurance could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Information technology failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.
We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our Facilities, Liquefaction Facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, Facilities, Liquefaction Facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.
Our current operations and future projects are subject to the inherent risks associated with LNG, natural gas and power operations, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the our Facilities, Liquefaction Facilities and assets or damage to persons and property. In addition, such operations and the vessels of third parties on which our current operations and future projects may be dependent face possible risks associated with acts of aggression or terrorism. Some of the regions in which we operate are affected by hurricanes or tropical storms. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not carry business interruption insurance for hurricanes and other natural disasters. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic release of natural gas, marine disaster or natural disasters could result in losses that exceed our insurance coverage, which could harm our business, financial condition and operating results. Any uninsured or underinsured loss could harm our business and financial condition. In addition, our insurance may be voidable by the insurers as a result of certain of our actions.
We intend to operate in jurisdictions that have experienced and may in the future experience significant political volatility. Our projects and developments could be negatively impacted by political disruption including risks of delays to our development timelines and delays related to regime change in the jurisdictions in which we intend to operate. We do not carry political risk insurance today. If we choose to carry political risk insurance in the future, it may not be adequate to protect us from loss, which may include losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain.
Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult for us to obtain. In addition, the insurance that may be available may be significantly more expensive than our existing coverage.
We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.
The COVID-19 pandemic has caused, and is expected to continue to cause, economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil. In addition, the pandemic has made travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly changing and difficult to predict, the pandemic’s impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains uncertain and difficult to predict. Further, the ultimate impact of the COVID-19 pandemic on our operations and financial performance depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of the pandemic and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs; general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery when the COVID-19 pandemic subsides.
The COVID-19 pandemic has subjected our operations, financial performance and financial condition to a number of operational financial risks. The COVID-19 pandemic has also affected Hygo and GMLP. For example, there is an increased risk that final investment decision of Hygo’s Barcarena Terminal (as defined herein) and Santa Catarina Terminal (as defined herein) may be delayed due to severe restrictions on travel within Brazil. Although the services we provide are generally deemed essential, we may face negative impacts from increased operational challenges based on the need to protect employee health and safety, workplace disruptions and restrictions on the movement of people including our employees and subcontractors, and disruptions to supply chains related to raw materials and goods both at our own Facilities, Liquefaction Facilities and at customers and suppliers. We may also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.
From time to time, we may be involved in legal proceedings and may experience unfavorable outcomes.
In the future we may be subject to material legal proceedings in the course of our business, including, but not limited to, actions relating to contract disputes, business practices, intellectual property and other commercial tax and regulatory matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time-consuming and expensive. Further, if any such proceedings were to result in an unfavorable outcome, it could have an adverse effect on our business, financial position and results of operations.
Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.
We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, and some of our other executive officers. 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 could disrupt our operations and increase our exposure to the other risks described in this “Risks Factors” section. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
Our construction of energy-related infrastructure is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.
The construction of energy-related infrastructure, including our Facilities and Liquefaction Facilities, assuming the consummation of the Hygo Merger, the Barcarena Terminal, the Santa Catarina Terminal and other assets in Brazil, as well as other future projects, involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital during construction and thereafter. These potential risks include, among other things, the following:
we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents or weather conditions;
we may issue change orders under existing or future engineering, procurement and construction (“EPC”) contracts resulting from the occurrence of certain specified events that may give our customers the right to cause us to enter into change orders or resulting from changes with which we otherwise agree;
we will not receive any material increase in operating cash flows until a project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;
we may construct facilities to capture anticipated future energy consumption growth in a region in which such growth does not materialize;
the completion or success of our construction projects may depend on the completion of a third-party construction project (e.g., additional public utility infrastructure projects) that we do not control and that may be subject to numerous additional potential risks, delays and complexities;
the purchase of the project company holding the rights to develop and operate the Ireland Facility (as defined herein) is subject to a number of contingencies, many of which are beyond our control and could cause us not to acquire the remaining interests of the project company or cause a delay in the construction of our Ireland Facility;
we may not be able to obtain key permits or land use approvals including those required under environmental laws on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations, and there may be delays, perhaps substantial in length, such as in the event of challenges by citizens groups or non-governmental organizations, including those opposed to fossil fuel energy sources;
we may be (and have been in select circumstances) subject to local opposition, including the efforts by environmental groups, which may attract negative publicity or have an adverse impact on our reputation; and
we may be unable to obtain rights-of-way to construct additional energy-related infrastructure or the cost to do so may be uneconomical.
A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from future projects, which could have a material adverse effect on our business, financial condition and results of operations.
We expect to be dependent on our primary building contractor and other contractors for the successful completion of our energy-related infrastructure.
Timely and cost-effective completion of our energy-related infrastructure, including our Facilities and Liquefaction Facilities, and, assuming the consummation of the Hygo Merger, the Sergipe Terminal, the Barcarena Terminal and the Santa Catarina Terminal, as well as future projects, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our primary building contractor and our other contractors under our agreements with them. The ability of our primary building contractor and our other contractors to perform successfully under their agreements with us is dependent on a number of factors, including their ability to:
design and engineer each of our facilities to operate in accordance with specifications;
engage and retain third-party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failures to perform by subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
maintain their own financial condition, including adequate working capital.
Until and unless we have entered into an EPC contract for a particular project, in which the EPC contractor agrees to meet our planned schedule and projected total costs for a project, we are subject to potential fluctuations in construction costs and other related project costs. Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of our primary building contractor and our other contractors to pay liquidated damages under their agreements with us are subject to caps on liability, as set forth therein. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to its respective agreement. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
In addition, if our contractors are unable or unwilling to perform according to their respective agreements with us, our projects may be delayed and we may face contractual consequences in our agreements with our customers, including for development services, the supply of natural gas, LNG or steam and the supply of power. We may be required to pay liquidated damages, face increased expenses or reduced revenue, and may face issues complying with certain covenants in such customer agreements or in our financings. We may not have full protection to seek payment from our contractors to compensate us for such payments and other consequences.
We are relying on third-party engineers to estimate the future rated capacity and performance capabilities of our existing and future facilities, and these estimates may prove to be inaccurate.
We are relying on third parties for the design and engineering services underlying our estimates of the future rated capacity and performance capabilities of our Facilities and Liquefaction Facilities, as well as other future projects. If any of these facilities, when actually constructed, fails to have the rated capacity and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our existing Facilities, Liquefaction Facilities or future facilities to achieve our intended future capacity and performance capabilities could prevent us from achieving the commercial start dates under our customer contracts and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We perform development or construction services from time to time, which are subject to a variety of risks unique to these activities.
From time to time, we may agree to provide development or construction services as part of our customer contracts and such services are subject to a variety of risks unique to these activities. If construction costs of a project exceed original estimates, such costs may have to be absorbed by us, thereby making the project less profitable than originally estimated, or possibly not profitable at all. In addition, a construction project may be delayed due to government or regulatory approvals, supply shortages, or other events and circumstances beyond our control, or the time required to complete a construction project may be greater than originally anticipated. For example, the conversion of Unit 5 and 6 in the San Juan Power Plant was delayed in part due to the earthquakes that occurred near Puerto Rico in January 2020 and third-party delays.
We rely on third-party subcontractors and equipment manufacturers to complete many of our projects. To the extent that we cannot engage subcontractors or acquire equipment or materials in the amounts and at the costs originally estimated, our ability to complete a project in a timely fashion or at a profit may be impaired. If the amount we are required to pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price contracts, we could experience losses in the performance of these contracts. In addition, if a subcontractor or a manufacturer is unable to deliver its services, equipment or materials according to the negotiated terms for any reason including, but not limited to, the deterioration of its financial condition, we may be required to purchase the services, equipment or materials from another source at a higher price. This may reduce the profit we expect to realize or result in a loss on a project for which the services, equipment or materials were needed.
If any such excess costs or project delays were to be material, such events may adversely affect our cash flow and liquidity.
We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPA and SSA, which could have a material adverse effect on us.
Under the GSAs with JPS, SJPC and PREPA, we are required to deliver to JPS, SJPC and PREPA specified amounts of natural gas at specified times, while under the SSA with Jamalco, we are required to deliver steam, and under the PPA with JPS, we are required to deliver power, each of which also requires us to obtain sufficient amounts of LNG. However, we may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide JPS or SJPC or PREPA or Jamalco with the right to terminate its GSA, PPA or SSA, as applicable. In addition, price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices.
We are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Additionally, under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase or receive a sufficient quantity of natural gas in order to satisfy our delivery obligations under our GSAs, PPA and SSA with LNG produced at our own Liquefaction Facilities. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.
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.
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.
We are dependent on third-party LNG suppliers and the development of our own portfolio is subject to various risks and 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 remedial obligations under those agreements. While we have entered into contracts with a third-party tosupply agreements for the purchase a substantial portion of our currently contractedLNG between 2024 and expected LNG volumes through 2030,2047, we willmay 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 natural gasLNG or at favorable prices could materially and adversely affect our business, operating results, cash flows and liquidity.
Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptciesThe development of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amountown portfolio of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurances that we will complete the Pennsylvania Facility or be able to supply our Facilities with LNG produced at our own Liquefaction Facilities. Even if we do complete the Pennsylvania Facility, there can be no assurance that it will operate as we expect or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations.
We face competition based upon the international market price for LNG or natural gas.
Our business is subject to various risks and assumptions. In particular, the riskestimation of naturalproved gas reserves involves subjective judgements and LNG price competition at times when we needdeterminations 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 replace anyreflect acquisitions, divestments, new discoveries, extensions of existing customer contract, whether duefields and mines, and improved recovery techniques. Published proved gas reserves estimates could also be subject to natural expiration, default or otherwise, or enter into new customer contracts. Factors relatingcorrection 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 competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all. Such an eventimpairment of assets. This could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidityflows and prospects. Factors which may negatively affect potential demand for natural gasliquidity.
Additionally, we are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our business are diversetankers and include, 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 requiredenergy-related infrastructure. If any third parties were to maintain current price equilibrium with respect to supply;
increases in the cost to supply natural gas feedstock todefault on their obligations under our liquefaction projects;
increases in the cost to supply LNG feedstock to our Facilities;
decreases in the cost of competing sources of natural gas, LNGcontracts or alternate fuels such as coal, heavy fuel oil and 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,seek bankruptcy protection, we may not be able to successfully executereplace 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 are 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 may 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 losses, penalties, indemnification and potentially a termination of agreements with our customers. Furthermore, we may seek to litigate any such breaches 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 result in an unfavorable outcome, we may not be able to recover our losses (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 operations. Further, it could have an adverse effect on our strategybusiness, operating results, cash flows and liquidity, which could in turn materially and adversely affect our liquidity to supplymake payments on our existingdebt or comply with our financial ratios and future customers with LNG produced primarily at our own Liquefaction Facilities upon completion of the Pennsylvania Facility.other covenants. See “—We have incurred, and may in the future incur, a significant amount of debt.”
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. Where we have chartered in, but subsequently not yet completed contracting,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 are stored on an FSRU or are 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.
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 commissioningdelivery 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. 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 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.
We may not be able to fully utilize the capacity of our FSRUs and other facilities.
Our FSRU facilities have 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 Facilitiesexcess capacity. Factors which could cause us to contract less than full capacity include difficulties in negotiations with potential counterparties and Liquefaction Facilities. Therefactors outside of our control such as the price of and demand for LNG. 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.
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 offshore 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. 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.
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 no assurancesignificant.
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. We recognized an impairment charge on one of our Facilitiesvessels for the year ended December 31, 2023 and Liquefaction Facilitieswe cannot assure you that we will operatenot recognize impairment losses on our vessels in future years. Any impairment charges incurred as expected,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 not yet proven and we may not be able to implement it as planned or at all.”
As part of our business development, we enter into non-binding agreements, and may not agree final definitive documents on similar terms or at all.
Our business development process includes entering into non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responding to requests for proposals with potential customers. These agreements and any award following a request for proposals We are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations. We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements.
As part of our efforts to reduce global carbon emissions, we are making investments in green hydrogen energy technologies. The innovative nature of these projects entails the risk that we may never realize the anticipated benefits we hope to achieve for the planet.
We arealso 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 continue to develop our ISO container distribution systems in the various markets where 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 our investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology.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.
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.
ChangesWe 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 legislationthe natural gas liquefaction industry may be adversely affected by our inability to effectively implement our Fast LNG technology. We are about to finalize construction of our first Fast LNG solution, but we have not yet produced or supplied any LNG from that facility, and are therefore subject to construction risks, risks associated with third-party contracting and service providers, permitting and regulatory risks. We are also developing our first onshore LNG facility and are also 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 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, 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 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 which 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, or 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 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, 2023, we had approximately $6,919.5 million aggregate principal amount of indebtedness outstanding on a consolidated basis. The terms and conditions of our indebtedness 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 impacteffect on our business, results of operations,operation and financial condition, liquidity and prospects.
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 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 numerous governmental laws, rules, regulationsincreased restrictive covenants that could limit our flexibility in conducting future business activities and requires permitscould 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 impose various restrictionswe 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 obligationsour financial condition or results of operations may be materially adversely affected.
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 development of a global marine infrastructure platform, of which we owned 20% prior to our sale of our 20% stake in February 2024. 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 material effects on our resultsto receive assets of operations. In addition, eachany joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the applicable regulatorycreditors 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. Failure by any of our joint ventures, equity method investees and/or affiliates to service their debt requirements and limitations is subjectcomply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to change, either through new regulations enactedan 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 federal, staterelevant assets or local level,vessels securing the loans or by newseek repayment of the loan from us, or modified regulations that may be implemented under existing law. The nature and extentboth. Either of any changes in these laws, rules, regulations and permits may be unpredictable and maypossibilities could have a material effectsadverse effect on our business. Future legislationFurther, 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.
Existing and future environmental, social, health and safety laws and regulations could result in increased or changesmore stringent compliance requirements, which may be difficult to comply with or result in existing legislationadditional 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, or interpretations thereof, such as thosein the United States and in the jurisdictions where we operate, relating to the liquefaction,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 regasificationprohibit the types, quantities and concentrations of LNG,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 its transportationnew environmental, social, health and safety laws and regulations could cause additional expenditures, restrictions and delays in connection with our business and operations, as well as other future projects, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in March 2021, an amendmentOctober 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance
document was a “rule” subject to the Mexican Power Industry Law (Ley de la Industria ElectricaCongressional Review Act (“CRA”) was published which would reduce. This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the dispatch priority of privately-owned power plants comparedCRA, potentially increasing the likelihood that laws and regulations applicable to state-owned power plantsour business will become subject to revised interpretations in Mexico. The amendment is being challenged as unconstitutional, and a judge recently awarded a temporary injunction halting the implementation of the amendment. However, if the amendment is enforced against us, it could negatively affect our plant's dispatch and our revenue and results of operations. 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 ana 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 charterer 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 could 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, resultsmarkets.
Greenhouse Gases/Climate Change. The threat of operations, financial condition, liquidity and prospects.
Increasing trucking regulations may increase our costs and negatively impact our results of operations.
We are developing a transportation system specifically dedicatedclimate change continues to transporting LNG from our Liquefaction Facilities to a nearby port, from which our LNG can be transported to our operationsattract considerable attention in the Atlantic BasinUnited States and elsewhere. This transportation system may include trucks that we oraround 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 affiliates own and operate. Any such operations would be subject to various trucking safety regulations, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to 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 and/coalitions have adopted or local safetyconsidered adopting legislation, regulations that mirror federal regulations but also regulateor 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 weightinternational 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 in February 2021, and size dimensionsother 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 loads.
All federally regulated carriers’ safety ratings are measured through a program implementedfuture 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 the FMCSA knownU.S. government, 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 Compliance Safety Accountability (“CSA”) program. 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 CSA program measures a carrier’s safety performance basedadoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of the company’s operating authority by the FMCSA, whichGHG emissions could result in a material adverse effectincreased 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 businessfacilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and consolidated results of operationsadminister and financial position.
Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental regulations, changes in the hours of service regulations which govern the amount of timemanage a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.
GHG emissions program. We may not be able to renew or obtain new or favorable charters or leases, which could adversely affect our business, prospects, financial condition, results of operations and cash flows.
We have obtained long-term leases and corresponding rights-of-way agreements with respect to the land on which the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the Miami Facility, the San Juan Facility and the CHP Plant are situated. However, we do not own the land. As a result, we are subject to the possibility ofrecover such increased costs to retain necessary land use rights as well as local law. If we were to lose these rightsthrough increases in customer prices or be required to relocate, our business could be materially and adversely affected. The Miami Facility is currently located on land we are leasing from an affiliate. Any payments under the existing lease or future modifications or extensions to the lease could involve transacting with an affiliate. We have also entered into LNG tanker chartersrates. In addition, changes in order to secure shipping capacity for our import of LNG to the Jamaica Facilities.
Our ability to renew existing charters or leases for our current projects or obtain new charters or leases for our future projects will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of rates and contract provisions. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.
We may not be able to successfully enter into contracts or renew existing contracts to charter tankers in the future, which mayregulatory policies that result in us not being able to meet our obligations.
We enter into time charters of ocean-going tankers for the transportation of LNG, which extend for varying lengths of time. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers in the future, which may result in us not being able to meet our obligations. We are also exposed to changes in market rates and availability for tankers, which may affect our earnings. Fluctuations in rates result from changes in the supply of and demand for capacity and changesa reduction in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demandhydrocarbon products that are outside of our control and are unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable.
We rely on the operation of tankers under our time chartersprocessing, transportation, marketing and ship-to-ship kits to transfer LNG between ships. The operation of ocean-going tankersstorage. Furthermore, political, litigation, and kits carries inherent risks. Thesefinancial risks include the possibility of:
may result in reduced natural disasters;
mechanical failures;
grounding, fire, explosions and collisions;
piracy;
human error; and
war and terrorism.
We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. Asgas production activities, increased liability for infrastructure damages as a result if our current equipment fails, is unavailableof climatic changes, or insufficientan impaired ability to service our LNG purchases, production,continue to operate in an economic manner. One or delivery commitments we may need to procure new equipment, which may not be available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Anymore of these resultsdevelopments could have a material adverse effect on our business, financial condition and operating results.results of operation.
The operationFossil 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 carriersfacilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is inherently risky, and an incident resulting in significant loss or environmental consequences involving an LNG vessel could harm our reputation and business.
Cargoes of LNG and our chartered vessels are at risk of being damaged or lost because of events such as:
marine disasters;
piracy;
bad weather;
mechanical failures;
environmental accidents;
grounding, fire, explosions and collisions;
human error; and
war and terrorism.
An accident involving our cargoes or anysubject to these regulations, none of our chartered vessels could result in any of the following:
death or injuryLNG facilities currently under development are subject to persons, loss of property or environmental damage;
delaysPHMSA’s jurisdiction, but regulators and governmental agencies in the deliveryother 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 cargo;
lossglobal 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 revenues;
termination of charter contracts;
governmental fines, penalties or restrictions on conducting business;
higher insurance rates;our business, 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. 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, ourfinancial position, results of operations and cash flowsflows.
Hydraulic Fracturing. Certain of our suppliers of natural gas and weakenLNG 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 financial condition. These risks also affect Hygoability to develop commercially viable LNG facilities.
Indigenous Communities. Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and GMLPnational laws. Brazil has ratified the International Labor Organization’s Indigenous and would remain relevant following the Proposed Mergers.
Our chartered vessels operating in certain jurisdictionsTribal 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 United States, now orgrant 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 future, will be subject to cabotage laws includinglocalities in which we operate, the Merchant Marine Act of 1920, as amended (the “Jones ActFederal Public Prosecutor’s Office and the National Indian Foundation (”Fundação Nacional do Índio or “FUNAI”) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities).
There are several indigenous communities that surround our operations in Brazil. Certain activitiesof 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 logistics and shipping operations, may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act, in the U.S., only vessels meeting specific national ownership and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade”. When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as finesface construction delays, increased costs, or forfeiture of any vessels or their cargo,otherwise experience adverse impacts on its business and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition. These risks also affect Hygo and GMLP and would remain relevant following the Proposed Mergers.operations.
Offshore operations.Our chartered vessels operating in international waters, now or in the future, will be subject to various international and local laws and regulations relating to protection of the environment.
Our chartered vessels’ operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our 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.
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 between 2018 and 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the governments of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S., European, U.K. and other 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. 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 FCPA, the U.K. Bribery Act and local anti-bribery laws, 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 operate present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico. Furthermore, our strategy has been, and continues to be, dependent in part on our ability to expand our operations in additional emerging markets, including in Latin America, Asia and Africa. Efforts to expand our operations in these markets could expose us to additional risks related to anti-corruption laws and regulations. Although we have adopted policies and procedures that are designed to assist us, our officers, directors, employees and other intermediaries in complying with the FCPAand other anti-corruption laws and regulations, developing, implementing and maintaining policies and procedures is a complex endeavor, particularly given the high level of complexity of these laws and regulations. There is no assurance that these policies and procedures have or 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 officers, directors, employees and other intermediaries with respect to our business or any businesses that we may be shortagesacquire, particularly in high risk jurisdictions.
Failure to comply with trade and economic sanctions laws and anti-corruption laws and regulations, including the FCPA, the U.K. Bribery Act and local anti-bribery laws, may subject us to costly and intrusive criminal and civil investigations as well as significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and controls, the imposition of LNG tankers worldwide, whichan independent compliance monitor, as well as potential personnel changes and disciplinary actions. In addition, non-compliance with such laws could constitute a breach of certain covenants in our commercial or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial or debt 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. On occasion, we also use third-party agents and other intermediaries to assist us in exploring and entering new markets and to retain business. 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. The occurrence of any of these events could have a material adverse effectimpact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We rely on ocean-going LNG tankers and freight carriers (for ISO containers) for the movement of LNG. Consequently, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, and other factors not within our control. The construction and delivery of LNG tankers require significant capital and long construction lead times, and the availability of the tankers could be delayed to the detriment of our LNG business and our customers because of:
an inadequate number of shipyards constructing LNG tankers and a backlog of orders at these shipyards;
political or economic disturbances in the countries where the tankers are being constructed; changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances at the shipyards, including as a result of the COVID-19 pandemic;
bankruptcy or other financial crisis of shipbuilders;
quality or engineering problems;
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; or
shortages of or delays in the receipt of necessary construction materials.
Changes in ocean freight capacity, which are outside our control, could negatively impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers. Material interruptions in service or stoppages in LNG transportation could adversely impact our business, results of operations, financial condition, reputation, liquidity and financial condition.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 change and be amended or strengthened over time.
Competitionapplicable sanctions, embargo and anti-corruption laws and regulations could result in the LNG industry is intense,fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and some ofconduct our competitors have greater financial, technological and other resources than we currently possess.
We operate in the highly competitive area of LNG production and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, many of which have been in operation longer than us.
Many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities in North America. We may face competition from major energy companies and others in pursuing our proposed business strategy to provide liquefaction and export products and services.business. In addition, competitors have and are developing LNG facilities in other markets, which will compete with our LNG facilities. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greatercertain financial technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.
Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. The COVID-19 pandemic and actions by OPEC have significantly impacted energy markets, and the price of oil has recently traded at historic low prices.
Potential expansion in the Caribbean and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. The success of our operations in the Caribbean is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to Caribbean customers at a lower cost than the cost to deliver other alternative energy sources.
Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean. Furthermore, some foreign suppliers of LNGinstitutions may have economicpolicies against lending or other reasonsextending credit to direct their LNG to non-Caribbean marketscompanies that have contracts with U.S. embargoed countries or from or to our competitors’ LNG facilities. Natural gas also competes with other sourcescountries identified by the U.S. government as state sponsors of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy,terrorism, 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 toaccess funding and liquidity, our customers infinancial condition and prospects.
The swaps regulatory and other provisions of the Caribbean orDodd-Frank Act and the rules adopted thereunder and other locations on a commercial basis.
Any use of hedging arrangements mayregulations, including EMIR and REMIT, could adversely affect our futureability to hedge risks associated with our business and our operating results or liquidity.and cash flows.
To reduce our exposure to fluctuationsWe have entered and may in the price, volume and timing risk associated with the purchase of natural gas, we mayfuture 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”)OTC options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to riskTitle VII of financial loss in some circumstances, including when:
expected supply is less than the amount hedged;
Dodd-Frank Act established federal regulation of the counterpartyOTC 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, contract defaultsincluding, without limitation, rules setting limits on its contractual obligations; or
there is a changethe positions in the expected differential between the underlying price in the hedging agreementcertain contracts, rules regarding aggregation of positions, requirements to clear through specific derivatives clearing organizations and actual prices received.
The use of derivatives also may require thetrading platforms, requirements for posting of cash collateral withmargins, regulatory requirements on swaps market participants. Our counterparties which can impact working capital when commodity prices change. However, we do not currently have any hedging arrangements, and failure to properly hedge our positions against changes in natural gas prices could also have a material adverse effect on our business, financial condition and operating results.
Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.
Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas. These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our Facilities. If we were to incur a material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows. There can be no assurance that we will complete the Pennsylvania Facility or be able to supply our Facilities and the CHP Plant with LNG produced at our own Liquefaction Facilities. Even if we do complete the Pennsylvania Facility, there can be no assurance that it will operate as expected or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations.
We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us.
We are dependent upon the available labor pool of skilled employees, including truck drivers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our energy-related infrastructure and to provide our customers with the highest quality service. In addition, the tightening of the transportation related labor market due to the shortage of skilled truck drivers may affect our ability to hire and retain skilled truck drivers and require us to pay increased wages. Our affiliates in the United States who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governscapital requirements set out by the Basel Committee on 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 matters as minimum wage, overtimeswaps 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 other working conditions. We are alsoaffiliates operating in Europe and the Caribbean may be subject to applicable labor regulationsthe 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 the other jurisdictionsmarket manipulation in which we operate, including Jamaica. We may face challengeswholesale energy markets, and costs in hiring, retaining and managing our Jamaican and other employee base. A shortage in the labor pool of skilled workers, particularly in Jamaica or the United States, or other general inflationary pressures or changes in applicable laws andan obligation to report certain data, as well as requiring liquid collateral. These regulations could make itsignificantly 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 difficult for us to attract and retain qualified personnelvolatile 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 andbe otherwise adversely affect our business, financial condition, operating results, liquidity and prospects.
Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The substantial majority of our anticipated revenue in 2021 will be dependent upon our assets and customers in Jamaica and Puerto Rico. Jamaica and Puerto Rico have historically experienced economic volatility and the general condition and performance of their economies, over which we have no control, may affect our business, financial condition and results of operations. Due to our current lack of asset and geographic diversification, an adverse development at the Jamaica Facilities or our San Juan Facility, in the energy industry or in the economic conditions in Jamaica or Puerto Rico, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.
We may incur impairments to long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, and decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business, or adverse actions by governmental entities, changes to regulation or legislation have in the past and could in the future lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.
A major healthWeather events such as storms and safety incident involving LNGrelated storm activity and collateral effects, or the energy industry more broadlyother disasters, accidents, catastrophes or relating to our business may lead to more stringent regulation of LNG operationssimilar events, natural or the energy business generally,manmade, such as explosions, fires, seismic events, floods or accidents, could result in greater difficultiesdamage to our facilities, liquefaction facilities, or related infrastructure, interruption of our operations or our supply chain, as well as delays or cost increases in obtaining permits, including under environmental laws,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 favorable terms,our onshore and may otherwise lead to significant liabilities and reputational damage.
Health and safety performance is criticaloffshore operations. Due to the success of all areasnature of our business. Any failureoperations, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in healthparticular with respect to fleet operations, floating offshore liquefaction units and safety performance fromother 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 may result in an event that causes personal harmcoastal 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 employees,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 persons, and/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, 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, as well as the imposition of injunctive relief and/or penalties for non-compliance with relevant regulatory requirements or litigation. Any such failure that results inand repairs could take a significant healthamount 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 safety incidentlosses. 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 costly in termsinsufficient to cover losses that may occur to our property or result from our operations.” The occurrence of potential liabilities, and may result in liabilities that exceed the limits of our insurance coverage. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain permits and approvals, and otherwise jeopardize our reputationsignificant event, or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets. Similarly, such developmentsthreat thereof, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The swaps regulatory and other provisions
Our charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, our business and our operating results and cash flows.
Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect our ability to manage certain of our risks on a cost-effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our Facilities, our CHP Plant and to secure natural gas feedstock for our Liquefaction Facilities.
The CFTC has proposed new rules setting limits on the positions in certain core futures contracts, economically equivalent futures contracts, options contracts and swaps for or linked to certain physical commodities, including natural gas, held by market participants, with limited exemptions for certain bona fide hedging and other types of transactions. The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief, until August 12, 2022, from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
Under the Dodd-Frank Act and the rules adopted thereunder, we may be required to clear through a derivatives clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain trading platforms. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for any swaps entered into to hedge our commercial risks, if we fail to qualify for that exception and have to clear such swaps through a derivatives clearing organization, we could be required to post margin with respect to such swaps, our cost of entering into and maintaining such swaps could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we may enter. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as Swap Dealers, may change the cost and availability of the swaps that we may use for hedging.
As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect initial and variation margin with respect to uncleared swaps from their counterparties that are financial end-users and certain registered Swap Dealers and Major Swap Participants. The requirements of those rules are subject to a phased-in compliance schedule, which commenced on September 1, 2016. Although we believe we will qualify as a non-financial end user for purposes of these rules, were we not to do so and have to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. In June 2011, the Basel Committee on the Banking Supervision, an international trade body comprised of senior representatives of bank supervisory authorities and central banks from 27 countries including the United States and the European Union, announced the final framework for a comprehensive set of capital and liquidity standards, commonly referred to as “Basel III.” Our counterparties that are subject to restrictions imposed by the Basel III capital requirements may increaseU.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 costU.S. government or countries identified by the U.S. government as state sponsors of terrorism.When we charter our vessels to usthird parties we conduct comprehensive due diligence of entering into swaps with themthe charterer and include prohibitions on the charterer calling on ports in countries subject to comprehensive U.S. sanctions or although not required to collect margin from us under the margin rules, require us to post collateral with themotherwise engaging in connectioncommerce with such swaps in ordercountries. However, our vessels may be sub-chartered out to offset their increased capital costsa sanctioned party or to reduce their capital costs to maintain those swapscall on their balance sheets.
The Dodd-Frank Act also imposes regulatory requirementsa sanctioned nation on swaps market participants, including Swap Dealerscharterers’ instruction, and other swaps entities as well as certainwithout our knowledge or consent.If our charterers or sub-charterers violate applicable sanctions and embargo laws and regulations on end-users of swaps, including regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to Swap Dealers and other swaps entities. Together with the Basel III capital requirements on certain swaps market participants, these regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we wereactions that do not involve us, those violations could in turn negatively affect our reputation and cause us to forgo the useincur significant costs associated with responding to any investigation into such violations.
Increasing transportation regulations may increase our costs and negatively impact our results of swapsoperations.
We are developing a transportation system specifically dedicated to hedgetransporting LNG using ISO tank containers and trucks to our risks, such as commodity price riskscustomers and facilities. This transportation system may include trucks that we encounter inor our affiliates own and operate. Any such operations our operating results and cash flows may become more volatile and could be otherwise adversely affected.
The European Market Infrastructure Regulation (“EMIR”) may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral that EMIR requires central counterparties to accept. Although we expect to qualify as a non-financial counterparty under EMIR and thus not be required to post margin under EMIR, our subsidiaries and affiliates operating in the Caribbean may stillwould be subject to increased regulatory requirements, including recordkeeping, marking to market, timely confirmations, derivatives reporting, portfolio reconciliation and dispute resolution procedures. Regulation under EMIR could significantly increase the cost of derivatives contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter. The increased trading costs and collateral costs may have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our subsidiaries and affiliates operatingvarious trucking safety regulations in the Caribbean mayvarious countries where we operate, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, 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 Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants. This classification imposes increased regulatory obligations on our subsidiaries and affiliates, includinghours of service regulations which govern the amount of time a prohibitiondriver may drive or work in any specific period, onboard black box recorder device requirements, requirements to use electric vehicles or disclose insider informationlimits on vehicle weight and size. In addition to increased costs, fines and penalties, any non-compliance or to engageviolation of these regulations, could result in market manipulation in wholesale energy markets, and an obligation to report certain data. These regulatory obligations may increase the cost of compliance for our business and if we violate these laws and regulations, we could be subject to investigation and penalties.
Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operationsuspension of our facilities could impede operations, and construction andwhich could have a material adverse effect on us.our business and consolidated results of operations and financial position.
The design, constructionCertain activities related to our logistics and operationshipping operations may constitute “coastwise trade” within the meaning of energy-related infrastructure, including our existinglaws and proposed facilities, the import and export of LNG and the transportation of natural gas, are highly regulated activities at the federal, state and local levels. Approvalsregulations of the DOE under Section 3 of the NGA, as well as several other material governmental and regulatory permits, approvals and authorizations, including under the CAA and the CWA and their state analogues, may be required in order to construct and operate an LNG facility and export LNG. Permits, approvals and authorizations obtained from the DOEU.S. and other federaljurisdictions in which we operate. Under these laws and state regulatory agencies also contain ongoing conditions,regulations, often referred to as cabotage laws, including the Jones Act in the U.S., only vessels meeting specific national ownership and additionalregistration requirements or which are subject to an exception or exemption, may be imposed. Certain federal permitting processes may triggerengage in such “coastwise trade.” When we operate or charter foreign-flagged vessels, we do so within the requirementscurrent interpretation of the National Environmental Policy Act (“NEPA”), which requires federal agenciessuch cabotage laws with respect 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 costspermitted activities for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challengesforeign-flagged vessels. Significant changes in cabotage laws or to the adequacyinterpretation of such laws in the NEPA analysis, whichplaces where we operate 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 NEPA regulations; however, the regulations, which would become effective 60 days after publication, have been challengedability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in court, and thus the impacts of any such revisions are uncertain at this time. 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. Becausethose waters. If we do not believe thatcontinue 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 may 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 is jurisdictional, we providedand 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 reply to FERC on July 20, 2020 and requested that FERC act expeditiously. The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved, is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending. We do not know if or when FERCoperations will respondrequire agreements with ports proximate to our reply, orfacilities capable of handling the outcometransload of any such response. Although FERC has civil penalty authority andLNG direct from our occupying vessel to our transportation assets. We may not own the authority to authorize the siting, construction, and operation of jurisdictional LNGland on which these facilities are located. As a result, we do not know, nor has FERC indicated, what remedy FERC may require if FERC determines that our San Juan Facility isare subject to FERC’s Section 3 jurisdiction. In addition, we may be subjectthe possibility of increased costs to additional requirements and new regulations by relevant authorities in Jamaica, Mexico, Ireland, Nicaragua, Brazil or other jurisdictions, including with respect toretain necessary land use approvalsrights as well as applicable law and permits needed to construct and operate our facilities and sell LNG and power.
We cannot control the outcome of any review and approval process,regulations, including whether or when any such permits approvals and authorizations willfrom governmental agencies or third parties. If we were to lose these rights or be obtained, the terms of their issuance, or possible appeals or other potential interventions by third parties thatrequired to relocate, we would not be able to continue our operations at those sites and our business could interfere with our ability to obtainbe materially and maintain such permits, approvals and authorizations or the terms thereof.adversely affected. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and maintain such permits,land use approvals and authorizations on favorable terms, we may not be able to recoverconstruct and operate our investmentassets 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 our projectsthis area are rapidly evolving. We have announced, and may be subject to financial penalties underin the future announce, sustainability-focused goals, initiatives, investments and partnerships. These initiatives, aspirations, targets or objectives reflect our customercurrent plans and other agreements. Many of these permits, approvalsaspirations and authorizations require public notice and comment before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations on favorable terms, orare not guarantees that we will be able to obtain themachieve them. Our efforts to accomplish and accurately report on a timely basis,these initiatives and failure to obtaingoals present numerous operational, regulatory, reputational, financial, legal, and maintainother risks, any of these permits, approvals or authorizationswhich could have a material adverse effectnegative 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 results, liquiditycosts. Moreover, there can be no assurance that such procedures and prospects. Moreover, manycontrols will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of these permits, approvalssensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and authorizationsour 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 administrativethe inherent risks associated with construction of energy-related infrastructure, LNG, natural gas, power and judicial challenges,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 can delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty.
Existing and future environmental, health and safety laws and regulations could result in increased compliance costssignificant delays in commencement or additional operating costs interruptions of operations and/or construction costsresult in damage to or destruction of the facilities, liquefaction facilities and restrictions.assets or damage to persons and property. We do not, nor do we intend to, maintain insurance
Ouragainst all of these risks and losses. In particular, we do not generally carry business is nowinterruption insurance or political risk insurance with respect to political disruption in the countries in which we operate and willthat may in the future be subject to extensive federal, stateexperience significant political volatility. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and local laws and regulations both in the United States and in other jurisdictions where we operate. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is subject to these regulations, none of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but state and local regulators can impose similar siting, design, construction and operational requirements. In addition, the U.S. Coast Guard regulations require certain security and response plans, protocols and trainings to mitigate and reduce the risk of intentionallosses or accidental impacts to energy transportation and production infrastructure located in certain domestic ports.
Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up any such hazardous substances that may be released into the environment at or from our facilities and for any resulting damage to natural resources.
Many of these laws and regulations, such as the CAA and the CWA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities, and require us to obtain and maintain permits and provide governmental authorities with accessdelays to our facilities for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Relevant local authorities may also require us to obtain and maintain permits associated with the construction and operation of our facilities, including with respect to land use approvals. Failure to comply with these laws and regulations could lead to substantial liabilities, fines and penalties or capital expenditures related to pollution control equipment and restrictions or curtailment of our operations,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.
Other future legislationWe 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.In addition, jurisdiction-specific employment, labor, and subcontracting laws may affect contracting strategies and impact construction and operations. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations, could cause additional expenditures, restrictionsmake it more difficult for us to attract and delaysretain 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 our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. In October 2017, the U.S. Government Accountability Office issuedapplicable labor legislation. As a legal determination that a 2013 interagency guidance document was a “rule”result, we are subject to the Congressional Review Act (“CRA”). This legal determinationrisk of labor disputes, strikes, work stoppages and other labor-relations matters. We could openexperience a broader setdisruption 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, reinterpretedoperations or additional laws and regulations that result in increased compliancehigher ongoing labor costs, or additional operating or construction costs and restrictionswhich could have a material adverse effect on our business, contracts, financial condition, operating results cash flow, liquidity and prospects.
Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associatedfinancial condition. Future negotiations 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, regulationsunions or other regulatory initiatives, including GHG capcertified bargaining representatives could divert management attention and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement, effective February 19, 2021, and other countries where we operate or plan to operate, including Jamaica, Ireland, Mexico, and Nicaragua, have signed or acceded to this agreement. However, the scope of future climate and GHG emissions-focused regulatory requirements, if any, remain uncertain.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States. For example, based in part on the publicized climate plan and pledges by President Biden, theredisrupt operations, which may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. For example, although the U.S. has withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris Agreement and calling for for the federal government to begin formulating the United States nationally determined emissions reductions goal under the agreement with the U.S. recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals.
Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.
The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs,operating expenses and thereby reduce demand for or erode value for, the natural gas that we processlower net income. Moreover, future agreements with unionized and market. Additionally, political, litigation, and financial risksnon-unionized employees 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 effectbe on our business, financial condition and results of operation.
The adoption and implementation of any U.S. federal, state or local regulations or foreign regulations imposing obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for natural gas and natural gas products. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon productsterms that are deemednot as attractive as our current agreements or comparable to contributeagreements entered into by our competitors. Labor unions could also seek to GHGs,organize some or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows.
Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change.
Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and managementall of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.
Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several states have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition to state laws, some local municipalities have adopted or considered adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular.
Hydraulic fracturing activities are typically regulated at the state level, but federal agencies have asserted regulatory authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Federal and state legislatures and agencies may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing). Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.
We are subject to numerous governmental export laws and trade and economic sanctions laws and regulations. Our failure to comply with such laws and regulations could subject us to liability and have a material adverse impact on our business, results of operations or financial condition.
We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Ireland, Mexico, Nicaragua and the other countries in which we seek to do business. We must also comply with U.S. trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. Although we take precautions to comply with all such laws and regulations, violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations or otherwise, we may face an array of issues, including, but not limited to: having to abandon the related project, being unable to recuperate prior invested time and capital or being subject to law suits, investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.
We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently, or may in the future, operate may present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Mexico and Puerto Rico. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, it is highly challenging to adopt policies and procedures that ensure compliance in all respects with the FCPA, particularly in high-risk jurisdictions. Developing and implementing policies and procedures is a complex endeavor. There is no assurance that these policies and procedures will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire.
If we are not in compliance with anti-corruption laws and regulations, including the FCPA, we may be subject to costly and intrusive criminal and civil investigations as well significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, as well as potential personnel change and disciplinary actions. In addition, non-compliance with anti-corruption laws could constitute a breach of certain covenants in operational or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, liquidity and future business prospects.
In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries, such as customs agents. Violations of applicable import, export, trade and economic sanctions laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with export control and economic sanctions laws and regulations in the future. In such event of non-compliance, our business and results of operations could be adversely impacted.
Risks Related to the Jurisdictions in Which We Operate
We are currently highly dependent uponsubject to the economic, political, social and other conditions and developments in the Caribbean, particularly Jamaica, Puerto Rico and the other jurisdictions in which we operate.
We currently conduct a meaningful portionOur projects are located in 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 businessstrategy consists in Jamaica and Puerto Rico.seeking to expand our operations to other jurisdictions. As a result, our currentprojects, operations, business, results of operations, financial condition and prospects are materially dependent upon economic, political, social and other conditions and developments in Jamaica and Puerto Rico.
We currently have interests and operations in Jamaica and the United States (including Puerto Rico) and currently intend to expand into additional markets in the Caribbean, Mexico, Ireland, Nicaragua and other geographies, and such interests are subject to governmental regulation in each market. The governments in these markets differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. To the extent that our operations depend on governmental approval and regulatory decisions, the operations may be adversely affected by changes in the political structure or government representatives in each of the markets in which we operate. Recent political, security and economic changes have resulted in political and regulatory uncertainty in certain countries in which we operate or may pursue operations.jurisdictions. Some of these marketscountries have experienced political, security, and social economic instability in the recent past and may experience instability in the future. Infuture, including 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 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 and/or Puerto Rico Public - Private Partnerships Authority (P3A) could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship withthat one of our subsidiaries, as agent of PREPA, could change given PREPA’s award for its transmission and distribution system.their role as operator of PREPA's legacy generation assets. Additionally, 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. In addition, we cannot predict how local sentiment and support for our subsidiaries’ operations in Puerto Rico could change now that Puerto Rico’s power generation systems have been privatized. Should our operations face material local opposition, it could materially adversely affect our ability to 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. 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. 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.
Any slowdown or contraction affectingFurthermore, some of the local economy in a jurisdictionregions in which we operate could negatively affecthave been subject to significant levels of terrorist activity and social unrest, particularly in the abilityshipping and maritime industries. Past political conflicts in certain of our customersthese regions have included attacks on vessels, mining of waterways and other efforts to purchase LNG, natural gas, steam or power from us ordisrupt shipping in the area. In addition to fulfill their obligations under their contracts with us. Ifacts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Tariffs, trade embargoes and other economic sanctions by the economy in Jamaica, Puerto RicoUnited States or other jurisdictionscountries against countries in which we operate worsens because of, for example:
lower economic activity, includingthe 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 COVID-19 pandemicU.S. or other governments, which has significantly affected Jamaica’scould 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 jurisdictions’ tourism industries;
change in applicable laws;
an increase in oil, natural gasinstability or petrochemical prices;
devaluation of the applicable currency;
higher inflation;adverse conditions or
an increase in domestic interest rates,
then our business, results of operations, financial condition and prospects may also be significantly affected by actions taken by the government developments in the jurisdictions in which we operate. The COVID-19 pandemic has resulted in lower economic activity andoperate, could have a decrease in oil prices worldwide. Certain of the jurisdictions in which we operate have recently restricted travel, implemented workforce pressures, and experienced reduced business development, travel, hospitality and tourism due to COVID-19. Caribbean governments traditionally have played a central role in the economy and continue to exercise significant influence over many aspects of it. They may make changes in policy, or new laws or regulations may be enacted or promulgated, relating to, for example, monetary policy, taxation, exchange controls, interest rates, regulation of banking and financial services and other industries, government budgeting and public sector financing. These and other future developments in the Jamaican economy or in the governmental policies in our Caribbean markets may reduce demand for our products and adversely affectmaterial adverse effect on our business, contracts, financial condition, operating results, of operations orcash flow, liquidity and prospects.
For example, JPS and SJPC are subject to the mandate of the OUR. The OUR regulates the amount of money that power utilities in Jamaica, including JPS and SJPC, can charge their customers. Though the OUR cannot impact the fixed price we charge our customers for LNG, pricing regulations by the OUR and other similar regulators could negatively impact our customers’ ability to perform their obligations under our GSAs and, in the case of JPS, the PPA, which could adversely affect our business, financial condition, results of operations or prospects.
Our development activities and future operations in Nicaragua may be materially affected by political, economic and other uncertainties.
Nicaragua has recently experienced political and economic challenges. Specifically, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua. In 2018, 2019 and 2020, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the government of Nicaragua and Venezuela. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to: having to suspend our development or operations on a temporary or permanent basis, being unable to recuperate prior invested time and capital or being subject to lawsuits, investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties. There is also a risk of civil unrest, strikes or political turmoil in Nicaragua, and the outcome of any such unrest cannot be predicted.
Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.
OurWhile our consolidated financial statements are presented in U.S. dollars.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 willcould 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.
A portion of our cash flowsdollars and expenses may in the future be incurred in currencies other than the U.S. dollar. Our material counterparties’ cash flowselect to intervene by implementing exchange rate regimes, including sudden devaluations, periodic mini devaluations, exchange controls, dual exchange rate markets and expenses may be incurred in currencies other than the U.S. dollar.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 the Jamaican dollarthese currencies against the U.S. dollar or other currencies could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.
We have operations in multiple jurisdictions and may expand our operations to additional jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated.
We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income and operations related to those jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.
Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.
A change in tax laws in any country in which we operate could adversely affect us.
Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings.
Risks Related to Hygo’s Business Activities
Hygo has commenced commercial operations at one facility. Hygo’s other planned facilities are in various stages of contracting customers, construction, permitting and commissioning. There can be no assurance that Hygo’s planned facilities will commence operations timely, or at all.
Hygo’s Sergipe Facility commenced commercial operations in March 2020. However, Hygo has not yet commenced commercial operations or entered into binding construction contracts or obtained all necessary environmental, regulatory, construction and zoning permissions for any of its other facilities. Hygo may convert the Golar Celsius or the Golar Penguin into a FSRU to service its Barcarena Facility, but has not yet reached final investment decision for the deployment and conversion of such vessel. In addition, although Hygo has been awarded environmental and regulatory licenses for its Santa Catarina Facility, Hygo has not secured any commercial projects nor obtained all remaining necessary approvals. There can be no assurance that Hygo will be able to enter into the contracts required for the development of Hygo facilities on commercially favorable terms, if at all, or that Hygo will be able to obtain all of the environmental, regulatory, construction and zoning permissions Hygo needs in Brazil and elsewhere.
In particular, Hygo will require agreements with ports proximate to its facilities capable of handling the transload of LNG direct from its occupying vessel to its transportation assets. If Hygo is unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, Hygo may not be able to construct and operate these assets as anticipated, or at all. In addition, to develop future projects Hygo will, in many cases, have to secure the use of suitable vessels and, as required, convert them. Finally, the construction of facilities is inherently subject to the risks of cost overruns and delays. For example, the construction of Hygo’s Sergipe Power Plant experienced a two-month delay related to the installation of various offshore equipment.
If Hygo is unable to construct, commission and operate all of its facilities, or, when and if constructed, they do not accomplish their goals, or if Hygo experiences delays or cost overruns in construction, assuming the Hygo Merger has been consummated, our business, operating results, cash flows and liquidity could be materially and adversely affected. Expenses related to Hygo’s pursuit of contracts and regulatory approvals related to Hygo’s facilities still under development may be significant and will be incurred by Hygo regardless of whether these assets are ultimately constructed and operational.
There is no existing market in Brazil for the sale of LNG as a fuel source for trucking or vehicles generally. BR Distribuidora does not currently distribute, nor is obligated to commence distribution of, LNG through its distribution and fuel centers. Additionally, BR Distribuidora is not obligated to, and may not, convert any portion of its existing fleet of diesel trucks. Moreover, Hygo’s agreement with BR Distribuidora is subject to regulatory approval and other uncertainties. Hygo may be unable to realize the anticipated benefits of this partnership.
The transportation industry in Brazil currently relies on traditional fuels such as gasoline and diesel. And although there is wide acknowledgement in the industry that LNG represents a less expensive and more environmentally friendly alternative to these fuels, no significant portion of the transportation industry is currently utilizing LNG. Hygo cannot predict when, or even if, any meaningful portion of the transportation industry within Brazil will convert to LNG powered vehicles. Hygo’s agreement with Petrobras Distribuidora S.A. (“BR Distribuidora”) does not contractually obligate it to convert any portion of its fleet of diesel trucks to LNG-powered vehicles. Unless and until there is a significant conversion to LNG-powered vehicles within Brazil, Hygo will not realize the anticipated benefits of Hygo’s partnership, which could adversely impact Hygo’s, and assuming the consummation of the Merger, our future revenues.
In addition, Hygo’s activities with respect to the sale of LNG are subject to the approval of other regulatory authorities, including Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (“ANP”). There can be no assurance as to whether regulatory approvals will be received or that they will be granted in a timely manner. Until Hygo receives these approvals, Hygo will be unable to make sales through BR Distribuidora’s distribution channels or other channels. Accordingly, Hygo has not yet made any sales pursuant to this arrangement.
Brazil and the Netherlands are conducting a joint investigation into allegations against Hygo’s former Chief Executive Officer, including allegations of improper payments made in Brazil. The outcome of this investigation could cause Hygo reputational harm or have a material adverse effect on Hygo’s business.
On September 23, 2020, Eduardo Antonello, Hygo’s former Chief Executive Officer, was named in a joint corruption investigation in Brazil and the Netherlands. Mauricio Carvalho, the majority shareholder of Evolution Power Partners S.A. (“Evolution”), Hygo’s joint venture partner in Centrais Elétricas Barcarena S.A. (“CELBA”), was also named in the investigation. In connection with the investigation, on September 23, 2020, Brazilian federal police executed search warrants on Hygo’s office in Brazil and certain of its joint ventures, and seized documents and electronic records and devices belonging to those entities relating to Mr. Antonello, Hygo and its joint ventures. On September 25, 2020, Hygo’s board of directors initiated an internal review with respect to Mr. Antonello’s conduct with respect to Hygo and its joint ventures. The board of directors was assisted in this review by outside counsel and accounting advisors. The review included forensic accounting work, review of certain contracts, interviews with certain company personnel and representatives, and review of internal audit material, certain corporate credit card expenses and Hygo’s anti-corruption policies. The board of directors of Hygo and its advisors did not identify any evidence establishing bribery or other corrupt conduct involving Hygo. In October 2020, before the review was completed, Mr. Antonello resigned as Chief Executive Officer and was replaced by Paul Hanrahan, who also joined the Hygo board of directors. The Hygo board of directors will continue its oversight and review of compliance procedures in accordance with the ethical and corporate governance standards established by applicable law.
The investigation is ongoing and Hygo will continue to monitor its progress. While Hygo has conducted its own internal investigation and did not identify evidence establishing bribery or other corrupt conduct involving Hygo, Hygo cannot predict when the investigation will be completed or the results of the investigation, including whether any litigation will arise out of, relating to, or in connection with the investigation or the extent of the impact that the investigation or any such litigation may have on Hygo’s business. Publicity or other events associating with Mr. Antonello or the investigation, regardless of their foundation or accuracy, could adversely affect Hygo’s and our reputation and Hygo’s ability to conduct Hygo’s business in Brazil and other jurisdictions. For example, Hygo may experience difficulties participating in public auctions and in some cases, may be disqualified, as was the case with respect to Hygo’s bid to lease Petrobras’s Bahìa Regasification Terminal (the “Bahìa Facility”). On September 30, 2020, Hygo’s subsidiary, Golar Power Comercializadora de Gás Natural Ltda. (“Golar Power Comercializadora”), participated in a public competitive bid process sponsored by Petrobras for the lease of the Bahìa Terminal. Although Golar Power Comercializadora was the only qualifying participant to submit a bid, in October 2020, Petrobras notified all participants that Golar Power Comercializadora was disqualified. Golar Power Comercializadora subsequently filed an administrative appeal before the Petrobras Bid Committee challenging the final result of the competitive process. In December 2020, Golar Power Comercializadora lost the appeal and was not awarded the bid for the Bahìa Facility.
Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various factors.
Hygo currently anticipates that a major source of Hygo’s earnings will be cash distributions from Hygo’s operating subsidiaries and joint ventures. The amount of cash that Hygo’s operating subsidiaries and joint ventures can distribute each quarter to their owners, including Hygo, principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things:
the amount of LNG or natural gas sold to customers;
market price of LNG;
the level of dispatch of the Sergipe Power Plant and Hygo’s future power plants;
any restrictions on the payment of distributions contained in covenants in their financing arrangements and joint venture agreements;
the levels of investments in each of Hygo’s operating subsidiaries, which may be limited and disparate;
the levels of operating expenses, maintenance expenses and general and administrative expenses;
regulatory action affecting: (i) the supply of, or demand for electricity in Brazil, (ii) operating costs and operating flexibility; and
prevailing economic conditions.
Hygo’s facilities may be impacted by operational issues and delays. For example, in September 2020, the Sergipe Power Plant experienced transformer failures impacting its ability to dispatch at 100%, which have not yet been resolved. In addition, Hygo does not wholly own all of its operating subsidiaries and joint ventures. As a result, if such operating subsidiaries and joint ventures make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners.
Hygo may not be able to fully utilize the capacity of its facilities, which could impact its future revenues and materially harm Hygo’s business, financial condition and operating results.
Hygo’s FSRU facilities have significant excess capacity that is currently not dedicated to a particular anchor customer. Part of Hygo’s business strategy is to utilize undedicated excess capacity of Hygo’s FSRU facilities to serve additional downstream customers in the regions in which Hygo operates. However, Hygo has not secured, and Hygo may be unable to secure, commitments for all of its excess capacity. Factors which could cause Hygo to contract less than full capacity include difficulties in negotiations with potential counterparties and factors outside of its control such as the price of and demand for LNG. Failure to secure commitments for less than full capacity could impact Hygo’s future revenues and materially harm Hygo’s business, financial condition and operating results.
In addition, the operator of the Sergipe Facility, Centrais Elétricas de Sergipe S.A. (“CELSE”) (which is an entity wholly owned by Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), a 50/50 joint venture between Hygo and Ebrasil Energia Ltda. (“Ebrasil”)), has the right to utilize 100% of the capacity at Hygo’s Sergipe Facility pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Facility, Hygo will need the consent of CELSE and the senior lenders under CELSE’s financing arrangements. If Hygo is unable to obtain the necessary consents to utilize the excess capacity of the Sergipe Facility, Hygo’s business, financial condition and operating results may be adversely affected.
Failure of LNG to be a competitive source of energy in the markets in which Hygo operates, and seeks to operate, could adversely affect Hygo’s expansion strategy.
Hygo’s operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which Hygo operates. In particular, hydroelectric power generation is the predominant source of electricity in Brazil and LNG is one of several other energy sources used to supplement hydroelectric generation. Potential expansion in other parts of world where Hygo may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. Likewise, recent declines in the cost of crude oil, if sustained, will make crude oil and its derivatives a more competitive fuel source to LNG.
As a result of these and other factors, natural gas may not be a competitive source of energy in the markets Hygo intends to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect Hygo’s ability to deliver LNG or natural gas to Hygo’s customers or other locations on a commercial basis.
CELSE is subject to risk of loss or damage to LNG that is processed and/or stored at its FSRUs and transported via pipeline.
LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. For the period of time during which LNG is stored on an FSRU or is dispatched to a pipeline, CELSE, in the case of the Sergipe Facility, bears the risk of loss or damage to all such LNG. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at the Sergipe Power Plant. If CELSE cannot generate energy at the Sergipe Power Plant by burning natural gas, Hygo’s, and, after consummation of the Hygo Merger, our revenues, financial condition and results of operations may be materially and adversely affected.
Hygo has a limited operating history and anticipates significant capital expenditures.
Hygo commenced operations in May 2016 and has a limited operating history and track record. As a result, its prior operating history and historical consolidated financial statements may not be a reliable basis for evaluating its business prospects. In addition, Hygo has historically derived its revenues from the operation of its vessels on short-term charters, but Hygo expects the majority of its future revenues to be derived from its LNG-to-power projects. Hygo’s strategy may not be successful, and if unsuccessful, it may be unable to modify it in a timely and successful manner. Hygo cannot give any assurance that it will be able to implement its strategy on a timely basis, if at all, or achieve its internal model or that its assumptions will be accurate. Hygo’s limited history also means that it continues to develop and implement various policies and procedures including those related to data privacy and other matters. Hygo will need to continue to build its team to implement its strategies.
Hygo will continue to incur significant capital and operating expenditures while it develops its network of downstream LNG infrastructure, including for the completion of the Barcarena Facility, the Santa Catarina Facility and other projects in Brazil currently under construction, as well as other future projects. Hygo will need to invest significant amounts of additional capital to implement its strategy. Hygo has not completed constructing all of its facilities and its strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Hygo’s future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under its customer contracts in relation to the incurrence of project and operating expenses. Hygo’s ability to generate any positive operating cash flow and achieve profitability in the future is dependent on, among other things, its ability to successfully and timely complete necessary infrastructure, including its Barcarena and Santa Catarina Terminals and other projects in Brazil currently under construction, and fulfill its delivery obligations under its customer contracts.
Hygo’s power generation projects may depend on the construction and operation of transmission and interconnection facilities by third parties.
Hygo’s power generation projects must interconnect to Brazil’s transmission system and such projects may depend on the completion of new lines and/or increases in the capacity of existing facilities by the applicable power transmission concessionaires in order to interconnect and become fully operational. Delays from such concessionaires in the completion of the necessary interconnection and associated facilities may affect the ability of Hygo’s power generation projects to start commercial operation and/or fulfill power delivery commitments under the PPAs.
Hygo’s ability to dispatch electricity from its power plants is dependent upon hydrological and other grid conditions in Brazil.
Historically, Brazil’s electricity generation has been dominated by hydroelectricity plants. There are substantial seasonal variations in monthly and annual flows to the plants, which depend fundamentally on the volume of rain that falls in each rainy season. When hydrological conditions are poor, the National Electricity System Operator (Operador Nacional do Sistema, or “ONS”) dispatches thermoelectric power plants, including those that Hygo operates, to top up hydroelectric generation and maintain the electricity supply level.
The ONS Grid Code allows the ONS to dispatch thermoelectric power plants for the following reasons or under the following circumstances:
when marginal operation cost is the same as the variable unit cost of such power plant;
due to inflexibility or necessity of the generator;
when dispatch of such power plant is needed in order to maintain the stability of the system;
as determined by the Energy Industry Monitoring Committee where extraordinary circumstances exist;
due to accelerated and/or replacement generation as proposed by the generator in order to make up for the unavailability of fuel; and
for purposes of exportation of power to foreign markets.
As a result, the amount of electricity generated by thermoelectric power plants, including Hygo’s power plants that are already contracted and its power plants under development, can vary significantly in response to the hydrological and other grid conditions in Brazil. If Hygo’s power plants are not dispatched or are dispatched at levels lower than expected, its operations and financial results may be adversely affected.
Hygo may not be profitable for an indeterminate period of time.
Hygo has a limited operating history and did not commence revenue-generating activities until 2016, and therefore did not achieve profitability as of December 31, 2020. Hygo will need to make a significant capital investment to construct and begin operations of the Barcarena Terminal, the Santa Catarina Terminal, its downstream distribution hubs and its other LNG-to-power projects in Brazil, and Hygo will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. Hygo also expects to make significant expenditures and investments in identifying, acquiring and/or developing other future projects. Hygo also expects to incur significant expenses in connection with the launch and growth of its business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. Hygo will need to raise significant additional debt and/or equity capital to achieve its goals. Hygo may not be able to achieve profitability, and if it does, Hygo cannot assure you that it would be able to sustain such profitability in the future.
Hygo’s operational and consolidated financial results are partially dependent on the results of the joint ventures, affiliates and special purpose entities in which it invests.
Hygo conducts its business mainly through its operating subsidiaries. In addition, Hygo and its subsidiaries conduct some of their business through joint venture and other special purpose entities, which are created specifically to participate in public auctions for enterprises in the generation and transmission segments. Hygo’s ability to meet its financial obligations is therefore related in part to the cash flow and earnings of its subsidiaries and joint ventures and the distribution or other transfers of earnings to Hygo in the form of dividends, loans or other advances and payments that are governed by various joint venture financing and operating arrangements.
Hygo has entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict its operational and corporate flexibility.
Hygo entered into joint ventures to acquire and develop LNG infrastructure projects and may in the future enter into additional joint venture arrangements with third parties. As Hygo does not operate the assets owned by these joint ventures, its control over their operations is limited by provisions of the agreements it has entered into with its joint venture partners and by its percentage ownership in such joint ventures. Because Hygo does not control all of the decisions of its joint ventures, it may be difficult or impossible for Hygo to cause the joint venture to take actions that Hygo believes would be in its or the joint venture’s best interests. For example, Hygo cannot unilaterally cause the distribution of cash by its joint ventures. Additionally, as the joint ventures are separate legal entities, any right Hygo may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities and trade creditors). Moreover, joint venture arrangements involve various risks and uncertainties, such as committing Hygo to fund operating and/or capital expenditures, the timing and amount of which it may not control, and its joint venture partners may not satisfy their financial obligations to the joint venture. Hygo’s results of operations depend on the performance of these joint ventures and their ability to distribute funds to Hygo, and Hygo may be unable to control the amount of cash it will receive from their operations or the timing of capital expenditures, which could adversely affect its financial condition.
Hygo may guarantee the indebtedness of its joint ventures and/or affiliates.
Hygo may provide guarantees to certain banks with respect to commercial bank indebtedness of its joint ventures and/or affiliates. Failure by any of its joint ventures, equity method investees and/or affiliate to service their debt requirements and comply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to an event of default under the related loan agreement. As a result, if Hygo’s joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to repay the outstanding borrowings, the relevant lenders may foreclose their liens on the vessels securing the loans or seek repayment of the loan from Hygo, or both. Either of these possibilities could have a material adverse effect on Hygo’s business. Further, by virtue of Hygo’s guarantees with respect to Hygo’s joint ventures and/or affiliates, this may reduce its ability to gain future credit from certain lenders.
Hygo is dependent upon GLNG and its affiliates for the operation and maintenance of its vessels.
Each of Hygo’s vessels is operated and maintained by GLNG or its affiliates pursuant to ship management agreements. These agreements are the result of arms-length negotiations and subject to change. In addition, we expect to enter into management agreements with GLNG or its affiliates with respect to Hygo's vessels concurrently with the closing of the Hygo Merger. If GLNG or any of its affiliates that provide services to Hygo fails to perform these services satisfactorily or the terms of the ship management agreements change now or after the consummation of the Proposed Mergers, it could have a material adverse effect on Hygo’s or, after the consummation of the Hygo Merger, our, business, results of operations and financial condition.
Hygo may not be able to purchase or receive physical delivery of natural gas or LNG in sufficient quantities and/or at economically attractive prices to supply the Sergipe Power Plant and satisfy its delivery obligations under the PPAs, which could have a material adverse effect on Hygo.
Under the PPAs related to the Sergipe Power Plant and its other LNG-to-power facilities, Hygo is required to deliver power, which also requires Hygo to obtain sufficient amounts of LNG. However, Hygo may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may subject Hygo to certain penalties and provide its counterparties with the right to terminate their PPAs. With respect to the Sergipe Power Plant, Hygo has entered into a supply agreement with Ocean LNG, an affiliate of Qatar Petroleum. If Ocean LNG fails to deliver sufficient LNG to Sergipe, Hygo would be forced to purchase LNG on the spot market, which may be on less favorable terms. In addition, price fluctuations in natural gas and LNG may make it expensive or uneconomical for Hygo to acquire adequate supply of these items for its other customers.
Hygo is dependent upon third party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from its tankers and energy-related infrastructure. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, Hygo’s ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing its revenues. Additionally, under tanker charters, Hygo will be obligated to make payments for its chartered tankers regardless of use. Hygo may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity it has purchased. If any third parties were to default on their obligations under Hygo’s contracts or seek bankruptcy protection, Hygo may not be able to purchase or receive a sufficient quantity of natural gas in order to supply the Sergipe Power Plant and satisfy its delivery obligations under its PPAs. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported to Hygo’s facilities could have a material adverse effect on its business, financial condition, operating results, cash flow, liquidity and prospects.
Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third party LNG suppliers and shippers negatively impacts Hygo’s ability to purchase a sufficient amount of LNG or significantly increases its costs for purchasing LNG, its business, operating results, cash flows and liquidity could be materially and adversely affected.
Under certain circumstances, Hygo may be required to make payments under its gas supply agreements.
If Hygo fails to take delivery of contracted volumes under its gas supply agreements, it may be required to make payments to counterparties under such agreements. For example, CELSE entered into a 25-year LNG supply agreement with Ocean LNG for the supply of LNG to the Sergipe Terminal. Pursuant to the terms of the Sergipe Supply Agreement, CELSE is required to take delivery of a specified base quantity of LNG each year, subject to certain adjustments. If CELSE takes less than the full number of scheduled cargoes per year under the Sergipe Supply Agreement, CELSE will be required to pay Ocean LNG a cancellation fee per cargo according to a formula based on the number of the cargoes not taken, subject to a cap over every five-year period and the full 25 year term.
Hygo’s current lack of asset and geographic diversification could have an adverse effect on its business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The substantial majority of Hygo’s anticipated revenue in the future will be dependent upon its assets and customers in Brazil. Brazil has historically experienced economic volatility and the general condition and performance of the Brazilian economy, over which Hygo has no control, may affect its business, financial condition and results of operations. Due to its current lack of asset and geographic diversification, an adverse development at any of its facilities in Brazil, in the energy industry or in the economic conditions in Brazil, would have a significantly greater impact on Hygo’s financial condition and operating results than if it maintained more diverse assets and operating areas.
Hygo’s operations could be limited or restricted in order to comply with protections for indigenous populations located in the areas in which it operates, and could also be adversely impacted by any changes in Brazilian law to comply with certain requirements embodied in international treaties and other laws related to indigenous communities.
Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. There are several indigenous communities that surround its operations in Brazil. Hygo has entered into agreements with some of these communities that mainly provide for the use of their land for its operations, and negotiations with other such communities are ongoing. In the event that Hygo is unable to reach an agreement with indigenous communities, that its relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to Hygo’s operations, it could have a material adverse effect on Hygo’s business and results of operations.
Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which is grounded on the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). ILO Convention 169 sets forth that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations such as are required for Hygo’s operations, are consulted through appropriate procedures and through their representative institutions. ILO Convention 169 further states that the consultation must be undertaken aiming at achieving an agreement or consent to the proposed legislative or administrative measures.
Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for Hygo’s operations, Hygo is required to comply with the requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: the National Congress (in specific cases), the Federal Public Prosecutor’s Office and the National Indian Foundation (Fundação Nacional do Índio or FUNAI) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities). If Hygo is not able to timely obtain the necessary authorizations or obtain them on favorable terms for its operations in areas where indigenous communities reside, Hygo could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.
Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact its operations. For example, in February 2020, the Interamerican Court of Human Rights (“IACtHR”) found that Argentina had not taken adequate steps, in law or action, to ensure the consulting of indigenous communities and obtaining those communities’ free prior and informed consent for a project impacting their territories. IACtHR further found that Argentina had thus violated the ACHR due to infringements on the indigenous communities’ rights to property, cultural identity, a healthy environment, and adequate food and water by failing to take effective measures to stop harmful, third-party activities on the indigenous communities’ traditional land. As a result, IACtHR ordered Argentina, among other things, to achieve the demarcation and grant of title to the indigenous communities over their territory and the removal of the third-parties from the indigenous territory. Hygo cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact its existing development agreements or its negotiations for outstanding development agreements with indigenous communities in the areas in which it operates. However, if the consultations with indigenous communities potentially impacted by Hygo’s operations are found to be insufficient, Hygo could experience a material adverse impact to its business and results of operations.
Hygo is subject to comprehensive regulation of its business, which fundamentally affects its financial performance.
Hygo’s business is subject to extensive regulation by various Brazilian regulatory authorities, particularly Agência Nacional de Energia Elétrica (“ANEEL”), ANP and Agência Nacional de Transportes Aquaviários (“ANTAQ”). ANEEL regulates and oversees various aspects of Hygo’s business and establishes its tariffs. If Hygo is obligated by ANEEL to make additional and unexpected capital investments and is not allowed to adjust its tariffs accordingly, if ANEEL does not authorize the recovery of all costs or if ANEEL modifies the regulations related to tariff adjustments, Hygo may be adversely affected. ANP regulates the import and export of LNG and the transportation and distribution of natural gas activities, including Hygo’s downstream distribution business. ANTAQ regulates and oversees port activities in Brazil.
In addition, both the implementation of Hygo’s strategy for growth and its ordinary business may be adversely affected by governmental actions such as changes to current legislation, the termination of federal and state concession programs, creation of more rigid criteria for qualification in public energy auctions, or a delay in the revision and implementation of new annual tariffs.
If regulatory changes require Hygo to conduct its business in a manner substantially different from its current operations, Hygo’s operations, financial results and its capacity to fulfill its contractual obligations may be adversely affected.
CELSE and CELBA could be penalized by ANEEL for failing to comply with the terms of their respective authorizations and applicable legislation and CELSE and CELBA may not recover the full value of their respective investments if such authorizations are terminated.
CELSE and CELBA will carry out their respective power generation activities in accordance with the authorizations granted by the Brazilian government through the MME (the ‘‘MME Authorizations”). CELSE’s authorization expires in November 2050, and CELBA’s authorization, which is in the process of being granted, is expected to expire in 2055. ANEEL may impose penalties on CELSE and CELBA if they fail to comply with any provision of the MME Authorizations or with the legislation and regulations applicable to the Brazilian power industry. Depending on the extent of the non-compliance, these penalties could include:
warnings;
substantial fines (in some cases up to 2% of gross revenues arising from the generation activity in the 12-month period immediately preceding the assessment);
prohibition on operations;
bans on the construction of new facilities or the acquisition of new projects;
restrictions on the operation of existing facilities and projects; or
restrictions on operations (including the exclusion from participating in upcoming auctions), temporary suspension of participation in auctions and bidding processes for new concessions and authorizations.
ANEEL may also terminate the MME Authorizations prior to their expiration in the event that CELSE or CELBA fails to comply with the provisions of the MME Authorizations, is declared bankrupt or is dissolved. In the event of non-compliance by CELSE and/or CELBA, ANEEL may also impose certain of the penalties (in particular, bans and restrictions) on affiliates of CELSE and CELBA.
CELSE and CELBA are subject to extensive legislation and regulations imposed by the Brazilian government and ANEEL, and cannot predict the effect of any changes to the legislation or regulations currently in force regarding their respective businesses.
The implementation of Hygo’s business strategy and its ability to carry out its activities may be adversely affected by certain governmental actions.
Hygo may be subject to new regulations enacted by the Brazilian government that could retroactively affect the rules for renewal of its concessions and authorizations.
The non-renewal of any of Hygo’s authorizations, as well as the non-renewal of its energy supply contracts, could have a material adverse effect on its financial condition, results of operations and Hygo’s capacity to fulfill its contractual obligations.
The regulatory framework under which Hygo operates is subject to legal challenge.
The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the Lei do Novo Modelo do Setor Elétrico, or New Regulatory Framework. Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed. It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including Hygo’s business and results of operations. Due to the duration of the lawsuit, it is possible that the Brazilian Federal Supreme Court will not give retroactive effect to its decision, but rather preserve the validity of past acts applying a judicial practice known as modulation of effects.
If the regulatory framework under which Hygo operates is revised in a way that results in Hygo being required to conduct its business in a manner substantially different from its current operations, Hygo’s operations, financial results and capacity to fulfill its contractual obligations may be adversely affected.
Commercialization activity is subject to potential losses due to short-term variations in energy prices on the spot market.
Hygo’s sales on the spot market are subject to potential differences in the settlement between the energy delivered and the energy sold. The differences are settled by the Câmara de Comercialização de Energia Elétrica (the Electric Energy Trading Chamber) at the spot price, or the PLD. The PLD is based on the energy traded in the spot energy market. It is calculated for each submarket and load level on a weekly basis and is based on the marginal cost of operation. The maximum and the minimum value of the PLD are set every year by ANEEL. Short-term variations in energy prices on the spot energy market may lead to potential losses in Hygo’s commercialization activity.
Hygo is uncertain as to the review of the Physical Guarantee of its generation power plants.
The “Physical Guarantee” is the amount of power that a plant is expected to contribute to the electricity grid over the life of a PPA. Hygo cannot be certain if future events could affect the Physical Guarantee of each of its individual power plants. When the Physical Guarantee of a power plant is decreased, Hygo’s ability to supply electricity under that plant’s PPAs is adversely affected, which can lead to a decrease in Hygo’s revenues and increase Hygo’s costs if its generation subsidiaries are required to purchase power elsewhere. Damage to the step up transformer and related equipment at the Sergipe Power Plant in September 2020 is expected to temporarily decrease the Sergipe Power Plant’s Physical Guarantee by 8.75 MWh per year. To the extent CELSE is required to dispatch before repairs to the transformer and related equipment are complete, CELSE could be required to purchase the difference between its committed output and the final available power for delivery to PPA customers for the length of the requested dispatch period.
Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil.
Hygo currently conducts a meaningful portion of its business in Brazil. As a result, Hygo’s current business, results of operations, financial condition and prospects are materially dependent upon economic, political and other conditions and developments in Brazil. For example, on July 8, 2019, Petróleo Brasileiro S.A. – Petrobras (“Petrobras”) the state-owned oil company in Brazil, entered into an agreement (Termo de Compromisso de Cessão de Prática) with Brazilian antitrust authorities (Conselho Administrativo de Defesa Econômica - CADE) pursuant to which it has agreed to divest its equity participation in the gas pipelines and state gas distribution companies in Brazil by December 31, 2021. Such divestment plan, intended to end Petrobras’s monopoly on the distribution of gas in Brazil, will increase competition and may affect Hygo’s business.
In particular, the Brazilian economy has been characterized by frequent and occasionally extensive intervention by the Brazilian government and unstable economic cycles. The Brazilian government has often changed monetary, taxation, credit, tariff and other policies to influence the course of Brazil’s economy. The Brazilian government’s actions to control inflation and implement other policies have at times involved wage and price controls, blocking access to bank accounts, imposing capital controls and limiting imports into Brazil. In addition, Brazilian markets and politics have been characterized by considerable instability in recent years due to uncertainties derived from the ongoing corruption investigations such as Operation Car Wash, the conviction of Former President Luiz Inácio Lula da Silva, the impeachment of Former President Dilma Rousseff and the election of Congressman Jair Bolsonaro. The spread of COVID-19 in Brazil has resulted in heightened uncertainty and political instability as government officials debate appropriate response measures. These uncertainties and any measures adopted by the new administration may increase market volatility and political instability.
Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities, and could have an adverse effect on its financial condition and results of operations.
Hygo’s sale and leaseback agreements for the Golar Nanook, Golar Penguin and Golar Celsius contain, and any future sale and leaseback agreements it may enter into are expected to contain, customary covenants and event of default clauses, including cross-default provisions and restrictive covenants and performance requirements that may affect Hygo’s operational and financial flexibility. In addition, Hygo also assigns the shares in its subsidiaries which are the charterers of these vessels to the owners/lessors. Such restrictions could affect, and in many respects limit or prohibit, among other things, its ability to incur additional indebtedness, create liens, sell assets, or engage in mergers or acquisitions. These restrictions could also limit Hygo’s ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities. There can be no assurance that such restrictions will not adversely affect its ability to finance its future operations or capital needs.
Certain of Hygo’s sale and leaseback agreements contain cross-default clauses and require it to maintain specified financial ratios, satisfy certain financial covenants and/or assign equity interests in its subsidiaries to third parties, including, among others, the following requirements:
that Hygo maintains Free Liquid Assets (as defined in the Penguin Leaseback) of at least $50.0 million; and
that Hygo assigns the shares in each of Golar Hull M2026 Corp., Golar Hull M2023 Corp. and Golar FSRU 8 Corp., its subsidiaries that are the charterers under Hygo’s sale and leaseback agreements, to the applicable vessel owners.
As of December 31, 2020, Hygo was in compliance with the consolidated leverage ratio and the minimum free liquidity covenants in its sale and leaseback agreements.
As a result of the restrictions in its sale and leaseback agreements, or similar restrictions in future sale and leaseback agreements, Hygo may need to seek permission from the owners of its leased vessels in order to engage in certain corporate actions. Their interests may be different from Hygo’s and Hygo may not be able to obtain their permission when needed. This may prevent Hygo from taking actions that it believes are in its best interest, which may adversely impact Hygo’s revenues, results of operations and financial condition.
A failure by Hygo to meet its payment and other obligations, including its financial covenant requirements, could lead to defaults under its sale and leaseback agreements or any future sale and leaseback agreements. If Hygo is not in compliance with its covenants and is not able to obtain covenant waivers or modifications, the current or future owners of its leased vessels, as appropriate, could retake possession of the vessels or require Hygo to pay down its indebtedness to a level where Hygo is in compliance with its covenants or sell vessels in its fleet. Hygo could lose its vessels if it defaults on its bareboat charters in connection with the sale and leaseback agreements, which would negatively affect Hygo’s revenues, results of operations and financial condition.
There are risks and uncertainties relating to Hygo’s sale and leaseback transactions.
On closing of its sale and leaseback transactions, Hygo transferred its ownership interests in each of the Golar Nanook, the Golar Penguin and the Golar Celsius. Although the operation of these vessels is expected to continue in the ordinary course, the bareboat charters in connection with the sale and leaseback transactions may, in certain circumstances, be terminated. Any such termination could have a significant adverse effect on Hygo’s business, financial condition and results of operations of its vessels. The sale and leaseback agreements will also require significant periodic cash payments in respect of the required rent thereunder, which Hygo has not historically incurred for the Golar Celsius or, prior to December 2019, the Golar Penguin, and other allocated operating and maintenance costs. The increase in Hygo’s lease expense may have an adverse impact on its future operations and profitability.
Risks Related to GMLP Business Activities
GMLP currently derives all of its revenue from a limited number of customers. The loss of any of its customers would result in a significant loss of revenues and cash flow, if it is unable to re-charter a vessel to another customer for an extended period of time.
GMLP’s fleet consists of six FSRUs, four LNG carriers and an interest in the Hilli. GMLP has derived, and believes that it will continue to derive, all of its revenues and cash flow from a limited number of customers. The majority of its charters have fixed terms, but might nevertheless be lost in the event of unanticipated developments such as a customer’s breach. The ability of each of GMLP’s customers to perform its respective obligations under a charter with GMLP will depend on a number of factors that are beyond its control and may include, among other things, general economic conditions, the condition of the LNG shipping industry, prevailing prices for natural gas and LNG, the impact of COVID-19 and similar pandemics and epidemics and the overall financial condition of the counterparty. GMLP could also lose a customer or the benefits of a charter if the customer fails to make charter payments because of its financial inability, disagreements with GMLP or otherwise or the customer exercises its right to terminate the charter in certain circumstances.
If GMLP loses any of its charterers and are unable to re-deploy the related vessel for an extended period of time, it will not receive any revenues from that vessel, but it will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, it is an event of default under the credit facilities related to all of GMLP’s vessels if the time charter of any vessel related to any such credit facility is cancelled, rescinded or frustrated and it is unable to secure a suitable replacement charter, post additional security or make certain significant prepayments. Any event of default under GMLP’s credit facilities would result in acceleration of amounts due thereunder. GMLP will be required to provide additional security or make prepayments under its $800 million credit facility in the event that the charter in respect of the Golar Winter is terminated early and it cannot find an alternative acceptable charter. In addition, under the sale and leaseback arrangement in respect of the Golar Eskimo, if the time charter pursuant to which the Golar Eskimo is operating is terminated, the owner of the Golar Eskimo (which is a wholly-owned subsidiary of China Merchants Bank Leasing) will have the right to require GMLP to purchase the vessel from it unless GMLP is able to place such vessel under a suitable replacement charter within 24 months of the termination. GMLP may not have, or be able to obtain, sufficient funds to make these accelerated payments or prepayments or be able to purchase the Golar Eskimo. In such a situation, the loss of a charterer could have a material adverse effect on GMLP’s business, results of operations and financial condition.
GMLP’s business strategy depends on its ability to expand relationships with existing customers and obtain new customers, for which it will face substantial competition.
GMLP’s principal strategy is to provide steady and reliable shipping, regasification and liquefaction operations for its customers. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. GMLP believes FSRU and LNG carrier time charters are awarded based upon bid price as well as a variety of factors relating to the vessel operator, including:
its FSRU and LNG shipping experience, technical ability and reputation for operation of highly specialized vessels;
its shipping industry relationships and reputation for customer service and safety;
the quality and experience of its seafaring crew;
its financial stability and ability to finance FSRUs and LNG carriers at competitive rates;
its relationships with shipyards and construction management experience; and
its willingness to accept operational risks pursuant to the charter.
GMLP faces substantial competition for providing FSRU and marine transportation services for potential LNG projects from a number of experienced companies, including state-sponsored entities and major energy companies. Many of these competitors have significantly greater financial resources and larger and more versatile fleets than GMLP. GMLP anticipates that an increasing number of marine transportation companies, including many with strong reputations and extensive resources and experience will enter the FSRU market and the LNG transportation market. This increased competition may cause greater price competition for time charters. As a result of these factors, GMLP may be unable to expand its relationships with existing customers or to obtain new customers on a favorable basis, if at all, which would have a material adverse effect on its business, results of operations and financial condition.
GMLP’s future long-term charter revenue depends on its competitive position and future hire rates for FSRUs and LNG carriers.
One of GMLP’s principal strategies is to enter into new long-term FSRU and LNG carrier time charters and to replace expiring charters with similarly long-term contracts. Most requirements for new LNG projects continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands. More frequent changes to vessel sizes and propulsion technology together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the duration of long-term charters could also decrease over time.
GMLP may also face increased difficulty entering into long-term time charters upon the expiration or early termination of its contracts. If as a result GMLP contracts its vessels on short-term contracts, its earnings from these vessels are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require that GMLP enter into charters based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in its cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover its financing costs for related vessels.
Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when GMLP is seeking a new charter, its earnings may decline.
Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to current and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a number of factors outside GMLP’s control. For example, driven in part by an increase in LNG production capacity, the market supply particularly of LNG carriers has been increasing. As of March 2, 2021, the LNG carrier order book totaled 141 vessels. GMLP believes that this and any future expansion of the global LNG carrier fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, the impact of which could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth. The LNG market is also closely connected to world natural gas prices and energy markets, which it cannot predict. A substantial or extended decline in demand for natural gas or LNG, including as a result of the spread of COVID-19, could adversely affect GMLP’s ability to charter or re-charter its vessels at acceptable rates or to acquire and profitably operate new vessels. Accordingly, this could have a material adverse effect on its earnings.
The charterers of two of GMLP’s vessels have the option to extend the charter at a rate lower than the existing hire rate. The exercise of these options could have a material adverse effect on its cash flow.
The charterers of the NR Satu and Methane Princess have options to extend their respective existing contracts. If they exercise these options, the hire rate for the NR Satu will be reduced by approximately 12% per day for any day in the extension period falling in 2023, with a further 7% reduction for any day in the extension period falling in 2024 and 2025; and the hire rate for the Methane Princess will be reduced by 37% from 2024. The exercise of these options could have a material adverse effect on GMLP’s results of operations and cash flows.
GMLP’s equity investment in Golar Hilli LLC may not result in anticipated profitability or generate cash flow sufficient to justify its investment. In addition, this investment exposes GMLP to risks that may harm its business, financial condition and operating results.
In July 2018, GMLP completed an acquisition of 50% of the common units in Hilli LLC (as defined here), the disponent owner of Hilli Corp. (as defined herein), the owner of the Hilli. The acquired interest in Hilli LLC represents the equivalent of 50% of the two liquefaction trains, out of a total of four, that have been contracted to Perenco Cameroon SA (“Perenco”) and Société Nationale Des Hydrocarbures (“SNH” and, together with Perenco, the “Customer”) pursuant to a Liquefaction Tolling Agreement (“LTA”) with an 8 year term. The acquired interest is not exposed to the oil linked pricing elements of the tolling fee under the LTA. However, it exposes us to risks that GMLP may:
fail to realize anticipated benefits through cash distributions from Hilli LLC;
fail to obtain the benefits of the LTA if the Customer exercises certain rights to terminate the charter upon the occurrence of specified events of default;
fail to obtain the benefits of the LTA if the Customer fails to make payments under the LTA because of its financial inability, disagreements with us or otherwise;
incur or assume unanticipated liabilities, losses or costs;
| • | be required to pay damages to the Customer or suffer a reduction in the tolling fee in the event that the Hilli fails to perform to certain specifications;
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incur other significant charges, such as asset devaluation or restructuring charges; or
be unable to re-charter the FLNG on another long-term charter at the end of the LTA.
Due to the sophisticated technology utilized by the Hilli, operations are subject to risks that could negatively affect GMLP’s business and financial condition.
FLNG vessels are complex and their operations are technically challenging and subject to mechanical risks and problems. Unforeseen operational problems with the Hilli may lead to Hilli LLC experiencing a loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm GMLP’s business and financial condition.
GMLP guarantees 50% of Hilli Corp’s indebtedness under the Hilli Facility.
Hilli Corp, a wholly owned subsidiary of Hilli LLC, is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Facility”). The Hilli Facility provided for post-construction financing for the Hilli in the amount of $960 million.
In connection with the closing of the Hilli Acquisition, GMLP agreed to provide a several guarantee (the “GMLP Guarantee”) of 50% of the obligations of Hilli Corp under the Hilli Facility pursuant to a Deed of Amendment, Restatement and Accession relating to a guarantee between GLNG, Fortune and GMLP dated July 12, 2018. In the event that Hilli Corp fails to meet its payment obligations under the Hilli Facility or fails to comply with certain other covenants contained therein, GMLP may be required to make payments to Fortune under the GMLP Guarantee, and such payments may be substantial. The Hilli Facility and the GMLP Guarantee contain certain financial restrictions and other covenants that may restrict GMLP’s business and financing activities.
GMLP may experience operational problems with its vessels that reduce revenue and increase costs.
FSRUs and LNG carriers are complex and their operations are technically challenging. Marine LNG operations are subject to mechanical risks and problems. GMLP’s operating expenses depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond its control such as the overall economic impacts caused by the global COVID-19 outbreak and affect the entire shipping industry. Factors such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements could also increase operating expenditures. Future increases to operational costs are likely to occur. If costs rise, they could materially and adversely affect GMLP’s results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm GMLP’s business, financial condition and results of operations.
GMLP may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits, which could have a material effect on its operations.
The design, construction and operation of FSRUs, FLNGs and LNG carriers and interconnecting pipelines require, and are subject to the terms of governmental approvals and permits. The permitting rules, and the interpretations of those rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may increase the length of time it takes to receive regulatory approval for offshore LNG operations. In the future, the relevant regulatory authorities may take actions to restrict or prohibit the access of FSRUs or LNG carriers to various ports or adopt new rules and regulations applicable to FSRUs and LNG carriers that will increase the time needed or affect GMLP’s ability to obtain necessary environmental permits.
A shortage of qualified officers and crew, including due to disruption caused by the outbreak of pandemic diseases, such as COVID-19, could have an adverse effect on GMLP’s business and financial condition.
FSRUs, FLNGs and LNG carriers require technically skilled officers and crews with specialized training. As the worldwide FSRU, FLNG and LNG carrier fleet has grown, the demand for technically skilled officers and crews has increased, which could lead to a shortage of such personnel. Increases in GMLP’s historical vessel operating expenses have been attributable primarily to the rising costs of recruiting and retaining officers for its fleet. If GMLP’s vessel managers are unable to employ technically skilled staff and crew, they will not be able to adequately staff its vessels. A material decrease in the supply of technically skilled officers or an inability of GLNG or its vessel managers to attract and retain such qualified officers could impair its ability to operate or increase the cost of crewing its vessels, which would materially adversely affect GMLP’s business, financial condition and results of operations.
In addition, the Golar Winter is employed by Petrobras in Brazil. As a result, GMLP is required to hire a certain portion of Brazilian personnel to crew this vessel in accordance with Brazilian law. Also, the NR Satu is employed by PT Nusantara Regas, in Indonesia. As a result, GMLP is required to hire a certain portion of Indonesian personnel to crew the NR Satu in accordance with Indonesian law. Any inability to attract and retain qualified Brazilian and Indonesian crew members could adversely affect its business, results of operations and financial condition.
Furthermore, should there be an outbreak of COVID-19 on board one of GMLP’s vessels, adequate crewing may not be available to fulfill the obligations under its contracts. Due to COVID-19, GMLP could face (i) difficulty in finding healthy qualified replacement officers and crew; (ii) local or international transport or quarantine restrictions limiting the ability to transfer infected crew members off the vessel or bring new crew on board, and (iii) restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives. Any inability GLNG or its affiliates experiences in the future to attract, hire, train and retain a sufficient number of qualified employees could impair GMLP’s ability to manage, maintain and grow its business.
Due to the locations in which GMLP operate, GMLP is subject to political and security risks.
GMLP’s operations may be affected by economic, political and governmental conditions in the countries where GMLP is engaged in business or where its vessels are registered. Any disruption caused by these factors could harm its business. In particular:
GMLP derives a substantial portion of its revenues from shipping LNG from politically unstable regions, particularly the Arabian Gulf, Brazil, Indonesia and West Africa. Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Future hostilities or other political instability in the regions in which GMLP operates or may operate could have a material adverse effect on the growth of its business, results of operations and financial condition and its ability to make cash distributions. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could also harm GMLP’s business and ability to make cash distributions.
The operations of Hilli Corp in Cameroon under the LTA are subject to higher political and security risks than operations in other areas of the world. Recently, Cameroon has experienced instability in its socio-political environment. Any extreme levels of political instability resulting in changes of governments, internal conflict, unrest and violence, especially from terrorist organizations prevalent in the region, such as Boko Haram, could lead to economic disruptions and shutdowns in industrial activities. In addition, corruption and bribery are a serious concern in the region. The operations of Hilli Corp in Cameroon are subject to these risks, which could materially adversely affect GMLP’s revenues, its ability to perform under the LTA and its financial condition.
In addition, Hilli Corp maintains insurance coverage for only a portion of the risks incidental to doing business in Cameroon. There also may be certain risks covered by insurance where the policy does not reimburse Hilli Corp for all of the costs related to a loss. For example, any claims covered by insurance will be subject to deductibles, which may be significant. In the event that Hilli Corp incurs business interruption losses with respect to one or more incidents, they could have a material adverse effect on GMLP’s results of operations.
Vessel values may fluctuate substantially and, if these values are lower at a time when GMLP is attempting to dispose of vessels, GMLP may incur a loss.
Vessel values can fluctuate substantially over time due to a number of different factors, including:
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 or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.
As GMLP’s vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on its business and operations if GMLP 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, GMLP will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, GMLP may be unable to re-deploy the affected vessels at attractive rates and, rather than continue to incur costs to maintain and finance them, GMLP may seek to dispose of them. When vessel values are low, GMLP may not be able to dispose of vessels at a reasonable price when GMLP wish to sell vessels, and conversely, when vessel values are elevated, GMLP may not be able to acquire additional vessels at attractive prices when GMLP wish to acquire additional vessels, which could adversely affect GMLP’s business, results of operations, cash flow, financial condition and ability to make distributions to unitholders.
The carrying values of GMLP’s vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates and the cost of new build vessels. GMLP’s vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Although GMLP did not recognize an impairment charge on any of its vessels for the year ended December 31, 2020, GMLP cannot assure you that GMLP will not recognize impairment losses on its vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect GMLP’s business, financial condition, operating results or the trading price of GMLP’s common and preferred units.
GMLP vessels may call on ports located in countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.
Although no vessels operated by GMLP have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism, in the future GMLP’s vessels may call on ports in these countries from time to time on its charterers’ instructions. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.
Although GMLP believes that it has been in compliance with all applicable sanctions and embargo laws and regulations, and intends to maintain such compliance, there can be no assurance that GMLP will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact GMLP’s ability to access U.S. capital markets and conduct its business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism. Moreover, GMLP charterers may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve GMLP or its vessels, and those violations could in turn negatively affect GMLP’s reputation. In addition, GMLP’s reputation may be adversely affected if it engages in certain other activities, such as entering into charters with individuals or entities in countries subject to U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.
Maritime claimants could arrest GMLP’s vessels, which could interrupt its cash flow.
If GMLP is in default on certain kinds of obligations, such as those to its lenders, crew members, suppliers of goods and services to its vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of GMLP’s vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in GMLP’s fleet for claims relating to another of its vessels. The arrest or attachment of one or more of GMLP’s vessels could interrupt its cash flow and require it to pay to have the arrest lifted. Under some of GMLP’s present charters, if the vessel is arrested or detained (for as few as 14 days in the case of one of our charters) as a result of a claim against it, GMLP may be in default of its charter and the charterer may terminate the charter. This would negatively impact GMLP’s revenues and reduce its cash available for distribution to unitholders.
Risks Related to Ownership of Our Class A Common Stock
The Proposed Mergers may not occur, and if they do, they may not be accretive and may cause dilution to our earnings per share, which may negatively affect the market price of our common stock.
Although we currently anticipate that the Proposed Mergers will occur and will be accretive to earnings per share (on an as adjusted earnings basis that is not pursuant to GAAP) from and after the Proposed Mergers, this expectation is based on assumptions about our, Hygo’s and GMLP’s business and preliminary estimates, which may change materially. As a result, should the Proposed Mergers occur, certain other amounts to be paid in connection with the Proposed Mergers may cause dilution to our earnings per share or decrease or delay the expected accretive effect of the Proposed Mergers and cause a decrease in the market price of our common stock. The Proposed Mergers may not occur as a result. See “—Risks Related to the Proposed Mergers.” In addition, we could also encounter additional transaction-related costs or other factors such as the failure to realize all of the benefits anticipated in the Proposed Mergers, including cost and revenue synergies. All of these factors could cause dilution to our earnings per share or decrease or delay the expected accretive effect of the Proposed Mergers and cause a decrease in the market price of our common stock.
The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.
The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:
•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 Proposed 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 Proposed 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 Proposed Mergers as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Proposed 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 Proposed Mergers may be affected by factors different from those currently affecting the independent results of operations of each of our, Hygo’s and GMLP’s and business.
We are a “controlled company” within the meaning of Nasdaq rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.
Affiliates of certain entities controlled by Wesley R. Edens, and Randal A. Nardone 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 Fortress Investment Group LLC and NFE SMRSEnergy Transition Holdings LLC are parties to the Shareholders’ Agreement and as of March 15, 2021 collectivelyDecember 31, 2023 hold approximately 27%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 March 15, 2021,December 31, 2023, affiliates of the Founder Entities own an aggregate of approximately 98,824,30187,136,768 shares of Class A common stock, representing 56.2%approximately 42.5% of our voting power. Aspower, and affiliates of March 15, 2021, Wesley R. Edens and Randal A. Nardone directly or indirectlyEnergy Transition Holdings LLC, party to the Shareholders' Agreement, own 72,627,775an aggregate of approximately 25,559,846 shares and 26,196,526 shares, respectively, of our Class A common stock, representing 41.3% and 14.9%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 IPO, we entered into a shareholders’ agreement (the “Shareholders’ Agreement”) with New Fortress Energy Holdings and its affiliates, and in connection with the Exchange Transactions (as defined herein), New Fortress Energy Holdingshas assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition, our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.
Our Certificate of Incorporation and By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock.
Our Certificate of Incorporation and By-Laws authorize our board of directors to issue preferred stock (including the Series A Convertible Preferred Stock to be issued upon closing of the Barcarena PPA Exchange) 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 By-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 securityholders.security holders. These provisions include:
•dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;
•providing that allany vacancies including newly created directorships, may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;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 Certificate of Incorporation and By-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Certificate of Incorporation and By-Laws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or employees arising pursuant to any provision of our organizational documents or the Delaware Limited Liability Company Act or the DGCL, as applicable,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 Proposed 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 Proposed 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)such as the Series A Convertible Preferred Stock to be issued upon closing of the Barcarena PPA Exchange, 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, whether directly, or through convertible securities, such as the Series A Convertible Preferred Stock, 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, and the Series A Convertible Preferred Stock will, 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 additional debt or issue equity or equity-related securities (other than the Series A Convertible Preferred Stock, which will be issued upon satisfaction of the closing conditions for the Barcarena PPA Exchange) in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.
We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.
Our Certificate of Incorporation and By-Laws authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock in respect of dividends and distributions, as our board of directors may determine. As part of the Barcarena PPA Exchange, we agreed to issue approximately 125,000 shares of the Series A Convertible Preferred Stock upon the satisfaction of the closing conditions for the Barcarena PPA Exchange. The terms of the Series A Convertible Preferred Stock or one or more classes or series of other 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..
We recently ceased to be an emerging growthare a holding company and nowour operational and consolidated financial results are required to comply with certain heightened reporting requirements, including those relating to auditing standards and disclosure about our executive compensation.
The Jumpstart Our Business Startups Act of 2012, or “JOBS Act”, contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. Prior to September 2, 2020, we were classified as an emerging growth company. As an emerging growth company, we were not required to, among other things, (i) provide an auditor’s attestation reportdependent on management’s assessment of the effectivenessresults of our system of internal control oversubsidiaries, 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 reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act and (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplementobligations is therefore related in part to the auditor’s report in which the auditor would be required to provide additional information about the auditcash flow and earnings of our subsidiaries and affiliates and the financial statementsability or willingness of these entities to make distributions or other transfers of earnings to us in the issuer, (iii) provide certain disclosures regarding executive compensation requiredform of larger public companiesdividends, loans or (iv) hold nonbinding advisory votesother 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 executive compensation. Whendividend 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 were an emerging growth company, we followed the exemptions described above. We also electedmay fail to use the extended transition period provided in Section 7(a)(2)(B)realize anticipated benefits of the Securities Act for complying with newany joint venture or revised accounting standards under Section 102(b)(2) of the JOBS Act. This election allowed us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result,similar arrangement, which could adversely affect our financial statements may not have been comparable to companies that comply with public company effective dates,condition and our stockholders and potential investors may have difficulty in analyzing our historical operating results if comparing us to such companies. In addition, because we relied on exemptions available to emerging growth companies, our historical public filings contained less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.
We expectmay engage in mergers, sales and acquisitions, divestments, reorganizations or similar transactions related to incur additional costs associated withour businesses or assets in the heightened reporting requirements described above, including the requirement to provide auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, as well as additional audit costs resulting from PCAOB requirements. In addition, our auditors may identify control deficiencies of varying degrees of severity,future and we may incurfail 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 costsrisks and contingencies, including the risk of integration, valuation and successful implementation, and we may not be able to remediate those deficienciesrealize the benefits of any such transactions. We may also engage in sales of our assets or otherwise improvesale and leaseback transactions that seek to monetize our internal controls. As a public company,assets and there is no guarantee that such sales of assets will be executed at the prices we are requireddesire 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 reportsuccessfully complete any control deficiencies that constitute a “material weakness” insuch transactions or whether we will be able to retain key personnel, suppliers or distributors. Our ability to successfully implement our internal control over financial reporting, and doing so could impairstrategy through such transactions depends upon our ability to raise capitalidentify, negotiate and otherwisecomplete 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.
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 valuecountries 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 securities.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. For example, the Organization for Economic Cooperation and Development is coordinating negotiations among more than 140 countries with the goal of achieving consensus around substantial changes to international tax policies, including the implementation of a minimum global effective tax rate of 15%. Various countries have implemented the legislation and others may in the future, which could increase our effective tax rate.
We have been and may be involved in legal proceedings and may experience unfavorable outcomes.
We have 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.
The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company with stock listed on Nasdaq, we are and will be subject to an extensive body of regulations that did not apply to us previously, 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 increase our legal, accounting, compliance and other expenses that we did not incur prior to the IPO and has made some activities more time-consuming and costly. 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. FIG LLC will also continue to provide compliance services for the foreseeable future. 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.
The COVID-19 pandemic caused 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. 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 any such crisis or pandemic and its economic consequences are uncertain, rapidly-changing and difficult to predict, its impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, could be uncertain and difficult to predict. Further, the ultimate impact of any 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 may be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of such 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 any 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 pandemic or crisis subsides. Our operations, financial performance and financial condition could be subjected to a number of operational financial 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 fail to realize the anticipated benefitsalso experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the Exchange Transactionspandemic’s impact on the operations and financial condition of our customers and potential customers, as well as the Conversionprice 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 those benefitsother 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 takelimit 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 to realize than expected or may not offsetthis period of economic and global supply chain and disruption continues, the costs ofgreater the Exchange Transactions anduncertainty will be regarding the Conversion, which could have anpossible adverse impact on the trading priceour business operations, financial performance and results of our Class A common stock.operations.
We expect the Exchange Transactions and the Conversion will confer several significant benefits to us. Most notably, we expect that the Exchange Transactions will significantly reduce our future tax distribution obligations to the members of NFI, which will enable us to instead invest those funds to develop projects that we expect will increase our returns for all stockholders, enhance our liquidity, improve our credit profile and potentially lower our cost of capital.
We may fail to realize the anticipated benefits of the Exchange Transactions and the Conversion or those benefits may take longer to realize than we expect. Moreover, there can be no assurance that the anticipated benefits of the Exchange Transactions and the Conversion will offset their costs. Our failure to achieve the anticipated benefits of the Exchange Transactions and the Conversion at all or in a timely manner, or a failure of any benefits realized to offset its costs, could have an adverse impact on the trading price of our Class A common stock.
Item 1B. | Item 1B. Unresolved Staff Comments. |
None.
Item 1C. Cybersecurity.
Risk Management and Strategy
The Company assesses risks from cybersecurity threats, monitors its information systems for potential vulnerabilities and tests those systems pursuant to the Company’s cybersecurity standards, processes and practices, which are integrated into the Company’s overall risk management processes. To protect the Company’s information systems from cybersecurity threats, including those related to third-party service providers, the Company uses various security tools, such as third party vendors that help the Company identify, escalate, investigate, resolve and recover from security incidents in a timely manner. The Company’s cybersecurity procedures and standards are reviewed and overseen by the Company’s cybersecurity group.
The cybersecurity group holds periodic meetings and reviews metrics it deems appropriate, including any incidents and threats, and the current state of cybersecurity issues and threats in the industry. These efforts include developing a threat model that assesses potential damage to the Company’s business and the likelihood of threat. We test the risk prioritization rankings of our threat model with external data about breaches and incidents reported by governmental agencies, including the Cybersecurity and Infrastructure Security Agency and National Security Agency. The Company partners with third parties to assess the effectiveness of our cybersecurity prevention and response systems and processes as needed.
For high priority incidents, the cybersecurity group will manage a risk-appropriate response, which may include the use of third-party vendors to support any investigation, response, and remediation efforts. Updates regarding any incidents are provided to management as appropriate.
During the year ended December 31, 2023, the Company is not aware of any cybersecurity incidents or threats that materially affected our business, results of operations or financial condition.
Governance
Management oversees the Company’s risk management process, including cybersecurity risks, and receives updates regarding any cybersecurity incidents directly from the cybersecurity group as appropriate. The cybersecurity group is led by the Chief Technology Officer, who has over 15 years of experience in information security. Management will evaluate any cybersecurity risks, concerns and issues and determine whether to escalate such issues to the Board or any of its committees. Our Board is responsible for the oversight of management as well as the business and affairs of the Company. In carrying out this responsibility, the Board discusses and receives regular updates on a wide variety of matters affecting the Company.
Risks
Please see the risk factor captioned "Information technology failures and cyberattacks could affect us significantly” in Part I, Item 1A. “Risk Factors” for additional description of cybersecurity risks and potential related impacts on the Company.
Item 3. | Item 3. Legal Proceedings. |
We are not currently a party to any material legal proceedings. In the ordinary course of business,From time to time, we may become involved in various legal and regulatory claims and proceedings may be pending or threatened against us.relating to claims arising out of our operations and activities in the normal course of business. 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 4. | Item 4. Mine Safety Disclosures. |
Not applicable.
Item 5. | Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities. |
Market Information
Our Class A common stock is traded on the NASDAQNasdaq Global Select Market under the symbol “NFE.” On March 15, 2021,February 26, 2024, there were eight holders of record of our Class A common stock. This number does not include shareholders whose shares are held for them in “street name” meaning that such shares are held for their accounts by a broker or other nominee. The actual number of beneficial shareholders is greater than the number of holders of record.
Dividends
We declared and paid quarterly dividends of $0.10$0.10 per share in August and October 2020, totaling $33,742 in dividend payments$81,976 during the year ended December 31, 2020. 2023. Additionally, 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 in January 2023. Our future dividend policy is within the discretion of our boardBoard of directorsDirectors 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 boardBoard of directorsDirectors may deem relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item is set forth in In the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection withthird quarter of 2023, our 2021 annual meetingBoard of shareholders and is incorporated herein by reference.
Share Performance Graph
The following graph compares the cumulative total return to shareholders on our Class A common stock relative to the S&P 500, Alerian MidstreamiShares Global Clean Energy ETF Index (“AMNA”ICLN”) and, Vanguard Energy ETF (“VDE”), Energy Select Sector SPDR Fund ("XLE"), including reinvestment of dividends. The addition of XLE reflects that as a global energy infrastructure company, our common stock can trade in correlation with global oil, gas and consumable fuel companies, and such companies are the components of XLE. The graph assumes that on January 31, 2019, the date our Class A shares began trading on the NASDAQ,Nasdaq, $100 was invested in our Class A shares and in each index based on the closing market price, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.
The graph assumes that on January 31, 2019, the date our Class A shares began trading on the Nasdaq, $100 was invested in our Class A shares and in each index based on the closing market price, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.
The following Performance Graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such filing.
| Cumulative Total Return Percentage |
| Company / Index | January 31, 2019(1) | March 2019(2) | June 2019(2) | Sepember 2019(2) | December 2019(2) | March 2020(2) | June 2020(2) | Sepember 2020(2) | December 2020(2) |
| NFE | 100 | (10.6) | (10.4) | 37.9 | 19.9 | (25.1) | (0.8) | 237.9 | 312.4 |
| S&P 500 | 100 | 4.8 | 8.8 | 10.1 | 19.5 | (4.4) | 14.7 | 24.4 | 38.9 |
| Alerian Midstream Index (“AMNA”) | 100 | 2.5 | 0.6 | (6.4) | (12.3) | (63.3) | (46.5) | (56.6) | (44.2) |
| Vanguard Energy ETF (“VDE”) | 100 | 4.5 | 0.2 | (7.2) | (2.2) | (53.5) | (38.0) | (49.7) | (34.5) |
(2) | Last trading day of the month |
Use of Proceeds from Registered Securities
| | | | | | | | | | | | | | | | | | | | |
| Cumulative Total Return Percentage |
| Company / Index | January 31, 2019(1) | December 2019(2) | December 2020(2) | December 2021(2) | December 2022(2) | December 2023(2) |
| NFE | 100.0% | 19.9% | 312.4% | 88.0% | 233.6% | 225.4% |
| S&P 500 | 100.0% | 21.7% | 44.1% | 85.4% | 51.8% | 91.7% |
| iShares Global Clean Energy ETF Index ("ICLN") | 100.0% | 25.6% | 203.8% | 130.3% | 117.9% | 73.5% |
| Energy Select Sector SPDR Fund ("XLE") | 100.0% | 0.5% | (32.2)% | 4.0% | 70.7% | 69.6% |
| Vanguard Energy ETF ("VDE") | 100.0% | -2.2% | (34.5)% | 2.3% | 66.6% | 66.6% |
On February 4, 2019, we completed the IPO of 20,000,000 Class A shares pursuant to our registration statement on Form S-1 (File No. 333-228339) (the “Registration Statement”) declared effective by the SEC on January 30, 2019. In connection with the IPO, Morgan Stanley & Co. LLC, Barclays Capital Inc., Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC acted as representatives of the underwriters; Evercore Group L.L.C. and Allen & Company LLC acted as joint book-running managers; and JMP Securities LLC and Stifel, Nicolaus & Company Incorporated acted as co-managers. The gross proceeds(1)Date of the IPO based on a public offering price of $14.00 per Class A share, were $280.0 million, which resulted in net proceeds to us of $257.0 million, after deducting underwriting discounts and commissions and transaction costs. In addition, on March 1, 2019, the underwriters exercised their option to purchase an additional 837,272 Class A shares at the initial offering price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. We contributed the net proceeds
(2)Last trading day of the IPO to NFI in exchange for NFI’s issuance to us of 20,837,272 NFI LLC Units. NFI used the net proceeds in connection with the construction of our Facilities, as well as for working capital and general corporate purposes, including the development of future projects. No fees or expenses were paid, directly or indirectly, to any officer, director, 10% unitholder or other affiliate.month
In December 2020, NFE issued 5,882,352 shares of Class A common stock and received proceeds of $290.8 million, net of $1.2 million in issuance costs. The use of these proceeds will be for general corporate purposes.
Item 6. | Selected Financial Data. |
The following table presents our selected historical consolidated financial and operating data. NFE was formed on August 6, 2018 and did not have historical financial results. The selected historical financial data as of December 31, 2018, 2017 and 2016 and for the years ended December 31, 2018, 2017 and 2016, prior to the IPO, was derived from the audited historical consolidated financial statements of New Fortress Energy Holdings, our predecessor for financial reporting purposes. Due to the change in organization structure as a result of reorganization transactions completed at the time of our IPO in 2019, the net loss per share and weighted average number of shares outstanding are not presented for the years ended December 31, 2018, 2017 and 2016.
You should read the information set forth below together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this Annual Report. The historical financial results are not necessarily indicative of results to be expected for any future periods.
| | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | | | 2017 | | | 2016 | |
| | | (In thousands, except share and per share amounts) | |
| Statements of Operations Data: | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Revenues | | | | | | | | | | | | | | | |
| Operating revenue | | $ | 318,311 | | | $ | 145,500 | | | $ | 96,906 | | | $ | 82,104 | | | $ | 18,615 | |
| Other revenue | | | 133,339 | | | | 43,625 | | | | 15,395 | | | | 15,158 | | | | 2,780 | |
| Total revenues | | | 451,650 | | | | 189,125 | | | | 112,301 | | | | 97,262 | | | | 21,395 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | | | | | | | | | | | | | | | | | | | |
| Cost of sales | | | 278,767 | | | | 183,359 | | | | 95,742 | | | | 78,692 | | | | 22,747 | |
| Operations and maintenance | | | 47,581 | | | | 26,899 | | | | 9,589 | | | | 7,456 | | | | 5,205 | |
| Selling, general and administrative | | | 124,170 | | | | 152,922 | | | | 62,137 | | | | 33,343 | | | | 18,160 | |
| Contract termination charges and loss on mitigation sales | | | 124,114 | | | | 5,280 | | | | - | | | | - | | | | - | |
| Depreciation and amortization | | | 32,376 | | | | 7,940 | | | | 3,321 | | | | 2,761 | | | | 2,341 | |
| Total operating expenses | | | 607,008 | | | | 376,400 | | | | 170,789 | | | | 122,252 | | | | 48,453 | |
| Operating loss | | | (155,358 | ) | | | (187,275 | ) | | | (58,488 | ) | | | (24,990 | ) | | | (27,058 | ) |
| Interest expense | | | 65,723 | | | | 19,412 | | | | 11,248 | | | | 6,456 | | | | 5,105 | |
| Other expense (income), net | | | 5,005 | | | | (2,807 | ) | | | (784 | ) | | | (301 | ) | | | (53 | ) |
| Loss on extinguishment of debt, net | | | 33,062 | | | | - | | | | 9,568 | | | | - | | | | 1,177 | |
| Loss before taxes | | | (259,148 | ) | | | (203,880 | ) | | | (78,520 | ) | | | (31,145 | ) | | | (33,287 | ) |
| Tax expense (benefit) | | | 4,817 | | | | 439 | | | | (338 | ) | | | 526 | | | | (361 | ) |
| Net loss | | | (263,965 | ) | | | (204,319 | ) | | | (78,182 | ) | | | (31,671 | ) | | | (32,926 | ) |
| Net loss attributable to non-controlling interest | | | 81,818 | | | | 170,510 | | | | 106 | | | | - | | | | - | |
| Net loss atrributable to stockholders | | $ | (182,147 | ) | | $ | (33,809 | ) | | $ | (78,076 | ) | | $ | (31,671 | ) | | $ | (32,926 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net loss per share - basic and diluted | | $ | (1.71 | ) | | $ | (1.62 | ) | | | | | | | | | | | | |
| Weighted average number of shares outstanding - basic and diluted | | | 106,654,918 | | | | 20,862,555 | | | | | | | | | | | | | |
| | As of December 31, | |
| | | 2020 | | | 2019 | | | 2018 | | | 2017 | | | 2016 | |
| Balance Sheet Data (at period end): | | | | | | | | | | | | | | | |
| Property, plant and equipment, net | | $ | 614,206 | | | $ | 192,222 | | | $ | 94,040 | | | $ | 69,350 | | | $ | 70,633 | |
| Construction in progress | | | 234,037 | | | | 466,587 | | | | 254,700 | | | | 35,413 | | | | 4,668 | |
| Total assets | | | 1,908,091 | | | | 1,123,814 | | | | 699,402 | | | | 381,190 | | | | 389,054 | |
| Long-term debt (includes current portion) | | | 1,239,561 | | | | 619,057 | | | | 272,192 | | | | 75,253 | | | | 80,385 | |
| Total liabilities | | | 1,533,005 | | | | 736,490 | | | | 416,755 | | | | 102,280 | | | | 99,684 | |
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | | | 2017 | | | 2016 | |
| Statements of Cash Flow Data: | | | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | |
| Operating activities | | $ | (125,566 | ) | | $ | (234,261 | ) | | $ | (93,227 | ) | | $ | (54,892 | ) | | $ | (43,493 | ) |
| Investing activities | | | (157,631 | ) | | | (376,164 | ) | | | (184,455 | ) | | | (29,858 | ) | | | (98,325 | ) |
| Financing activities | | | 819,498 | | | | 602,607 | | | | 260,204 | | | | 13,960 | | | | 275,936 | |
Item 7. | Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
Certain information contained in thisthe 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 “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“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 comparison of the years ended December 31, 20192022 and 20182021 can be found in our Annual Report on Form 10‑K10-K for the year ended December 31, 20192022 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with GAAP.generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in thousands.
Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or 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. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes.
Overview
We are a global integrated gas-to-powerenergy infrastructure company that seeksfounded to usehelp 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 satisfy the world’s large and growing power needs. Werapidly deliver targetedturnkey energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins.global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon 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 this Annual Report, “Items 1 and 2: Business and Properties” under “Toward“Sustainability—Toward a Carbon-Free Future”.Low Carbon Future.”
As an integrated gas-to-power energy infrastructure company, our business model spansOur 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 partythird-party suppliers and from our own liquefaction facility in Miami, Florida. WeUpon the completion of commissioning in 2024, we expect that controlto begin to source a portion of our verticalLNG from our modular liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply chain, from procurement to deliveryand the deployment of LNG, will help to reduce our exposure to future LNG price variations and enablevessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply our existing and futurefleet.
Our Ships segment includes all vessels which are leased to customers with LNG at a price that reinforces our competitive standingunder long-term arrangements. The Company’s investment in Energos (defined below) is also included in the LNG market. Our strategy is simple:Ships segment. Over time, we seekexpect to procure LNG at attractive prices using long-term agreements and throughutilize these vessels in our own production, and we seek to sell natural gas (delivered through LNG infrastructure) or gas-fired power to customers that sign long-term, take-or-pay contracts.terminal operations as charter agreements for these vessels expire.
Our Current Operations
Our management team has successfully employed our strategy to secure long-term contracts with significant customers, in Jamaica and Puerto Rico, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina productionproducer in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), 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 natural gas liquefaction and storage facility located in Miami-Dade County, Florida (the “Miami Facility”). Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”).
Montego Bay Facility
Our storage and regasification terminal inThe Montego Bay Jamaica (the “Montego Bay Facility”)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 740,000 gallons60,000 MMBtu of LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.
Our marine LNG storage and regasification facility inThe Old Harbour Jamaica (the “OldFacility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus from LNG per day. The Old Harbour Facility”)Facility commenced commercial operations in June 2019 and is capable of processing approximately six million gallons of LNG (500,000 MMBtu) per day. The Old Harbour Facility supplies natural gas to the new 190MW Old Harbour power plant (the “Old(“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP(“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term power purchase agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay steam supply agreement. On March 3, 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliverThe Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
In July 2020, we finalizedOur San Juan Facility became fully operational in the developmentthird quarter of the2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico (the “SanRico. The San Juan Facility”).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
In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. ("Weston") for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas usedand ADO. Weston has been contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 150MW of duel-fuel power generation using our gas supply in the second quarter of 2023, and the remaining 200MW was commissioned in September 2023.
In the first quarter of 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-year contract for the commissioningoperation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power plantgeneration in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees, beginning after the service period under the Fuel Salecontract commenced on July 1, 2023.
La Paz Facility
In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and Purchase Agreementcould have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023.
In the fourth quarter of 2022, we finalized short-form agreements with PREPA since April 2020.CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant.
Miami Facility
Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 100,000 gallons of8,300 MMBtu from LNG (8,300 MMBtu) per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.
Other Development Projects
We are inNFE provides reliable, affordable and clean energy supplies to customers around the process of developing an LNG regasification facility and power plant at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, the La Paz Facility is expected to supply approximately 270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW of power supplied by gas-fired modular power unitsworld that we plan to develop,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 operated, which may be increased to 350,000 gallons (29,000 MMBtu)receive physical delivery of LNG per dayvolumes for up100% 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 135 MWcommence in 2027. Finally, we plan to commence production from our first Fast LNG facility upon the completion of power.commissioning in 2024. We plan to expand that capacity when additional Fast LNG units come online over the next two years.
Natural gas and LNG markets have experienced unprecedented price volatility in recent years. 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, we plan to further mitigate our exposure to variability in LNG prices. In addition,2022 and 2023, our revenue and results of operations have benefited from selling cargos into the global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.
Our Current Operations – Ships
Our Ships segment includes Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term arrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we have chartered these vessels for our own operational purposes. The results of operations of vessels utilized in our terminal operations are reflected in the Terminals and Infrastructure segment.
In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of 11 vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were declaredsubject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the winnerrecognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheets as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos.
Our Development Projects
Our projects currently under development include our development of a bid with CFEnergia for theseries of modular liquefaction facilities to provide a source of low-cost supply of natural gasLNG to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons ofcustomers around the world through our Fast LNG (20,700 MMBtu) per day and are in the process of finalizing definitive agreements for this supply.
We are also in the process of developing antechnologies; our LNG regasificationterminal facility and power plant in Puerto Sandino, Nicaragua (the “Puerto(“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); our LNG terminal (“Ireland Facility”) and power plant in Ireland; and our first green hydrogen project ("ZeroPark I"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance
that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.
The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.
We describe each of our current development projects below.
Fast LNG
We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our initial “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 other greenfield alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application.
Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore projects. In February 2020,partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. Our first Fast LNG unit has been deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years.
We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.
Altamira
In the first quarter of 2023, we executed an agreement, which includes conditions to effectiveness that have not been satisfied, with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of commissioning the project.
We have also entered into a non-binding MOU with CFE to develop and operate an onshore liquefied natural gas terminal with up to four 1.4 MTPA FLNG units. The terminal is to be located at the existing Altamira LNG import facility and would source feedgas from the Sur de Texas-Tuxpan Pipeline. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.
Louisiana
In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility which remain subject to review and approval as described under “Risk Factors—Risks Related to Our Business—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.” If constructed, the facility would 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
We have been in discussions 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. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project.
Puerto Sandino Facility
We are developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua, as well as an onshore regasification facility. We have entered into a 25-year power purchase agreementPPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in the processa market that is underserved. We expect to complete this optimization in 2024.
Barcarena Facility
The Barcarena Facility consists of constructing an approximately 300 MW natural gas-fired power plant that will consume approximately 700,000 gallonsFSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing over one million MMBtu from LNG (57,500 MMBtus) per day.
Recent Developments: Hygoday and GMLP Acquisitions
Hygo Acquisition
On January 13, 2021, NFE and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”),storing up to 160,000 cubic meters of LNG. We have entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”)a 15-year gas supply agreement with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo Merger as a wholly owned subsidiary of NFE. AsNorsk Hydro ASA for the supply of natural gas to the date ofAlunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. We substantially completed our Barcarena Facility in 2022 and expect to commence operations, including delivery to the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.
The Hygo Merger is expected to closeAlunorte Alumina Refinery in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions.2024.
Upon completion of the acquisition of Hygo, we expect to acquire one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Terminal”) a 50% interest in a 1.5 GWThe Barcarena Facility will also supply our new 630MW combined cycle thermal power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in developmentto be located in Pará, Brazil (the “Barcarena Terminal”) and Santa Catarina, Brazil (the “Santa Catarina Terminal”Power Plant”). In addition, weThe power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. We expect to acquire Hygo’s vessel fleet, which consistscomplete the Barcarena Power Plant and begin delivering power to nine committed offtakers for 25 years beginning in 2025.
In the fourth quarter of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which may be converted into FSRUs.
GMLP Acquisition
On January 13, 2021,2023, we entered into an Agreement and Planagreement to acquire a 1.6GW PPA in exchange for newly issued 5% NFE redeemable Series A Convertible Preferred Stock, the closing of Merger (the “GMLP Merger Agreement) with Golar LNG Partners LP,which remains subject to customary closing conditions, including regulatory approval for the transfer of the PPA. NFE has applied to transfer the 1.6 GW PPA to a Marshall Islands limited partnership (“GMLP”), Golar GP LLC,site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build a Marshall Islands limited liability company andpower plant to supply the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporatedPPA using gas from the Barcarena Facility. We expect to begin delivering electricity under the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP survivingacquired PPA in July 2026.
We have financed the merger as an indirect subsidiary of NFE (the “GMLP Merger”).
At the effective timedevelopment of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediately prior to the GMLP Effective Time will automatically be converted into the right to receive $3.55 in cash. At the GMLP Effective Time, each of the incentive distribution rights of GMLP will be canceled and cease to exist, and no consideration shall be delivered in respect thereof. Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof. Each outstanding unit representing a general partner interest of GMLP that is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time.
Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General PartnerBarcarena Power Plant pursuant to a Transfer Agreement dated asfinancing agreement. For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in this Annual Report.
Santa Catarina Facility
The Santa Catarina Facility is located on the southern coast of January 13, 2021 forBrazil and consists of an FSRU with a purchase priceprocessing capacity of approximately $5 million, which is equivalent 500,000 MMBtu from LNG per day and LNG storage capacity of up to $3.55 per general partner unit of GMLP.
The GMLP Merger Agreement may be terminated by NFE or GMLP (which,138,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the casemunicipality of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021,Garuva. The Santa Catarina Facility and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million.
The GMLP Merger isassociated pipeline are expected to closehave a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations in the first half of 2021, subject2024.
Ireland Facility
We intend to receiptdevelop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of applicable regulatory approvals, the approvala power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the GMLP Merger Agreementauction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the majoritythird quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the holdersdevelopment of GMLP common units and other customary closing conditions.
Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel, the Hilli, which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support our existing facilities and international project pipeline. The majority of the FSRUs in GMLP’s fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters. GMLP’s uncontracted vessels are available for short term employment in the spot market.
Suape Development
On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GWpower plant. We are challenging this decision. The continued development of gas-fired power at the Port of Suape in the city of Ipojuca, State of Pernambuco, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.(“ Pecém”)this project is uncertain and Energética Camaçari Muricy II S.A (“Muricy”). These companies collectively hold certain 15-year power purchase agreements totaling 288 MW forthere are multiple risks, including regulatory risks, that could preclude the development of this project, and the thermoelectric power plants in the Stateresults of Bahia, Brazil. We will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Portthese risks could have a material effect on our results of Suape and update the technical characteristics in orderoperations.
ZeroParks
In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to constructbuild a 288MW gas-fired power plantportfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumersreliable electrolyzer technologies.
Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within the port complex and across the greater Northeast region of Brazil.
COVID-19 Pandemic
We are closely monitoring the impacta 10-mile radius of the novel coronavirus (“COVID-19”) pandemic on all aspects of our operationstwo largest refineries in the western hemisphere and development projects. We primarily operate under long-term contracts with customers,numerous petrochemical manufacturers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis.require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have continuedcommenced design, engineering and permitting for ZeroPark I and expect to invoice our customers for these fixed minimum volumes even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been deteriorationcommence operations on the first phase in the timing or volumefirst half of collections.2025. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect our Beaumont Facility to be the largest green hydrogen plant in the United States.
Based on the essential natureRecent Developments
On February 14, 2024, we completed a transaction to sell substantially all of our stake in Energos, receiving proceeds of approximately $136.4 million. As a result of the servicestransaction, we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-beingrecognized an other than temporary impairment of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendorsinvestment in Energos of $5.3 million for COVID-19 symptoms upon entering our development projects, operations and office facilities. For the year ended December 31, 2020,2023, and this loss was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income.
On February 28, 2024, we have incurred approximately $1.2entered into a commitment letter for the Company to receive $700 million for safety measures introduced intoin financing secured by our operationsonshore FLNG project in Altamira, Mexico as well as the collateral securing the 2025 Notes and other responsesthe 2026 Notes. The commitment letter is subject to the COVID-19 pandemic.finalization of a credit agreement and customary closing conditions. The proceeds will be used to complete our onshore FLNG project in Altamira.
We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects and daily operations during the year ended December 31, 2020 from the COVID-19 pandemic; however, there are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures. We do not currently expect these factors to have a significant impact on our results of operations, liquidity or financial position, or our development budgets or timelines.
Other Matters
WeOn June 18, 2020, we received an order from the Federal Energy Regulatory Commission (“FERC”("FERC") on June 18, 2020,, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the Natural Gas Act. WhileNGA. 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. The matterOn 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 raisedSeptember 15, 2021, but also found that allowing operation of the San Juan Facility to continue during athe pendency of an application is in the public interest. FERC open meeting heldalso concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.
On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 19, 2021 but was30, 2024, FERC reaffirmed the order allowing the construction and operation to continue.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows are not resolved, is on the agenda during the FERC open meetingindicative of results of operations and cash flows to be held on March 18, 2021,expected in the future, principally for the following reasons:
• and remains pending. WeOur historical financial results do not know ifreflect 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 99% of our
LNG volumes from third parties for the year ended December 31, 2023. We anticipate that the deployment of Fast LNG liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers. We expect to deploy our first Fast LNG unit upon the completion of commissioning in 2024.
•Our historical financial results do not include significant projects that have recently been completed or when FERCare near completion. Our results of operations for the year ended December 31, 2023 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed our La Paz Facility in service in 2021, and in the third quarter of 2023, we placed the La Paz Power Plant into service. We have executed agreements to extend and amend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur, and as such, our revenue and results of operations have begun to be impacted by our operations in Mexico.We are also continuing to develop our Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects.
Additionally, we began to deliver power to the Puerto Rican grid from the Palo Seco Power Plant as part of the grid stabilization project in the second quarter of 2023. At the end of September 2023, we placed additional power generation assets in service at the San Juan Power Plant. We expect that our power generation assets at both the Palo Seco Power Plant and at the San Juan Power Plant will respondoperate at full capacity, and we expect that our revenue and results of operations will benefit from significant gas consumption required to operate these assets.
•Our historical financial results include the results from our reply,investments in the common units of Hilli LLC and CELSEPAR. On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC (“Hilli Common Units”), disponent owner and operator of the Hilli Episeyo (the “Hilli”) through its subsidiary Golar Hilli Corporation, in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). In the fourth quarter of 2022, we sold our interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), the indirect owner of the Sergipe Power Plant in Brazil. As a result of these transactions, we no longer have any ownership interest in either the Hilli or the outcomeSergipe Power Plant, and their results will no longer be included in NFE's results of any such response.operations.
Results of Operations – Three Months Ended December 31, 2023 compared to Three Months Ended September 30, 2023 and Year Ended December 31, 20202023 compared to Year Ended December 31, 2019 (in thousands)2022
| | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | Change | |
| Revenues | | | | | | | | | |
| Operating revenue | | $ | 318,311 | | | $ | 145,500 | | | $ | 172,811 | |
| Other revenue | | | 133,339 | | | | 43,625 | | | | 89,714 | |
| Total revenues | | | 451,650 | | | | 189,125 | | | | 262,525 | |
| Operating expenses | | | | | | | | | | | | |
| Cost of sales | | | 278,767 | | | | 183,359 | | | | 95,408 | |
| Operations and maintenance | | | 47,581 | | | | 26,899 | | | | 20,682 | |
| Selling, general and administrative | | | 124,170 | | | | 152,922 | | | | (28,752 | ) |
| Contract termination charges and loss on mitigation sales | | | 124,114 | | | | 5,280 | | | | 118,834 | |
| Depreciation and amortization | | | 32,376 | | | | 7,940 | | | | 24,436 | |
| Total operating expenses | | | 607,008 | | | | 376,400 | | | | 230,608 | |
| Operating loss | | | (155,358 | ) | | | (187,275 | ) | | | 31,917 | |
| Interest expense | | | 65,723 | | | | 19,412 | | | | 46,311 | |
| Other expense (income), net | | | 5,005 | | | | (2,807 | ) | | | 7,812 | |
| Loss on extinguishment of debt, net | | | 33,062 | | | | - | | | | 33,062 | |
| Loss before taxes | | | (259,148 | ) | | | (203,880 | ) | | | (55,268 | ) |
| Tax expense | | | 4,817 | | | | 439 | | | | 4,378 | |
| Net loss | | $ | (263,965 | ) | | $ | (204,319 | ) | | $ | (59,646 | ) |
RevenuesConsolidated 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 from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.
Operating revenue fromThe tables below present our segment information for the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilitiesthree months ended December 31, 2023 and September 30, 2023, and for the year ended December 31, 2020 was $318,311 which2023 and December 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended December 31, 2023 |
| (in thousands of $) | | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | | $ | 695,068 | | | $ | 63,290 | | | $ | 758,358 | | | $ | — | | | $ | 758,358 | |
Cost of sales(4) | | $ | 259,976 | | | — | | | 259,976 | | | (1,491) | | | 258,485 | |
Vessel operating expenses(5) | | — | | | 9,092 | | | 9,092 | | | — | | | 9,092 | |
Operations and maintenance(5) | | $ | 61,938 | | | — | | | 61,938 | | | — | | | 61,938 | |
| Segment Operating Margin | | $ | 373,154 | | | $ | 54,198 | | | $ | 427,352 | | | $ | 1,491 | | | $ | 428,843 | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Three Months Ended December 31, 2023 |
| (in thousands of $) | | | | | | | | | | Consolidated |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Gross margin (GAAP) | | | | | | | | | | $ | 366,679 | |
| Depreciation and amortization | | | | | | | | | | 62,164 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 428,843 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2023 |
| (in thousands of $) | | Terminals and Infrastructure(1) | | Ships(2) | | Total Segment | | Consolidation and Other(3) | | Consolidated |
| Total revenues | | $ | 447,905 | | | $ | 66,557 | | | $ | 514,462 | | | $ | — | | | $ | 514,462 | |
Cost of sales(4) | | 208,683 | | | — | | | 208,683 | | | (423) | | | 208,260 | |
Vessel operating expenses(5) | | — | | | 11,613 | | | 11,613 | | | — | | | 11,613 | |
Operations and maintenance(5) | | 44,479 | | | — | | | 44,479 | | | — | | | 44,479 | |
| Segment Operating Margin | | $ | 194,743 | | | $ | 54,944 | | | $ | 249,687 | | | $ | 423 | | | $ | 250,110 | |
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| Three Months Ended September 30, 2023 |
| (in thousands of $) | | | | | | | | | | Consolidated |
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| Gross margin (GAAP) | | | | | | | | | | $ | 201,440 | |
| Depreciation and amortization | | | | | | | | | | 48,670 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 250,110 | |
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| | Year Ended December 31, 2023 |
| (in thousands of $) | | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Total revenues | | $ | 2,141,085 | | | $ | 293,605 | | | $ | 2,434,690 | | | $ | (21,394) | | | $ | 2,413,296 | |
Cost of sales(4) | | 764,828 | | | — | | | 764,828 | | | 112,623 | | | 877,451 | |
Vessel operating expenses(5) | | — | | | 51,387 | | | 51,387 | | | (5,948) | | | 45,439 | |
Operations and maintenance(5) | | 166,785 | | | — | | | 166,785 | | | — | | | 166,785 | |
| Segment Operating Margin | | $ | 1,209,472 | | | $ | 242,218 | | | $ | 1,451,690 | | | $ | (128,069) | | | $ | 1,323,621 | |
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| Year Ended December 31, 2023 |
| (in thousands of $) | | | | | | | | | | Consolidated |
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| Gross margin (GAAP) | | | | | | | | | | $ | 1,136,297 | |
| Depreciation and amortization | | | | | | | | | | 187,324 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 1,323,621 | |
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| | Year Ended December 31, 2022 |
| (in thousands of $) | | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Total revenues | | $ | 2,168,565 | | | $ | 444,616 | | | $ | 2,613,181 | | | $ | (244,909) | | | $ | 2,368,272 | |
Cost of sales(4) | | 1,142,374 | | | — | | | 1,142,374 | | | (131,946) | | | 1,010,428 | |
Vessel operating expenses(5) | | — | | | 90,544 | | | 90,544 | | | (27,026) | | | 63,518 | |
Operations and maintenance(5) | | 129,970 | | | — | | | 129,970 | | | (24,170) | | | 105,800 | |
| Segment Operating Margin | | $ | 896,221 | | | $ | 354,072 | | | $ | 1,250,293 | | | $ | (61,767) | | | $ | 1,188,526 | |
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| Year Ended December 31, 2022 |
| (in thousands of $) | | | | | | | | | | Consolidated |
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| Gross margin (GAAP) | | | | | | | | | | $ | 1,045,886 | |
| Depreciation and amortization | | | | | | | | | | 142,640 | |
| Consolidated Segment Operating Margin (Non-GAAP) | | | | | | | | | | $ | 1,188,526 | |
(1)Prior to the completion of the sale of our ownership interest in CELSEPAR, Terminals and Infrastructure included our effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR. Terminals and Infrastructure does not include the unrealized mark-to-market gains on derivative instruments of $1.5 million and $0.4 million for the three months ended December 31, 2023 and September 30, 2023, respectively. The segment measure also excludes losses and gains of $106.4 million and $106.1 million for the years ended December 31, 2023 and 2022, respectively, reported in Cost of sales.
(2)Prior to the Hilli Exchange, Ships included our effective share of revenues, expenses and operating margin attributable to our 50% ownership of the Hilli Common Units.
(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 and Hilli Common Units in our segment measure prior to the disposition of these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments and the exclusion of non-capitalizable contract acquisition costs.
(4)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive Income.
(5)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 as defined under GAAP.
Terminals and Infrastructure Segment
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| Three Months Ended, | | |
| (in thousands of $) | December 31, 2023 | | September 30, 2023 | | Change | | | | | | | | | | |
| Total revenues | $ | 695,068 | | | $ | 447,905 | | | $ | 247,163 | | | | | | | | | | | |
| Cost of sales (exclusive of depreciation and amortization) | $ | 259,976 | | | 208,683 | | | 51,293 | | | | | | | | | | | |
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| Operations and maintenance | 61,938 | | | 44,479 | | | 17,459 | | | | | | | | | | | |
| Segment Operating Margin | $ | 373,154 | | | $ | 194,743 | | | $ | 178,411 | | | | | | | | | | | |
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| Year Ended, |
| (in thousands of $) | December 31, 2023 | | December 31, 2022 | | Change |
| Total revenues | $ | 2,141,085 | | | $ | 2,168,565 | | | $ | (27,480) | |
| Cost of sales (exclusive of depreciation and amortization) | 764,828 | | | 1,142,374 | | | (377,546) | |
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| Operations and maintenance | 166,785 | | | 129,970 | | | 36,815 | |
| Segment Operating Margin | $ | 1,209,472 | | | $ | 896,221 | | | $ | 313,251 | |
Total revenue
Total revenue for the Terminals and Infrastructure Segment increased by $172,811$247.2 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. The increase was primarily driven by additional volumes delivered in Puerto Rico, and increases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment.
•Volumes delivered to downstream terminal customers increased from $145,50020.1 TBtus in the third quarter of 2023 to 22.2 TBtu in the fourth quarter of 2023. We continue to support the grid stabilization project in Puerto Rico, and we recognized a full quarter of operations for our San Juan Power Plant during the fourth quarter; we completed the commissioning of these additional power assets at the San Juan Power Plant in September 2023. We also realize higher margins for volumes delivered at the temporary power plants at Palo Seco and San Juan, and our segment operating margin in the fourth quarter benefited from delivering additional volumes to these projects.
•The average Henry Hub index pricing used to invoice our downstream customers increased by 13% for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023.
Total revenue for the Terminals and Infrastructure Segment decreased by $27.5 million for the year ended December 31, 2019. The increase was primarily driven by volumes sold from the Old Harbour Terminal, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020:
For2023 as compared to the year ended December 31, 2020, we recognized $189,1962022. The decrease was primarily driven by lower LNG cargo sales, no pro rata share of revenue from volumes sold atour former investment in CELSEPAR and a reduction in the Old Harbour Facility, asHenry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. The decrease in revenue was partially offset by increased revenue from sales to downstream terminal customers.
The decrease in revenue in the year ended December 31, 2023 when compared to $41,229the year ended December 31, 2022 was primarily attributable to the following:
•LNG cargo sales to third parties decreased by $557.4 million for the year ended December 31, 2019. Revenue recognized2023, decreasing from $1,175.9 million for the year ended December 31, 2020 included $112,334 from sales2022 to the Old Harbour Power Plant and $76,862 from natural gas utilized in the CHP Plant and Jamalco’s boilers. For the year ended December 31, 2020, the volume delivered to the Old Harbour Power Plant was 96.0$618.5 million gallons (8.0 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 96.2 million gallons (7.9 TBtu). For the year ended December 31, 2019, the volume delivered to the Old Harbour Power Plant was 22.2 million gallons (1.9 TBtu).
Additional revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco added $23,062 in revenue for the year ended December 31, 2020.
Operating revenue was also impacted by operations at2023. In the second half of 2023, we utilized all LNG purchased under our Montego Bay Facility, includinglong-term supply contracts for sales to our downstream terminal customers.
•After the following:
In connection withcompletion of the adoptionsale of ASC 842,our investment in CELSEPAR in the fourth quarter of 2022, we no longer identify a lease of the Montego Bay Facilityrecognize revenue from this investment in our gas sale agreement with our customer. Accordingly, interest income associated with the direct financing leasesegment measure. Our share of the Montego Bay Facility is no longer recognized within Other revenue and all amounts recognized as revenue for activities at the Montego Bay Facility were included in Operating revenuefrom CELSEPAR was $148.3 million for the year ended December 31, 2020, resulting in an increase2022, which was primarily comprised of $15,771fixed capacity payments received under related PPAs.
•The average Henry Hub index pricing used to Operating revenue.
| • | The increase in Operating revenue is partially offset by a decrease in sales at the Montego Bay Facility. The decrease in sales at the Montego Bay Facility was primarily due to a decrease in sales volume delivered to the Bogue Power Plant. Revenue from sales at the Montego Bay Facility decreased $14,399 to $77,464 for the year ended December 31, 2020 as compared to $91,863 for the year ended December 31, 2019. The delivered volume at the Montego Bay Facility decreased by 16.3 million gallons (1.2 TBtu) from 110.5 million gallons (9.1 TBtu) during the year ended December 31, 2019 to 94.2 million gallons (7.9 TBtu) during the year ended December 31, 2020.
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Other revenue includes revenue from development services, which is recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allowinvoice our downstream customers to receive power or other outputs from our power generation facilities, and such services are included within certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Other revenue increased $89,714decreased by 59% for the year ended December 31, 20202023 as compared to the year ended December 31, 2019, and2022.
Such decrease was offset by increases to revenue in the increases wereyear ended December 31, 2023 when compared to the year ended December 31, 2022, due to the following:
Increase of $113,777 for development services in Puerto Rico•Volumes delivered to downstream customers were 68.3 TBtu for the year ended December 31, 2020, including conversion of the customer’s infrastructure within the San Juan Power Plant and gas used by our customer for testing and commissioning their assets. Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of 129.5 million gallons (10.7 TBtu) of natural gas as part of commissioning their assets.
Lower revenue recognized for the infrastructure projects for customers of the CHP Plant. For the year ended December 31, 2020, we recognized $601 for the completion of infrastructure projects for customers of the CHP Plant,2023 as compared to $11,93339.5 TBtu for the year ended December 31, 2019.2022, and these increased volumes were primarily attributable to our operations in Puerto Rico, Jamaica and Mexico.
•In May 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets at the Palo Seco Power Plant. In September 2023, we finished commissioning additional power generation assets at the San Juan Power Plant. We have delivered 13.3 TBtu at a higher margin at these power plants during the year ended December 31, 2023.
Cost of sales
Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities, power generation facilities or to our customers.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 $51.3 million for the yearthree months ended December 31, 2020 was $278,767 which2023 as compared to the three months ended September 30, 2023.
•Cost of LNG purchased from third parties for sale to our downstream customers increased $95,408 from $183,359by $25.7 million for the yearthree months ended December 31, 2019.
Cost2023 as compared to the three months ended September 30, 2023. The increase was primarily attributable to a 10% increase in volumes delivered compared to the three months ended September 30, 2023. The weighted-average cost of LNG purchased from third parties for sale to our customers or deliveredincreased from $6.78 per MMBtu for commissioningthe three months ended September 30, 2023 to $7.08 per MMBtu for the three months ended December 31, 2023
•We also incurred additional costs of $19.6 million to make reimbursable improvements to our customer’s assets inthat are utilized as part of the Puerto Rico increased $92,433Rican grid stabilization project. The reimbursement of these costs has been recognized as Other revenue.
Cost of sales decreased by $377.5 million for the year ended December 31, 20202023 as compared to the year ended December 31, 2019. The increase2022.
•We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $310.3 million during the year ended December 31, 2023.
•During the year ended December 31, 2023, realized gains of $139.1 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales. For segment performance measures, unrealized mark to market gains and losses are excluded until settled.
•Cost of sales for the year ended December 31, 2022 included $28.6 million of our share of cost of sales from our investment in CELSEPAR, which was primarily attributablecomprised of LNG costs to fuel a power plant owned by CELSEPAR.
•We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $48.0 million during the increaseyear ended December 31, 2023 due to increased volumes delivered; we delivered 74% more volumes to our downstream terminal customers in volumes delivered of approximately 200%the current period as compared to the year ended December 31, 2019, partially offset by the decrease in2022. While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG cost. The weighted-average cost of LNG purchased from third parties decreased from $0.73for delivery to such customers was substantially lower, decreasing to $7.23 per gallon ($8.81 per MMBtu)MMBtu for the year ended December 31, 2019 to $0.462023 from $10.84 per gallon ($5.58 per MMBtu)MMBtu for the year ended December 31, 2020. 2022.
•We recognized additional payroll and other operating costs of $35.6 million to provide services under Genera's operations and maintenance contract.
The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 20202023 and 2019 was $0.40 per gallon ($4.81 per MMBtu) and $0.64 per gallon ($7.70 per MMBtu), respectively.
Charter costs associated with our expanded fleet increased Cost of sales by $5,763 for the year ended December 31, 2020. The increase2022 was attributable to a full year of charter costs of the Old Harbour Facility in 2020 as well as additional costs associated with our San Juan Facility after the assets were placed in service in the third quarter of 2020.
The increase in Cost of sales was partially offset by a decrease in costs associated with the infrastructure projects for customers of the CHP Plant$7.33 per MMBtu and conversion of our customer’s infrastructure within the San Juan Power Plant of $11,482 as compared to the year ended December 31, 2019.
Operations and maintenance
Operations and maintenance includes costs of operating our Facilities,facilities, exclusive of costs to convert that are reflected in Cost of sales.
Operations and maintenance increase by $17.5 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023, which was primarily related to additional vessel costs incurred in our terminal operations as costs related to the Winter and Princess are recognized in our terminal costs following the conclusion of these vessels long-term charters.
Operations and maintenance increased by $36.8 million for the year ended December 31, 20202023 as compared to the year ended December 31, 2022, which was $47,581,attributable to the following activity:
•In 2023, we leased turbines to generate power at the Palo Seco Power Plant as part of the grid stabilization project in Puerto Rico. We also undertook activities to ensure that we have LNG supply available for our expanded Puerto
Rican operations, including leasing berth space to place a storage vessel to service Puerto Rico, increasing operations and maintenance costs when compared to the prior year.
•These increases were partially offset by the exclusion of our share of Operations and maintenance from the investment in CELSEPAR; after the sale of our investment in CELSEPAR in the fourth quarter of 2022, we do not include these costs during the year ended December 31, 2023.
Ships Segment
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| Three Months Ended, | | |
| (in thousands of $) | December 31, 2023 | | September 30, 2023 | | Change | | | | | | | | | | |
| Total revenues | $ | 63,290 | | | $ | 66,557 | | | $ | (3,267) | | | | | | | | | | | |
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| Vessel operating expenses | 9,092 | | | 11,613 | | | (2,521) | | | | | | | | | | | |
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| Segment Operating Margin | $ | 54,198 | | | $ | 54,944 | | | $ | (746) | | | | | | | | | | | |
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| Year Ended, |
| (in thousands of $) | December 31, 2023 | | December 31, 2022 | | Change |
| Total revenues | $ | 293,605 | | | $ | 444,616 | | | $ | (151,011) | |
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| Vessel operating expenses | 51,387 | | | 90,544 | | | (39,157) | |
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| Segment Operating Margin | $ | 242,218 | | | $ | 354,072 | | | $ | (111,854) | |
Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. Prior to the completion of the Energos Formation Transaction, we also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook. We included the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements represented our ongoing ordinary business operations.
On March 15, 2023, we completed the "Hilli Exchange. In the fourth quarter of 2022, we recognized a loss on the investment in Hilli LLC of $118.6 million; this loss was recognized in Loss from equity method investments in the Consolidated Statements of Operations and Comprehensive Income. Upon completion of the Hilli Exchange during the first quarter of 2023, we recognized an additional loss on disposal of $37.4 million, which increased $20,682was included in Other expense (income), net. As a result of the Hilli Exchange we no longer have an ownership interest in the Hilli. NFE shares received from $26,899GLNG were cancelled upon the closing of the Hilli Exchange.
As of December 31, 2023, three FSRUs and one LNG carrier were leased to customers under long-term arrangements. In July 2023, we sold the vessel Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. The gain on sale is included in Gain on sale of assets, net in the Consolidated Statements of Operations and Comprehensive Income. In December 2023, we entered into an agreement to sell the vessel Mazo, for $22.4 million; the sale closed in the first quarter of 2024, and as such, the vessel has been classified as held for sale as of December 31, 2023. In conjunction with the classification as held for sale, the Company recognized an impairment of $10.9 million within Asset impairment expense in the Consolidated Statements of Operations and Comprehensive Income.
Total revenue
Total revenue for the Ships segment decreased $3.3 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of vessels included in the transaction (except the Nanook), and as such, we continue to recognize revenue from the charter of these vessels to third parties. The decrease in revenue was primarily driven by end of third-party charter of Winter and Princess during the fourth quarter of 2023.
Total revenue for the Ships segment decreased by $151.0 million for the year ended December 31, 2019. 2023 as compared to the year ended December 31, 2022. The increase isdecrease in revenue was primarily athe result of higher logistics coststhe sale of $the 9,727Nanook as part of the Energos Formation Transaction; we no longer recognize revenue related to the Nanook in 2023. After the Hilli
Exchange at the end of the first quarter of 2023, we no longer recognize revenue from the Hilli, further decreasing revenue in the Ships segment. Additionally the charters for two vessels concluded in the first quarter of 2023 and the charters for another two vessels concluded in the fourth quarter of 2023, lowering vessel revenue for the year ended December 31, 20202023. We plan to utilize these vessels in our operations following conversion and other upgrades starting in 2024.
Vessel operating expenses
, primarilyVessel operating expenses include direct costs associated with the operations of additional charter vessels deployed. Operationsoperating 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 increasedrecognize 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.5,425
Vessel operating expenses decreased by $2.5 million for the three months ended December 31, 2023, compared to the three months ended September 30, 2023 primarily due to end of third-party charter of Winter and Princess during the fourth quarter of 2023.
Vessel operating expenses decreased by $39.2 million for the year ended December 31, 20202023 as compared to the year ended December 31, 2022. forThe decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the Hilli Exchange at the end of operating the CHP Plant forfirst quarter of 2023. During 2023, the period after commencement of commercial operations in March 2020 and by $5,698 for costs of operating the San Juan Facility after our assetsCompany started using four vessels that were placed in service in the Ships segment in 2022 for its terminal operations, resulting in lower vessel operating costs. The costs also decreased as a result of the sale of the thirdNanook quarteras part of the Energos Formation Transaction; we recognized vessel operating expenses related to the 2020.Nanook during 2022 and no longer recognize vessel operating expenses related to the Nanook in 2023.
Other operating results
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| Three Months Ended, | | Year Ended, | | |
| (in thousands of $) | December 31, 2023 | | September 30, 2023 | | Change | | December 31, 2023 | | December 31, 2022 | | Change | | | | | | |
| Selling, general and administrative | $ | 48,056 | | | $ | 49,107 | | | $ | (1,051) | | | $ | 205,104 | | | $ | 236,051 | | | $ | (30,947) | | | | | | | |
| Transaction and integration costs | 2,159 | | | 2,739 | | | (580) | | | 6,946 | | | 21,796 | | | (14,850) | | | | | | | |
| Depreciation and amortization | 62,164 | | | 48,670 | | | 13,494 | | | 187,324 | | | 142,640 | | | 44,684 | | | | | | | |
| Asset impairment expense | 10,958 | | | — | | | 10,958 | | | 10,958 | | | 50,659 | | | (39,701) | | | | | | | |
| Gain on sale of assets, net | (21,534) | | | (7,844) | | | (13,690) | | | (29,378) | | | — | | | (29,378) | | | | | | | |
| Total operating expenses | 101,803 | | | 92,672 | | | 9,131 | | | 380,954 | | | 451,146 | | | (70,192) | | | | | | | |
| Operating income | 327,040 | | | 157,438 | | | 169,602 | | | 942,667 | | | 737,380 | | | 205,287 | | | | | | | |
| Interest expense | 76,951 | | | 64,822 | | | 12,129 | | | 277,842 | | | 236,861 | | | 40,981 | | | | | | | |
| Other expense (income), net | (13,586) | | | 5,573 | | | (19,159) | | | 10,408 | | | (48,044) | | | 58,452 | | | | | | | |
| Loss on extinguishment of debt, net | — | | | — | | | — | | | — | | | 14,997 | | | (14,997) | | | | | | | |
| Income before income from equity method investments and income taxes | 263,675 | | | 87,043 | | | 176,632 | | | 654,417 | | | 533,566 | | | 120,851 | | | | | | | |
| Income (loss) from equity method investments | (2,766) | | | 489 | | | (3,255) | | | 9,972 | | | (472,219) | | | 482,191 | | | | | | | |
| Tax provision (benefit) | 46,037 | | | 25,194 | | | 20,843 | | | 115,513 | | | (123,439) | | | 238,952 | | | | | | | |
| Net income | $ | 214,872 | | | $ | 62,338 | | | $ | 152,534 | | | $ | 548,876 | | | $ | 184,786 | | | $ | 364,090 | | | | | | | |
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 for the yearthree months ended December 31, 2020, was $124,170 which2023 decreased $28,752 from $152,922by $1.1 million as compared to the three months ended September 30, 2023.
Selling, general and administrative decreased by $30.9 million for the year ended December 31, 2019.2023, compared to the year ended December 31, 2022. The decrease wasdecreases were primarily attributabledue to decreasedlower share-based compensation expense, of $32,651,as we did not recognize any cost related to employee performance share units in 2023, as well as decreases tolower professional fees and screening costs.
Transaction and integration costs
For the three months ended December 31, 2023, we did not incur significant transaction and integration costs as compared to the prior quarter.
For the year ended December 31, 2023, we incurred $6.9 million for transaction and integration costs, as compared to $21.8 million for the year ended December 31, 2022. In the prior year, we incurred transaction and integration costs primarily associated with the sale of $3,743,our investment in CELSEPAR and the Energos Formation Transaction, and there were no such similar significant transactions during the year-ended December 31, 2023.
Depreciation and amortization
Depreciation and amortization increased by $13.5 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. In September 2023, we placed assets at the San Juan Power Plant in service as part of the grid stabilization project in Puerto Rico. Additionally, in September 2023 we placed our La Paz Power Plant into partial service, and we recognized a full quarter of depreciation in the fourth quarter of 2023.
Depreciation and amortization increased by $44.7 million for the year ended December 31, 2023 as compared to the year ended December 31, 2019. These decreases were partially offset by $8,3442022, primarily the result of higher payroll costsassets including turbines placed into service as part of the grid stabilization project at the Palo Seco Power Plant and San Juan Power Plant during 2023.
Asset impairment expense
As a result of our acquisition of Hygo Energy Transition Limited in 2021, we recognized long-lived assets associated with increased headcount.
Contract termination charges and loss on mitigation sales
Contract termination charges and loss on mitigation sales for the years ended December 31, 2020 and 2019 was $124,114 and $5,280, respectively. Through 2020, the pricing of LNG in the open market was significantly lower than the pricing in our LNG supply agreement with Centrica. In June 2020, we executed an agreement to terminate our obligation to purchase LNG from Centrica for the remainder of 2020 in exchange for a payment of $105,000, and we recognized this cancellation charge during the second quarter of 2020. We terminated our obligation in the second quarter of 2020 to, among other reasons, take advantageexpansion of the low pricing inSergipe Power Plant. During the open market and to align future deliveries of LNG with our expected needs. We purchased LNG in the open market for the remainder of our needs in 2020, significantly reducing our LNG supply cost from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 20192022, we recognized asset impairment expense of $50.7 million, as the fair value of these assets was less than the carrying value, and the asset group was held for sale. In December 2023, we entered into an agreement to $0.46 per gallon ($5.58 per MMBtu)sell the vessel Mazo, for $22.4 million; the sale closed in the first quarter of 2024. The vessel has been classified as held for sale as of December 31, 2023, and in conjunction with the classification as held for sale, the Company recognized an impairment of $10.9 million.
Gain on sale of assets, net
In July 2023, we sold the vessel Golar Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. In addition, during the fourth quarter of 2023, we completed the sale of 100% of shares of Pecém and Muricy for a total gain of $21.5 million.
Interest expense
Interest expense increased by $12.1 million for the yearthree months ended December 31, 2020.
We experienced lower than expected consumption by some of our customers in2023 as compared to the second quarter of 2020, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica. As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was recognized during the second quarter of 2020.
Loss on mitigation sales for the yearthree months ended December 31, 2019 was $5,280 which was attributable to losses incurred associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints.
Depreciation and amortization
Depreciation and amortization for the year ended December 31, 2020 was $32,376, which increased $24,436 from $7,940 for the year ended December 31, 2019.September 30, 2023. The increase was primarily due to the following:
Increase in depreciation of $3,582 for our Old Harbour Facility that went into service in June 2019;
Increase in depreciation of $9,515 for the CHP Plant that went into service in March 2020;
Increase in depreciation of $4,484 for the San Juan Facility that went into service in July 2020;
Additional depreciation of $4,499 recognizedhigher borrowing costs on our Montego Bay Facility during the year. These assets were presented as direct financing leases prior to the adoption of ASC 842,Term Loan B (defined below) issued in October 2023 and no depreciation for such assets was previously recorded.Barcarena Debentures (defined below) issued in November 2023.
Interest expense
Interest expense increased by $41.0 million for the year ended December 31, 20202023, as compared to the year ended December 31, 2022. The increase was $65,723,primarily due to an increase in total principal outstanding, including obligations incurred as a result of the Energos Formation Transaction, under which increased $46,311 from $19,412we incur higher borrowing costs. The total principal balance on outstanding facilities was $6.9 billion as of December 31, 2023 as compared to total outstanding debt of $4.6 billion as of December 31, 2022.
Other expense (income), net
Other income, net and other expense, net was $13.6 million and $5.6 million for the three months ended December 31, 2023 and September 30, 2023, respectively. Other expense, net and Other income, net was $10.4 million and $48.0 million for the year ended December 31, 2019, primarily as a result of the additional principal balances outstanding during 2020 under the Credit Agreement, Senior Secured Bonds2023 and Senior Unsecured Bonds, as compared to the Term Loan Facility (all defined below). When the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds were replaced by the Senior Secured Notes in September 2020, the outstanding principal balances totaled $980,000, as compared to the Term Loan Facility principal amount as of December 31, 2019 of $495,000, which had been extinguished2022, respectively.
Other income, net recognized in January 2020. As ofthe three months ended December 31, 2020, we have issued $1,250,0002023 was primarily comprised of Senior Secured Notes.
Other expense, (income), net
Other expense (income), net forrecognized in the year ended December 31, 20202023 was $5,005, which increased $7,812 from incomeprimarily comprised of ($2,807) forloss on disposal of our equity method investment in Hilli LLC in the year ended December 31, 2019, primarily as a resultHilli Exchange during the first quarter of 2023. The losses were partially offset by the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG, a decrease in interest income and an increase in unrealized lossgains on our investment in equity securities.
Loss on extinguishment of debt net
Loss on extinguishment of debt was $33,062$15.0 million for the year ended December 31, 20202022 as a result of the extinguishment of the Credit Agreement, Senior Secured Bondscertain debt facilities and Senior Unsecured Bonds in September 2020, as well assale leaseback financing arrangements with VIEs with proceeds from the loss recognized upon the extinguishment of the Term Loan Facility in January 2020. Loss on extinguishment of debt for the year ended December 31, 2019 was $0 as weEnergos Formation Transaction. We did not have any such transactions during the year.year ended December 31, 2023.
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We recognized a loss from our investment in Energos of $2.8 million for the three months ended December 31, 2023 as compared to income of $0.5 million and for the three months ended September 30, 2023. We have entered into a Unit Purchase Agreement to sell substantially all of our stake in the Energos, and as a result of the transaction, we recognized an other than temporary impairment ("OTTI") totaling $5.3 million.
Tax expense
Tax expense$10.0 million for the year ended December 31, 2020 was $4,817, which increased $4,3782023. For the year ended December 31, 2022, we recognized losses from our equity method investments of $472.2 million. The losses were primarily driven by an other than temporary impairment of the investments in CELSEPAR and Hilli LLC of $487.8 million recognized in connection with the announced sale of these investments, partially offset by income attributable to our investments in Energos.
Tax provision
We recognized a tax expenseprovision of $439$115.5 million for the year ended December 31, 2019. During 2020, the CHP Plant began operations and we placed our assets at the San Juan Facility in service. Certain2023 compared to a tax benefit of our Jamaican operations had increased earnings for$123.4 million year ended December 31, 2022. For the year ended December 31, 2020 without any historical net operating losses to offset additional2023, the tax expense. We have recognizedprovision was primarily driven by domestic income tax expense from significant income generated by our foreign operations on our domestic tax expense; this additional U.S. tax expense was partially offset by the tax benefit from the utilization of foreign tax credits.
For the year ended December 31, 2022, we reflected an excess benefit from stock compensation of $24.4 million. Prior to the completion of the sale of our investment in Puerto Rico atCELSEPAR, our equity method investment in CELSEPAR was directly held by a preferential tax rate due to our tax decreesubsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil, resulting in an effective tax rate lower than the U.S. federal income tax rate. We continue to have valuation allowances in manya discrete benefit of our foreign jurisdictions and tax expense for earnings generated in many foreign jurisdictions has been limited.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected$76.5 million recognized in the future, principally forfirst quarter of 2022. Additionally, in the following reasons:second and third quarters of 2022, we recognized an impairment on the value of this investment, resulting in a further discrete benefit of $122.4 million.
| • | Our historical financial results do not include significant projects that have recently been completed or are near completion.Our results of operations for the year ended December 31, 2020 include our Montego Bay Facility, Miami Facility, sales from our Old Harbour Facility to SJPC, and certain industrial end-users. The CHP Plant commenced commercial operations during March 2020, and our results now include revenue and results operations from sales of gas, power and steam from the CHP Plant. We also completed the development of our San Juan Facility in third quarter of 2020, and in the second quarter of 2020, we began to deliver natural gas to the San Juan Power Plant for PREPA to use in the commissioning of their assets. Our current results do not include revenue and operating results from other projects under development including the La Paz Facility, the Puerto Sandino Facility, or the Ireland Facility.
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| • | Our historical financial results do not reflect changes to our current long-term LNG supply agreement as well as new LNG supply agreements that will lower the cost of our LNG supply through 2030. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the year ended December 31, 2020. In June 2020, we entered into an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of $105,000, and for the remainder of 2020, we purchased all volumes needed for our operations on the open market, significantly reducing our LNG supply costs from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020. During 2020, we also entered into four LNG supply agreements for the purchase of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement.
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| • | Our historical financial results do not include the anticipated acquisitions of Hygo and GMLP as well as transaction and integration costs expected to be incurred associated with these acquisitions. Upon completion of the acquisition of Hygo, we expect to acquire the Sergipe Terminal, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Terminal and the Santa Catarina Terminal that are currently in development. In addition, we expect to acquire one FSRU in service at the Sergipe Terminal and two operating LNG carriers which may be converted into FSRUs. Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel. The results of operations of Hygo and GMLP will begin to be included in our financial statements upon the closing of the acquisitions, expected in the first half of 2021. Our results of operations in 2021 will also include transaction costs associated with these acquisitions as well as costs incurred to integrate the operations of Hygo and GMLP into our business.
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| • | We no longer qualify as an emerging growth company or “EGC”. As an EGC we were able to take advantage of an exemption from providing an auditor’s attestation on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act. Following the issuance of Senior Secured Notes in September 2020, we ceased to qualify as an EGC and can no longer take advantage of this exemption. We are also now required to accelerate the adoption of certain new or revised accounting pronouncements. Starting in 2020, we will incur additional costs associated with providing an auditor’s attestation report, adoption of accounting standards on an accelerated timeline, as well as additional audit costs resulting from PCAOB requirements.
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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. months and the reasonably foreseeable future. Our significant capital projects, primarily our first FLNG unit, are nearing completion, and as with many capital projects, a significant portion of the overall capital spending becomes due near the completion of the project.
We expect the current working capital position to improve based on the following: (1) expected cash flows generated from the temporary power project and from sales of our own LNG generated by our first deployed Fast LNG unit; (2) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil and we have commitments to fund substantially all of the the remaining cost of our onshore FLNG project at Altamira; (3) our credit
agreements allow for proceeds from the sale of assets to be reinvested in our business, and we have significant non-core assets that could be used to fund our developments; and (4) our relationships with certain significant vendors constructing our Fast LNG assets have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project.
We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash 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 fundedFrom time to time, we may seek to repay, refinance or restructure all or a portion of our developmentsdebt or to repurchase our outstanding debt through, proceeds fromas applicable, tender offers, exchange offers, open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on a number of factors, including prevailing market conditions, our IPOliquidity requirements and contractual requirements (including compliance with the terms of our debt and equity financing as follows:
Our IPO was completed on February 4, 2019,remaining committed capital expenditures is approximately $1,365 million and we raised net proceeds of $268,010, inclusive of additional net proceeds raised from the exercise of the underwriter’s optionincludes remaining expenditures to purchase additional sharescomplete our first Fast LNG project and after deducting underwriting discounts and commissions and transaction costs.
In March 2019, we drew the remaining availability on our Term Loan Facility and had $495,000 of outstanding principalonshore liquefaction project at Altamira, as of December 31, 2019.
In September 2019, we issued approximately $117,000 in Senior Secured Bonds and Senior Unsecured Bonds, and in December 2019, we issued an additional $63,000 in Senior Secured Bonds, which was fully funded by January 2020.
In January 2020, we borrowed $800,000 under the Credit Agreement and repaid the Term Loan Facility in full.
In September 2020, we issued $1,000,000 of Senior Secured Notes and repaid in full amounts due on the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds. No principal payments are due on the Senior Secured Notes until maturity in 2025.
In December 2020, we received proceeds of $263,500 from the issuance of $250,000 of additional notes on the same termswell as the Senior Secured Notes (subsequent to this issuance, these additional notes are included in the definition of Senior Secured 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.
We have assumed total expenditures for all completed and existing projects to be approximately $1,181 million, with approximately $789 million having already been spent through December 31, 2020. This estimate represents thecommitted expenditures necessary to complete the La Paz Facility and the Puerto Sandino Facility, expected expendituresBarcarena Facility, Barcarena Power Plant, Santa Catarina Facility and Beaumont Facility. We have secured financing commitments to serve new industrial end-userscontinue to develop our onshore Altamira project and other plannedthe Barcarena Power Plant, which represents approximately $1,072 million of our upcoming committed capital expenditures.
We expect fully completed Fast LNG units to be ablecost between $1.0 billion and $1.6 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 flow from operations, and cash flows from operations. Through borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.
As of December 31, 2020,2023, we have spent approximately $159$128.6 million to develop the Pennsylvania Facility. Approximately $20$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 $139$106.1 million, has been capitalized.capitalized, and to date, we have repurposed approximately $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.
We have obtained debt financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA for loans inOn December 12, 2022, our Board of Directors approved an aggregate principal amount of $1.7 billion, consisting of a $1.5 billion senior secured bridge facility (the “Bridge Loan”) and a $200 million senior secured revolving facilityupdate to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price inour dividend policy. In connection with the GMLP Merger, to refinance certain debtdividend policy update, the Board declared a dividend of GMLP$626.3 million, representing $3.00 per Class A share, which was paid during the first quarter of 2023. Additionally, we declared and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If NFE utilizespaid quarterly dividends totaling $81,976 during the Bridge Loan, the facility will bear a fixed interest rate of 6.25%, subject to a step-up of 50 basis points every three months. The Bridge Loan has a one-year term, is pre-payable without penalty and will automatically be converted into a seven-year term loan if it is not repaid in full at maturity. The senior secured revolving facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.
Cash Flows
The following table summarizes the changes to our cash flows for the years ended December 31, 2020 and 2019, respectively:
| | Year Ended December 31, | |
| (in thousands) | | 2020 | | | 2019 | | | Change | |
| Cash flows from: | | | | | | | | | |
| Operating activities | | $ | (125,566 | ) | | $ | (234,261 | ) | | $ | 108,695 | |
| Investing activities | | | (157,631 | ) | | | (376,164 | ) | | | 218,533 | |
| Financing activities | | | 819,498 | | | | 602,607 | | | | 216,891 | |
| Net increase (decrease ) in cash, cash equivalents, and restricted cash | | $ | 536,301 | | | $ | (7,818 | ) | | $ | 544,119 | |
Cash (used in) operating activities
Our cash flow used in operating activities was $125,566 for the year ended December 31, 2020, which decreased by $108,695 from $234,261 for2023, representing $0.10 per Class A share. Our future dividend policy is within the year ended December 31, 2019. The reduction in cash flow used in operating activities for the year ended December 31, 2020 was due to more favorable changes in working capital accounts. Fluctuations in inventory balances led to an increase in operating cash flows of $23,230 for the year ended December 31, 2020 compared to a $50,345 decrease in operating cash flows for the year ended December 31, 2019. The impact of increasing accounts payable and accrued liabilities on cash flows from operations was $55,514 for the year ended December 31, 2020 compared to $3,036 for the year ended December 31, 2019.
Cash (used in) investing activities
Our cash flow used in investing activities was $157,631 for the year ended December 31, 2020, which decreased by $218,533 from $376,164 for the year ended December 31, 2019. Cash outflows for investing activities during the year ended December 31, 2020 were primarily used to complete the CHP Plant and the San Juan Facility, as well as construction of the La Paz Facility.
Cash used in investing activities during the year ended December 31, 2019 significant capital expenditures for developmentdiscretion of our Old Harbour Facility, CHP Plant, San Juan FacilityBoard of Directors and Pennsylvania Facility, as well as payments for significant outstanding amounts towill depend upon then-existing conditions, including our suppliers that were accrued asresults of December 31, 2018.
Cash provided by financing activities
Our cash flow provided by financing activities was $819,498 for the year ended December 31, 2020, which increased by $216,891 from $602,607 for the year ended December 31, 2019. Cash provided by financing activities during the year ended December 31, 2020 was due to proceeds received from the borrowings under the Senior Secured Notes of $1,250,000, the Credit Agreement of $800,000operations and Senior Secured Bonds of $52,144. A portion of these proceeds from the Senior Secured Notes were used to fund the repayment of the Credit Agreement of $800,000, the Senior Secured Bondsfinancial condition, capital requirements, business prospects, statutory and Senior Unsecured Bonds of $183,600 and the Term Loan Facility of $506,402. The proceeds received were further offset by transaction costs and other fees incurred to obtain the borrowings. In 2020, we also received proceeds from the issuance of Class A common stock of $291,922, offset by stock issuance costs of $1,107. Cash dividends of $33,742 were paid, partially offsetting financing inflows.
Cash flow provided by financing activities during the year ended December 31, 2019 were primarily consisted of the issuance of Senior Secured Bonds and Senior Unsecured Bonds of $117,000 in September 2019, additional borrowings under the Term Loan Facility of $220,000 in March 2019 and proceeds received from our IPO of $274,948 in February 2019.
Long-Term Debt
Senior Secured Notes
On September 2, 2020, the Company issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “Senior Secured Notes”). Interest is payable semi-annually in arrearscontractual restrictions onMarch 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. The Company may redeem the Senior Secured Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The Senior Secured Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The Senior Secured Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The Senior Secured Notes also provide for customary events of default and prepayment provisions.
We used a portion of the net cash proceeds received from the Senior Secured Notes to repaypay dividends, including restrictions contained in full the outstanding principal and interest under the Credit Agreement, including related costs and expenses. We also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds, including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The redemption of the Senior Secured Bonds and Senior Unsecured Bonds was completed on September 21, 2020.
In connection with the issuance of the Senior Secured Notes, we incurred $17,937 in origination, structuringour debt agreements, and other fees. Issuance costsfactors our Board of 13,909 were deferred as a reduction of the principal balance of the Senior Secured Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes. As a portion of the repayment of the Credit Agreement was a modification, we recorded $4,028 of third-party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss.
On December 17, 2020, the Company issued $250,000 of additional notes on the same terms as the Senior Secured Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,188. As of December 31, 2020, total remaining unamortized deferred financing costs were $10,439.
The Credit Agreement
On January 10, 2020, the Company entered into a credit agreement to borrow $800,000 in term loans (the “Credit Agreement”). The Credit Agreement was to mature in January 2023 with the full principal balance due upon maturity. Interest was payable quarterly and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floor of 1.50%, plus a margin of 6.25%. The interest rate margin was to increase each year of the term by 1.50%. Outstanding balances could be prepaid at our option at any time without premium. We used a portion of the proceeds received to extinguish the Term Loan Facility.
We were required to comply with certain financial covenants as well as usual and customary affirmative and negative covenants, including limitations on liens and incurring additional indebtedness. The facility also provided for customary events of default and cure provisions.
Directors may deem relevant. In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the consolidated balance sheets. On September 2, 2020, we repaid the full amount outstanding using proceeds from the Senior Secured Notes. Certain holders of the Credit Agreement participated in the issuance of Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes.
Term Loan Facility
On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000. On December 31, 2018, the Company amended this credit agreement (as amended, the “Term Loan Facility”) to, among other things, (i) increase the amount available for borrowing thereunder from $240,000 to $500,000, (ii) extend the initial maturity date to December 31, 2019, (iii) modify certain provisions relating to restrictive covenants and existing financial covenants, and (iv) remove the mandatory prepayment required with the net proceeds received in connection with an IPO. As of December 31, 2018, the outstanding principal balance under the Term Loan Facility was $280,000.
On March 21, 2019, the Company drew an additional $220,000, bringing our total outstanding borrowings to $500,000 under the Term Loan Facility, and as of December 31, 2019, the total principal amount outstanding under the Term Loan Facility was $495,000.
All borrowings under the Term Loan Facility bore interest at a rate selected by us of either (i) LIBOR divided by one minus the applicable reserve requirement plus a spread of 4% or (ii) subject to a floor of 1%, a Base Rate equal to the higher of (a) the Prime Rate, (b) the Federal Funds Rate plus 1/2 of 1% or (c) the 1-month LIBOR rate plus 1.00% plus a spread of 3.0%. The Term Loan Facility was repayable in quarterly installments of $1,250 with a balloon payment due at maturity.
The Term Loan Facility was secured by mortgages on certain properties owned by our subsidiaries, in addition to other collateral. The Term Loan Facility was amended in the third quarter of 2019 to allow certain properties2023, our Board of Directors reinstated a consolidated subsidiary to secure the Senior Secured Bonds. We were also required to comply with certain financial covenants and other restrictive covenants customary for facilitiesdividend policy of this type, including restrictions on indebtedness, liens, acquisitions and investments, restricted payments and dispositions.
We incurred costs in connection with obtaining the Term Loan Facility, the extinguishmenttargeting a quarterly dividend of our prior debt facilities, and the amendment of the Term Loan Facility. Some of the costs incurred were capitalized as a reduction to the Term Loan Facility on the consolidated balance sheets, and all deferred financing costs associated with the Term Loan Facility were amortized over the term of the Term Loan Facility, through December 31, 2019. As such, there were no unamortized deferred financing costs as of December 31, 2019.
The Term Loan Facility had a maturity date of December 31, 2019 with an option to extend the maturity date for two additional six-month periods. Upon the exercise of each extension option, we would pay a fee equal to 1.0% of the outstanding principal balance at the time of the exercise, and the spread on the LIBOR and Base Rate would increase by 0.5%. On December 30, 2019, the Company entered into an amendment with the lenders to extend the maturity to January 21, 2020. Prior to this new maturity date, on January 15, 2020, we repaid the full amount outstanding, using proceeds from the Credit Agreement to extinguish the Term Loan Facility.
On September 2, 2019, NFE South Power Holdings Limited (“South Power”), a consolidated subsidiary of the Company, entered into a facility for the issuance of secured and unsecured bonds (the “Senior Secured Bonds” and “Senior Unsecured Bonds”, respectively) and subsequently issued $73,317 and $43,683 in Senior Secured Bonds and Senior Unsecured Bonds, respectively. The Senior Secured Bonds are secured by the CHP Plant and related receivables and assets, and the proceeds will be used to fund the completion of the CHP Plant and to reimburse shareholder advances. In the fourth quarter of 2019, South Power issued an additional $63,000 in Senior Secured Bonds. We received $10,856 of the proceeds in 2019 and received the remaining proceeds of $52,144 in January 2020.
The Senior Secured Bonds bore interest at an annual fixed rate of 8.25% and matured 15 years from the closing date of each issuance. No principal payments were due for the first seven years. Beginning in 2026, quarterly principal payments of approximately 1.6% of the original principal amount were due, with a 50% balloon payment due upon maturity. Interest payments on outstanding principal balances were due quarterly.
The Senior Unsecured Bonds bore interest at an annual fixed rate of 11.00% and matured in September 2036. No principal payments were due for the first nine years. Beginning in 2028, principal payments were due quarterly on an escalating schedule. Interest payments on outstanding principal balances were due quarterly.
South Power was required to comply with certain financial covenants as well as customary affirmative and negative covenants, including limitations on incurring additional indebtedness. The facility also provided for customary events of default, prepayment and cure provisions.
The Company paid approximately $$0.10 per share.3,892 of fees in connection with the issuance of Senior Secured Bonds and Senior Unsecured Bonds. These fees were capitalized on a pro-rata basis as a reduction of the Senior Secured Bonds and Senior Unsecured Bonds on the consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the Senior Secured Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds, the Company recognized a loss on extinguishment of debt of $7,195 in the consolidated statements of operations and comprehensive loss, including the write-off of $3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $3,601.
Off Balance Sheet Arrangements
As of December 31, 2020 and 2019, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2020:2023:
| (in thousands) | | Total | | | Less than 1 year | | | Years 2 to 3 | | | Year 4 to 5 | | | More than 5 years | |
| Long-term debt obligations | | $ | 1,675,203 | | | $ | 87,703 | | | $ | 168,750 | | | $ | 1,418,750 | | | $ | - | |
| Purchase obligations | | | 2,490,347 | | | | 376,096 | | | | 724,588 | | | | 724,090 | | | | 665,573 | |
| Lease obligations | | | 191,991 | | | | 47,135 | | | | 56,066 | | | | 36,006 | | | | 52,784 | |
| Total | | $ | 4,357,541 | | | $ | 510,934 | | | $ | 949,404 | | | $ | 2,178,846 | | | $ | 718,357 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands) | Total | | Year 1 | | Years 2 to 3 | | Years 4 to 5 | | More than 5
years |
| Long-term debt obligations | $ | 9,789,792 | | | $ | 909,103 | | | $ | 4,747,337 | | | $ | 1,728,806 | | | $ | 2,404,546 | |
| Purchase obligations | 14,526,719 | | | 1,744,718 | | | 1,605,535 | | | 1,422,191 | | | 9,754,275 | |
| Lease obligations | 759,231 | | | 210,212 | | | 218,753 | | | 155,048 | | | 175,218 | |
| Total | $ | 25,075,742 | | | $ | 2,864,033 | | | $ | 6,571,625 | | | $ | 3,306,045 | | | $ | 12,334,039 | |
Long-term debt obligations
For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2020.2023.
We entered into the BNDES Credit Agreement and an agreement to issue the Barcarena Debentures (defined below). Proceeds from these new credit arrangements have been or will be used to refinance the Barcarena Term Loan on a long term basis, and as such, these principal balances have been shown as non-current on the Consolidated Balance Sheets as of December 31, 2023.
Purchase obligations
The Company isWe 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 December 31, 2020.2023.
In 2020, we entered into fourWe have construction purchase commitments in connection with our development projects, including our Fast LNG supply agreements forprojects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and Beaumont Facility. Commitments included in the purchase of 415 TBtu of LNG attable above include commitments under engineering, procurement and construction contracts where a price indexednotice to Henry Hub from 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018.
Lease obligations
Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, gas turbines and a land lease.
Cash Flows
The Company currently has five vesselsfollowing table summarizes the changes to our cash flows for the year ended December 31, 2023 and 2022, respectively:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| (in thousands) | 2023 | | 2022 | | Change |
| Cash flows from: | | | | | |
| Operating activities | $ | 824,756 | | | $ | 355,111 | | | $ | 469,645 | |
| Investing activities | (2,904,143) | | | (82,726) | | | (2,821,417) | |
| Financing activities | 1,528,950 | | | 321,957 | | | 1,206,993 | |
| Net (decrease) increase in cash, cash equivalents, and restricted cash | $ | (550,437) | | | $ | 594,342 | | | $ | (1,144,779) | |
Cash provided by operating activities
Our cash flow provided by operating activities was $824.8 million for the year ended December 31, 2023, which increased by $469.6 million from cash provided by operating activities of $355.1 million for the year ended December 31, 2022. Our net income for the year ended December 31, 2023, when adjusted for non-cash items, increased by $175.5 million from the year ended December 31, 2022. The increase in cash provided by operating activities for the year ended December 31, 2023 was also driven by changes in working capital, including improved collection of receivables and the settlement of a significant commodity derivative, as well as significant cash receipts under time charter leases with non-cancellable terms rangingour temporary power agreements that are required to be deferred as contract liabilities.
Cash used in investing activities
Our cash flow used in investing activities was $2,904.1 million for the year ended December 31, 2023, which increased by $2,821.4 million from nine months to seven years. The lease commitmentscash used in the table above include only the lease componentinvesting activities of these arrangements due over the non-cancellable term and does not include any operating services.
We have leases for port space and a land site$82.7 million for the year ended December 31, 2022. Cash outflows from investing activities during the year ended December 31, 2023 were used primarily for continued development of our facilities. Terms for leasesFast LNG project and assets to service the grid stabilization project in Puerto Rico. Cash outflows were offset by proceeds of port space range$100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange, proceeds received from the sale of 20Pecém to 25 years. The land site lease is held with an affiliateand Muricy, as well as proceeds received from the sale of the CompanySpirit and has a remaining portion of our investment in equity securities.
Cash outflows for investing activities during the year ended December 31, 2022 were used for continued development of our Fast LNG project, Santa Catarina Facility, and Barcarena Facility. Cash outflows were offset by proceeds of $593.0 million from the sale of the finance lease of the Nanook and $500.1 million from selling our investment in CELSEPAR.
Cash provided by financing activities
Our cash flow provided by financing activities was $1,529.0 million for the year ended December 31, 2023, which increased by $1,207.0 million from cash provided by financing activities of $322.0 million for the year ended December 31, 2022. On December 12, 2022, the Company's Board of Directors approved an update to its dividend policy and declared a dividend of $626,310, representing $3.00 per Class A share, which was paid in January 2023. We have borrowed under our new Term Loan B Agreement, expanded Revolving Facility, Bridge Term Loans, Equipment Notes, Barcarena Debentures, EB-5 Loan, Tugboat Financing, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $3.0 billion. Such borrowings were primarily used to fund the ongoing development of our Fast LNG project and to support our grid stabilization project in Puerto Rico. Increased borrowings during 2023 were offset by repayments of debt totaling $686.5 million, primarily the repayment of the Bridge Term Loans and short-term borrowings under repurchase arrangements.
Cash provided by financing activities during the year ended December 31, 2022 was due to proceeds from issuance of debt of $2.0 billion, offset by repayments of debt of $1.5 billion, payment of dividends of $99.1 million and payments related to tax withholdings for share-based compensation of $72.6 million.
Long-Term Debt and Preferred Stock
2025 Notes
In September 2020, we issued $1,000.0 million of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments are due until maturity on September 15, 2025. We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.
In December 2020, we issued $250.0 million of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).
2026 Notes
In April 2021, we issued $1,500.0 million of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes.
Vessel Financing Obligation
In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to us at the time of closing were classified as finance leases. Additionally, our charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, we accounted for the Energos Formation Transaction as a failed sale-leaseback and have recorded a financing obligation for consideration received.
We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation; the effective interest rate on this financing obligation of approximately 15.9% includes the cash flows that Energos receives from these third-party charters.
Revolving Facility
In April 2021, we entered into a credit agreement (the "Revolving Credit Agreement") with a bank for $200.0 million senior secured revolving credit facility (the "Revolving Facility"). The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The Revolving Facility will mature in 2026 if the 2025 Notes are refinanced prior to maturity, with the potential for us to extend the maturity date of the Revolving Facility once for a one-year increment; if not, the Revolving Facility becomes due approximately 60 days prior to the maturity of the 2025 Notes. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.
In 2022, the Revolving Credit Agreement was amended twice to increase the borrowing capacity by a total of $240.0 million, and in the year ended December 31, 2023, we entered into additional amendments which increased the borrowing capacity by $510.0 million, for a total capacity of $950,000.0 million. The amendments did not impact the interest rate or
term of approximately five yearsthe Revolving Facility, and no deferred costs were written off. During the year ended December 31, 2023, we drew $866.6 million from the Revolving Facility, which is outstanding as of December 31, 2023.
The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries, including those that own the Company's first Fast LNG asset, and are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes. Additionally the Revolving Facility is secured by assets comprising our first Fast LNG project in Altamira, Mexico. We are required to comply with covenants under the Revolving Facility and Letter of Credit Facility (defined below), 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 4.0:1.0. We were in compliance with all covenants as of December 31, 2023.
The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.
Letter of Credit Facility
In July 2021, we entered into an automatic renewal termuncommitted letter of five yearscredit and reimbursement agreement (the "Letter of Credit Agreement") with a bank for the issuance of letters of credit for an aggregate amount of up to $75 million (the “Letter of Credit Facility”). In July 2022, the Letter of Credit Facility was upsized to $250 million with the ability to increase the total limit by up to $100 million, subject to satisfaction of certain conditions. In February 2023, the Letter of Credit Facility was upsized to $325 million, and in November 2023, the Letter of Credit Facility was upsized to $350 million. The letters of credit bear interest at a rate equal to a base rate plus 2.75%.
The obligations under the Letter of Credit Facility are guaranteed by certain of our subsidiaries, including those that own the Company's first Fast LNG asset, and are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes. Additionally the Letter of Credit Facility is secured by assets comprising our first Fast LNG project in Altamira, Mexico.
The Letter of Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.
Term Loan B Credit Agreement
On August 3, 2023, we entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to us in an additional 20 years.aggregate principal amount of $400.0 million. The Bridge Term Loans were to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.
During 2020,The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our first Fast LNG project in Altamira, Mexico. The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2025 Notes and the 2026 Notes, and, in addition, is secured by assets comprising our first Fast LNG project..
The Term Loan B bears interest at a per annum rate equal to Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. We may prepay the Term Loan B at our option subject to prepayment premiums until October 2025 and customary break funding costs. We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, we executed multiple lease agreementswill be required to prepay the Term Loan B with our Excess Cash Flow (as defined in the Term Loan B Agreement).
The Term Loan B Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Agreement.
South Power 2029 Bonds
In January 2022, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into an agreement for the issuance of up to $285.0 million secured bonds (“South Power 2029 Bonds”). The South Power 2029 Bonds are secured by, amongst other things, our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”), and NFE has provided a guarantee of the obligations under the South Power 2029 Bonds. As of both December 31, 2023 and 2022, South Power had $221.8 million, respectively, of South Power 2029 Bonds issued and outstanding.
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 is required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2023 and 2022.
Barcarena Financings
In the third quarter of 2022, certain of our indirect subsidiaries entered into a financing agreement to borrow up to $200.0 million due upon maturity in February 2024 (the “Barcarena Term Loan”); proceeds were utilized to fund a portion of the construction of the Barcarena Power Plant. As of December 31, 2022, the loan was fully funded. Interest is due quarterly, and outstanding borrowings bear interest at a rate equal to the Secured Overnight Financing Rate ("SOFR") plus 4.70%.
The obligations under the Barcarena Term Loan are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and New Fortress Energy Inc. has provided a parent company guarantee. Collateral on the Barcarena Term Loan includes liens on shares of entities constructing the our Barcarena Terminal and Barcarena Power Plant, liens on equipment and machinery owned by these entities, and rights to future operating cash flows and receivables under the Barcarena Power Plant's power purchase agreements. We are required to comply with customary affirmative and negative covenants, and the Barcarena Term Loan also provides for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2023 and 2022.
In October 2023, certain of our Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of the Barcarena Power Plant. Proceeds received will be used to repay the Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025. As we have committed financing in place to extinguish the Barcarena Term Loan as of December 31, 2023, the Barcarena Term Loan has been presented as long-term debt on the Consolidated Balance Sheets.
The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200.0 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. We are able to prepay the Barcarena Debentures, subject to customary break funding costs, and we are required to utilize certain excess cash flows from our Brazilian operations to prepay principal.
The Barcarena Debentures are convertible to shares of one of our indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.
The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own the Barcarena Terminal and Santa Catarina Terminal. NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are
required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.
Additionally, the owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). We are able to borrow up to R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of ISO tanks,proceeds ("BNDES Term Loan"); no amounts were funded under the BNDES Credit Agreement as of December 31, 2023. Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045.
The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.
Equipment Notes
In June 2023, we expectexecuted a Master Loan and Security Agreement with a lender to beginborrow up to receive these ISO tanks and for the lease terms to commence beginning$200.0 million under promissory notes secured by certain turbines acquired in the first quarter of 2021. 2023 to support our grid stabilization project in Puerto Rico (the “Equipment Notes”). During the second and third quarters of 2023, we borrowed the full capacity bearing interest at approximately 7.7%, and the principal is partially repayable in monthly installments over the 36 month term of the loan with the balance due upon maturity in July 2026.
The lease termEquipment Notes contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Equipment Notes do not contain any restrictive financial covenants. NFE has provided a guarantee of the obligations under the Equipment Notes.
EB-5 Loan Agreement
On July 21, 2023, we entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for eachthe development and construction of these leasesa new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is five$100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility, and expected paymentsNFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31, 2023, $62.9 million was funded under the EB-5 Loan Agreement.
The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.
Short-term Borrowings
We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2023, we had $182.3 million outstanding under these lease agreementsarrangements.
Tugboat Financing
In December 2023, we sold and leased back four tugboat vessels for 15 years receiving proceeds of $46.7 million. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, we accounted for the Tugboat Financing as a failed sale-leaseback and have been included in the above table.recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%.
Office space includes a space shared with affiliated companies in New York with lease terms up to 38 months and an office space in downtown Miami, with a lease term
Summary of Critical Accounting Estimates
The preparation of consolidated financial statements in conformity with GAAP requires managementus to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management evaluates itsWe evaluate our estimates and related assumptions regularly, and will continue to do so as we further grow our business. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.
Revenue recognition
Our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, and beginning in the first quarter of 2020, power and steam which are outputs from our natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, we have presented Operating revenue on an aggregated basis.
We have concluded that variable consideration included in these agreements meets the exception for allocating variable consideration to each unit sold under the contract. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.
Our contracts with customers to supply LNG or natural gas may contain a lease of equipment. We allocate consideration received from customers between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. We estimate the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term. The estimated fair value of the leased equipment, as a percentage of the estimated total revenue from LNG or natural gas and leased equipment at inception, will establish the allocation percentage to determine the fixed lease payments and the amount to be accounted for under the revenue recognition guidance.
The leases of certain facilities and equipment to customers are accounted for as finance or operating leases. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net, on the consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and is included in Other revenue in the consolidated statements of operations and comprehensive loss. The principal components of the lease payment are reflected as a reduction to the net investment in the finance lease. For our operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss.
In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes development services revenue recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as we transfer control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under development until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and we recognize revenue for the interest income component over the term of the financing as Other revenue.
Development services are typically included in arrangements that include other distinct performance obligations, and we allocate the transaction price to each performance obligation based on its standalone selling price (“SSP”) in relation to the aggregate value of the SSP of all performance obligations in the arrangement. Some of our performance obligations have observable inputs that are used to determine the SSP of those distinct performance obligations. Where SSP is not directly observable, we primarily determine the SSP using the cost-plus approach. In the circumstances when available information to determine SSP is highly variable or uncertain, we use the residual approach.
Impairment of long-lived assets
We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract, or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.
Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.
We have considered that the market price of LNGGeopolitical and other macroeconomic events can vary widely, including recent decreases throughout 2019 and 2020. Due to the decline in LNG prices, we executed three long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier. Further, we were able to take advantage of lower market pricing for LNG to supply our operations for the second half of 2020, resulting in an overall lower average cost of LNG. Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations insubstantially impact natural gas and LNG asmarkets, leading to volatility in market pricing. The majority of our pricing is basedLNG supply contracts are based on thea natural gas-based index, Henry Hub, index plus a contractual spread. Based on the long-term nature of our contracts and the market value of the underlying assets, we do not believe that changes in the price of LNG indicate that a recoverability assessment of our assets is necessary. Further, we plan to utilize our own liquefaction facilities to manufacture our own LNG at attractive prices, secure LNG to supply our expanding operations and reduce our exposure to future LNG price variations in the long term.
We have also considered the impacts of the ongoing COVID-19 pandemic, including the restrictions that governments may put in place and the resulting direct and indirect economic impacts, on our current operations and expected development budgets and timelines. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis, evenbasis. We limit our exposure to fluctuations in cases whennatural gas prices as our customer’s consumption has decreased. We have not changed our payment termspricing in contracts with these customers and there has not been any deterioration inis largely based on the timing or volume of collections.
Henry Hub index price plus a contractual spread. Based on the essentiallong-term nature of our supply and customer contracts, the nature of the services we provide to support power generation facilities,pricing in these contracts and the market value of our development projects haveunderlying assets, changes in the price of natural gas or LNG do not currently been significantly impacted by responses to the COVID-19 pandemic. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicatorsindicate that a recoverability assessment forof our assets should be performed.
The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil has traded at historic low pricesis necessary. Further, with our own LNG production from FLNG facilities expected to commence in 2020. Future expansion of2024, we plan to further mitigate our business is dependent upon LNG being a competitive source of energy and available at a lower cost than the costexposure to deliver other alternative energy sources, such as diesel or other distillate fuels. We do not believe that oil prices will remain at their historic low levels as evidenced by recent recovery, and we believe thatvariability in LNG and natural gas will remain a competitive fuel source for customers.
When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. Management developsWe develop the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.
Share-based compensation
We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model.
As of December 31, 2020, management determined that it was not probable that the performance condition for our outstanding PSUs would be met. For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period. A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable.
Recent Accounting Standards
For descriptions of recently issued accounting standards, seerefer to “Note 3 -3. Adoption of new and revised standards” toof our notes to consolidated financial statements included elsewhere in this Annual Report.
Item 7A. | Quantitative and Qualitative Disclosures About Market 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. Our exposure to market risk associated with LNG price changes may adversely impact our business. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with downstream customers is largely based on the Henry Hub
index price plus a contractual spread. Our exposure to market risk associated with LNG price changes may adversely impact our business.spread. We currently do not currently have any 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 Senior Secured2025 Notes, 2026 Notes, Equipment Notes, South Power 2029 Bonds and Barcarena Debentures (each defined above) were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the Senior Secured Notesdebt outstanding but such a change would have no impact on our results of operations or cash flows. A 100-basis100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $52 million.$74 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve. We do not currently have any derivative arrangements to protect against fluctuations
Interest under the Barcarena Term Loan and Term Loan B has a component based on the Secured Overnight Financing Rate ("SOFR"). A 100-basis point increase or decrease in the market interest rates applicable torate would decrease or increase our outstanding indebtedness.
Foreign Currency Exchange Risk
We primarily conducthave transactions, assets and liabilities denominated in Brazilian reais, and our Brazilian subsidiaries and investments receive income and pay expenses in Brazilian reais. Based on our Brazilian reais revenues and expenses, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations.
Outside of Brazil, our operations are primarily conducted in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions other than Brazil that are paid in local currencies, butcurrencies. As we expect our international operations to continue to grow in the near term. We do not currently have any derivative arrangements to protect against fluctuations in foreign exchange rates, but to mitigate the effect of fluctuations in exchange rates on our operations, weterm, we may enter into various derivative instruments.or hedging transactions with third parties to manage our exposure to changes in foreign currency exchange risks as we expand our international operations.
Item 8. | Item 8. Financial Statements and Supplementary Data. |
Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.
Item 9. | Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. |
None.
Item 9A. | Item 9A. Controls and Procedures. |
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15(b) of the Securities Exchange Act 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 December 31, 2020.2023. 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 December 31, 20202023 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
In the fourth quarter of 2023, we completed an implementation of our core financial systems, including our general ledger and other applications. As part of this implementation, we made certain changes to our processes and procedures, resulting in changes to our internal control over financial reporting. There werehas been no other changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during our lastthe quarter of 2020ended December 31, 2023 that havehas materially affected, or areis reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
As of December 31, 2020,2023, our management assessed the effectiveness of our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control – Integrated Framework (2013).”. Based on this assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2020.
The effectiveness of our internal control over financial reporting as of December 31, 20202023 has been audited by EY, an independent registered public accounting firm, as stated in their report, which appears herein.
Item 9B. | Item 9B. Other Information. |
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
Item 10. | Item 10. Directors, Executive Officers and Corporate Governance. |
The information required by this Item 10 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 20202023 in connection with our 20212024 annual meeting of shareholders (the “2024 Proxy Statement”) under the heading “Proposal No. 1 Election of Directors,” the subheadings “Information Concerning Our Directors, Including the Director Nominees,” “Code of Conduct” and “The Board and its Committees—Audit Committee,” and the headings “Management” and is incorporated herein by reference.
Item 11. | Item 11. Executive Compensation |
The information required by this Item 11 is set forth in the Company’s 2024 Proxy Statement to be filed withunder the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholdersheadings “Executive Compensation” (other than the information under the subheading “Pay Versus Performance”), “Compensation Committee Report” and “Director Compensation” and is incorporated herein by reference.
Item 12. | Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters. |
The information required by this Item 12 is set forth in the Company’s 2024 Proxy Statement to be filed withunder the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meetingheadings “Equity Compensation Plan Information” and “Security Ownership of shareholdersManagement and Certain Beneficial Owners” and is incorporated herein by reference.
Item 13. | Item 13. Certain Relationships and Related Transactions, and Director Independence. |
The information required by this Item 13 is set forth in the Company’s 2024 Proxy Statement to be filed withunder the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meetingheadings “Certain Relationships and Related Transactions” and “Proposal No. 1 Election of shareholdersDirectors—Determination of Director Independence” and is incorporated herein by reference.
Item 14. | Principal AccountingItem 14. Principal Accountant Fees and Services. |
The information required by this Item 14 is set forth in the Company’s Proxy Statement to be filed withunder the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meetingheading “Proposal No. 2 Approval of shareholdersAppointment of Ernst & Young LLP as Independent Registered Public Accounting Firm—Principal Accountant Fees and Services” and is incorporated herein by reference.
Item 15. | Item 15. Exhibits, Financial Statement Schedules. |
(a)(1) | Financial Statements. |
SeeThe financial statements of New Fortress Energy Inc. and consolidated subsidiaries are included in Item 8 of this Form 10-K (Form 10-K). Refer to “Index to Financial Statements” set forth onof page F-1.
(2) | Financial Statement Schedules. |
(2) Financial Statement Schedule.
See Schedule II set forth on page F-31.F-55.
The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.
| | | | | |
| Exhibit
Number
| | Description |
| |
| | Agreement and PlanCertificate of Merger, dated asConversion of January 13, 2021, by and among NFE, GMLP Merger Sub, GP Buyer, GMLP and the General PartnerNew Fortress Energy Inc. (incorporated by reference to Exhibit 2.199.2 to the Registrant’s Quarterly Report on Form 8-K (File No. 001-38790),10-Q filed with the CommissionSEC on January 20, 2021)August 4, 2020). |
| | 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 Commission on January 20, 2021) |
| | 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 Commission on January 20, 2021) |
| | 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 Commission on November 9, 2018) |
| | 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 Commission on November 9, 2018) |
| | 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 Commission on February 5, 2019) |
| | Certificate of Incorporation of New Fortress Energy Inc. (incorporated herein by reference to Exhibit 99.3 ofto the Company’sRegistrant’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2020). |
| |
| | Bylaws of New Fortress Energy Inc. (incorporated herein by reference to Exhibit 99.4 ofto the Company’sRegistrant’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2020). |
| |
| | Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated(incorporated by reference to Exhibit 99.14.1 to the Registrant's CurrentRegistrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the SEC on March 1, 2022). |
| |
| Report on Form 10-K, filed with the SEC on March 1, 2022). |
| |
| 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, filed with the SEC on December 24, 2018). |
| |
| Restricted Share Unit Award Agreement under the Amended and Restated New Fortress Energy Inc. 2019 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q, filed with the Commission on August 7, 2020)November 8, 2022). |
| |
| | Indenture,Shareholders’ Agreement, dated September 2, 2020,February 4, 2019, by and among New Fortress Energy Inc., the subsidiary guarantors from time to time party thereto,LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and U.S. Bank National Association, as trustee and collateral agentRandal 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 CommissionSEC on September 2, 2020)February 5, 2019). |
| |
| 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, filed with the SEC on February 5, 2019). |
| |
| First Supplemental 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). |
| | | | | |
| |
| Indemnification Agreement (Guinta) (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Catterall) (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). |
| |
| Indemnification Agreement (Jay ) (incorporated by reference to Exhibit 10.15 to the Registrant's Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2023). |
| |
| 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). |
| |
| 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). |
| |
| 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). |
| |
| Indenture, dated December 17,September 2, 2020, by and among New Fortress Energy Inc.,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, (File No. 001-38790), filed with the CommissionSEC on December 18,September 2, 2020). |
| |
| | Pledge and Security Agreement, dated September 2, 2020, by and among New Fortress Energy Inc.,the Company, the subsidiary guaranteesguarantors from time to time party thereto, and U.S. Bank National Association, as trustee andnotes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the CommissionSEC on September 2, 2020). |
| |
| | Contribution Agreement,First Supplemental Indenture, dated February 4, 2019,December 17, 2020, by and among New Fortress Energy LLC, New Fortress Intermediate LLC, New Fortress Energy Holdings LLC, NFE Atlantic Holdings LLCthe Company, the subsidiary guarantors from time to time party thereto 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 Commission on February 5, 2019) |
| | AmendedU.S. Bank National Association, as trustee 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 Commission on February 5, 2019) |
| | 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 Commission on February 4, 2019) |
| | 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 Commission on December 24, 2018) |
| | Offer Letter, dated March 14, 2017, by and between NFE Management LLC and Christopher Guinta (incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019) |
| | Offer Letter, dated August 30, 2018, by and between NFE Management LLC and Michael J. Utsler (incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019) |
| | Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardoneas notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the CommissionSEC on February 5, 2019)December 18, 2020). |
| |
| | | | | |
| | Administrative Services Agreement,Second Supplemental Indenture, dated February 4, 2019, byas of March 1, 2021, between NFE US Holdings LLC, as Guaranteeing Subsidiary, and between New Fortress Intermediate LLC and FIG LLCU.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.310.21 to the Registrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the CommissionSEC on February 5, 2019)March 1, 2023). |
| |
| | Gas Sales Agreement,Third Supplemental Indenture, dated August 5, 2015, byas of June 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and among New Fortress Energy LLC and Jamaica Public ServiceU.S. Bank Trust Company, LimitedNational Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.1210.22 to the Registrant’s Registration StatementAnnual Report on Form S-1 (File No. 333-228339),10-K, filed with the CommissionSEC on November 9, 2018)] |
Exhibit
Number
| | DescriptionMarch 1, 2023). |
| |
| | Gas Sales Agreement,Fourth Supplemental Indenture, dated August 5, 2015, byas of September 13, 2021, between NFE Mexico Power Holdings Limited and between New Fortress Energy LLCNFE Mexico Terminal Holdings Limited, as Guaranteeing Subsidiaries, and Jamaica Public ServiceU.S. Bank Trust Company, LimitedNational Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.1210.23 to the Registrant’s Registration StatementAnnual Report on Form S-1 (File No. 333-228339),10-K, filed with the CommissionSEC on November 9, 2018)March 1, 2023). |
| |
| | First Amendment to Gas Sales Agreement,Fifth Supplemental Indenture, dated May 23, 2016, by andas of November 24, 2021, between NFE NorthInternational Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and Jamaica Public ServiceU.S. Bank Trust Company, LimitedNational Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.1310.24 to the Registrant’s Registration StatementAnnual Report on Form S-1 (File No. 333-228339),10-K, filed with the CommissionSEC on November 9, 2018)March 1, 2023). |
| |
| | Indemnification Agreement (Edens)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 10.410.25 to the Registrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the CommissionSEC on February 5, 2019)March 1, 2023). |
| |
| | Indemnification Agreement (Guinta)Seventh Supplemental Indenture, dated as of December 22, 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 10.510.26 to the Registrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the CommissionSEC on February 5, 2019)March 1, 2023). |
| |
| | Indemnification Agreement (Utsler)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 10.64.1 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the CommissionSEC on February 5, 2019)April 12, 2021). |
| |
| | IndemnificationPledge and Security Agreement, (Catterall)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 10.74.2 to the Registrant’s Current Report on Form 8-K, (File No. 001-38790), filed with the CommissionSEC on February 5, 2019)April 12, 2021). |
| | Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
| | Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
| | Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
| | Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
| | Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
| | Indemnification Agreement (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019) |
Exhibit
Number
| | Description |
| | Master LNG Sale and Purchase Agreement, dated December 20, 2016, by and between Centrica LNG Company Limited and NFE North Trading Limited (incorporated by reference to Exhibit 10.16 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019) |
| | 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 Commission on January 25, 2019) |
| | Indemnification Agreement,First Supplemental Indenture, dated as of March 17, 2019, byJune 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and between New Fortress Energy LLC and Yunyoung ShinU.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K, (File 001-38790), filed with the CommissionSEC on March 26, 2019)1, 2023). |
| |
| 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). |
| |
| | | | | |
| MutualThird 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). |
| |
| 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). |
| |
| Fifth Supplemental Indenture, dated as of December 22, 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). |
| |
| Credit Agreement, dated June 3, 2020,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). |
| |
| 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 Annual Report on Form 10-K, filed with the SEC on March 1, 2022). |
| |
| 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 Annual Report on Form 10-K, filed with the SEC on March 1, 2022). |
| |
| 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 Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2022). |
| |
| 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). |
| |
| Fifth Amendment to Credit Agreement, dated as of September 15, 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. |
| |
| Sixth Amendment to Credit Agreement, dated as of December 18, 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. |
| |
| | | | | |
| 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). |
| |
| Second Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated July 27, 2022, by and among New Fortress Energy LLC, Fortress Equity Partners GP, LLC, WRE 2012 Trust LLC, FEP HoldCo LLC, Wesley R Edens, Randal A Nardone, NFE SMRS Holdings LLCInc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent, Natixis, New York Branch, as ULCA Collateral Agent, Natixis, New York Branch, and NFE Sub LLCeach of the other financial institutions party thereto, as Lenders and Issuing Banks (incorporated by reference to Exhibit 10.110.40 to the Registrant’s Quarterly Report on Form 8-K (File No. 001-38790),10-Q, filed with the CommissionSEC on June 9, 2020)August 5, 2022). |
| |
| | SupportIncremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated as of January 13, 2021,February 6, 2023, by and among NFE, GMLP, GLNGNew Fortress Energy Inc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent and the General Partneras Issuing Bank, Credit Agricole Corporate and Investment Bank, as Issuing Bank, and Sumitomo Mitsui Banking Corporation, as Issuing Bank (incorporated by reference to Exhibit 10.110.45 to the Registrant’s Annual Report on Form 8-K (File No. 001-38790),10-K, filed with the CommissionSEC on January 20, 2021)March 1, 2023). |
| |
| Incremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated November 2, 2023, by and among New Fortress Energy Inc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent and as an Issuing Bank and Banco Santander, S.A., New York Branch as an Incremental Lender. |
| |
| Credit Agreement, dated as of October 30, 2023, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent. |
| |
| | List of Subsidiaries of New Fortress Energy Inc. |
| |
| | Consent of Ernst & Young L.L.P.LLP, independent registered public accounting firm. |
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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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| Clawback Policy of the Company, effective as of December 1, 2023 |
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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 |
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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 Annual Report |
** | Furnished as an exhibit to this Annual Report |
† | Compensatory plan or arrangement |
‡ | Confidential treatment was granted with respect to certain portions of this exhibit. Omitted portions filed separately with the SEC. |
*Filed as an exhibit to this Annual Report
**Furnished as an exhibit to this Annual Report
† Compensatory plan or arrangement
# Portions of the exhibit (indicated by asterisks) have been omitted in pursuant to Item 601 (b)(10)(iv) of Regulation S-K.
Item 16. | Item 16. Form 10-K Summary. |
None.
Pursuant to the requirements of 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | |
| NEW FORTRESS ENERGY INC. |
Date: March 16, 2021February 29, 2024 | | |
| By: | By: | /s/ Christopher S. Guinta |
| Name: | Name: | Christopher S. Guinta |
| Title: | Title: | Chief Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
| | | | | | | | | | | | | | |
| Name | | Title | | Title | Date |
| | | | |
| /s/ Wesley R. Edens | | Chief Executive Officer and Chairman (Principal Executive Officer) | | March 16, 2021February 29, 2024 |
| | | Wesley R. Edens |
| | | | |
| /s/ Christopher S. Guinta | | Chief Financial Officer (Principal Financial Officer) | | March 16, 2021February 29, 2024 |
| | | Christopher S. Guinta |
| | | | |
| /s/ Yunyoung Shin | | Chief Accounting Officer (Principal Accounting Officer) | | March 16, 2021February 29, 2024 |
| | | Yunyoung Shin |
| | | | |
| /s/ Randal A. Nardone | | Director | | Director | March 16, 2021February 29, 2024 |
| Randal A. Nardone | | | | |
| | | | |
| /s/ C. William Griffin | | Director | | Director | March 16, 2021February 29, 2024 |
| C. William Griffin | | | | |
| | | | |
| /s/ John J. Mack | | Director | | Director | March 16, 2021February 29, 2024 |
| John J. Mack | | |
| | | | |
| /s/ Timothy W. Jay | | Director | | February 29, 2024 |
Matthew WilkinsonTimothy W. Jay | | | Director | March 16, 2021 |
| | | | |
| /s/ David J. Grain | | Director | | Director | March 16, 2021February 29, 2024 |
| David J. Grain | | | | |
| | | | |
| /s/ Desmond Iain Catterall | | Director | | Director | March 16, 2021February 29, 2024 |
| Desmond Iain Catterall | | | | |
| | | | |
| /s/ Katherine E. Wanner | | Director | | DirectorFebruary 29, 2024 |
| Katherine E. Wanner | | | March 16, 2021
Index to Consolidated Financial Statements
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| Page |
| | F-2 | |
| | F-8 | |
| | F-9 | |
| | F-10 | |
| | F-11 | |
| | F-12 | |
Report of Independent Registered Public Accounting Firm
To the ShareholdersStockholders and the Board of Directors of New Fortress Energy Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of New Fortress Energy Inc. (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations and comprehensive income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 29, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
| | | | | | | | |
| | Impairment Assessment of Construction in Progress |
| | |
| Description of the Matter | | As of December 31, 2023, the balance of construction in progress totaled $5,348 million. As described in Note 2(j) to the consolidated financial statements, the Company performs a recoverability assessment of all long-lived assets, including construction in progress, whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Impairment indicators affecting construction in progress asset groups may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates or has development activities, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates an asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the asset group over its fair value.
Auditing management’s determination of whether impairment indicators exist such that a recoverability test for a construction in progress asset group is required, was highly subjective and involved significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.
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| | |
| How We Addressed the Matter in Our Audit | | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups, including construction in progress, that may have been impacted by the impairment indicators described above.
To test the Company’s evaluation of potential indicators of impairment of its construction in progress, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company has development projects and their impact on the completion of the construction in progress and recoverability of the related asset groups. We also obtained capital budgets and construction bids, which included costs incurred to date and expected future cash flows, among other evidence, to understand management’s plans with respect to development activities. We considered information about the Company’s development projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.
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/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2016.
Philadelphia, Pennsylvania
February 29, 2024
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of New Fortress Energy Inc.
Opinion on Internal Control Over Financial Reporting
We have audited New Fortress Energy Inc.’s internal control over financial reporting as of December 31, 2020,2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework(2013 framework) (the COSO criteria). In our opinion, New Fortress Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020,2023, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the accompanying2023 consolidated balance sheetsfinancial statements of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). Ourour report dated March 16, 2021February 29, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’sManagement’s Report on Internal Control Over Financial Reporting”.Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
March 16, 2021
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of New Fortress Energy Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of New Fortress Energy Inc. (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework and our report dated March 16, 2021 expressed an unqualified opinion thereon.
Adoption of ASU No. 2016-02
As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for leases in 2020 due to the adoption of ASU No. 2016-02, Leases.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
FINANCIAL INFORMATION
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
| Revenue Recognition – Identification of Distinct Performance Obligations and Leases |
| |
Description of the Matter | As described in Note 2(p) to the consolidated financial statements, the Company’s contracts with customers may contain one or several performance obligations to provide goods or services or may contain a lease. At inception or upon amendment, management performs an evaluation to identify the obligations within the contract and determine the authoritative guidance applicable to such obligations. The Company allocates consideration received from customers between lease and non-lease components based on the relative fair value of each component.
Auditing management’s identification of performance and other obligations in each contract was challenging as it involved complex judgement to identify all promised goods and services and determining whether the customer can benefit from the promised goods or services on their own or on a combined basis. In addition, auditing management’s determination of whether a contract is or contains a lease required judgement to determine which party to the agreement controls how and for what purpose the underlying asset is used.
|
How We Addressed the Matter
in Our Audit
| We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company's revenue recognition process, including controls over the evaluation of new and amended customer contracts and the identification of distinct performance obligations and equipment leases.
Our audit procedures included, among others, evaluating the Company’s assessment of the authoritative guidance applicable to its customer contracts, inspecting contracts entered into or amended during the period, and evaluating management’s interpretation of certain contract provisions when identifying and determining distinct performance obligations and equipment leases. For example, we selected a sample of new and amended customer contracts executed in the current year and compared the identified promised goods and services, including lease components, to the analyses used by management to measure and allocate arrangement consideration. We also conducted meetings with various personnel at the Company responsible for negotiating the contract and overseeing the delivery of the performance obligations in order to understand the nature of the explicit and implicit promised goods and services as well as to understand whether the promises were capable of being distinct and distinct in the context of the contract. For leases elements, this evaluation included understanding whether the customer controls how and for what purpose the underlying equipment is used.
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| Impairment Assessment of Long-Lived Assets |
| |
Description of the Matter | As described in Note 2(k) to the consolidated financial statements, the Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for liquified natural gas (“LNG”) to the Company’s operations, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if long-lived assets or asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value.
Auditing management’s determination of whether impairment indicators exist such that a recoverability test of the Company’s long-lived assets is required, was highly subjective and involves significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.
|
How We Addressed the Matter
in Our Audit
| We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups that may have been impacted by the impairment indicators described above.
To test the Company’s evaluation of potential indicators of impairment of its long- lived assets, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company operates and their impact on the recoverability of the related long-lived assets and asset groups. We also obtained capital budgets and construction bids, among other evidence, to understand management’s plans with respect to in-process development projects. We considered information about Company’s projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.
|
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2016.
Philadelphia, Pennsylvania
March 16, 2021
Item 8. Financial StatementsNew Fortress Energy Inc.
Consolidated Balance Sheets
As of December 31, 20202023 and 20192022
(in thousands of U.S. dollars, except share and per share amounts)
| | December 31, 2020 | | | December 31, 2019 | |
| Assets | | | | | | |
| Current assets | | | | | | |
| Cash and cash equivalents | | $ | 601,522 | | | $ | 27,098 | |
| Restricted cash | | | 12,814 | | | | 30,966 | |
| Receivables, net of allowances of $98 and $0, respectively | | | 76,544 | | | | 49,890 | |
| Inventory | | | 22,860 | | | | 63,432 | |
| Prepaid expenses and other current assets, net | | | 48,270 | | | | 39,734 | |
| Total current assets | | | 762,010 | | | | 211,120 | |
| | | | | | | | | |
| Restricted cash | | | 15,000 | | | | 34,971 | |
| Construction in progress | | | 234,037 | | | | 466,587 | |
| Property, plant and equipment, net | | | 614,206 | | | | 192,222 | |
| Right-of-use assets | | | 141,347 | | | | 0 | |
| Intangible assets, net | | | 46,102 | | | | 43,540 | |
| Finance leases, net | | | 7,044 | | | | 91,174 | |
| Deferred tax assets, net | | | 2,315 | | | | 34 | |
| Other non-current assets, net | | | 86,030 | | | | 84,166 | |
| Total assets | | $ | 1,908,091 | | | $ | 1,123,814 | |
| | | | | | | | | |
| Liabilities | | | | | | | | |
| Current liabilities | | | | | | | | |
| Accounts payable | | $ | 21,331 | | | $ | 11,593 | |
| Accrued liabilities | | | 90,352 | | | | 54,943 | |
| Current lease liabilities | | | 35,481 | | | | 0 | |
| Due to affiliates | | | 8,980 | | | | 10,252 | |
| Other current liabilities | | | 35,006 | | | | 25,475 | |
| Total current liabilities | | | 191,150 | | | | 102,263 | |
| | | | | | | | | |
| Long-term debt | | | 1,239,561 | | | | 619,057 | |
| Non-current lease liabilities | | | 84,323 | | | | 0 | |
| Deferred tax liabilities, net | | | 2,330 | | | | 241 | |
| Other long-term liabilities | | | 15,641 | | | | 14,929 | |
| Total liabilities | | | 1,533,005 | | | | 736,490 | |
| | | | | | | | | |
| Commitments and contingences (Note 17) | | | 0 | | | | 0 | |
| | | | | | | | | |
| Stockholders’ equity | | | | | | | | |
| Class A common stock, $0.01 par value, 750.0 million shares authorized, 174.6 million issued and outstanding as of December 31, 2020 | | | 1,746 | | | | 0 | |
| Class A shares, 0 shares issued and outstanding as of December 31, 2020; 23.6 million shares issued and outstanding as of December 31, 2019 | | | 0 | | | | 130,658 | |
| Class B shares, 0 shares issued and outstanding as of December 31, 2020; 144.3 million shares, issued and outstanding as of December 31, 2019 | | | 0 | | | | 0 | |
| Additional paid-in capital | | | 594,534 | | | | 0 | |
| Accumulated deficit | | | (229,503 | ) | | | (45,823 | ) |
| Accumulated other comprehensive income (loss) | | | 182 | | | | (30 | ) |
| Total stockholders’ equity attributable to NFE | | | 366,959 | | | | 84,805 | |
| Non-controlling interest | | | 8,127 | | | | 302,519 | |
| Total stockholders’ equity | | | 375,086 | | | | 387,324 | |
| Total liabilities and stockholders’ equity | | $ | 1,908,091 | | | $ | 1,123,814 | |
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Assets | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 155,414 | | | $ | 675,492 | |
| Restricted cash | 155,400 | | | 165,396 | |
| Receivables, net of allowances of $1,158 and $884, respectively | 342,371 | | | 280,313 | |
| Inventory | 113,684 | | | 39,070 | |
| Prepaid expenses and other current assets, net | 213,104 | | | 226,883 | |
| Total current assets | 979,973 | | | 1,387,154 | |
| | | |
| | | |
| Construction in progress | 5,348,294 | | | 2,418,608 | |
| Property, plant and equipment, net | 2,481,415 | | | 2,116,727 | |
| Equity method investments | 137,793 | | | 392,306 | |
| Right-of-use assets | 588,385 | | | 377,877 | |
| Intangible assets, net | 51,815 | | | 85,897 | |
| | | |
| Goodwill | 776,760 | | | 776,760 | |
| Deferred tax assets, net | 9,907 | | | 8,074 | |
| Other non-current assets, net | 126,903 | | | 141,679 | |
| Total assets | $ | 10,501,245 | | | $ | 7,705,082 | |
| | | |
| Liabilities | | | |
| Current liabilities | | | |
| Current portion of long-term debt and short-term borrowings | $ | 292,625 | | | $ | 64,820 | |
| Accounts payable | 549,489 | | | 80,387 | |
| Accrued liabilities | 471,675 | | | 1,162,412 | |
| Current lease liabilities | 164,548 | | | 48,741 | |
| Other current liabilities | 227,951 | | | 52,878 | |
| Total current liabilities | 1,706,288 | | | 1,409,238 | |
| | | |
| Long-term debt | 6,510,523 | | | 4,476,865 | |
| Non-current lease liabilities | 406,494 | | | 302,121 | |
| Deferred tax liabilities, net | 44,444 | | | 25,989 | |
| Other long-term liabilities | 55,627 | | | 49,010 | |
| Total liabilities | 8,723,376 | | | 6,263,223 | |
| | | |
| Commitments and contingencies (Note 22) | | | |
| | | |
| Stockholders’ equity | | | |
| Class A common stock, $0.01 par value, 750.0 million shares authorized, 205.0 million issued and outstanding as of December 31, 2023; 208.8 million issued and outstanding as of December 31, 2022 | 2,050 | | | 2,088 | |
| Additional paid-in capital | 1,038,530 | | | 1,170,254 | |
| Retained earnings | 527,986 | | | 62,080 | |
| Accumulated other comprehensive income | 71,528 | | | 55,398 | |
| Total stockholders’ equity attributable to NFE | 1,640,094 | | | 1,289,820 | |
| Non-controlling interest | 137,775 | | | 152,039 | |
| Total stockholders’ equity | 1,777,869 | | | 1,441,859 | |
| Total liabilities and stockholders’ equity | $ | 10,501,245 | | | $ | 7,705,082 | |
The accompanying notes are an integral part of these consolidated financial statements.
New Fortress Energy Inc.
Consolidated Statements of Operations and Comprehensive
LossIncomeFor the years ended December 31, 2020, 20192023, 2022 and 20182021
(in thousands of U.S. dollars, except share and per share amounts)
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| Revenues | | | | | | | | | |
| Operating revenue | | $ | 318,311 | | | $ | 145,500 | | | $ | 96,906 | |
| Other revenue | | | 133,339 | | | | 43,625 | | | | 15,395 | |
| Total revenues | | | 451,650 | | | | 189,125 | | | | 112,301 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Operating expenses | | | | | | | | | | | | |
| Cost of sales | | | 278,767 | | | | 183,359 | | | | 95,742 | |
| Operations and maintenance | | | 47,581 | | | | 26,899 | | | | 9,589 | |
| Selling, general and administrative | | | 124,170 | | | | 152,922 | | | | 62,137 | |
| Contract termination charges and loss on mitigation sales | | | 124,114 | | | | 5,280 | | | | 0 | |
| Depreciation and amortization | | | 32,376 | | | | 7,940 | | | | 3,321 | |
| Total operating expenses | | | 607,008 | | | | 376,400 | | | | 170,789 | |
| Operating loss | | | (155,358 | ) | | | (187,275 | ) | | | (58,488 | ) |
| Interest expense | | | 65,723 | | | | 19,412 | | | | 11,248 | |
| Other expense (income), net | | | 5,005 | | | | (2,807 | ) | | | (784 | ) |
| Loss on extinguishment of debt, net | | | 33,062 | | | | 0 | | | | 9,568 | |
| Loss before taxes | | | (259,148 | ) | | | (203,880 | ) | | | (78,520 | ) |
| Tax expense (benefit) | | | 4,817 | | | | 439 | | | | (338 | ) |
| Net loss | | | (263,965 | ) | | | (204,319 | ) | | | (78,182 | ) |
| Net loss attributable to non-controlling interest | | | 81,818 | | | | 170,510 | | | | 106 | |
| Net loss attributable to stockholders | | $ | (182,147 | ) | | $ | (33,809 | ) | | $ | (78,076 | ) |
| | | | | | | | | | | | | |
| Net loss per share – basic and diluted | | $ | (1.71 | ) | | $ | (1.62 | ) | | | | |
| | | | | | | | | | | | | |
| Weighted average number of shares outstanding – basic and diluted | | | 106,654,918 | | | | 20,862,555 | | | | | |
| | | | | | | | | | | | | |
| Other comprehensive loss: | | | | | | | | | | | | |
| Net loss | | $ | (263,965 | ) | | $ | (204,319 | ) | | $ | (78,182 | ) |
| Unrealized (gain) loss on currency translation adjustment | | | (2,005 | ) | | | 219 | | | | 0 | |
| Unrealized loss on available-for-sale investment | | | 0 | | | | 0 | | | | 2,677 | |
| Comprehensive loss | | | (261,960 | ) | | | (204,538 | ) | | | (80,859 | ) |
| Comprehensive loss attributable to non-controlling interest | | | 80,025 | | | | 170,699 | | | | 106 | |
| Comprehensive loss attributable to stockholders | | $ | (181,935 | ) | | $ | (33,839 | ) | | $ | (80,753 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Revenues | | | | | |
| Operating revenue | $ | 2,060,212 | | | $ | 1,978,645 | | | $ | 930,816 | |
| Vessel charter revenue | 276,843 | | | 357,158 | | | 230,809 | |
| Other revenue | 76,241 | | | 32,469 | | | 161,185 | |
| Total revenues | 2,413,296 | | | 2,368,272 | | | 1,322,810 | |
| | | | | |
| Operating expenses | | | | | |
| Cost of sales (exclusive of depreciation and amortization shown separately below) | 877,451 | | | 1,010,428 | | | 616,010 | |
| Vessel operating expenses | 45,439 | | | 63,518 | | | 51,677 | |
| Operations and maintenance | 166,785 | | | 105,800 | | | 73,316 | |
| Selling, general and administrative | 205,104 | | | 236,051 | | | 199,881 | |
| Transaction and integration costs | 6,946 | | | 21,796 | | | 44,671 | |
| Depreciation and amortization | 187,324 | | | 142,640 | | | 98,377 | |
| Asset impairment expense | 10,958 | | | 50,659 | | | — | |
| Gain on sale of assets, net | (29,378) | | | — | | | — | |
| Total operating expenses | 1,470,629 | | | 1,630,892 | | | 1,083,932 | |
| Operating income | 942,667 | | | 737,380 | | | 238,878 | |
| Interest expense | 277,842 | | | 236,861 | | | 154,324 | |
| Other expense (income), net | 10,408 | | | (48,044) | | | (17,150) | |
| Loss on extinguishment of debt, net | — | | | 14,997 | | | 10,975 | |
| Income before income from equity method investments and income taxes | 654,417 | | | 533,566 | | | 90,729 | |
| Income (loss) from equity method investments | 9,972 | | | (472,219) | | | 14,443 | |
| Tax provision (benefit) | 115,513 | | | (123,439) | | | 12,461 | |
| Net income | 548,876 | | | 184,786 | | | 92,711 | |
| Net (income) loss attributable to non-controlling interest | (994) | | | 9,693 | | | 4,393 | |
| Net income attributable to stockholders | $ | 547,882 | | | $ | 194,479 | | | $ | 97,104 | |
| | | | | |
| Net income per share – basic | $ | 2.66 | | | $ | 0.93 | | | $ | 0.49 | |
| Net income per share – diluted | $ | 2.65 | | | $ | 0.93 | | | $ | 0.47 | |
| | | | | |
| Weighted average number of shares outstanding – basic | 205,942,837 | | | 209,501,298 | | | 198,593,042 | |
| Weighted average number of shares outstanding – diluted | 206,481,977 | | | 209,854,413 | | | 201,703,176 | |
| | | | | |
| Other comprehensive income: | | | | | |
| Currency translation adjustment | 18,005 | | | 68,403 | | | (3,489) | |
| Reclassification of net foreign currency translation adjustment realized upon sale of foreign subsidiary | (1,457) | | | — | | | — | |
| Comprehensive income | 565,424 | | | 253,189 | | | 89,222 | |
| Comprehensive (income) loss attributable to non-controlling interest | (1,412) | | | 10,795 | | | 5,615 | |
| Comprehensive income attributable to stockholders | $ | 564,012 | | | $ | 263,984 | | | $ | 94,837 | |
The accompanying notes are an integral part of these consolidated financial statements.
New Fortress Energy Inc.
Consolidated Statements of Changes in Stockholders’ Equity
For the years ended December 31, 2020, 20192023, 2022 and 20182021
(in thousands of U.S. dollars, except per share amounts)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 January 1, 2021 | | 174,622,862 | | | $ | 1,746 | | | $ | 594,534 | | | $ | (229,503) | | | $ | 182 | | | $ | 8,127 | | | $ | 375,086 | |
| Net income (loss) | | — | | | — | | | — | | | 97,104 | | | — | | | (4,393) | | | 92,711 | |
| Other comprehensive loss | | — | | | — | | | — | | | — | | | (2,267) | | | (1,222) | | | (3,489) | |
| Share-based compensation expense | | — | | | — | | | 37,043 | | | — | | | — | | | — | | | 37,043 | |
| Shares issued as consideration in business combinations | | 31,372,549 | | | 314 | | | 1,400,470 | | | — | | | — | | | — | | | 1,400,784 | |
| Issuance of shares for vested RSUs | | 1,537,910 | | | 9 | | | (9) | | | — | | | — | | | — | | | — | |
| Shares withheld from employees related to share-based compensation, at cost | | (670,079) | | | — | | | (28,214) | | | — | | | — | | | — | | | (28,214) | |
| Non-controlling interest acquired in business combinations | | — | | | — | | | — | | | — | | | — | | | 236,570 | | | 236,570 | |
| Deconsolidation of the Eskimo SPV | | — | | | — | | | — | | | — | | | — | | | (28,049) | | | (28,049) | |
| Dividends | | — | | | — | | | (79,834) | | | — | | | — | | | (8,554) | | | (88,388) | |
| 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 (loss) | | — | | | — | | | — | | | 194,479 | | | — | | | (9,693) | | | 184,786 | |
| Other comprehensive income | | — | | | — | | | — | | | — | | | 69,505 | | | (1,102) | | | 68,403 | |
| Currency translation adjustment released upon Sergipe Sale | | — | | | — | | | — | | | — | | | (12,022) | | | — | | | (12,022) | |
| Share-based compensation expense | | — | | | — | | | 30,382 | | | — | | | — | | | — | | | 30,382 | |
| Issuance of shares for vested RSU/PSUs | | 3,426,213 | | | 19 | | | (12) | | | — | | | — | | | — | | | 7 | |
| Shares withheld from employees related to share-based compensation, at cost | | (1,519,367) | | | — | | | (74,822) | | | — | | | — | | | — | | | (74,822) | |
| Deconsolidation of Nanook, Celsius and Penguin SPVs | | — | | | — | | | — | | | — | | | — | | | (23,569) | | | (23,569) | |
| Dividends | | — | | | — | | | (709,284) | | | — | | | — | | | (16,076) | | | (725,360) | |
| 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 | | — | | | — | | | — | | | 547,882 | | | — | | | 994 | | | 548,876 | |
| Other comprehensive income | | — | | | — | | | — | | | — | | | 16,130 | | | 418 | | | 16,548 | |
| Share-based compensation expense | | — | | | — | | | 1,573 | | | — | | | — | | | — | | | 1,573 | |
| Acquisition and cancellation of shares | | (4,100,000) | | | (41) | | | (123,778) | | | — | | | — | | | — | | | (123,819) | |
| Issuance of shares for vested share-based compensation awards | | 689,401 | | | 3 | | | — | | | — | | | — | | | — | | | 3 | |
| Shares withheld from employees related to share-based compensation, at cost | | (328,083) | | | — | | | (9,519) | | | — | | | — | | | — | | | (9,519) | |
| Dividends | | — | | | — | | | — | | | (81,976) | | | — | | | (15,676) | | | (97,652) | |
| Balance as of December 31, 2023 | | 205,031,406 | | | $ | 2,050 | | | $ | 1,038,530 | | | $ | 527,986 | | | $ | 71,528 | | | $ | 137,775 | | | $ | 1,777,869 | |
| | Members’ Capital | | | Class A shares | | | Class B shares | | | Class A common stock | | | Additional paid-in | | | Stock subscription | | | Accumulated | | | Accumulated other comprehensive | | | Non-controlling | | | Total stockholders’ | |
| | Units | | | Amounts | | | Shares | | | Amount | | | Shares | | | Amount | | | Shares | | | Amount | | | capital | | | receivable | | | deficit | | | (loss) income | | | Interest | | | equity | |
| Balance as of January 1, 2018 | | | 65,665,037 | | | $ | 406,591 | | | | 0 | | | $ | 0 | | | | 0 | | | $ | 0 | | | | 0 | | | $ | 0 | | | $ | 0 | | | $ | (50,000 | ) | | $ | (80,347 | ) | | $ | 2,666 | | | $ | 0 | | | $ | 278,910 | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (78,076 | ) | | | - | | | | (106 | ) | | | (78,182 | ) |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (2,677 | ) | | | - | | | | (2,677 | ) |
| Capital contributions | | | 665,843 | | | | 20,150 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 20,150 | |
| Stock subscription receivable | | | 1,652,215 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 50,000 | | | | - | | | | - | | | | - | | | | 50,000 | |
| Acquisition of Shannon LNG | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 14,446 | | | | 14,446 | |
| Balance as of December 31, 2018 | | | 67,983,095 | | | | 426,741 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (158,423 | ) | | | (11 | ) | | | 14,340 | | | | 282,647 | |
| Activity prior to the IPO and related organizational transactions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (7,923 | ) | | | 11 | | | | (91 | ) | | | (8,003 | ) |
| Effects of the IPO and related organizational transactions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Issuance of Class A shares in the IPO, net of underwriting discount and offering costs | | | - | | | | - | | | | 20,837,272 | | | | 32,136 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 235,874 | | | | 268,010 | |
| Effects of the reorganization transactions | | | (67,983,095 | ) | | | (426,741 | ) | | | - | | | | 51,092 | | | | 147,058,824 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 146,420 | | | | - | | | | 229,229 | | | | 0 | |
| Activity subsequent to the IPO and related organizational transactions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (25,897 | ) | | | - | | | | (170,419 | ) | | | (196,316 | ) |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (30 | ) | | | (189 | ) | | | (219 | ) |
| Share-based compensation expense | | | - | | | | - | | | | - | | | | 41,205 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 41,205 | |
| Exchange of NFI Units | | | - | | | | - | | | | 2,716,252 | | | | 6,225 | | | | (2,716,252 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (6,225 | ) | | | 0 | |
| Issuance of shares for vested RSUs | | | - | | | | - | | | | 53,572 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0 | |
| Balance as of December 31, 2019 | | | 0 | | | | 0 | | | | 23,607,096 | | | | 130,658 | | | | 144,342,572 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (45,823 | ) | | | (30 | ) | | | 302,519 | | | | 387,324 | |
| Cumulative effect of accounting change | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0 | | | | (1,533 | ) | | | 0 | | | | (7,780 | ) | | | (9,313 | ) |
| Class A stock issued, net of issuance costs | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 5,882,352 | | | | 59 | | | | 290,712 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 290,771 | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0 | | | | 0 | | | | (182,147 | ) | | | 0 | | | | (81,818 | ) | | | (263,965 | ) |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0 | | | | 0 | | | | 0 | | | | 212 | | | | 1,793 | | | | 2,005 | |
| Share-based compensation expense | | | - | | | | - | | | | - | | | | 4,430 | | | | - | | | | - | | | | - | | | | - | | | | 4,313 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 8,743 | |
| Issuance of shares for vested RSUs | | | - | | | | - | | | | 1,224,436 | | | | - | | | | - | | | | - | | | | 160,317 | | | | - | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | |
| Shares withheld from employees related to share-based compensation, at cost | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (593,911 | ) | | | - | | | | (6,468 | ) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (6,468 | ) |
| Exchange of NFI units | | | - | | | | - | | | | 144,342,572 | | | | 206,587 | | | | (144,342,572 | ) | | | - | | | | - | | | | - | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (206,587 | ) | | | 0 | |
| Conversion from LLC to Corporation | | | - | | | | - | | | | (169,174,104 | ) | | | (341,675 | ) | | | - | | | | - | | | | 169,174,104 | | | | 1,687 | | | | 339,988 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | |
| Dividends | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (34,011 | ) | | | - | | | | - | | | | - | | | | - | | | | (34,011 | ) |
| Balance as of December 31, 2020 | | | - | | | $ | - | | | | 0 | | | $ | 0 | | | | 0 | | | $ | 0 | | | | 174,622,862 | | | $ | 1,746 | | | $ | 594,534 | | | $ | 0 | | | $ | (229,503 | ) | | $ | 182 | | | $ | 8,127 | | | $ | 375,086 | |
The accompanying notes are an integral part of these consolidated financial statements.
New Fortress Energy Inc.
Consolidated Statements of
Cash Flows
For the years ended December 31, 2020, 20192023, 2022 and 20182021
(in thousands of U.S. dollars)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 548,876 | | | $ | 184,786 | | | $ | 92,711 | |
| Adjustments for: | | | | | |
| Amortization of deferred financing costs and debt guarantee, net | 6,589 | | | 2,536 | | | 14,116 | |
| Depreciation and amortization | 187,324 | | | 143,589 | | | 99,544 | |
| (Earnings) losses of equity method investees | (9,972) | | | 472,219 | | | (14,443) | |
| | | | | |
| Dividends received from equity method investees | 5,830 | | | 29,372 | | | 21,365 | |
| | | | | |
| Change in market value of derivatives | (3,204) | | | (136,811) | | | (8,691) | |
| | | | | |
| Deferred taxes | 14,938 | | | (279,536) | | | (8,825) | |
| | | | | |
| Share-based compensation | 1,573 | | | 30,382 | | | 37,043 | |
| Asset impairment expense | 10,958 | | | 50,659 | | | — | |
| Earnings recognized from vessels chartered to third parties transferred to Energos | (156,997) | | | (49,686) | | | — | |
| Loss on the disposal of equity method investment | 37,401 | | | — | | | — | |
| Gain on asset sales | (29,378) | | | — | | | — | |
| Loss on extinguishment of debt | — | | | 14,997 | | | 10,975 | |
| Loss on sale of net investment in lease | — | | | 11,592 | | | — | |
| Other | 21,438 | | | (14,186) | | | (11,177) | |
| Changes in operating assets and liabilities, net of acquisitions: | | | | | |
| (Increase) in receivables | (41,019) | | | (139,938) | | | (123,583) | |
| (Increase) in inventories | (39,790) | | | (7,933) | | | (11,152) | |
| Decrease (increase) in other assets | 41,828 | | | (30,086) | | | (1,839) | |
| Decrease in right-of-use assets | 83,537 | | | 63,593 | | | 28,576 | |
| Increase in accounts payable/accrued liabilities | 78,065 | | | 67,741 | | | 17,527 | |
| | | | | |
| (Decrease) in lease liabilities | (74,576) | | | (63,493) | | | (36,126) | |
| Increase (decrease) in other liabilities | 141,335 | | | 5,314 | | | (21,251) | |
| Net cash provided by operating activities | 824,756 | | | 355,111 | | | 84,770 | |
| | | | | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (3,029,834) | | | (1,174,008) | | | (669,348) | |
| Cash paid for business combinations, net of cash acquired | — | | | — | | | (1,586,042) | |
| Entities acquired in asset acquisitions, net of cash acquired | — | | | — | | | (8,817) | |
| Proceeds from sale of net investment in lease | — | | | 593,000 | | | — | |
| Sale of equity method investment | 100,000 | | | 500,076 | | | — | |
| Asset sales | 16,464 | | | — | | | — | |
| Other investing activities | 9,227 | | | (1,794) | | | (9,354) | |
| Net cash used in investing activities | (2,904,143) | | | (82,726) | | | (2,273,561) | |
| | | | | |
| Cash flows from financing activities | | | | | |
| Proceeds from borrowings of debt | 3,005,387 | | | 2,032,020 | | | 2,434,650 | |
| Payment of deferred financing costs | (37,806) | | | (17,598) | | | (37,811) | |
| Repayment of debt | (686,508) | | | (1,520,813) | | | (461,015) | |
| Payments related to tax withholdings for share-based compensation | (9,519) | | | (72,602) | | | (30,124) | |
| Payment of dividends | (723,962) | | | (99,050) | | | (88,756) | |
| Other financing activities | (18,642) | | | — | | | — | |
| Net cash provided by financing activities | 1,528,950 | | | 321,957 | | | 1,816,944 | |
| | | | | |
| Impact of changes in foreign exchange rates on cash and cash equivalents | 6,168 | | | (3,289) | | | 6,541 | |
| Net (decrease) increase in cash, cash equivalents and restricted cash | (544,269) | | | 591,053 | | | (365,306) | |
| Cash, cash equivalents and restricted cash – beginning of period | 855,083 | | | 264,030 | | | 629,336 | |
| Cash, cash equivalents and restricted cash – end of period | $ | 310,814 | | | $ | 855,083 | | | $ | 264,030 | |
| | | | | |
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| Cash flows from operating activities | | | | | | | | | |
| Net loss | | $ | (263,965 | ) | | $ | (204,319 | ) | | $ | (78,182 | ) |
| Adjustments for: | | | | | | | | | | | | |
| Amortization of deferred financing costs | | | 10,519 | | | | 5,873 | | | | 4,023 | |
| Depreciation and amortization | | | 33,303 | | | | 8,641 | | | | 4,034 | |
| Non-cash contract termination charges and loss on mitigation sales | | | 19,114 | | | | 2,622 | | | | 0 | |
| Loss on extinguishment and financing expenses | | | 37,090 | | | | 0 | | | | 3,188 | |
| Deferred taxes | | | 2,754 | | | | 392 | | | | (345 | ) |
| Share-based compensation | | | 8,743 | | | | 41,205 | | | | 0 | |
| Other | | | 4,341 | | | | 1,247 | | | | 439 | |
| Changes in operating assets and liabilities: | | | | | | | | | | | | |
| (Increase) in receivables | | | (26,795 | ) | | | (19,754 | ) | | | (9,516 | ) |
| Decrease (Increase) in inventories | | | 23,230 | | | | (50,345 | ) | | | (4,807 | ) |
| (Increase) in other assets | | | (35,927 | ) | | | (39,344 | ) | | | (28,338 | ) |
| Decrease in right-of-use assets | | | 41,452 | | | | 0 | | | | 0 | |
| Increase in accounts payable/accrued liabilities | | | 55,514 | | | | 3,036 | | | | 12,232 | |
| (Decrease) Increase in amounts due to affiliates | | | (1,272 | ) | | | 5,771 | | | | 2,390 | |
| (Decrease) in lease liabilities | | | (42,094 | ) | | | 0 | | | | 0 | |
| Increase in other liabilities | | | 8,427 | | | | 10,714 | | | | 1,655 | |
| Net cash used in operating activities | | | (125,566 | ) | | | (234,261 | ) | | | (93,227 | ) |
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Capital expenditures | | | (156,995 | ) | | | (377,051 | ) | | | (181,151 | ) |
| Acquisition of consolidated subsidiary | | | 0 | | | | 0 | | | | (4,028 | ) |
| Other investing activities | | | (636 | ) | | | 887 | | | | 724 | |
| Net cash used in investing activities | | | (157,631 | ) | | | (376,164 | ) | | | (184,455 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Proceeds from borrowings of debt | | | 2,095,269 | | | | 347,856 | | | | 280,600 | |
| Payment of deferred financing costs | | | (36,499 | ) | | | (8,259 | ) | | | (14,026 | ) |
| Repayment of debt | | | (1,490,002 | ) | | | (5,000 | ) | | | (76,520 | ) |
| Proceeds from IPO | | | 0 | | | | 274,948 | | | | 0 | |
| Proceeds from issuance of Class A common stock | | | 291,992 | | | | 0 | | | | | |
| Payments related to tax withholdings for share-based compensation | | | (6,413 | ) | | | 0 | | | | 0 | |
| Payment of dividends | | | (33,742 | ) | | | 0 | | | | 0 | |
| Capital contributed from Members | | | 0 | | | | 0 | | | | 20,150 | |
| Collection of subscription receivable | | | 0 | | | | 0 | | | | 50,000 | |
| Payment of stock issuance costs | | | (1,107 | ) | | | (6,938 | ) | | | 0 | |
| Net cash provided by financing activities | | | 819,498 | | | | 602,607 | | | | 260,204 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | | | 536,301 | | | | (7,818 | ) | | | (17,478 | ) |
| Cash, cash equivalents and restricted cash – beginning of period | | | 93,035 | | | | 100,853 | | | | 118,331 | |
| Cash, cash equivalents and restricted cash – end of period | | $ | 629,336 | | | $ | 93,035 | | | $ | 100,853 | |
| | | | | | | | | | | | | |
| 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 | | $ | (12,786 | ) | | $ | (48,150 | ) | | $ | 74,280 | |
| Cash paid for interest, net of capitalized interest | | | 27,255 | | | | 6,765 | | | | 7,515 | |
| Cash paid for taxes | | | 58 | | | | 28 | | | | 0 | |
The accompanying notes are an integral part of these consolidated financial statements.
New Fortress Energy Inc.
Consolidated Statements of Cash Flows
For the years ended December 31, 2023, 2022 and 2021
(in thousands of U.S. dollars)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Cash paid for interest, net of capitalized interest | 100,304 | | | 160,618 | | | 154,249 | |
| Cash paid for taxes | 52,897 | | | 151,210 | | | 17,319 | |
| | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| 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 | $ | 322,598 | | | $ | 284,390 | | | $ | 108,790 | |
| Accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions | 738,163 | | | 422,391 | | | 133,705 | |
| Liabilities associated with consideration paid for entities acquired in asset acquisitions | — | | | — | | | 10,520 | |
| Consideration paid in shares for business combinations | — | | | — | | | 1,400,784 | |
| Consideration received on asset sale | 27,704 | | | — | | | — | |
| Principal payments on financing obligation paid to Energos by third party charters | (66,866) | | | (24,949) | | | — | |
| Shares received in Hilli Exchange | (122,754) | | | — | | | — | |
| Investment in Energos | 1,501 | | | 129,518 | | | — | |
| Accrued dividend | — | | | 626,310 | | | — | |
| Non-cash financing costs | — | | | 46,371 | | | — | |
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 Other non-current assets, net on the Consolidated Balance Sheets (Note 17) presented in the Consolidated Statement of Cash Flows:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 |
| Cash and cash equivalents | 155,414 | | | 675,492 | |
| Current restricted cash | 155,400 | | | 165,396 | |
| Non-current restricted cash | — | | | 2,581 | |
| Cash and cash equivalents classified as held for sale | — | | | 11,614 | |
| Cash, cash equivalents and restricted cash – end of period | $ | 310,814 | | | $ | 855,083 | |
Cash and cash equivalents as of December 31, 2022 includes $11,614 which has been classified as assets held for sale and included in Other non-current assets on the Consolidated Balance Sheets.
The accompanying notes are an integral part of these consolidated financial statements.
New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”) is, a Delaware corporation, formed by New Fortress Energy Holdings LLC (“New Fortress Energy Holdings”). The Company is a global integrated gas-to-powerenergy infrastructure company that seeksfounded to usehelp address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. The Company owns and operates natural gas and liquefied natural gas (" LNG") infrastructure, ships and logistics assets to satisfy the world’s large and growing power needs and is engaged in providingrapidly deliver turnkey energy and development servicessolutions to end-users worldwide seeking to convert their operating assets from diesel or heavy fuel oil to LNG. The Company currently sources LNG from a combination of its own liquefaction facility in Miami, Florida and purchases on the open market.global markets. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, Brazil and Jamaica.
The Company manages, analyzes and reports oncurrently conducts its business through two operating segments, Terminals and results of operations onInfrastructure and Ships. The business and reportable segment information reflect how the basis of 1 operating segment. The chief operating decision maker makes resource allocation decisionsChief Operating Decision Maker (“CODM”) regularly reviews and assesses performance based on financial information presented on a consolidated basis.
manages the business.
2. | 2. Significant accounting policies |
The principleprincipal accounting policies adopted are set out below.
(a) | Basis of presentation and principles of consolidation |
The accompanying consolidated financial statements contained herein were prepared in accordance with GAAP.accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest. All significant intercompany transactions and balances have been eliminated on consolidation. Certain prior year amounts have been reclassified to conform to current year presentation.
On February 4, 2019, the Company completed an initial public offeringA variable interest entity (“IPO”VIE”) and a series of other transactions, in which the Company issued and sold 20,000,000 Class A shares at an IPO price of $14.00 per share. The Company’s Class A shares began trading on NASDAQ Global Select Market (“NASDAQ”) under the symbol “NFE” on January 31, 2019. Net proceeds from the IPO were $257.0 million, after deducting underwriting discounts and commissions and transaction costs. These proceeds were contributed to New Fortress Intermediate LLC (“NFI”),is an entity formed in conjunction withthat by design meets any of the IPO, in exchange for 20,000,000 limited liability company units in NFI (“NFI LLC Units”). In addition, New Fortress Energy Holdings contributed allfollowing characteristics: (1) lacks sufficient equity to allow the entity to finance its activities without additional subordinated financial support; (2) as a group, equity investors do not have the ability to make significant decisions relating to the entity’s operations through voting rights, do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of its interests in consolidated subsidiaries that comprisedthe entity; or (3) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and substantially all of its historical operationsthe entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. The primary beneficiary of a VIE is required to NFI in exchange for NFI LLC Units. In connection withconsolidate the IPO, New Fortress Energy Holdings also received 147,058,824 Class B shares of NFE, which is equal to the number of NFI LLC Units held by New Fortress Energy Holdings immediately following the IPO. New Fortress Energy Holdings retained a significant interest in NFE through its ownership of 147,058,824 Class B shares, representing an 88.0% votingassets and non-economic interest. New Fortress Energy Holdings also had an 88.0% economic interest in NFI through its ownership of 147,058,824 of NFI LLC Units. New Fortress Energy Holdings is NFE’s predecessor for accounting purposes.
On March 1, 2019, the underwritersliabilities of the IPO exercised their optionVIE. The primary beneficiary is the party that has both (1) the power to purchase an additional 837,272 Class A shares atdirect the IPO price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting $0.7 million of underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. In connection with the exerciseeconomic activities of the underwriters’ option to purchase an additional 837,272 Class A shares, NFE contributed such additional net proceeds to NFI in exchange for 837,272 NFI LLC Units.
UntilVIE that most significantly impact the Exchange Transactions (as defined below) were completed, NFE was a holding company whose sole material asset was a controlling equity interest in NFI. As the sole managing member of NFI, NFE operatedVIE’s economic performance; and controlled all of the business and affairs of NFI, and(2) through NFI and its subsidiaries, conducted the Company’s historical business. The contribution of the assets of New Fortress Energy Holdings and net proceeds from the IPO to NFI was treated as a reorganization of entities under common control (the “Reorganization”). As a result, NFE presented the consolidated balance sheets and statements of operations and comprehensive loss of New Fortress Energy Holdings for all periods prior to the IPO.
On June 3, 2020, the Company entered into a mutual agreement (the “Mutual Agreement”) with the members holding the majority voting interest in New Fortress Energy Holdings (“Exchanging Members”) and NFE Sub LLC, a wholly-owned subsidiary of NFE. Pursuant to the Mutual Agreement, the Exchanging Members agreed to deliver a block redemption notice in accordance with the Amended and Restated Limited Liability Company Agreement of NFI (the “NFI LLCA”) with respect to all of the NFI LLC Units, together with an equal number of Class B shares of NFE, that such Exchanging Members indirectly own as members of New Fortress Energy Holdings. Pursuant to the Mutual Agreement, NFE agreed to exercise the Call Right (as defined in the NFI LLCA), pursuant to which NFE would acquire such NFI LLC Units and such Class B shares in exchange for Class A shares of NFE (the “Exchange Transactions”). The Exchange Transactions were completed on June 10, 2020. In connection with the closing of the Exchange Transactions, NFE issued 144,342,572 Class A shares in exchange for an equal number of NFI LLC Units, together with an equal number of Class B shares of NFE. Following the completion of the Exchange Transactions, NFE owns all of the NFI LLC Units directly or indirectly and 0 Class B shares remain outstanding.
Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s consolidated financial statements. Results of operations forVIE, the period priorobligation to absorb the losses or the right to receive the benefits from the VIE that could potentially be significant to the dateVIE.
Non-controlling interests are classified as a separate component of equity on the Exchange Transactions, June 10, 2020, wasConsolidated Balance Sheets and Consolidated Statements of Changes in Stockholders’ Equity. Additionally, net income and comprehensive income (loss) attributable to non-controlling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Changes in Stockholders’ Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and non-controlling interests. Losses continue to be attributed to the non-controlling interest based oninterests, even when the Exchanging Members’ interest in NFI; subsequent to the Exchange Transactions, results of operations, excluding results attributable to other investors in non-wholly owned subsidiaries, were recognized as net income or loss attributable to stockholders. Amounts that were attributable to these Exchanging Members’ prior interest in NFI previously shown as non-controlling interest on the Company’s consolidated balance sheets have been reclassified to Class A shares.
On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (“the Conversion”). Since the IPO, NFE LLCinterests’ basis has been a corporation for U.S. federal tax purposes and converting NFE LLC from a limited liability companyreduced to a corporation has zero.
(b)no effect on the U.S. federal tax treatmentUse of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion was converted into estimates1 issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of NFE (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity. As of December 31, 2020, NFE had 174,622,862 Class A common stock outstanding.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include relative fair value allocations between revenue and lease components of contracts with customers, determination of current expected credit losses, the incremental borrowing rates used in the determination of lease liabilities, total consideration and fair value of identifiable net assets related to acquisitions and the fair value of equity awards granted to both employees and non-employees. Management evaluates its estimates and related assumptions regularly. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
(c)Foreign currencies
The Company has certain foreign subsidiaries wherein which the functional currency is the local currency. All of the assets and liabilities of these subsidiaries are translated to U.S. dollars at the exchange rate in effect at the balance sheet date; income and expense accounts are translated at average rates for the period. The effects of translating financial statements of foreign operations into our reporting currency are recognized as a cumulative translation adjustment in accumulated other comprehensive income (loss).
The Company also has foreign subsidiaries that have aconduct business in currencies other than their respective functional currencies. Transactions are remeasured to the subsidiaries’ functional currency ofat the U.S. dollar. Purchases and sales of assets and income and expense items denominatedexchange rate in foreign currencies are remeasured into U.S. dollar amountseffect on the respective dates of such transactions. Net realized foreign currency gains or losses relating to the differences between these recorded amounts and the U.S. dollarfunctional currency equivalent actually received or paid are included within Other expense (income), net in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in accumulatedAccumulated other comprehensive income (loss).income. Accumulated foreign currency translation adjustments are reclassified from accumulatedAccumulated other comprehensive income (loss) to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. If the Company commits to a plan to sell or liquidate a foreign entity, accumulated foreign currency translation adjustments would be included in carrying amounts in impairment assessments.
(d) | Cash and cash equivalents |
The Company considers all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on the consolidated balance sheets.Consolidated Balance Sheets.
(f)Receivables
Receivables are reported at amortized cost,contractual rights to receive cash on a fixed or determinable date and are recognized on the balance sheet as the amount invoiced to the customer, net of an allowance for current expected credit losses. AmountsAccounts receivable are carried at amortized cost. Amounts are written off against the allowance when management is certain that outstanding amounts will not be collected. The Company estimates expected credit losses based on relevant information about the current credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount. Credit loss expense, inclusive of credit loss expense on all categories of financial assets, is recorded within Selling, general and administrative in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income.
LNG and natural gas inventories, bunker fuel inventories and automotive diesel oil inventories are recorded at weighted average cost, and materials and other inventory are recorded at cost. The Company’s cost to convert from natural gas to LNG, which primarily consists of labor, depreciation and other direct costs to operate liquefaction facilities, is reflected in Inventory on the consolidated balance sheets.
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 consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.
LNG is subject to “boil-off,” a natural loss of gas volume over time when LNG is exposed to environments with temperatures above its optimum storage state. Boil-off losses are expensed through Cost of sales in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive lossComprehensive Income in instances where gas cannot be contained and recycled back into the production process.
F-11
(h) | Construction in progress |
(h)Construction in progress
Construction in progress is recorded at cost, and at the point at which the constructed asset is put into use, the full cost of the asset is reclassified from Construction in progress to Property, plant and equipment, net or Finance leases, net on the consolidated balance sheets.Consolidated Balance Sheets. Construction progress payments, engineering costs and other costs directly relating to the asset under construction are capitalized during the construction period, provided the completion of the construction project is deemed probable or if the costs are associated with activities that could be utilized in future projects. Prior to putting our projects into service we may utilize gas to test and commission the assets, and we may be able to invoice our customers for gas used in commissioning. Amounts received as a result of the sale of test gas reduce the Construction in progress balance. Depreciation is not recognized during the construction period.
The interest cost associated with major development and construction projects is capitalized during the construction period and included in the cost of the project in Construction in progress.
(i) | Property, plant and equipment, net |
(i)Property, plant and equipment, net
Property, plant and equipment is initially recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Vessel refurbishment costs are capitalized and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs increase the capacity or improve the efficiency or safety of vessels and equipment. Expenditures for routine maintenance and repairs for assets in the Terminals and Infrastructure segment are charged to expense as incurred within Operations and maintenance in the Consolidated Statements of Operations and Comprehensive Income; such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses.
Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul, whileoverhaul.
Drydocking expenditures, for routine maintenanceincluding drydocking expenditures related to vessels that were included in the Energos Formation Transaction (defined below), are capitalized when incurred and repairs are chargedamortized over the period until the next anticipated drydocking, which is generally five years. For vessels, the Company utilizes the “built-in overhaul” method of accounting and segregates vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals. If drydocking occurs prior to expense as incurredthe expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the Consolidated Statements of Operations and maintenance in the consolidated statements of operations and comprehensive loss. Comprehensive Income.
The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:
| | | | | |
| Useful life (Yrs) |
| Vessels | 5-30 |
| Terminal and power plant equipment | 4-24 |
| CHP facilities | 4-20 |
| Gas terminals | 5-24 |
ISO containers and otherassociated equipment | 3-25 |
| LNG liquefaction facilities | 20-40 |
| Gas pipelines | 4-24 |
| Leasehold improvements | 2-20 |
The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.
Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income. When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal.
F-12
(j) | Asset retirement obligations (“AROs”) |
AROs are recognized for legal obligations associated with the retirement(j)Impairment of long-lived assets that result from the acquisition, leasing, construction, development and/or normal use of the assets and for conditional AROs in which the timing or method of settlement are conditional on a future event. The fair value of a liability for an ARO is recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made and is accreted to its final value over the life of the liability. The initial fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
The Company estimates the fair value of the ARO liability based on the present value of expected cash flows using a credit-adjusted risk-free rate. Liabilities for AROs may be incurred over more than one reporting period if the events that create the obligation occur over more than one period or if estimates change. The liability is accreted to its present value each period and the capitalized cost is depreciated in Depreciation and amortization in the consolidated statements of operations and comprehensive loss. Upon settlement of the obligation, the Company eliminates the liability and based on the actual cost to retire, may incur a gain or loss. There were 0 settlements of AROs during the years ended December 31, 2020 and 2019.
(k) | Impairment of long-lived assets |
The Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for LNG to the Company’s operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology.
When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge.
Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources. The Company did 0t record an impairment during the years ended December 31, 2020, 2019 and 2018.
(l) | Investment in equity securities |
Investment(k)Investments in equity securities is
Investments in equity securities are carried at fair value and included in Other non-current assets on the consolidated balance sheets,Consolidated Balance Sheets, with gains or losses recorded in earnings in Other expense (income), net in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income.
(m)Intangible assets
Upon a business combination or asset acquisition, the Company may obtain identifiable intangible assets. Intangible assets with a finite life are amortized over the estimated useful life of the asset under the straight-line method.
Indefinite lived intangible assets are not amortized. Intangible assets with an indefinite useful life are tested for impairment on an annual basis, on October 1st of each year, or more frequently if changes in circumstances indicate that it is more likely than not that the asset is impaired. Indefinite lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense in the consolidated statementsConsolidated Statements of operationsOperations and comprehensiveComprehensive Income.
(n)Goodwill
Goodwill includes the excess of the purchase price over the fair value of the net tangible and intangible assets acquired in a business combination.
The Company reviews the carrying values of goodwill at least annually to assess impairment since these assets are not amortized. An annual impairment assessment is conducted as of October 1st of each year. Additionally, the Company reviews the carrying value of goodwill whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.
For an annual goodwill impairment assessment, an optional qualitative analysis may be performed. If the option is not elected or if it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then a two-step goodwill impairment test is performed to identify potential goodwill impairment and to measure an impairment loss. A qualitative analysis was elected for the years ended December 31, 2023 and 2022.
F-13
(n) | Long-term debt and debt issuance costs |
A goodwill impairment assessment compares the fair value of a respective reporting unit with its carrying amount, including goodwill. The Company’sestimate of fair value of the respective reporting unit is based on the best information available as of the date of assessment, which primarily incorporates assumptions about operating results, business plans, income projections, anticipated future cash flows and market data. If goodwill is determined to be impaired, an impairment loss, measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.
There was no impairment of goodwill for the years ended December 31, 2023 and 2022.
(o)Long-term debt has historically consisted of credit facilities with financial institutions and secured and unsecured bonds. debt issuance costs
Costs directly related to the issuance of debt are reported on the consolidated balance sheetsConsolidated Balance Sheets as a reduction from the carrying amount of the recognized debt liability and amortized over the term of the debt using the effective interest method. Unamortized debt issuance costs associated with the revolving credit agreement, facilities for the issuance of letters of credit and other similar arrangements are presented as an asset within Other non-current assets on the Consolidated Balance Sheets (regardless of whether there are any amounts outstanding under the credit facility) and amortized over the life of the particular arrangement. Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project.
The Company may be involved in legal actions in the ordinary course of business, including governmental and administrative investigations, inquiries and proceedings concerning employment, labor, environmental and other claims. The Company will recognizerecognizes a loss contingency in the consolidated financial statements when it is probable a liability has been incurred and the amount of the loss can be reasonably estimated. The Company will disclosediscloses any loss contingencies that do not meet both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.
TheTerminals and Infrastructure
Within the Terminals and Infrastructure segment, the Company’s contracts with customers may contain 1one or several performance obligations usually consisting of the sale of LNG, natural gas, and beginning in the first quarter of 2020, power and steam, which are outputs from the Company’s natural gas-fueled infrastructure.infrastructure and the sale of LNG cargos. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites.sites but may also be delivered via vessel to an unloading point specified in a contract. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, the Company has presented Operating revenue on an aggregated basis.
The Company has concluded that variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.
The Company’s contracts with customers to supply natural gas or LNG may contain a lease of equipment.equipment or vessels, which may be accounted for as a finance or operating lease. For operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated the lease component. The lease component of such operating leases is recognized as Operating revenue in the Consolidated Statements of Operations and Comprehensive Income. The Company allocates consideration received from customersin agreements containing finance leases between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term.
The leases of certain facilities and equipment to customers are accounted for as finance or operating leases. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases,Other non-current assets, net on the consolidated balance sheets,Consolidated Balance Sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. For the Company’s operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss.
In addition to the revenue recognized from the leasingfinance lease components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as the Company transfers control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and the Company recognizes revenue for the interest income component over the term of the financing as Other revenue.
The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration; unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer.consideration. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Both unbilled receivables and contractContract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the consolidated balance sheets.Consolidated Balance Sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the consolidated balance sheets.
Shipping and handling costs are not considered to be separate performance obligations. These costs are recognized in the period in which the costs are incurred and presented within Cost of sales in the consolidated statements of operations and comprehensive loss. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas.
The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has elected to present sales tax collections in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive lossComprehensive Income on a net basis and, accordingly, such taxes are excluded from reported revenues.
The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.
(q) | Contract termination charges and loss on mitigation salesShips
|
At inception, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. Renewal periods and termination options are included in the lease term if the Company believes such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. The Company assesses leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease.
For charter contracts that are determined to be finance leases accounted for as sales-type leases, the profit from the sale of the vessel is recognized upon lease commencement in Other revenue in the Consolidated Statements of Operations and Comprehensive Income. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the Consolidated Statements of Operations and Comprehensive Income. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive Income.
Revenue includes lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenue generated from charters contracts is recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive Income. Lease payments include fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, the Company has elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based become probable or occur.
Repositioning fees are included in Vessel charter revenue and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee is recognized evenly over the term of the charter.
Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the Consolidated Statements of Operations and Comprehensive Income over the lease term.
The Company has long-term supply agreementscontinues to purchase LNG,be the accounting owner of vessels included in the Energos Formation Transaction (Note 5), and the Company may incur termination charges toaccounts for third party charters of these vessels under the extent that the Company cancels such contractual arrangements. Further, if the Companyaccounting policies for vessel leases described above. The third-party charters of these vessels are operating leases, and revenue is unable to take physical possession of a portion of the contracted quantity of LNG due to capacity limitations, the supplier will attempt to sell the undelivered quantity through a mitigation sale. The Company may incur a loss on a mitigation sale if the cargo is unable to be sold for a price greater than the contracted price. These costs are included in a separate linerecognized from these charters within Vessel charter revenue in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss because such costs are not related to inventory delivered to the Company’s customers.
During the year ended (r)December 31, 2020, the Company recognized a termination charge of $105,000 associated with an agreement with one of the Company’s LNG suppliers to terminate the obligation to purchase any LNG from this supplier for the remainder of 2020. Loss on mitigation sales of $19,114 were recognized during the year ended December 31, 2020.Leases, as lessee
Effective January 1, 2020, the Company adopted ASU 2016-02, Leases (Topic 842), using a modified retrospective approach. The Company has entered into lease agreements primarily for the use of LNG vessels, marine port space, office space, land and equipment, all of which are operating leases.equipment. Right-of-use (“ROU”) assets recognized for these leases represent the Company’s right to use an underlying asset for the lease term, and the lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of fixed lease payments over the lease term.
Leases with terms of 12 months or less are excluded from ROU assets and lease liabilities on the balance sheet, and short-term lease payments are recognized on a straight-line basis over the lease term. Variable payments under short-term leases are recognized in the period in which the obligation that triggers the variable payment becomes probable.
The Company, as lessee, has also elected the practical expedient not to separate lease and non-lease components for marine port space, office space, land and equipment leases. The Company separates the lease and non-lease components for LNG vessel leases. The allocation of lease payments between lease and non-lease components has been determined based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone price to lease a bareboat LNG vessel. The fair value of the non-lease component is estimated based on the estimated standalone price of operating the respective vessel, inclusive of the costs of the crew and other operating costs.
The Company has elected the land easement practical expedient, which allows the Company to continue to account for pre-existing land easements as intangible assets under the accounting policy that existed before adoption of ASC 842.842 Leases.
(s) | Share-based compensation |
In connection with the IPO, theThe Company adopted the New Fortress Energy LLCInc. 2019 Omnibus Incentive Plan (the “Incentive Plan”), effective as of February 4, 2019. Under the Incentive Plan, the Company may issue options, share appreciation rights, restricted shares, restricted share units (“RSUs”), performance share bonusesunits (“PSUs”) or other share-based awards to selected officers, employees, non-employee directors and select non-employees of NFE or its affiliates. The Company accounts for share-based compensation in accordance with ASC 718, Compensation – Stock Compensation, and ASC 505, Equity, which require all share-based payments to employees and members of the board of directors to be recognized as expense in the consolidated financial statements based on their grant date fair values. The Company has elected not to estimate forfeitures of its share-based compensation awards but recognizes the reversal in compensation expense in the period in which the forfeiture occurs.
During the first quarter of 2020, theThe Company has granted performance share units (“PSUs”)PSUs to certain employees and non-employees. The PSUs contain a performance condition, and vesting will beis determined based on achievement of an adjusted operating margin fora performance metric in the year ended December 31, 2021.subsequent to the grant. Compensation expense is recognized on a straight-line basis over the service period based on the expected attainment of a performance metric. At each reporting period, the Company reassesses the probability of the achievement of the performance metric, and any increase or decrease in share-based compensation expense resulting from an adjustment in the number of shares expected to vest is treated as a cumulative catch-up in the period of adjustment.
FederalVessel operating expenses are recognized when incurred. Vessel operating expenses include crewing, repairs and state income taxesmaintenance, insurance, stores, lube oils, communication expenses and third-party management fees. Initial direct costs include costs directly related to the negotiation and consummation of the lease and are deferred and recognized in Vessel operating expenses over the lease term.
Certain vessels included in the Energos Formation Transaction (Note 5) are chartered to third parties under operating leases. As the accounting owner of these vessels, the Company recognizes the cost of operating these vessels in Vessel operating expenses.(u)Transaction and integration costs
Transaction and integration costs is comprised of costs related to business combinations and dispositions and include advisory, legal, accounting, valuation and other professional or consulting fees. This caption also includes gains or losses recognized in connection with business combinations, including the settlement of preexisting relationships between the Company and an acquired entity. Financing costs which are not deferred as part of the cost of the financing on the balance sheet including fees associated with debt modifications are recognized within this caption. The Company records cloud computing costs incurred in the preliminary project stage and post-implementation stage within this caption.
(v)Taxation
The Company accounts for income taxes in accordance with ASC 740, “Accounting for Income Taxes”Taxes (“ASC 740”), under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of assets and liabilities by applying the enacted tax rates in effect for the year in which the differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s consolidated balance sheetsConsolidated Balance Sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.
The Company recognizes the effect of tax positions only if those positions are more likely than not of being sustained. Recognized tax positions are measured at the largest amount that is greater than 50 percent likely of being realized.realized upon ultimate settlement with the relevant tax authority. Conclusions reached regarding tax positions are continually reviewed based on ongoing analyses of tax laws, regulations and interpretations thereof. To the extent that the Company’s assessment of the conclusions reached regarding tax positions changes as a result of the evaluation of new information, such change in estimate will be recorded in the period in which such determination is made. The Company reports interest and penalties relating to an underpayment of income taxes, if applicable, as a component of income tax expense.
The Company has elected to treat amounts incurred under the global intangible low-taxed income (“GILTI”) rules as an expense in the period in which the tax is accrued. Accordingly, 0no deferred tax assets or liabilities are recorded related to GILTI.
Foreign taxes
Certain subsidiaries of the Company are subject to income tax in the local jurisdiction in which they operate; foreign taxes are computed based on the taxable income and the local jurisdictional tax rate.
Other taxes
Certain subsidiaries may be subject to payroll taxes, excise taxes, property taxes, sales and use taxes, in addition to income taxes in foreign countries in which they conduct business. In addition, certain subsidiaries are exposed to local state taxes, such as franchise taxes. Local state taxes that are not income taxes are recorded within Other expense (income), netSelling, general and administrative in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income.
Basic net lossincome per share (“EPS”) is computed by dividing net lossincome attributable to Class A common stock by the weighted average number of shares of Class A common stock outstanding during the period following the Reorganization. Class B shares represented non-economic interests in the Company, and as such, prior to the Exchange Transactions, earnings were not allocated to Class B shares.
outstanding. The dilutive effect of outstanding awards, if any, is reflected in diluted earnings per share by application of the treasury stock method or if-converted method, as applicable. For
(x)Acquisitions
Business combinations are accounted for under the years ended December 31, 2020acquisition method. On acquisition, the identifiable assets acquired and 2019, there were 0 potentially dilutive shares outstanding.
3. | Adoption of new and revised standards |
Followingliabilities assumed are measured at their fair values at the issuancedate of Senior Secured Notes (defined below) on September 2, 2020, the Company ceased to qualify as an “emerging growth company” or EGC and is required to accelerate the adoption of certain new or revised accounting pronouncements. The adoption dates below reflect the changes as a result of no longer qualifying as an EGC.
(a) | New standards, amendments and interpretations issued but not effective for the financial year beginning January 1, 2020: |
In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes, including removing certain exceptions related to the general principles in ASU 740, Income Taxes. ASU 2019-12 also clarifies and simplifies other aspectsacquisition. Any excess of the accounting for income taxes. The new standardpurchase price over the fair values of the identifiable net assets acquired is effective for interimrecognized as goodwill. Acquisition-related costs are expensed as incurred as Transaction and annual periods beginning after December 15, 2020, and early adoption is permitted. The Company will adopt ASC 2019-12integration costs in the first quarterConsolidated Statements of 2021Operations and does not expect the adoption of this new standard to materially impact the Company’s financial position,Comprehensive Income. The results of operations of acquired businesses are included in the Company’s Consolidated Statements of Operations and Comprehensive Income from the date of acquisition.
If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values.
(y)Equity method investments
The Company accounts for investments in entities over which the Company has significant influence, but do not meet the criteria for consolidation, under the equity method of accounting. Under the equity method of accounting, the Company’s investment is recorded at cost. In the case of equity method investments acquired as part of a business combination or cash flows.acquired in exchange for the contribution of assets or entities to the investee, the investment is initially recorded at the acquisition date fair value of the investment. The carrying amount is adjusted for the Company’s share of the earnings or losses, and dividends received from the investee reduce the carrying amount of the investment. The Company allocates the difference between the fair value of investments acquired in a business combination and the Company’s proportionate share of the carrying value of the underlying assets, or basis difference, across the assets and liabilities of the investee. The basis difference assigned to amortizable net assets is included in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income. When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee.
loss in value is deemed other-than-temporary and included in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income.
In August 2020,relation to the Company's 20% equity interest in Energos, the Company elected to recognize its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. The Company has not elected to recognize the results of other equity method investments on a financial reporting lag.
(z)Loss of control of subsidiary
When there is a loss of control over a subsidiary, the Company de-consolidates the entity as of the date the Company ceases to have a controlling financial interest. The Company accounts for the deconsolidation of a subsidiary by recognizing a gain or loss in the Consolidated Statements of Operations and Comprehensive Income, measured by the difference between the aggregate of the fair value of the consolidation received, fair value of any retained non-controlling interest in the former subsidiary and the carrying amount of any non-controlling interest in the former subsidiary with the carrying amount of the former subsidiary’s assets and liabilities. If a change of ownership interest causes a loss of control of a foreign entity, in addition to de-recognizing the assets and liabilities, the Company will also de-recognize any amounts previously recorded in other comprehensive income.
(aa)Guarantees
Guarantees issued by the Company, excluding those that are guaranteeing the Company’s own performance, are recognized at fair value at the time that the guarantees are issued and recognized in Other current liabilities and Other non-current liabilities on the Consolidated Balance Sheets. The guarantee liability is amortized each period as a reduction to Selling, general and administrative expenses. If it becomes probable that the Company will have to perform under a guarantee, the Company will recognize an additional liability if the amount of the loss can be reasonably estimated.
(ab)Derivatives
The Company has entered into derivative positions that were used to reduce market risks associated with interest rates, foreign exchange rates and commodity prices. The Company also accounts for arrangements that require the Company to pay sellers contingent payments in asset acquisitions as derivatives. All derivative instruments are initially recorded at fair value as either assets or liabilities on the Consolidated Balance Sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative, unless they qualify for a Normal Purchases and Normal Sales (“NPNS”) exception. The Company has not designated any derivatives as cash flow or fair value hedges; however, certain instruments may be considered economic hedges. Cash inflows and outflows related to commodity derivatives and interest rate swap are classified as cash flows from operating activities in the Consolidated Statements of Cash Flows.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered under other applicable GAAP (e.g., ASC 606 or ASC 705). While these contracts are considered derivative financial instruments under ASC 815, Derivatives and Hedging, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
3. Adoption of new and revised standards
New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2023:
In October 2023, the FASB issued ASU 2020-06, 2023-06, Accounting for Convertible InstrumentsDisclosure Improvements, to clarify or improve disclosure and Contractspresentation requirements of a variety of topics and align the requirements in an Entity’s Own Equity (ASU 2020-06)the FASB accounting standard codification (ASC) with the SEC's regulations. The amendments in ASU 2023-06 will be effective on the date the related disclosures are removed from Regulation S-X or Regulation S-K by the SEC, and will no longer be effective if the SEC has not removed the applicable disclosure requirement by June 30, 2027. Early adoption is prohibited. Although ASU 2023-06 incorporates certain existing or incremental requirements of Regulation S-X into the Codification, those amendments do not affect the information that is already included in the audited financial statements of entities subject to the SEC’s current disclosure or presentation requirements. The Company has determined there is no material impact which will result from adoption of the ASU.
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. ASU 2020-06 simplifies2023-07 requires disclosure of significant segment expenses and other segment items that are regularly provided to the accounting for certain financial instruments with characteristicsCODM and included within each reported measure of liabilitiessegment profit or loss, and equity, including convertible instrumentsthe title and contracts on anposition of the entity’s own equity. ASU 2020-06 requiresCODM. The amendments in this update also require entities to provide expandedin interim periods all disclosures about the termsa reportable segment’s profit or loss 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.assets that are currently required annually. ASU 2020-06 is2023-07 will be effective for public companies for fiscal years beginning after December 15, 2021,2023, and interim periods within those fiscal years withbeginning after December 15, 2024. Early adoption is permitted, and the amendments in this update are required to be applied retrospectively to all periods presented in the financial statements, unless it is impracticable. The Company is currently reviewing the impact that the adoption of ASU 2023-07 may have on the Company's consolidated financial statements and disclosures.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, requiring companies to annually disclose specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. Further, the ASU requires disclosure of income taxes paid (net of refunds received) disaggregated by federal (national), state and foreign taxes and to disaggregate the information by jurisdiction based on a quantitative threshold. The amendments in this ASU are effective for annual periods beginning after December 15, 2024, and early adoption of allis permitted. The amendments in the same periodshould be applied on a prospective basis, but retrospective application is permitted. The Company is currently assessingreviewing the impact ofthat the adoption of this guidance.ASU 2023-09 may have on the Company's consolidated financial statements and disclosures.
(b) | New and amended standards adopted by the Company: |
In June 2016,
4. Acquisitions
Hygo Merger
On April 15, 2021, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Disclosure Framework – MeasurementCompany completed the acquisition of Credit Losses on Financial Instruments (“ASU 2016-13”), which requires financial assets measured at amortized cost basis, including trade receivables, to be presented netall of the amountoutstanding 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 three gas-to-power projects in Brazil’s large and fast-growing market. The Company acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”); CELSEPAR owns 100% of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of a 1.5GW power plant in Sergipe, Brazil (the "Sergipe Power Plant"). Assets acquired also included an operating FSRU terminal in Sergipe, Brazil (the "Sergipe Facility"), as well as a terminal and power plant under development in 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 two 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 | |
| Assets under development | 128,625 | |
| Property, plant and equipment, net | 385,389 | |
| Equity method investments | 823,521 | |
| Finance leases, net | 601,000 | |
| Deferred tax assets, net | 1,065 | |
| Other non-current assets | 52,996 | |
| Total assets acquired: | $ | 2,081,663 | |
| Liabilities Assumed | |
| Current portion of long-term debt | $ | 38,712 | |
| Accounts payable | 3,059 | |
| Accrued liabilities | 39,149 | |
| Other current liabilities | 13,495 | |
| Long-term debt | 433,778 | |
| Deferred tax liabilities, net | 273,682 | |
| Other non-current liabilities | 21,520 | |
| Total liabilities assumed: | 823,395 | |
| Non-controlling interest | 38,306 | |
| Net assets acquired: | 1,219,962 | |
| Goodwill | $ | 760,822 | |
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 had consolidated. These VIEs were SPVs (defined below) for the sale and leaseback of certain vessels, and Hygo had 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 collected. The measurement of all expected credit losses will be based on relevant information aboutuncollectible.
Goodwill was calculated as the credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectabilityexcess of the reported amount. Uponpurchase price over the loss of EGC status, ASU 2016-13 was adopted in the third quarter of 2020 with an effective date of January 1, 2020. The Company electednet assets acquired. Goodwill represents access to apply the modified retrospective transition method, which allowedadditional LNG and natural gas distribution systems and power markets, including workforce that will allow the Company to begin recognizingrapidly develop and measuring current expected credit losses at January 1, 2020, without modifyingdeploy LNG to power solutions. While the comparative period financial statements. In connection with the adoption of ASC 2016-13, the Company recorded a transition adjustment of $228 which was recordedgoodwill is not deductible for local tax purposes, it is treated as an adjustment to retained earnings. amortizable expense for the U.S. GILTI computation.
The Company recorded credit loss expenseCompany’s results of $316operations for the year ended December 31, 2020.
2023 include Hygo’s result of operations for the entire period. Revenue and net loss attributable to Hygo during the period was $5,465 and $11,389, respectively, which excludes revenue generated from the acquired vessels after the Energos Formation Transaction on August 15, 2022.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 six FSRUs and four LNG carriers to support the Company's existing facilities and international business development pipeline. Assets acquired also included an interest in a floating natural gas liquefaction vessel (“FLNG”), the Hilli Episeyo (the "Hilli").
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 FASB issued ASU No. 2016-02, fair value of other investors’ interest in the Leases Mazo(“ASC 842”), GMLP’s preferred units which amendedwere not acquired by the existing accounting standardsCompany 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 accounting, including requiring most leasesreceivable 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 was approximately three years, and the unfavorable contract liability had 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 Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2021.
The Company’s results of operations for the year ended December 31, 2023 include GMLP’s result of operations from the entire period. Revenue and net loss attributable to GMLP during this period was $0 and $33,148, respectively, which excludes revenue generated from the acquired vessels after the Energos Formation Transaction on August 15, 2022.
Acquisition costs associated with the Mergers of $33,907 for the year ended December 31, 2021 were included in Transaction and integration costs in the Company’s Consolidated Statements of Operations and Comprehensive Income.
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.
| | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 |
| Revenue | | $ | 1,429,361 | | | $ | 813,079 | |
| Net income (loss) | | 75,415 | | | (339,909) | |
| Net income (loss) attributable to stockholders | | 62,059 | | | (264,075) | |
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 lessee’s balance sheetresult of incurring new debt and making targeted changesextinguishing historical debt, elimination of a pre-existing lease relationship between the Company and GMLP, and a step-up of the equity method investments.
Pro forma net income (loss) for the year ended December 31, 2020 includes non-recurring expenses associated with the Mergers of $37,885; such non-recurring expenses have been removed from the pro forma financial information for the year ended December 31, 2021. Transaction costs incurred and the elimination of a pre-existing lease relationship between the Company and GMLP are considered to lessor accounting.be non-recurring. The recognition, measurementunaudited pro forma financial information does not give effect to any synergies, operating efficiencies or cost savings that may result from the Mergers.
CH4 Energia Ltda.
On January 12, 2021, the Company acquired 100% of the outstanding shares of CH4 Energia Ltda. (“CH4”), an entity that owns key permits and presentationauthorizations to develop an LNG terminal. The purchase consideration consisted of expenses$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 met 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 Consolidated Balance Sheets.
The purchase of CH4 was 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.
Pecém Energia S.A. and Energetica Camacari Muricy II S.A.
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 purchase consideration consisted of $8,041 of cash flows arising frompaid at closing in addition to potential future payments contingent on achieving commercial operations of a leasegas-fired power plant of up to approximately $10.5 million. As the contingent payments met 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 Consolidated Balance Sheets. The selling shareholders may also receive future payments based on power generated by a lesseepower plant, 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 was recorded in Intangible assets, net, and the remaining purchase consideration was related to working capital acquired.
In the fourth quarter of 2023, a consolidated indirect subsidiary of NFE completed the sale of 100% of the shares of Pecém and Muricy. The sale price included cash consideration of BRL109,547 ($22,434 using exchange rates as of December 31, 2023), of which BRL 35,019 ($7,234 using exchange rates as of December 31, 2023) will depend primarilybe settled in the second quarter of 2024. Consideration under this agreement also included potential future earnout payments based on the lease’s classificationrevenue generated from power purchase agreements held by Pecém and Muricy. The estimated value of the contingent payments as of the disposition date of BRL101,836 ($21,036 using exchange rates as of December 31, 2023) was included as part of the sale consideration and was recognized in Other non-current assets on the Consolidated Balance Sheets. Total consideration, including the value of contingent payments, totaled $43,470, and the Company recognized a pre-tax gain of $21,534 in Gain on sale of assets, net in the Consolidated Statements of Operations and Comprehensive Income.
5. Energos Formation Transaction
On August 15, 2022, the Company completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which the Company transferred ownership of 11 vessels to Energos Infrastructure ("Energos") in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with the Company and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to the Company of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a finance or operating lease. However, unlike ASC 840, which required only capital leasesfailed sale leaseback. As a result, these ten vessels continue to be recognized on the balance sheet, ASC 842 requires most leases to be recognized on the balance sheet as a ROU asset and a lease liability.
The Company adopted ASC 842 effective January 1, 2020 and elected to apply the modified retrospective transition method at the beginning of the period of adoption, which allowed the Company to begin recognizing and measuring leases under ASC 842 at January 1, 2020, without modifying the comparative period financial statements. Upon adoption of ASC 842, the Company recorded ROU assets and corresponding lease liabilities of $124,774 and $103,874, respectively.
The Company did not elect the package of practical expedients and therefore, as part of transition, the Company reassessed the previous conclusions made under ASC 840 related to the identification of leases, classification of leases and initial direct costs based on the standards of ASC 842. In connection with the reassessment of previous conclusions, the Company determined that the direct financing lease recognized related to the Montego Bay Facility is no longer a lease under ASC 842. The Company recognized a transition adjustment that removed the unamortized net investment in the direct financing lease and recognized the underlying assetsConsolidated Balance Sheets as Property, plant and equipment, netand the proceeds are recognized as debt ("Vessel Financing Obligation"). Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by the Company as Vessel charter revenue; (ii) the costs of depreciation, that would have been recognized sinceoperating the commissioningvessels is included in Vessel operating expenses for the remaining terms of the Montego Bay Facility, withthird-party charters and (iii) such revenues are included as part of debt service for the differencesale leaseback financing debt and are included in additional financing costs within Interest expense, net. The Company has accounted for the investment in Energos as an equity method investment; see Note 13 for further discussion of approximately $9,085, netthis investment.
6. VIEs
The Company assumed sale leaseback arrangements for four vessels as part of taxesthe Mergers. To effectuate a financing, 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 did not hold an equity investment in these lending entities, these entities are VIEs, and the Company had a variable interest in these lending entities due to the guarantees and fixed price repurchase options that absorb the losses of $2,945, recordedthe VIE that could potentially be significant to the entity. The Company had concluded that it had the power to direct the economic activities that most impact the economic performance as a reductionit controlled the significant decisions relating to retained earnings. Beginningthe assets and it had the obligation to absorb losses or the right to receive the residual returns from the leased asset. Therefore, the Company consolidated these lending entities. As NFE had no equity interest in 2020,these VIEs, all equity attributable to the VIEs was included in non-controlling interest in the consolidated financial statements. Transactions between NFE's wholly-owned subsidiaries and the VIEs were eliminated in consolidation, including sale leaseback transactions.
One of these sale leaseback arrangements was terminated in 2021; the remaining three sale leaseback arrangements were terminated as part of the Energos Formation Transaction in the third quarter of 2022. The Company is no longer party to any lessor VIE arrangements.
Prior to the Energos Formation Transaction, the most significant impact of the lessor VIEs operations on the Company’s Consolidated Statements of Operations and Comprehensive Income was an addition to interest expense of $6,348 for the year ended December 31, 2022. Upon termination of the sale leaseback financing arrangements in the third quarter of 2022, the Company recognized payments previously allocateda loss on extinguishment of debt of $9,082 in the Consolidated Statements of Operations and Comprehensive Income.
For the period subsequent to the leasing componentcompletion of the gas sales agreement with this customer within Mergers in 2021, the most significant impact of the lessor VIEs operations on the Company’s Consolidated Statements of Operations and Comprehensive Income was an addition to interest expense of $11,766 for the year ended December 31, 2021.
The most significant impact of the lessor VIEs cash flows on the Consolidated Statements of Cash Flows is net cash used in financing activities of $400,622 and $236,916 for the years ended December 31, 2022 and 2021, respectively. In the second quarter of 2022, one of the lessor VIEs declared a dividend of $4,000, which was paid in the third quarter of 2022. The declared dividend was recognized as a change to non-controlling interest in the consolidated financial statements.
7. Revenue recognition
Operating revenue in the consolidated statements Consolidated Statements of operationsOperations and comprehensive loss. Under ASC 840, amounts allocatedComprehensive Income 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 are LNG cargo sales to customers of $618,521, $1,175,866, and $462,695 for the leasing component had been recognized on an effective interest method over the lease term with only the portion representing interest income recognized as Other revenue.
In August 2018, the FASB issued ASU 2018-13, years ended December 31, 2023, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement 2022 and 2021, respectively.(“ASU 2018-13”), which provides additional guidance to improve the effectiveness of disclosure requirements on fair value measurement. The Company has adopted ASU 2018-13 LNG cargo sales for the year beginning January 1, 2020. As this guidance is only relatedended December 31, 2023 included $332,000 of contract settlements. The table below summarizes the balances in Other revenue:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Development services revenue | $ | — | | | $ | — | | | $ | 125,924 | |
| Interest income and other revenue | 26,341 | | | 32,469 | | | 35,261 | |
| Operation and maintenance revenue | 49,900 | | | — | | | — | |
| Total other revenue | $ | 76,241 | | | $ | 32,469 | | | $ | 161,185 | |
Operation and maintenance revenue began to qualitative financial disclosures, it did not have a material impact on the Company’s consolidated financial statements.
In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets. A customer’s accounting for the costs of the hosting component of the arrangement is not affected by the new guidance. The Company has early adopted ASU 2018-15 for the year beginning January 1, 2020, using the prospective transition approach. This approach did not require any adjustment to comparative financial statements. The Company has not capitalized a significant amount of implementation costs as a result of adopting this guidancebe recognized in the year ended December 31, 2020,2023 once Genera's contract with PREPA commenced on July 1, 2023. Amounts recognized include fixed fees and the adoption did not result in material impact on the Company’s consolidated financial statements.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitationreimbursement of the Effectspass-through expenditures, and all variable consideration was fully constrained as of Reference Rate Reform on Financial Reporting. The guidance provides temporary optional expedients and exceptions to the current guidance on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and generally can be applied to applicable contract modifications and hedge relationships prospectively through December 31, 2022. The adoption of this guidance did not have a significant impact on the Company’s financial statements.
2023.
4. | Revenue from contracts with customers |
Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of December 31, 20202023 and 2019,2022, receivables related to revenue from contracts with customers totaled $76,431$331,108 and $40,731,$280,382, respectively, and were included in Receivables, net on the consolidated balance sheets,Consolidated Balance Sheets, net of current expected credit losses of $98$1,158 and $0,$884, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent receivables associated with reimbursable costs and leases, which are accounted for outside the scope of ASC 606.
and receivables associated with reimbursable costs.Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are expected to be satisfied during the next 12 months, and the contract liabilities are classified within Other current liabilities on the 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 assetsliabilities balances as of December 31, 20202023 and 20192022 are detailed below:
| | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Contract assets, net - current | $ | 8,714 | | | $ | 8,083 | |
| Contract assets, net - non-current | 19,901 | | | 28,651 | |
| Total contract assets, net | $ | 28,615 | | | $ | 36,734 | |
| | | |
| Contract liabilities, net - current | $ | 65,287 | | | $ | 12,748 | |
| Contract liabilities, net - non-current | 31,698 | | | — | |
| Total contract liabilities, net | $ | 96,985 | | | $ | 12,748 | |
| | | |
| Revenue recognized in the year from: | | | |
| Amounts included in contract liabilities at the beginning of the year | $ | 12,748 | | | $ | 2,951 | |
| | December 31, 2020 | | | December 31, 2019 | |
| Contract assets, net - current | | $ | 3,673 | | | $ | 3,787 | |
| Contract assets, net - non-current | | | 23,972 | | | | 19,474 | |
| Total contract assets, net | | $ | 27,645 | | | $ | 23,261 | |
| | | | | | | | | |
| Contract liabilities | | $ | 8,399 | | | $ | 6,542 | |
| | | | | | | | | |
| Revenue recognized in the year from: | | | | | | | | |
| Amounts included in contract liabilities at the beginning of the year | | $ | 6,542 | | | $ | 0 | |
Contract assets are presented net of expected credit losses of $372$326 and $0$401 as of December 31, 20202023 and 2019,2022, respectively. As of December 31, 20202023 and 2022, contract assets were comprised of $28,536 and $36,483 of unbilled receivables, respectively, which represent unconditional rights to payment only subject to the passage of time.
Contract liabilities increased during the year ended December 31, 2023 primarily due to advance 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 contract with customers, which primarily consist of expenses required to enhance resources to deliver under agreements with these customers. These costs can include set-up and mobilization costs incurred ahead of the service period, and such costs will be recognized on a straight-line basis over the expected term of the agreement. As of December 31, 2023, the Company has unbilled receivables, net of current expected credit losses, of $6,818,capitalized $25,282, of which $356$2,864 of these costs is presented within OtherPrepaid and other current assets and $6,462$22,418 is presented within Other non-current assets on the consolidated balance sheets. These unbilled receivables represent unconditional right to payment subject only to the passageConsolidated Balance Sheets. As of time.
Operating revenue which includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, was $318,311, $145,500 and $96,906 for the years ended December 31, 2020, 2019 and 2018 respectively. During March 2020,2022, the Company began to deliver power and steam recognizing $23,062 in operating revenue for the year ended December 31, 2020.
Other revenue includes revenue for development services as well as leasehad capitalized $10,377, of which $604 of these costs was presented within Prepaid and other revenue. The table below summarizescurrent assets and $9,773 was presented within Other non-current assets on the balances in Other revenue:
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| Development services revenue | | $ | 129,753 | | | $ | 27,308 | | | $ | 0 | |
| Lease and other revenue | | | 3,586 | | | | 16,317 | | | | 15,395 | |
| Total other revenue | | $ | 133,339 | | | $ | 43,625 | | | $ | 15,395 | |
Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of natural gas as part of commissioning their assets.
Transaction price allocated to remaining performance obligations
Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.
The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements is $4,357,054 as of December 31, 2020, representing 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 | |
| 2021 | | $ | 258,738 | |
| 2022 | | | 250,226 | |
| 2023 | | | 250,317 | |
| 2024 | | | 249,804 | |
| 2025 | | | 246,709 | |
| Thereafter | | | 3,101,260 | |
| Total | | $ | 4,357,054 | |
| | | | | |
| Period | Revenue |
| 2024 | $ | 2,073,254 | |
| 2025 | 1,606,743 | |
| 2026 | 685,108 | |
| 2027 | 681,418 | |
| 2028 | 667,251 | |
| Thereafter | 9,188,750 | |
| Total | $ | 14,902,524 | |
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
Property, plant and equipment subject to vessel charters accounted for as operating leases is included within Vessels within "Note 15. Property, plant and equipment, net." Vessels included in the Energos Formation Transaction, including those vessels chartered to third parties, continue to be recognized on the Consolidated Balance Sheets, and as such, the carrying amount of these vessels that are leased to third parties under operating leases is as follows:
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Property, plant and equipment | $ | 686,683 | | | $ | 1,292,957 | |
| Accumulated depreciation | (69,977) | | | (80,233) | |
| Property, plant and equipment, net | $ | 616,706 | | | $ | 1,212,724 | |
The Company has recognized costs to fulfill a contract with a significant customer, which primarily consistcomponents of expenses required to enhance resources to deliver underlease income from vessel operating leases for the agreement with the customer. As of years ended December 31,
2020,2023, 2022 and 2021 are shown below. As the Company has capitalized $11,276,not recognized the sale of which $588all of these costs is presented within Other current assets and $10,688 is presented within Other non-current assets on the consolidated balance sheets. As of vessels included in the Energos Formation Transaction, the operating lease income shown below for the years ended December 31,
20192023 and 2022, respectively, is comprised of revenue from third-party charters of vessels included in the Energos Formation Transaction. | | | | | | | | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 | | December 31,
2021 |
| Operating lease income | $ | 276,113 | | | $ | 328,366 | | | $ | 214,193 | |
| Variable lease income | 730 | | | 22,940 | | | 11,067 | |
| Total operating lease income | $ | 276,843 | | | $ | 351,306 | | | $ | 225,260 | |
The Company’s charter of the Nanook and certain equipment leases provided in connection with the supply of natural gas or LNG are accounted for as finance leases. The Company recognized the sale of the net investment in the finance lease of the Nanook as part of the Energos Formation Transaction. Proceeds of $593,000 were allocated to the sale of this financial asset, and upon derecognition of the finance lease, a loss of $14,598 was recognized as Other expense (income), net, in the Consolidated Statements of Operations and Comprehensive Income.
Prior to the completion of the Energos Formation Transaction, the Company's charter of the Nanook was accounted for as a finance lease, and the Company had capitalized $recognized interest income of $28,643 and $32,880 for the years ended December 31, 2022 and 2021, respectively, related to the finance lease8,839, of which $331 of these costs was presented within Other current assetsrevenue in the Consolidated Statements of Operations and $8,508 was presented within Other non-current assets onComprehensive Income. The Company also recognized revenue of $5,852 and $5,549 for the consolidated balance sheets. Inyears ended December 31, 2022 and 2021, respectively, related to the first quarter of 2020, the Company began delivery under theoperation and services agreement and started recognizing these costs on a straight-line basis overvariable charter revenue within Vessel charter revenue in the expected termConsolidated Statements of Operations and Comprehensive Income. The Company recognized the sale of the agreementnet investment in the finance lease of the .
Nanook as part of the Energos Formation Transaction.
The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.
The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.
As of December 31, 2023 and 2022, ROU assets, current lease liabilities and non-current lease liabilities consisted of the following:
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Operating right-of-use assets | $ | 538,055 | | | $ | 355,883 | |
Finance right-of-use assets (1) | 50,330 | | | 21,994 | |
| Total right-of-use assets | $ | 588,385 | | | $ | 377,877 | |
| | | |
| Current lease liabilities: | | | |
| Operating lease liabilities | $ | 135,867 | | | $ | 44,371 | |
| Finance lease liabilities | 28,681 | | | 4,370 | |
| Total current lease liabilities | $ | 164,548 | | | $ | 48,741 | |
| Non-current lease liabilities: | | | |
| Operating lease liabilities | $ | 390,519 | | | $ | 290,899 | |
| Finance lease liabilities | 15,975 | | | 11,222 | |
| Total non-current lease liabilities | $ | 406,494 | | | $ | 302,121 | |
(1)Finance lease ROU assets are recorded net of accumulated amortization of $21,470 and $2,134 as of December 31, 2023 and 2022, respectively.
For the yearyears ended December 31, 2020,2023, 2022, and 2021, the Company’s operating lease cost recorded within the consolidated statementsConsolidated Statements of operationsOperations and comprehensive lossComprehensive Income were as follows:
| | December 31, 2020 | |
| Fixed lease cost | | $ | 39,841 | |
| Variable lease cost | | | 2,013 | |
| Short-term lease cost | | | 1,454 | |
| | | | | |
| Lease cost - Cost of sales | | $ | 36,283 | |
| Lease cost - Operations and maintenance | | | 2,501 | |
| Lease cost - Selling, general and administrative | | | 4,524 | |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Fixed lease cost | $ | 109,873 | | | $ | 75,771 | | | $ | 41,054 | |
| Variable lease cost | 4,601 | | | 2,203 | | | 1,711 | |
| Short-term lease cost | 23,903 | | | 20,129 | | | 6,974 | |
| | | | | |
| Lease cost - Cost of sales | $ | 88,608 | | | $ | 87,610 | | | $ | 41,147 | |
| Lease cost - Operations and maintenance | 42,520 | | | 3,681 | | | 2,343 | |
| Lease cost - Selling, general and administrative | 7,249 | | | 6,812 | | | 6,249 | |
For the yearyears ended December 31, 2020,2023, 2022 and 2021, the Company has capitalized $10,457$61,320, $20,403 and $15,568 of lease costs, forrespectively. Capitalized costs include 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 bringtransport inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Interest expense related to finance leases | $ | 3,706 | | | $ | 852 | | | $ | 409 | |
| Amortization of right-of-use asset related to finance leases | 19,337 | | | 1,512 | | | 622 | |
Cash paid for operating leases is reported in operating activities in the consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the yearyears ended December 31, 2020:2023, 2022 and 2021:
| | December 31, 2020 | |
| Operating cash outflows for operating lease liabilities | | $ | 45,934 | |
| Right-of-use assets obtained in exchange for new operating lease liabilities | | | 182,799 | |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Operating cash outflows for operating lease liabilities | $ | 133,132 | | | $ | 96,698 | | | $ | 46,066 | |
| Financing cash outflows for finance lease liabilities | 21,187 | | | 3,697 | | | 2,156 | |
| Right-of-use assets obtained in exchange for new operating lease liabilities | 265,537 | | | 135,075 | | | 172,996 | |
| Right-of-use assets obtained in exchange for new finance lease liabilities | 47,672 | | | — | | | 24,533 | |
The future payments due under operating and finance leases as of December 31, 20202023 are as follows:
| | Operating Leases | |
| 2021 | | $ | 43,467 | |
| 2022 | | | 29,949 | |
| 2023 | | | 18,738 | |
| 2024 | | | 17,884 | |
| 2025 | | | 10,698 | |
| Thereafter | | | 50,387 | |
| Total lease payments | | $ | 171,123 | |
| Less: effects of discounting | | | 51,319 | |
| Present value of lease liabilities | | $ | 119,804 | |
| | | | | |
| Current lease liability | | $ | 35,481 | |
| Non-current lease liability | | | 84,323 | |
| | | | | | | | | | | |
| Operating Leases | | Financing Leases |
| 2024 | $ | 179,273 | | | $ | 30,939 | |
| 2025 | 125,262 | | | 12,427 | |
| 2026 | 78,023 | | | 3,041 | |
| 2027 | 77,557 | | | 436 | |
| 2028 | 76,966 | | | 89 | |
| Thereafter | 174,365 | | | 853 | |
| Total Lease Payments | $ | 711,446 | | | $ | 47,785 | |
| Less: effects of discounting | 185,060 | | | 3,129 | |
| Present value of lease liabilities | $ | 526,386 | | | $ | 44,656 | |
| | | |
| Current lease liability | $ | 135,867 | | | $ | 28,681 | |
| Non-current lease liability | 390,519 | | | 15,975 | |
As of December 31, 2020,2023, the weighted-average remaining lease term for all operating leases was 7.25.9 years and finance leases was 2.0 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 December 31, 20202023 and 2022 was 8.3%.
Future annual minimum lease payments for operating10.1% and 8.5%, respectively. The weighted average discount rate associated with finance leases as of December 31, 2019, prepared2023 and 2022 was 8.2% and 5.1%, respectively.
In January 2024, the Company has commenced a 10-year lease of a vessel with expected future payments of approximately $376 million.
9. Financial instruments
Commodity risk management
The Company has utilized commodity swap transactions to manage exposure to changes in accordance with accounting standardsmarket pricing of natural gas or LNG. Realized and unrealized gains and losses on these transactions have been recognized in Cost of sales in the 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 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 series of commodity swap transactions. Realized loss of $8,495 for the year ended December 31, 2023 on this instrument have been recognized in Cost of sales in the Consolidated Statements of Operations and Comprehensive Income. All swaps have been settled prior to December 31, 2023.
Interest rate and currency risk management
In connection with the adoptionMergers during 2022, the Company acquired an interest rate swap to reduce the risk associated with fluctuations in interest rates by converting floating rate interest obligations to fixed rates, which from an economic perspective hedges the interest rate exposure. The interest rate swap was terminated in the first quarter of ASC 842, were as follows:2023.
Year ending December 31: | | | |
| 2020 | | $ | 37,776 | |
| 2021 | | | 35,478 | |
| 2022 | | | 18,387 | |
| 2023 | | | 7,083 | |
| 2024 | | | 7,151 | |
| Thereafter | | | 26,458 | |
| Total | | $ | 132,333 | |
During the years ended December 31, 2019 and 2018,fourth quarter of 2023, the Company recognized rental expense for all operating leasesentered into a non-deliverable forward to secure the currency position of $37,069the Barcarena Debentures (defined below) to be issued nominated in USD. The forward was settled in November 2023, and $23,687, respectively, related primarily to LNG vessel time charters, office space,the Company recorded a land site lease and marine port berth leases.
The Company has entered into several leasesdoes not hold or issue instruments for ISO tanksspeculative purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that have not commenced as of December 31, 2020 with noncancelable terms of 5 years and including fixed payments of approximately $19 million.
Lessor
In the Company’s agreementscounterparties are unable to sell LNG or natural gas to customers,perform under the contracts; however, the Company may also lease certain equipment to customers which are accounted for either as a financedoes not anticipate non-performance by any counterparties.
The mark-to-market gain or an operating lease. Property, plant and equipment subject to operating leases is included within ISO containersloss on the interest rate swap, non-deliverable forward and other equipment within Note 11. Property, plantderivative instruments that are not intended to mitigate commodity risk are reported in Other expense (income), net in the Consolidated Statements of Operations and equipment, net. The following is the amount of property, plant and equipment that is leased to customers:Comprehensive Income.
| | December 31, 2020 | |
| Property, plant and equipment | | $ | 18,394 | |
| Accumulated depreciation | | | (932 | ) |
| Property, plant and equipment, net | | $ | 17,462 | |
The following table shows the expected future lease payments as of December 31, 2020, for 2021 through 2025 and thereafter:
| | Future cash receipts | |
| | | Financing leases | | | Operating leases | |
| 2021 | | $ | 1,965 | | | $ | 256 | |
| 2022 | | | 2,065 | | | | 247 | |
| 2023 | | | 2,066 | | | | 249 | |
| 2024 | | | 2,068 | | | | 234 | |
| 2025 | | | 1,933 | | | | 194 | |
| Thereafter | | | 5,438 | | | | 539 | |
| Total | | $ | 15,535 | | | $ | 1,719 | |
| Less: Imputed interest | | | 7,119 | | | | | |
| Present value of total lease receipts | | $ | 8,416 | | | | | |
| | | | | | | | | |
| Current finance leases, net | | $ | 1,372 | | | | | |
| Non-current finance leases, net | | | 7,044 | | | | | |
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 following table presentsCompany uses the Company’s financialmarket approach when valuing investment in equity securities which is recorded in Other non-current assets and financial liabilities that are measured at fair valueon the Consolidated Balance Sheets as of December 31, 20202023 and 2019:2022.
| | | December 31, 2020 | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Valuation technique | |
| Assets | | | | | | | | | | | | | | | 0 | |
| Cash and cash equivalents | | $ | 601,522 | | | $ | 0 | | | $ | 0 | | | $ | 601,522 | | | Market approach | |
| Restricted cash | | | 27,814 | | | | 0 | | | | 0 | | | | 27,814 | | | Market approach | |
| Investment in equity securities | | | 1,095 | | | | 0 | | | | 0 | | | | 1,095 | | | Market approach | |
| Total | | $ | 630,431 | | | $ | 0 | | | $ | 0 | | | $ | 630,431 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
| Derivative liability¹ | | $ | 0 | | | $ | 0 | | | $ | 10,716 | | | $ | 10,716 | | | Income approach | |
| Equity agreement² | | | 0 | | | | 0 | | | | 22,768 | | | | 22,768 | | | Income approach | |
| Total | | $ | 0 | | | $ | 0 | | | $ | 33,484 | | | $ | 33,484 | | | | | |
•Interest rate swap and commodity swaps - The Company did not have any interest rate swaps or commodity swaps outstanding as of December 31, 2023. As of December 31, 2022, the interest rate swap and commodity swaps were recorded within Other non-current assets and Prepaid expenses and other current assets on the Consolidated Balance Sheets, respectively.
| | | December 31, 2019 | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Valuation technique | |
| Assets | | | | | | | | | | | | | | | 0 | |
| Cash and cash equivalents | | $ | 27,098 | | | $ | 0 | | | $ | 0 | | | $ | 27,098 | | | Market approach | |
| Restricted cash | | | 65,937 | | | | 0 | | | | 0 | | | | 65,937 | | | Market approach | |
| Investment in equity securities | | | 2,540 | | | | 0 | | | | 0 | | | | 2,540 | | | Market approach | |
| Total | | $ | 95,575 | | | $ | 0 | | | $ | 0 | | | $ | 95,575 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
| Derivative liability¹ | | $ | 0 | | | $ | 0 | | | $ | 9,800 | | | $ | 9,800 | | | Income approach | |
| Equity agreement² | | | 0 | | | | 0 | | | | 16,800 | | | | 16,800 | | | Income approach | |
| Total | | $ | 0 | | | $ | 0 | | | $ | 26,600 | | | $ | 26,600 | | | | | |
(1) | Consideration due to the sellers of Shannon LNG once first gas is supplied from the terminal to be built. |
(2) | To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received as specified in the amended Shannon LNG Agreement. |
The fair value of certain derivative instruments, including commodity swaps, is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties. The Company estimates fair value of the contingent consideration derivative liability and equity agreementliabilities 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 eventevents occurring.
The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| December 31, 2023 | | | | | | | | |
| Assets | | | | | | | | |
| Investment in equity securities | | $ | — | | | $ | — | | | $ | 7,678 | | | $ | 7,678 | |
| | | | | | | | |
| Liabilities | | | | | | | | |
| Contingent consideration derivative liabilities | | — | | | — | | | 37,832 | | | 37,832 | |
| | | | | | | | |
| December 31, 2022 | | | | | | | | |
| Assets | | | | | | | | |
| Investment in equity securities | | $ | 10,128 | | | $ | — | | | $ | 7,678 | | | $ | 17,806 | |
| Interest rate swap | | — | | | 11,650 | | | — | | | 11,650 | |
| Commodity swap | | — | | | 104,797 | | | — | | | 104,797 | |
| | | | | | | | |
| Liabilities | | | | | | | | |
| Contingent consideration derivative liabilities | | $ | — | | | $ | — | | | $ | 46,619 | | | $ | 46,619 | |
The Company believes the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value as of December 31, 2023 and 2022 and are classified as Level 1 within the fair value hierarchy.
The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, including the contingent consideration derivative liabilities. These adjustments have been recorded within Other expense (income), net in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss,Comprehensive Income for the year ended December 31, 2020 and 2019:
| | December 31, 2020 | | | December 31, 2019 | |
| Fair value adjustment - Loss | | $ | 4,408 | | | $ | 121 | |
| Currency translation adjustment - Loss/(gain) | | | 2,476 | | | | (280 | ) |
During the years ended December 31, 20202023, 2022 and 2019,2021:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Contingent consideration derivative liabilities - Fair value adjustment - loss (gain) | $ | (4,801) | | | $ | 703 | | | $ | (341) | |
| | | | | |
| | | | | |
During the years ended December 31, 2023 and 2022, the Company had no settlements of the equity agreement or derivative liability or any transfers in or out of Level 3 in the fair value hierarchy.
F-32
The liability associated with the equity agreement of $22,768 and $16,800 as of December 31, 2020 and 2019, respectively, is recorded within Other current liabilities on the consolidated balance sheets. The liability associated with the derivative liability of $10,716 and $9,800 as of December 31, 2020 and 2019, respectively, is recorded within Other long-term liabilities on the consolidated balance sheets.
The Company estimates fair value of outstanding debt using quoted market prices. The fair value of the Senior Secured Notes (defined below in “Note 15. Debt”) was approximately $1,327,488 as of December 31, 2020. The fair value estimate is classified as Level 2 in the fair value hierarchy.
As of December 31, 20202023 and 2019,2022, restricted cash consisted of the following:
| | | December 31,
2020 | | | December 31,
2019 | |
| Collateral for performance under customer agreements | | $ | 15,000 | | | $ | 15,000 | |
| Collateral for LNG purchases | | | 11,664 | | | | 35,000 | |
| December 31,
2023 | | | December 31,
2023 | | December 31,
2022 |
| Cash restricted under the terms of loan agreements | |
| Collateral for letters of credit and performance bonds | | | 900 | | | | 7,388 | |
| Debt service reserve account | | | 0 | | | | 8,299 | |
| Other restricted cash | | | 250 | | | | 250 | |
| Collateral for interest rate swaps | |
| Total restricted cash | | $ | 27,814 | | | $ | 65,937 | |
| | | | | | | | | |
| Current restricted cash | | $ | 12,814 | | | $ | 30,966 | |
| Current restricted cash | |
| Current restricted cash | |
| Non-current restricted cash | | | 15,000 | | | | 34,971 | |
As of December 31, 20202023 and 2019,2022, inventory consisted of the following:
| | | December 31,
2020 | | | December 31,
2019 | |
| LNG and natural gas inventory | | $ | 13,986 | | | $ | 57,436 | |
| Automotive diesel oil inventory | | | 3,986 | | | | 4,746 | |
| Bunker fuel, materials, supplies and other | | | 4,888 | | | | 1,250 | |
| Total inventory | | $ | 22,860 | | | $ | 63,432 | |
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| LNG and natural gas inventory | $ | 75,417 | | | $ | 15,398 | |
| Automotive diesel oil inventory | 10,121 | | | 8,164 | |
| Bunker fuel, materials, supplies and other | 28,146 | | | 15,508 | |
| Total inventory | $ | 113,684 | | | $ | 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 consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss. Comprehensive Income. In the second quarter of 2023, the Company acquired a spot cargo at a higher cost to obtain a new customer contract. The Company recordednet realizable value of this cargo was below the cost as of June 30, 2023, and as such, we recognized an adjustment to the value of inventory of $0, $251 and $0$6,232. No other adjustments were recorded during the years ended December 31, 2020, 20192023, 2022 and 2018, respectively.
2021.
9. | 12. Prepaid expenses and other current assets |
As of December 31, 20202023 and 2019,2022, prepaid expenses and other current assets consisted of the following:
| | | December 31,
2020 | | | December 31,
2019 | |
| Prepaid LNG | | $ | 11,987 | | | $ | 7,097 | |
| Prepaid expenses | | | 4,941 | | | | 7,458 | |
| Due from affiliates (Note 21) | | | 1,881 | | | | 1,577 | |
| Other current assets | | | 29,461 | | | | 23,602 | |
| Total prepaid expenses and other current assets, net | | $ | 48,270 | | | $ | 39,734 | |
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Prepaid expenses | $ | 31,490 | | | $ | 56,380 | |
| Recoverable taxes | 80,630 | | | 37,504 | |
| Commodity swap | — | | | 104,797 | |
| Due from affiliates | 1,566 | | | 698 | |
| Assets held for sale | 21,265 | | | — | |
| Other current assets | 78,153 | | | 27,504 | |
| Total prepaid expenses and other current assets, net | $ | 213,104 | | | $ | 226,883 | |
OtherDuring the fourth quarter of 2023, the Company began to sub-charter the Winter, a vessel included in the Energos Formation Transaction, and an asset was recorded representing the existing charterer's remaining payments to Energos,
which was $59,074 as of December 31, 2023. The Company also recognized a liability of $49,400 (see Note 19) representing the Company's obligation to pay sub-charter payments until the vessel is chartered directly from Energos.
The remaining balance of other current assets as of December 31, 20202023 and 20192022 primarily consists of receivablesdeposits, as well as the current portion of contract assets (Note 7).
Assets held for recoverable taxes.sale
In December 2023, the Company entered into an agreement to sell the vessel, Mazo, for $22,400; the sale closed in the first quarter of 2024, and as such, the vessel has been classified as held for sale as of December 31, 2023. In conjunction with the classification to held for sale, the Company recognized an impairment of $10,958 within Asset impairment expense in the Consolidated Statements of Operations and Comprehensive Income. Nonrecurring, Level 2 inputs were used to
estimate the fair value of the investment for the purpose of recognizing the OTTI.
13. Equity method investments
As a result of the Mergers, the Company acquired a 50% ownership interest in both CELSEPAR and Hilli LLC, and both investments have been recognized as equity method investments. As part of the Energos Formation Transaction, the Company contributed certain vessels to Energos in exchange for an equity interest, and this equity interest has been accounted for under the equity method. The Company has a 20% ownership interest in Energos.
The investment in CELSEPAR was reflected in the Terminals and Infrastructure segment; the investments in Hilli LLC and Energos were reflected in the Ships segment.
Changes in the balance of the Company’s equity method investments is as follows:
| | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Equity method investments as of beginning of period | $ | 392,306 | | | $ | 1,182,013 | |
| Capital contributions | 1,501 | | | 133,314 | |
| Dividends | (5,830) | | | (29,372) | |
| Equity in earnings of investees | 15,249 | | | 15,546 | |
| Other-than-temporary impairment | (5,277) | | | (487,765) | |
| Sale of equity method investments | (260,156) | | | (500,076) | |
| Foreign currency translation adjustment | — | | | 78,646 | |
| Equity method investments as of end of period | $ | 137,793 | | | $ | 392,306 | |
The carrying amounts of the Company's equity method investments as of December 31, 2023 and 2022 are as follows:
| | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Hilli LLC | $ | — | | | $ | 260,000 | |
| Energos | 137,793 | | | 132,306 | |
| Total | $ | 137,793 | | | $ | 392,306 | |
As of December 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 investee by $5,277. At December 31, 2022, the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $16,976, and the basis difference attributable to amortizable net assets was amortized to Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Incomeover the remaining estimated useful lives of the underlying assets.
10. | The Company acquired a 20% equity interest in Energos as part of the Energos Formation Transaction in the third quarter of 2022. The Company's equity investment provided certain rights, including representation on the Energos board of directors, that gave the Company significant influence over the operations of Energos, and as such, the investment was accounted for under the equity method. Energos was also an affiliate, and all transactions with Energos were transactions with an affiliate. Subsequent to December 31, 2023, the Company entered into a Unit Purchase Agreement to sell substantially all of its stake in Energos. As a result of the transaction, the Company has recognized an other than temporary impairment ("OTTI") of the investment in Energos totaling $5,277 for the year ended December 31, 2023, and this loss was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income. Nonrecurring, Level 2 inputs were used to estimate the fair value of the investment for the purpose of recognizing the OTTI. The sale was completed on February 14, 2023. Following the disposition of substantially all of the stake in Energos, the Company no longer has significant influence over Energos, and the value of any remaining investment will not be accounted for under the equity method. Due to the timing and availability of financial information of Energos, the Company recognized its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. For the years ended December 31, 2023 and 2022, the Company has recognized earnings from Energos of $9,263 and $2,788, respectively. Hilli LLC On March 15, 2023, the Company completed a transaction with Golar LNG Limited ("GLNG") for the sale of the Company's investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100,000 in cash (the "Hilli Exchange"). In the fourth quarter of 2022, the Company recognized an OTTI on the investment in Hilli LLC of $118,558; this impairment was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income. Upon completion of the Hilli Exchange, a loss on disposal of $37,401 was recognized in Other expense (income), net in the 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. CELSEPAR CELSEPAR was jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounted for this 50% investment using the equity method. On May 31, 2022, an indirect subsidiary of NFE and certain Ebrasil sellers as owners of CELSEPAR (the “Sergipe Sellers”), Eneva S.A., as purchaser ("Eneva") and Eletricidade do Brasil S.A. -- Ebrasil, entered into a Share Purchase Agreement pursuant to which Eneva 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$6.1 billion in cash (the “Sergipe Sale”). The purchase price payable by Eneva accrued interest at a rate of CDI +1% from December 31, 2021 until the date of the closing (CDI at closing used for interest calculation purposes) and was subject to certain customary adjustments, including for the amount of any (a) distributions or payments to or for the benefit of Sergipe Sellers and their affiliates and liabilities incurred or assumed 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. The Sergipe Sale was completed on October 3, 2022, and Eneva paid the Sergipe Sellers R$6.8 billion (approximately $1.3 billion using the exchange rate as of the closing date), prior to the settlement of debt, settlement of other contractual liabilities and payment of transaction costs and consent fees at closing. The Company also entered into a foreign currency forward to mitigate foreign currency risk to the expected proceeds from the transaction, and this foreign currency forward settled at the time of the Sergipe Sale resulting in a gain of $20,394, recognized in Other expense (income), net in the Consolidated Statements of Operations and Comprehensive Income. As a result of the announcement of the Sergipe Sale, the Company recognized an OTTI of the investment in CELSEPAR totaling $369,207 for the year ended December 31, 2022, and this loss was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income.
14. Construction in progress |
The Company’s construction in progress activity during the years ended December 31, 20202023 and 20192022 is detailed below:
| | | December 31, 2020 | | | December 31, 2019 | |
| Balance at beginning of period | | $ | 466,587 | | | $ | 254,700 | |
| Additions | | | 118,530 | | | | 315,188 | |
| Transferred to property, plant and equipment, net (Note 11) | | | (351,080 | ) | | | (103,301 | ) |
| Balance at end of period | | $ | 234,037 | | | $ | 466,587 | |
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Construction in progress as of beginning of period | $ | 2,418,608 | | | $ | 1,043,883 | |
| Additions | 3,438,895 | | | 1,482,871 | |
| Asset impairment expense | — | | | (50,659) | |
| Impact of currency translation adjustment | 30,989 | | | 5,580 | |
| Assets placed in service | (540,198) | | | (63,067) | |
| Construction in progress as of end of period | $ | 5,348,294 | | | $ | 2,418,608 | |
Interest expense of $25,924, $25,172$295,809, $94,454 and $1,732$30,093, inclusive of amortized debt issuance costs, was capitalized for the years ended December 31, 2020, 20192023, 2022 and 2018, respectively, inclusive2021, respectively.
The Company has significant development activities in Latin America as well as the development of amortized debt issuance costs disclosedthe Company's Fast LNG liquefaction solution, and the completion of such developments are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. The Company's development activities for the year ended December 31, 2023 were primarily focused on Fast LNG and the construction of temporary power generation assets to support the Puerto Rican grid stabilization project; additions to construction in “Note progress in 2023 of $2,930,384 were to develop Fast LNG projects and Puerto Rican temporary power.
Assets placed in service during 2023 are primarily comprised of assets to support our Puerto Rican temporary power project and our power plant at the Port of Pichilingue in Baja California Sur, Mexico.
15. Debt.”
11. | Property, plant and equipment, net |
As of December 31, 20202023 and 20192022, the Company’s property, plant and equipment, net consisted of the following:
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Vessels | $ | 1,494,433 | | | $ | 1,518,839 | |
| Terminal and power plant equipment | 430,883 | | | 218,296 | |
| CHP facilities | 273,978 | | | 123,897 | |
| Gas terminals | 179,103 | | | 177,780 | |
| ISO containers and other equipment | 156,925 | | | 134,324 | |
| LNG liquefaction facilities | 63,316 | | | 63,316 | |
| Gas pipelines | 66,319 | | | 65,985 | |
| Land | 54,324 | | | 52,995 | |
| Leasehold improvements | 139,967 | | | 9,377 | |
| Accumulated depreciation | (377,833) | | | (248,082) | |
| Total property, plant and equipment, net | $ | 2,481,415 | | | $ | 2,116,727 | |
| | | December 31, 2020 | | | December 31, 2019 | |
| Terminal and power plant equipment | | $ | 188,855 | | | $ | 14,981 | |
| CHP facilities | | | 119,723 | | | | 0 | |
| Gas terminals | | | 120,810 | | | | 53,380 | |
| ISO containers and other equipment | | | 100,137 | | | | 42,704 | |
| LNG liquefaction facilities | | | 63,213 | | | | 62,929 | |
| Gas pipelines | | | 58,974 | | | | 11,684 | |
| Land | | | 16,246 | | | | 15,401 | |
| Leasehold improvements | | | 8,723 | | | | 8,054 | |
| Accumulated depreciation | | | (62,475 | ) | | | (16,911 | ) |
| Total property, plant and equipment, net | | $ | 614,206 | | | $ | 192,222 | |
Depreciation for the years ended December 31, 2020, 20192023, 2022 and 20182021 totaled $32,116, $7,527$141,069, $104,823 and $3,900,$80,220, respectively, of which $927, $701$905, $954 and $713,$1,167, respectively, is included within Cost of sales in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.
12. | Goodwill The carrying amount of goodwill was $776,760 as of both December 31, 2023 and 2022. The Company performed its annual goodwill impairment test as of October 1, 2023 and 2022 and, in both periods, conducted a qualitative assessment. The Company concluded that the fair value of each reporting unit was greater than the carrying amount, and no goodwill impairment charges were recognized during the years ended December 31, 2023 and 2022. Intangible assets net |
The following table summarizestables summarize the composition of intangible assets as of December 31, 20202023 and 2019:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 |
| Gross Carrying
Amount | | Accumulated
Amortization | | Currency Translation
Adjustment | | Net Carrying
Amount | | Weighted
Average Life |
| Definite-lived intangible assets | | | | | | | | | |
| Favorable vessel charter contracts | $ | 17,700 | | | $ | (10,615) | | | $ | — | | | $ | 7,085 | | | 4 |
| Permits and development rights | 48,217 | | | (5,557) | | | (291) | | | 42,369 | | | 38 |
| | | | | | | | | |
| Easements | 1,555 | | | (341) | | | — | | | 1,214 | | | 30 |
| | | | | | | | | |
| Indefinite-lived intangible assets | | | | | | | | | |
| Easements | 1,191 | | | — | | | (44) | | | 1,147 | | | n/a |
| Total intangible assets | $ | 68,663 | | | $ | (16,513) | | | $ | (335) | | | $ | 51,815 | | | |
| | | December 31, 2020 | |
| | | Gross Carrying Amount | | | Accumulated Amortization | | | Net Carrying Amount | | | Weighted Average Life | |
| Definite-lived intangible assets | | | | | | | | | | | | |
| Shannon LNG permits | | $ | 45,897 | | | $ | 2,438 | | | $ | 43,459 | | | | 40 | |
| Easements | | | 1,559 | | | | 190 | | | | 1,369 | | | | 30 | |
| | | | | | | | | | | | | | | | | |
| Indefinite-lived intangible assets | | | | | | | | | | | | | | | | |
| Easements | | | 1,274 | | | | - | | | | 1,274 | | | | n/a | |
| Total intangible assets | | $ | 48,730 | | | $ | 2,628 | | | $ | 46,102 | | | | | |
| | | December 31, 2019 | |
| | | Gross Carrying Amount | | | Accumulated Amortization | | | Net Carrying Amount | | | Weighted Average Life | |
| Definite-lived intangible assets | | | | | | | | | | | | |
| Shannon LNG permits | | $ | 42,157 | | | $ | 1,198 | | | $ | 40,959 | | | | 40 | |
| Easements | | | 1,559 | | | | 139 | | | | 1,420 | | | | 30 | |
| | | | | | | | | | | | | | | | | |
| Indefinite-lived intangible assets | | | | | | | | | | | | | | | | |
| Easements | | | 1,161 | | | | - | | | | 1,161 | | | | n/a | |
| Total intangible assets | | $ | 44,877 | | | $ | 1,337 | | | $ | 43,540 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | |
As of December 31, 20202023 and 2019,2022, the weighted-average remaining amortization periods for the intangible assets was 37.5 yearswere 28.8 and 38.818.0 years, respectively. As of January 1, 2020, intangible assets associated with favorable lease terms in acquired leases have been reclassified as ROU assets as a result of adoption of ASC 842.
Amortization expense for the years ended December 31, 20202023, 2022, and 2019 totaled $1,1202021 was $26,853, $37,162, and $1,114, respectively. $18,609, respectively which were inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed in the Mergers.
During the year ended December 31, 2023, certain favorable vessel charter contract intangibles with a gross carrying amount of $88,000 became fully amortized, and the gross carrying amount and accumulated amortization have been written-off. Additionally, a vessel charter contract was terminated during 2023, and the net book value of the intangible asset on the date of termination of $9,553 was recognized as an impairment in the Consolidated Statements of Operations and Comprehensive Income.
In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied the Company's application for the development of an LNG terminal and power plant in Shannon, Ireland. The Company is challenging this decision. Capitalized permits and development rights are primarily comprised of capitalized costs related to this project. The Company has concluded that these recent events do not indicate that these assets are not recoverable. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect to the Company's results of operations.
The estimated aggregate amortization expense, inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed in the Mergers, for each of the next five years is:
| Year ending December 31: | | | |
| 2021 | | $ | 1,199 | |
| 2022 | | | 1,199 | |
| 2023 | | | 1,199 | |
| | Year ended December 31: | |
| 2024 | |
| 2024 | |
| 2024 | | | 1,199 | |
| 2025 | | | 1,199 | |
| 2026 | |
| 2027 | |
| 2028 | |
| Thereafter | | | 38,833 | |
| Total | | $ | 44,828 | |
13. | Other non-current assets |
As of December 31, 20202023 and 2019, other2022, Other non-current assets consisted of the following:
| | | December 31,
2020 | | | December 31,
2019 | |
| Nonrefundable deposit | | $ | 28,509 | | | $ | 22,262 | |
| Contract asset, net (Note 4) | | | 23,972 | | | | 19,474 | |
| Cost to fulfill (Note 4) | | | 10,688 | | | | 8,508 | |
| Unbilled receivables, net (Note 4) | | | 6,462 | | | | 0 | |
| Upfront payments to customers | | | 6,330 | | | | 5,904 | |
| Port access rights and initial lease costs | | | 0 | | | | 17,762 | |
| Other | | | 10,069 | | | | 10,256 | |
| Total other non-current assets, net | | $ | 86,030 | | | $ | 84,166 | |
Nonrefundable deposits are primarily related to deposits for planned land purchases in Pennsylvania and Ireland.
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Assets held for sale | $ | — | | | $ | 40,685 | |
| Contract asset, net (Note 7) | 19,901 | | | 28,651 | |
| Investments in equity securities | 7,678 | | | 17,806 | |
| Cost to fulfill (Note 7) | 22,418 | | | 9,773 | |
| Upfront payments to customers | 8,855 | | | 9,158 | |
| Other | 68,051 | | | 35,606 | |
| Total other non-current assets | $ | 126,903 | | | $ | 141,679 | |
All assets and liabilities of Pecém and Muricy were classified as held for sale as of 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 Company recognized unrealized (loss) gain on its investments in equity securities of $(1,067) and $8,254 for the years ended December 31, 2022 and 2021, respectively, within Other expense (income), net in the Consolidated Statements of Operations and Comprehensive Income. During the third quarter of 2023, the Company sold certain investments in equity securities recognizing a realized gain of $165. Investments in equity securities include investments without a readily determinable fair value of $7,678 as of both December 31, 2023 and 2022.
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 upfront payments to our service providers, a long-term refundable depositthe value of the earnout receivable recognized upon the sale of Pecém and investments in equity securities. During the fourth quarter of 2020, the Company invested $1,000 in a hydrogen technologyMuricy, development company through a Simple Agreementcosts for Future Equity (“SAFE”) that will convert to preferred shares upon completion of a qualifiedhosted software products and deferred financing by the investee, and this amount is classified within other in the table above.
As of January 1, 2020, port access rightscosts related to the Company’s port lease in Baja California Sur, Mexico, and payments to incumbent tenants to secure the Company’s port lease in San Juan, Puerto Rico were reclassified as ROU assets in connection with the adoptionRevolving Facility.
14. | 18. Accrued liabilities |
As of December 31, 20202023 and 20192022, accrued liabilities consisted of the following:
| | December 31,
2020 | | | December 31,
2019 | |
| December 31,
2023 | | | December 31,
2023 | | December 31,
2022 |
| Accrued development costs | | $ | 16,631 | | | $ | 25,037 | |
| Accrued interest | | | 27,938 | | | | 0 | |
| Accrued bonuses | | | 17,344 | | | | 14,991 | |
| Accrued dividend | |
| Other accrued expenses | | | 28,439 | | | | 14,915 | |
| Total accrued liabilities | | $ | 90,352 | | | $ | 54,943 | |
As of December 31, 20202023 and 2019,2022, Other current liabilities consisted of the following:
| | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| Derivative liabilities | $ | 19,450 | | | $ | 19,458 | |
| Contract liabilities | 65,287 | | | 12,748 | |
| Income tax payable | 54,040 | | | 6,261 | |
| Due to affiliates | 9,579 | | | 7,499 | |
| Winter sub-charter liability | 49,400 | | | — | |
| Other current liabilities | 30,195 | | | 6,912 | |
| Total other current liabilities | $ | 227,951 | | | $ | 52,878 | |
During the fourth quarter of 2023, the Company began to sub-charter the Winter, a vessel included in the Energos Formation Transaction, and a liability was recorded representing the Company's obligation to pay sub-charter payments until the vessel is chartered directly from Energos. The Company also recognized an asset of $59,074 (see Note 12) representing the charterer's remaining payments to Energos.
The remaining balance of other current liabilities as of December 31, 2023 primarily consists of recoverable taxes payable.
20. Debt
As of December 31, 2023 and 2022, debt consisted of the following:
| | December 31, 2020 | | | December 31, 2019 | |
| Senior Secured Notes, due September 15, 2025 | | $ | 1,239,561 | | | $ | 0 | |
| Term Loan Facility, due January 21, 2020 | | | 0 | | | | 495,000 | |
Senior Secured Bonds, due September 2034 | | | 0 | | | | 70,960 | |
Senior Secured Bonds, due December 2034 | | | 0 | | | | 10,823 | |
Senior Unsecured Bonds, due September 2036 | | | 0 | | | | 42,274 | |
| Total debt | | $ | 1,239,561 | | | $ | 619,057 | |
| | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Senior Secured Notes, due September 2025 | $ | 1,245,662 | | | $ | 1,243,351 | |
| Senior Secured Notes, due September 2026 | 1,486,374 | | | 1,481,639 | |
| Vessel Financing Obligation, due August 2042 | 1,359,995 | | | 1,406,091 | |
| Revolving Facility | 866,600 | | | — | |
| Term Loan B, due October 2028 | 771,420 | | | — | |
| South Power 2029 Bonds, due May 2029 | 216,993 | | | 216,177 | |
| Barcarena Term Loan, due February 2024 | 199,678 | | | 194,427 | |
| Equipment Notes, due July 2026 | 190,789 | | | — | |
| Short-term Borrowings | 182,270 | | | — | |
| Barcarena Debentures, due October 2028 | 175,025 | | | — | |
| EB-5 Loan, due July 2028 | 61,614 | | | — | |
| Tugboat Financing, due December 2038 | 46,728 | | | — | |
| Total debt | $ | 6,803,148 | | | $ | 4,541,685 | |
| Current portion of long-term debt | $ | 292,625 | | | $ | 64,820 | |
| Long-term debt | 6,510,523 | | | 4,476,865 | |
Long-term debt is recorded at amortized cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is $6,835,487 and $4,327,311 as of December 31, 2023 and 2022, respectively, and is classified as Level 2 within the fair value hierarchy. The Company's debt arrangements include cross-acceleration clauses whereby events of default under an individual debt agreement can lead to acceleration of principal under other debt arrangements.
Senior SecuredOur outstanding debt as of December 31, 2023 is repayable as follows:
| | | | | |
| December 31, 2023 |
| 2024 | $ | 292,625 | |
| 2025 | 1,341,060 |
| 2026 | 2,605,990 |
| 2027 | 162,460 |
| 2028 | 1,124,501 |
| Thereafter | 1,392,834 |
| Total debt | $ | 6,919,470 | |
| |
| Less: deferred finance charges | (116,322) |
| Total debt, net deferred finance charges | $ | 6,803,148 | |
The Company's future payments for the Vessel Financing Obligation include the expected carrying value of vessels that will be derecognized at the end of the lease term. The future payments also include third-party charter payments that will be received by Energos and included as part of debt service.
2025 Notes
On In September 2, 2020,, the Company issued $1,000,000$1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A144A under the Securities Act (the “Senior Secured“2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; year; no principal payments are due until maturity on September 15, 2025.2025. The Company may redeem the Senior Secured2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The Senior Secured2025 Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The Senior Secured2025 Notes may limit the Company’s ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The Senior Secured2025 Notes also provide for customary events of default and prepayment provisions.
The Company used a portion of the net cash proceeds received from the Senior Secured Notes to repay in full the outstanding principal and interest under the Credit Agreement (as defined below), including related costs and expenses. The Company also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds (as defined below), including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The Company completed the redemption of the Senior Secured Bonds and Senior Unsecured Bonds on September 21,In December 2020,.
In connection with the issuance of the Senior Secured Notes, the Company incurred $17,937 in origination, structuring and other fees. Issuance costs of $13,909 were deferred as a reduction of the principal balance of the Senior Secured Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes. As a portion of the repayment of the Credit Agreement was a modification, the Company recorded $4,028 of third-party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss.
On December 17, 2020, the Company issued $250,000$250,000 of additional notes on the same terms as the Senior Secured2025 Notes in a private offering pursuant to Rule 144A144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of Senior Secured2025 Notes herein). Proceeds received includedAs of December 31, 2023 and 2022, remaining unamortized deferred financing costs for the 2025 Notes were $4,338 and $6,649, respectively.
2026 Notes
In April 2021, the Company issued $1,500,000 of 6.50% senior secured notes in a premiumprivate offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of $13,125,each year; no principal payments are due until maturity on September 30, 2026. The Company may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes.
In connection with the issuance of the 2026 Notes, the Company incurred $25,240 in origination, structuring and other fees, which was offset by additionaldeferred as a reduction of the principal balance of the 2026 Notes on the Consolidated Balance Sheets. As of December 31, 2023 and 2022, total remaining unamortized deferred financing costs for the 2026 Notes was $13,626 and $18,361, respectively.
Vessel Financing Obligation
In connection with the Energos Formation Transaction (see discussion in Note 5), the Company entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to the Company at the time of closing were classified as finance leases. Additionally, the Company's charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, the Company accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation for consideration received.
The Company continues to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, the Company will recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation; at inception of the arrangement, the effective interest rate on this financing obligation was approximately 15.9% and includes the cash flows that Energos receives from these third-party charters.
In connection with closing the Energos Formation Transaction, the Company incurred $10,010 in origination, structuring and other fees, of $which $2,995 was allocated to the sale of the 4,188Nanook and recognized as Other expense (income), net in the Consolidated Statements of Operations and Comprehensive Income. Financing costs of $7,015 were allocated and deferred as a reduction of the principal balance of the financing obligation on the Consolidated Balance Sheets. As of December 31, 20202023 and 2022, the remaining unamortized deferred financing costs for the Vessel Financing Obligation was $6,490 and $6,866, respectively.
Revolving Facility
In April 2021, the Company entered into a credit agreement (the "Revolving Credit Agreement") with a bank for $200,000 senior secured revolving credit facility (the "Revolving Facility"). The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The Revolving Facility will mature in 2026 if the 2025 Notes are refinanced prior to maturity, with the potential for the Company to extend the maturity date of the Revolving Facility once for a one-year increment; if not, the Revolving
Facility becomes due approximately 60 days prior to the maturity of the 2025 Notes. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.
In 2022, the Revolving Credit Agreement was amended twice to increase the borrowing capacity by a total of $240,000, and in the year ended December 31, 2023, the Company entered into additional amendments which increased the borrowing capacity by $510,000, for a total capacity of $950,000. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. During the year ended December 31, 2023, the Company drew $866,600 from the Revolving Facility, which is outstanding as of December 31, 2023.
The Company incurred $5,398 in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees to expand the facility in 2022. During the year ended December 31, 2023, the Company incurred an additional $9,431 in fees in relation to the 2023 amendments. These costs have been capitalized within Other non-current assets on the Consolidated Balance Sheets. As of December 31, 2023 and 2022, total remaining unamortized deferred financing costs were $for the Revolving Facility was $11,923 and $5,172, respectively.10,439
The obligations under the Revolving Facility are guaranteed by certain of the Company's subsidiaries, including those that own the Company's first Fast LNG asset, and are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes.Additionally, the Revolving Facility is secured by assets comprising the Company's first Fast LNG project in Altamira, Mexico. The Company is required to comply with covenants under the Revolving Facility and Letter of Credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 4.0:1.0. The Company was in compliance with all covenants as of December 31, 2023.
The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.
TheTerm Loan B Credit Agreement
On January 10, 2020,August 3, 2023, the Company entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to borrow $800,000 inwhich the lenders funded term loans (the “Credit Agreement”“Bridge Term Loans”). to the Company in an aggregate principal amount of $400,000. The Credit Agreement wasBridge Term Loans were initially set to mature on August 1, 2024 and were payable in Januaryfull on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.
On October 30, 2023, with the fullCompany entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal balance due upon maturity. Interest was payable quarterlyamount of $856,000 ("Term Loan B"). Borrowings were issued at a discount, and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floorCompany received proceeds of 1.50%, plus a margin of 6.25%.$787,520. The interest rate margin was to increase each year of the term by 1.50%. A portion of the proceeds received were utilized to extinguishfrom the Term Loan Facility (defined below),B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2025 Notes and 2026 Notes are refinanced in full prior to their maturities, (ii) July 16, 2025 if any of the 2025 Notes remain outstanding as of such date, and (iii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2,140 will be due starting March 2024.
The obligations under the Term Loan B are guaranteed by certain of the Company's subsidiaries, including outstanding principal of $495,000.
those that own the Company's first Fast LNG project in Altamira, Mexico. The Credit Agreement wasTerm Loan B is secured by mortgages onsubstantially the same collateral as the first lien obligations under the 2025 Notes and the 2026 Notes, and, in addition, is secured by assets compromising the Company's first Fast LNG Project.
The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain properties owned byasset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, the Company will be required to prepay the Term Loan B with the Company’s subsidiaries,Excess Cash Flow (as defined in addition to other collateral. the Term Loan B Agreement).
The Company wasTerm Loan B Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required to comply with certain financial covenants and other restricted covenants customary for credit agreements of this type, including restrictions on indebtedness, liens, acquisitions and investments, restricted payments and dispositions. The Credit Agreement also provided for customary events of default, prepayment and cure provisions.
under the Term Loan B Agreement.
In connection with obtaining the Creditexecution of the Bridge Term Loan Agreement and the extinguishment of the Term Loan Facility,B Agreement, the Company incurred $37,051$17,719 in origination, structuring and other fees. The repayment of the Bridge Term Loans with borrowings under the Term Loan B Agreement was treated as a modification, and fees whichattributable to lenders that participated in the Bridge Term Loans will be amortized over the life of the Term Loan B Agreement; additional third-party fees associated with such lenders of $1,578 were recognized as expense in Transaction and integration costs. Additional fees for new lenders participating in the Term Loan B were recognized as a reduction of the principal balance of the Credit Agreement on the consolidated balance sheets.
On Consolidated Balance SheetsSeptember 2, 2020, the Company repaid the full amount outstanding using proceeds from the Senior Secured Notes. Certain lenders in the Credit Agreement participated in the issuance. As of the Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes.
Term Loan Facility
On August 16, 2018, the Company entered into a credit agreement with a syndicate of 2 lenders to borrow up to an aggregate principal amount of $240,000, and proceeds received from this credit agreement were utilized to repay prior debt facilities. On December 31, 2018, the Company amended this credit agreement to increase the available borrowing principal amount to $500,000 (as amended, the “Term Loan Facility”)2023, and as of December 31, 2018, the Company had an outstanding principal balance of $280,000 under the Term Loan Facility. On March 21, 2019, the Company drew an additional $220,000, bringing the Company’s total outstanding borrowings to $500,000 under the Term Loan Facility.
All borrowings under the Term Loan Facility bore interest at a rate selected by the Company of either (i) LIBOR divided by one minus the applicable reserve requirement plus a spread of 4% or (ii) subject to a floor of 1%, a Base Rate equal to the higher of (a) the Prime Rate, (b) the Federal Funds Rate plus 1/2 of 1% or (c) the 1-month LIBOR rate plus 1.00% plus a spread of 3.0%. The Term Loan Facility was repayable in quarterly installments of $1,250 with a balloon payment due at maturity.
The Term Loan Facility was secured by mortgages on certain properties owned by the Company’s subsidiaries, in addition to other collateral. The Term Loan Facility was amended in the third quarter of 2019 to allow certain properties of a consolidated subsidiary to secure the Senior Secured Bonds.
The Company incurred costs in connection with obtaining the Term Loan Facility, the extinguishment of the Company’s prior debt facilities and the amendment of the Term Loan Facility. Some of the costs incurred were capitalized as a reduction to the Term Loan Facility on the consolidated balance sheets, and all deferred financing costs associated with the Term Loan Facility were amortized over the term of the Term Loan Facility, through December 31, 2019. As such, there were 0remaining unamortized deferred financing costs, as of December 31, 2019.
The Term Loan Facility had a maturity date of December 31, 2019 with an option to extendincluding the maturity dateunamortized original issue discount, for2 additional six-month periods. Upon the exercise of each extension option, the Company would pay a fee equal to 1.0% of the outstanding principal balance at the time of the exercise and the spread on LIBOR and Base Rate would increase by 0.5%. On December 30, 2019, the Company entered into an amendment with the lenders to extend the maturity to January 21, 2020; no fees were due to lenders from the execution of this amendment. On January 15, 2020, the Company repaid the full amount outstanding including fees due to the lenders using proceeds from the Credit Agreement to extinguish the Term Loan Facility. In conjunction with the extinguishment of the Term Loan Facility, the Company recognized a Loss on extinguishment of debt of $B was $84,580.9,557 in the consolidated statements of operations and comprehensive loss.
South Power 2029 Bonds
On September 2, 2019,In January 2022, NFE South Power Holdings Limited (“South Power”), a consolidatedwholly owned subsidiary of the Company,NFE, entered into a facilityan agreement for the issuance of up to $285,000 secured and unsecured bonds (the “Senior Secured(“South Power 2029 Bonds” and “Senior Unsecured Bonds”, respectively) and subsequently issued $73,317 and $43,683 in Senior Secured). The South Power 2029 Bonds and Senior Unsecured Bonds, respectively. The Senior Secured Bonds wereare secured by, amongst other things, the dual-firedCompany’s combined heat and power facilityplant in Clarendon, Jamaica (the “CHP(“CHP Plant”), and related receivables and assets, and the proceeds were used to fund the completionNFE has provided a guarantee of the CHP Plant and to reimburse shareholder advances. Upon completion of construction ofobligations under the CHP Plant in the fourth quarter of 2019, South Power 2029 Bonds. As of both December 31, 2023 and 2022, South Power had $221,824 of South Power 2029 Bonds issued an additional $63,000 in Senior Secured Bonds. The Company received $10,856 of the proceeds in 2019 and received the remaining proceeds of $52,144 in January 2020.
The Senior SecuredSouth Power 2029 Bonds borebear interest at an annual fixed rate of 8.25%6.50% and matured 15 years fromshall be repaid in quarterly installments beginning in August 2025 with the closingfinal repayment date of each issuance. No principal payments were due for the first seven years. After seven years, quarterly principal payments of approximately 1.6% of the original principal amount were due, with a 50% balloon payment due upon maturity.in May 2029. Interest payments on outstanding principal balances wereare due quarterly.
The Senior Unsecured Bonds bore interest at an annual fixed rate of 11.00% and matured in September 2036. No principal payments were due for the first nine years. Beginning in 2028, principal payments were due quarterly on an escalating schedule. Interest payments on outstanding principal balances were due quarterly.
South Power wasis required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. The Company was in compliance with all covenants including limitationsas of December 31, 2023 and 2022.
As of December 31, 2023 and 2022, the remaining unamortized deferred financing costs for the South Power 2029 Bonds was $4,832 and $5,647, respectively.
Equipment Notes
In June 2023, the Company executed a Master Loan and Security Agreement with a lender to borrow up to $200,000 under promissory notes secured by certain turbines acquired in the first quarter of 2023 to support our grid stabilization project in Puerto Rico (the “Equipment Notes”). During the second and third quarters of 2023, the Company borrowed the full capacity bearing interest at approximately 7.68%, and the principal is partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in July 2026.
The Equipment Notes contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Equipment Notes do not contain any restrictive financial covenants. NFE has provided a guarantee of the obligations under the Equipment Notes.
Proceeds received were net of upfront fees due to the lender, and through December 31, 2023, the Company has incurred $2,516 in origination, structuring and other fees, associated with entry into the Equipment Notes. As of December 31, 2023, total remaining unamortized deferred financing costs for the Equipment Notes was $2,382.
EB-5 Loan Agreement
On July 21, 2023, the Company entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100,000, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility,
and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31, 2023, $62,928 was funded under the EB-5 Loan Agreement.
The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.
The Company has incurred $1,357 in origination, structuring and other fees associated with entry into the EB-5 Loan Agreement. As of December 31, 2023, the total remaining unamortized deferred financing costs for the EB-5 Loan Agreement was $1,314.
Short-term Borrowings
The Company may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby the Company sells to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2023, the Company had $182,270 due under repurchase arrangements with a weighted average interest rate of 9.68%.
Barcarena Financings
In the third quarter of 2022, certain of the Company's indirect subsidiaries entered into a financing agreement to borrow up to $200,000 due upon maturity in February 2024 (the “Barcarena Term Loan”); proceeds were utilized to fund a portion of the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant"). As of December 31, 2022, the loan was fully funded. Interest is due quarterly, and outstanding borrowings bear interest at a rate equal to the Secured Overnight Financing Rate ("SOFR") plus 4.70%.
The obligations under the Barcarena Term Loan are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and New Fortress Energy Inc. has provided a parent company guarantee. Collateral on incurring additional indebtedness.the Barcarena Term Loan includes liens on shares of entities constructing the Company's LNG regasification terminal located in Pará, Brazil ("Barcarena Terminal") and Barcarena Power Plant, liens on equipment and machinery owned by these entities, and rights to future operating cash flows and receivables under the Barcarena Power Plant's power purchase agreements. The facilityCompany is required to comply with customary affirmative and negative covenants, and the Barcarena Term Loan also provides for customary events of default, prepayment and cure provisions. The Company was in compliance with all covenants as of December 31, 2023 and 2022.
The Company incurred $4,011 of structuring and other fees, and such fees were deferred as a reduction to the principal balance of the Barcarena Term Loan. As of December 31, 2023 and 2022, the remaining unamortized deferred financing costs for the Barcarena Term Loan was $334 and $3,077, respectively.
In October 2023, certain of the Company's Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of the Barcarena Power Plant. Proceeds received will be used to repay the Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025. As the Company has committed financing in place to extinguish the Barcarena Term Loan as of December 31, 2023, the Barcarena Term Loan has been presented as long-term debt on the Consolidated Balance Sheets. The Barcarena Term Loan was repaid in January 2024 using proceeds from the BNDES Term Loan (defined below).
The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. The remaining series may be issued upon the achievement of certain conditions precedent. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. The Company is able to prepay the Barcarena Debentures, subject
to customary break funding costs, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal.
The Barcarena Debentures are convertible to shares of one of the Company's indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.
The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own the Barcarena Terminal and the LNG regasification terminal located in Santa Catarina, Brazil. NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.
The Company incurred $5,061 of structuring and other fees, and such fees were deferred as a reduction to the principal balance of the Barcarena Debentures. As of December 31, 2023, the remaining unamortized deferred financing costs for the Barcarena Debentures was $4,975.
The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). The Company is able to borrow up to R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"); no amounts were funded under the BNDES Credit Agreement as of December 31, 2023. Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045.
The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.
In December 2023, the Company sold and leased back four tugboat vessels for 15 years receiving proceeds of $46,728. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, the Company paid approximately $3,892 of fees in connection withaccounted for the issuance of Senior Secured Bonds and Senior Unsecured Bonds. These fees were capitalized on a pro-rata basisTugboat Financing as a reduction of the Senior Secured Bondsfailed sale-leaseback and Senior Unsecured Bondshas recorded a financing obligation for consideration received. The effective interest rate on the consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the Senior Secured Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds, the Company recognized a loss on extinguishment of debt of $7,195 in the consolidated statements of operations and comprehensive loss, including the write-off of $3,594 of unamortized deferredthis financing costs and prepayment premium paid to bondholders of $obligation is approximately 3,601.
Interest Expense
Interest and related amortization of debt issuance costs, premiums and discounts recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the years ended December 31, 2020, 20192023, 2022 and 20182021 consisted of the following:
| | Year Ended December 31, | |
| Year Ended December 31, | | | Year Ended December 31, |
| 2023 | | | 2023 | | 2022 | | 2021 |
| Interest per contractual rates | |
| Interest expense on Vessel Financing Obligation | |
| Amortization of debt issuance costs, premiums and discounts | |
| | | 2020 | | | 2019 | | | 2018 | |
| Interest per contractual rates | | $ | 76,176 | | | $ | 32,283 | | | $ | 9,363 | |
| Amortization of debt issuance costs | | | 15,471 | | | | 12,301 | | | | 3,617 | |
| Interest expense incurred on finance lease obligations | |
| Interest expense incurred on finance lease obligations | |
| Interest expense incurred on finance lease obligations | |
| Total interest costs | | | 91,647 | | | | 44,584 | | | | 12,980 | |
| Capitalized interest | | | 25,924 | | | | 25,172 | | | | 1,732 | |
| Total interest expense | | $ | 65,723 | | | $ | 19,412 | | | $ | 11,248 | |
In connection withInterest expense on the IPO, NFE LLC contributedVessel Financing Obligations includes non-cash expense of $169,641 and $84,517 for the net proceeds from the IPO to NFI in exchange for NFI LLC Units, and NFE LLC became the managing member of NFI. NFI is a limited liability company that was treated as a partnership through years ended December 31, 2020 for U.S. federal income tax purposes2023 and for most applicable state and local income tax purposes. As a partnership, NFI was not subject2022, respectively, related to U.S. federal and certain state and local income taxes. Any taxable income or loss generatedpayments received by NFI was passed through to and included in the taxable income or loss of its members, on a pro rata basis, subject to applicable tax regulations. NFE is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of NFI. Additionally, NFI and its subsidiaries are subject to income taxes in the various foreign jurisdictions in which they operate.
Energos from third party charterers.
In connection with the IPO, NFE recorded a deferred tax asset of $42,783 related to the difference between its tax basis in its investment in NFI and NFE’s share of the financial statement carrying amount of the net assets of NFI. The deferred tax asset was recorded to equity and is fully offset by a valuation allowance also recorded to equity.
Subsequent to the Exchange Transactions completed on June 10, 2020, 100% of NFI’s operations are included in the NFE income tax provision; there was no impact on income tax expense due to the Exchange Transactions. Additionally, in the third quarter of 2020, the Company completed the Conversion; NFE LLC has been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation has no effect on the U.S. federal tax treatment of the Company or its shareholders.
The components of the Company’s lossincome (loss) before income taxes for the years ended December 31, 2020, 2019,2023, 2022 and 20182021 were as follows:
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| United States | | $ | (166,571 | ) | | $ | (194,481 | ) | | $ | (74,873 | ) |
| Foreign | | | (92,577 | ) | | | (9,399 | ) | | | (3,647 | ) |
| Loss before taxes | | $ | (259,148 | ) | | $ | (203,880 | ) | | $ | (78,520 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| United States | $ | 287,768 | | | $ | 551,500 | | | $ | (283,363) | |
| Foreign | 376,621 | | | (490,153) | | | 388,535 | |
| Income before taxes | $ | 664,389 | | | $ | 61,347 | | | $ | 105,172 | |
Income tax expense (benefit) is comprised of the following for the years ended December 31, 2020, 2019,2023, 2022 and 2018:2021:
| | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| Current: | | | | | | | | | |
| Domestic | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Foreign | | | 2,063 | | | | 47 | | | | 7 | |
| Total current tax expense | | | 2,063 | | | | 47 | | | | 7 | |
| Deferred: | | | | | | | | | | | | |
| Domestic | | | 0 | | | | 0 | | | | 0 | |
| Foreign | | | 2,754 | | | | 392 | | | | (345 | ) |
| Total deferred tax expense (benefit) | | | 2,754 | | | | 392 | | | | (345 | ) |
| Total provision for (benefit from) income taxes | | $ | 4,817 | | | $ | 439 | | | $ | (338 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Current: | | | | | |
| Domestic | $ | 47,198 | | | $ | 37,831 | | | $ | 311 | |
| Foreign | 53,377 | | | 118,266 | | | 20,975 | |
| Total current tax expense | 100,575 | | | 156,097 | | | 21,286 | |
| Deferred: | | | | | |
| Domestic | 4,030 | | | 5,794 | | | — | |
| Foreign | 10,908 | | | (285,330) | | | (8,825) | |
| Total deferred tax (benefit) expenses | 14,938 | | | (279,536) | | | (8,825) | |
| Total provision for (benefit from) income taxes | $ | 115,513 | | | $ | (123,439) | | | $ | 12,461 | |
Effective Tax Rate
A reconciliation of the U.S. federal statutory income tax rate to the Company’s effective tax rate is as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Income tax at the statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Foreign tax rate differential | (12.1) | | | (25.5) | | | (33.8) | |
| US taxation on foreign earnings | 0.1 | | | 25.5 | | | 9.6 | |
| Impact from foreign operations | 0.4 | | | (10.7) | | | 1.5 | |
| Change in valuation allowance | 8.2 | | | (22.9) | | | 14.7 | |
| Income attributable to non-controlling interest | — | | | 1.3 | | | 0.8 | |
| Effects of share-based compensation | 0.3 | | | (39.8) | | | (8.5) | |
| Withholding taxes | 0.6 | | | 12.6 | | | 9.5 | |
| Income tax credits | (4.8) | | | (0.3) | | | (2.4) | |
| | | | | |
| Sergipe Sale | — | | | (165.4) | | | — | |
| Outside basis differences | 0.1 | | | (3.2) | | | 2.6 | |
| Other | 3.6 | | | 6.2 | | | (3.2) | |
| Effective income tax rate | 17.4 | % | | (201.2 | %) | | 11.8 | % |
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | | | 2018 | |
| Income tax at the statutory rate | | | 21.0 | % | | | 21.0 | % | | | 0 | |
| Impact from foreign operations | | | (2.9 | %) | | | 0 | | | | 0 | |
| Foreign tax rate differential | | | 2.9 | % | | | 0.8 | % | | | 0.4 | % |
| Foreign tax on foreign operations | | | 0.4 | % | | | 2.9 | % | | | 0 | |
| Foreign permanent adjustments | | | (0.4 | %) | | | 5.0 | % | | | 0 | |
| Foreign valuation allowance | | | 0.1 | % | | | (10.8 | %) | | | 0 | |
| Domestic valuation allowance | | | (14.2 | %) | | | (2.1 | %) | | | 0 | |
| Income attributable to non-controlling interest | | | (6.4 | %) | | | (18.2 | %) | | | 0 | |
| Other | | | (2.4 | %) | | | 1.2 | % | | | 0 | |
| Effective income tax rate | | | (1.9 | %) | | | (0.2 | %) | | | 0.4 | % |
The Company has certain operations in jurisdictions that are not subject to income taxes. The effect of these earnings taxed at zero percent, as well as the impact of preferential tax rates are included in the foreign rate differential. The Organization
The primary items which decreasedfor Economic Cooperation and Development is coordinating negotiations among more than 140 countries with the Company’sgoal of achieving consensus around substantial changes to international tax policies, including the implementation of a minimum global effective tax rate of 15%. As of December 31, 2023, various countries have implemented the legislation, however, the Company does not expect a resulting material change to the income tax rate fromprovision for the federal statutory rate in 2020 and 2019 were increases in domestic and foreign valuation allowances and income attributable to non-controlling interests. For 2018, the entire difference between the statutory and effective rate was attributable to foreign taxes.
During the yearsyear ended December 31, 2020, 20192024. As additional jurisdictions enact such legislation, the effective tax rate and 2018, the Company did 0t have any unrecognizedcash tax benefits.
The following table summarizes the changespayments could increase in the Company’s valuation allowance on deferred tax assets for the period indicated for the years ended December 31, 2020 and 2019:
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | |
| Balance at the beginning of the period | | $ | 80,911 | | | $ | 241 | |
| Change in valuation allowance | | | 51,586 | | | | 80,670 | |
| Balance at the end of the period | | $ | 132,497 | | | $ | 80,911 | |
The tax effect of each type of temporary difference and carryforward that give rise to a significant deferred tax asset or liability as of December 31, 20202023 and 20192022 are as follows:
| | | Year Ended December 31, | |
| | | 2020 | | | 2019 | |
| Deferred tax assets: | | | | | | |
| Investment in NFI | | $ | 64,553 | | | $ | 46,185 | |
| Accrued interest | | | 18,885 | | | | 14,047 | |
| IRC Section 163(j) interest carryforward | | | 6,909 | | | | 182 | |
| Federal and state net operating loss carryforward | | | 32,145 | | | | 3,215 | |
| Foreign net operating loss carryforward | | | 24,525 | | | | 19,713 | |
| Share-based compensation | | | 6,611 | | | | 8,958 | |
| Lease liability | | | 4,383 | | | | 0 | |
| Other | | | 1,252 | | | | 224 | |
| Total deferred tax assets | | | 159,263 | | | | 92,524 | |
| Valuation allowance | | | (132,497 | ) | | | (80,911 | ) |
| Deferred tax assets, net of valuation allowance | | | 26,766 | | | | 11,613 | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | |
| Property and equipment | | | (22,566 | ) | | | (11,820 | ) |
| Lease asset | | | (4,215 | ) | | | 0 | |
| Total deferred tax liabilities | | | (26,781 | ) | | | (11,820 | ) |
| Net deferred tax liabilities | | $ | (15 | ) | | $ | (207 | ) |
U.S. Federal and State Jurisdictions
The Company and its subsidiaries file income tax returns in the U.S. federal and various state and local jurisdictions. The Company is not currently under income tax examination in any jurisdiction, and NFE filed its first corporate U.S. federal and state income tax returns for the period ended December 31, 2019. NFI was taxed as a U.S. partnership and controlled the underlying operations, thus the tax effects of temporary differences were captured through December 31, 2020 within the net deferred tax asset for the investment in the partnership.
| | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 |
| Deferred tax assets: | | | |
| | | |
| Accrued interest | $ | 37,735 | | | $ | 33,262 | |
| IRC Section 163(j) interest carryforward | 758 | | | 19,251 | |
| Federal and state net operating loss carryforward | 2,063 | | | 2,900 | |
| Foreign net operating loss carryforward | 123,386 | | | 100,614 | |
| Debt | 289,820 | | | 300,834 | |
| Lease liability | 106,293 | | | 70,241 | |
| Goodwill | 47,043 | | | 51,315 | |
| Other | 24,214 | | | 17,141 | |
| Total deferred tax assets | 631,312 | | | 595,558 | |
| Valuation allowance | (188,036) | | | (130,649) | |
| Deferred tax assets, net of valuation allowance | 443,276 | | | 464,909 | |
| | | |
| Deferred tax liabilities: | | | |
| Property and equipment | (343,247) | | | (355,596) | |
| Right-of-use assets | (107,919) | | | (74,289) | |
| Investments | — | | | (2,687) | |
| Commodity swap | — | | | (22,421) | |
| Deferred income | (20,714) | | | (22,414) | |
| Other | (5,933) | | | (5,417) | |
| Total deferred tax liabilities | $ | (477,813) | | | $ | (482,824) | |
| Net deferred tax liabilities | $ | (34,537) | | | $ | (17,915) | |
As of December 31, 2020,2023, the deferred tax asset related to Section 163(j) interest carryforward decreased due to the utilization of interest expense previously limited by the Tax Cuts and Jobs Act 163(j) business interest limitation rule.
Tax Attributes
United States
As of December 31, 2023, NFE has approximately $147,928$8,015 of federal and $30,661$9,021 of state net operating loss carry forwards. The federal and state net operating losses are generally allowed to be carried forward indefinitely and can offset up to 80 percent of future taxable income. The state net operating losses relate to Florida and are generally allowed to be carried forward indefinitely.
Under the provisions of Internal Revenue Code Section 382, certain substantial changes in the Company’s ownership may result in a limitation on the amount of U.S. net operating loss carryforwards that can be utilized annually to offset future taxable income and taxes payable. A portion of theThe Company’s net operating loss carryforwards are subject to an annual limitation of $5,431 under Section 382 of the Internal Revenue Code.
Foreign Jurisdictions
The Company’s foreign subsidiaries file income tax returns in certain foreign jurisdictions. As of December 31, 2023, the Company’s foreign subsidiaries have approximately $506,673 of net operating loss carry forwards, of which $170,294 will expire, if unused between 2028 and 2041, and the remaining $336,379 are allowed to be carried forward indefinitely.
Valuation Allowances
The following table summarizes the changes in the Company’s valuation allowance on deferred tax assets for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 |
| Balance at the beginning of the period | $ | 130,649 | | | $ | 146,269 | |
| Change in valuation allowance | 57,387 | | | (15,620) | |
| Balance at the end of the period | $ | 188,036 | | | $ | 130,649 | |
The change in valuation allowance was mainly due to losses in foreign jurisdictions for the year ended December 31, 2023.
NFE recorded a valuation allowance against its U.S.US federal and state deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized. As of December 31, 2020,2023, the Company concluded, based on the weight of all available positive and negative evidence, those deferred tax assets are not more likely than not to be realized and accordingly, a valuation allowance has been recorded on this deferred tax asset as of December 31, 2020 for the amount not supported by reversing taxable temporary differences.
The Company has not recorded any deferred tax liabilities for undistributed earnings of controlled foreign corporations, primarily consisting of the Company’s Puerto Rican operations. The Company’s intent is to only make distributions from non-U.S. subsidiaries in the future when distributions can be made at no net tax cost; any remaining cash will be reinvested to grow operations in such subsidiaries. The Company has no material unremitted earnings from its non-U.S. subsidiaries.
On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act, which includes various income and payroll tax provisions, was signed into law by the U.S. government. In addition, various other coronavirus tax relief initiatives have been implemented around the world. This tax legislation did not have a material impact on the Company’s financial position, results of operations or cash flows for the year ended December 31, 2020.
Foreign Jurisdictions
NFI’s foreign subsidiaries file income tax returns in certain foreign jurisdictions. As of December 31, 2020, NFI’s foreign subsidiaries have approximately $86,176 of net operating loss carry forwards. Net operating losses of $64,819 incurred in Jamaica are generally allowed to be carried forward indefinitely. Net operating loss carryforwards of $11,830 incurred in Puerto Rico and Mexico will expire, if unused, between 2028 and 2029. Net operating loss carryforwards of $8,865 incurred in Ireland are generally allowed to be carried forward indefinitely.
The Company commenced operations in Puerto Rico during the year ended December 31, 2020 giving rise to cumulative profits, and the valuation allowance against a portion of the net deferred tax asset has been released. The Company recorded a valuation allowance against othercertain foreign deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized.realized, generally based on cumulative losses in certain development stage jurisdictions.
The following table summarizes the changes in the Company’s unrecognized tax benefits for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 |
| Balance at the beginning of the period | $ | — | | | $ | 12,474 | |
| Reduction as a result of Energos Formation Transaction | — | | | (12,474) | |
| Balance at the end of the period | $ | — | | | $ | — | |
Income Tax Examinations
The Company and its subsidiaries file income tax returns in the U.S. federal and various state and local jurisdictions, as well as various foreign jurisdictions. The Company filed its first corporate U.S. federal and state income tax returns for the period ended December 31, 2019. The U.S. Federal and state income tax returns filed for tax years 2020, 2021 and 2022 are open for examination. The Company is generally open to tax examinations in other foreign jurisdictions for a period of four to six years from the filing of the income tax return.
Undistributed Earnings
The Company has not recorded a deferred tax liability for undistributed earnings for any controlled foreign corporation as of December 31, 2023. The Company has unremitted earnings in certain jurisdictions where distributions can be made at no net tax cost. From time to time, the Company may remit these earnings. The Company has the ability and intent to indefinitely reinvest any earnings that cannot be remitted at no net tax cost. It is not practicable to estimate the amount of any additional taxes which may be payable on these undistributed earnings.
Preferential Tax Rates
The Company has subsidiaries incorporated in Bermuda. Under current Bermuda law, the Company is not required to pay taxes in Bermuda on either income or capital gains. The Company has received an undertaking from the Bermuda government that, in the event of income or capital gain taxes being imposed, it will be exempted from such taxes until 2035.
On December 27, 2023, Bermuda enacted the Bermuda Corporate Income Tax Act 2023, which institutes a corporate income tax rate of 15% effective for tax years beginning January 1, 2025. As a result, such tax exemptions will not be valid beyond such subsidiaries' taxable year ending December 31, 2024, the impact of which has been included in the tax provision and was not material.
17. | 22. Commitments and contingencies |
In conjunction with its principal business activities, the Company enters into various firm commitments for the purchase, production, and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop the Company’s terminals and related infrastructure. The estimated future cash payments related to outstanding contractual commitments, at market prices as of December 31, 2020, is summarized as follows:
| | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | _2024+ | |
| Purchase obligations | | $ | 376,097 | | | $ | 362,294 | | | $ | 362,294 | | | $ | 362,311 | | | $ | 1,027,352 | |
The future cash payments summarized above represent the Company’s minimum firm purchase commitments as of December 31, 2020.
In 2020, the Company entered into 4 LNG supply agreements for the purchase of 415 TBtu of LNG between 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract entered into in December 2018.
The Company has a contractual purchase commitment for feedgas with a remaining term of approximately five years. This commitment is designed to assure sources of supply and is not expected to be in excess of normal requirements. For agreements for supply where there is an active market, such agreements qualify for and the Company has elected the normal purchase exception under the derivatives guidance; therefore, the purchases under these contracts are included in Inventory and Cost of sales as incurred.
The Company’s lease obligations are discussed in Note 5. Leases.
Contingencies
The Company may be subject to certain legal and regulatory 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.
| | December 31, 2020 | | | December 31, 2019 | |
| Numerator: | | | | | | |
| Net loss | | $ | (263,965 | ) | | $ | (204,319 | ) |
| Less: net loss attributable to non-controlling interests | | | 81,818 | | | | 170,510 | |
| Net loss attributable to Class A common stock | | $ | (182,147 | ) | | $ | (33,809 | ) |
| Denominator: | | | | | | | | |
| Weighted-average shares-basic and diluted | | | 106,654,918 | | | | 20,862,555 | |
| | | | | | | | | |
| Net loss per share - basic and diluted | | $ | (1.71 | ) | | $ | (1.62 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| Basic | | | | | |
| Numerator: | | | | | |
| Net income | $ | 548,876 | | | $ | 184,786 | | | $ | 92,711 | |
| Net income (loss) attributable to non-controlling interests | (994) | | | 9,693 | | | 4,393 | |
| Net income attributable to Class A common stock | $ | 547,882 | | | $ | 194,479 | | | $ | 97,104 | |
| | | | | |
| Denominator: | | | | | |
| Weighted-average shares - basic | 205,942,837 | | | 209,501,298 | | | 198,593,042 | |
| Net income per share - basic | $ | 2.66 | | | $ | 0.93 | | | $ | 0.49 | |
| | | | | |
| Diluted | | | | | |
| Numerator: | | | | | |
| Net income | $ | 548,876 | | | $ | 184,786 | | | $ | 92,711 | |
| Net income (loss) attributable to non-controlling interests | (994) | | | 9,693 | | | 4,393 | |
| Adjustments attributable to dilutive securities | (736) | | | — | | | (2,861) | |
| Net income attributable to Class A common stock | $ | 547,146 | | | $ | 194,479 | | | $ | 94,243 | |
| | | | | |
| Denominator: | | | | | |
| Weighted-average shares - diluted | 206,481,977 | | | 209,854,413 | | | 201,703,176 | |
| Net income per share - diluted | $ | 2.65 | | | $ | 0.93 | | | $ | 0.47 | |
In connection with the closingTable of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares. The weighted average shares outstanding for the year ended December 31, 2020 are significantly lower than the Class A common stock outstanding on December 31, 2020 due to the timing of the Exchange Transactions.Contents
The following table presents potentially dilutive securities excluded from the computation of diluted net lossincome per share for the periods presentedyears ended December 31, 2023, 2022 and 2021 because its effects would have been anti-dilutive.
| | | December 31, 2020 | | | December 31, 2019 | |
| Unvested RSUs1 | | | 1,538,060 | | | | 3,137,415 | |
| Class B shares2 | | | 0 | | | | 144,342,572 | |
| Shannon Equity Agreement shares3 | | | 428,275 | | | | 1,083,995 | |
| Total | | | 1,966,335 | | | | 148,563,982 | |
1 | Represents the number of instruments outstanding at the end of the period. |
2 | Class B shares at the end of the period are considered potentially dilutive Class A shares. |
3 | Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement. |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
| | | | | |
Equity agreement shares(1) | — | | | 458,696 | | | — | |
| Total | — | | | 458,696 | | | — | |
19. | The Company declared and paid quarterly dividends totaling $81,976 during the year ended December 31, 2023, representing $0.10 per Class A share. Additionally, on December 12, 2022, the Company’s Board of Directors approved an update to its dividend policy and declared a dividend of $626,310, representing $3.00 per Class A share, which was paid in January 2023. During the year ended December 31, 2023, the Company paid dividends of $12,076 to holders of 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 the Company’s consolidated subsidiaries, the value of the Series A Preferred Units is recognized as non-controlling interest in the consolidated financial statements. 24. Share-based compensation |
RSUs
The Company has granted RSUsPerformance Share Units ("PSUs") to select officers,certain employees non-employee members of the board of directors and select non-employees that contain a performance condition under the Incentive Plan. The fair value of RSUs on the grant dateVesting 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 year ended December 31, 2020:
| | | Restricted Share Units | | | Weighted-average grant date fair value per share | |
| Non-vested RSUs as of December 31, 2019 | | | 3,137,415 | | | $ | 13.44 | |
| Granted | | | 109,409 | | | | 14.47 | |
| Vested | | | (1,507,633 | ) | | | 13.47 | |
| Forfeited | | | (201,131 | ) | | | 13.51 | |
| Non-vested RSUs as of December 31, 2020 | | | 1,538,060 | | | $ | 13.49 | |
The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the year ended December 31, 2020 and 2019:
| | Year Ended December 31, | |
| | | 2020 | | | 2019 | |
| Operations and maintenance | | $ | 800 | | | $ | 853 | |
| Selling, general and administrative | | | 7,943 | | | | 40,594 | |
| Total share-based compensation expense | | $ | 8,743 | | | $ | 41,447 | |
For the years ended December 31, 2020 and 2019, cumulative compensation expense recognized for forfeited RSU awards of $914 and $2,248, respectively, was reversed. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized.
As of December 31, 2020, the Company had 1,538,060 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $8,211. The non-vested RSUs will vest over a period from ten months to three years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 1.03 years as of December 31, 2020.
Performance Share Units (“PSUs”)
During the first quarter of 2020, the Company granted 1,109,777 PSUs to certain employees and non-employees. The PSUs contain a performance condition, and vesting will be determined based on achievement of a performance metric for the year ended December 31, 2021. Thesubsequent to the grant, and the number of shares that will vest can range from 0zero to 2,219,554. For the year ended a multiple of units granted. As of December 31, 2020,2023, the Company determined that it was not probable that the performance condition required for anythe PSUs granted in the fourth quarter of the PSUs2022 to vest would be achieved, and as such, no compensation expense has beenwas recognized for this award. During the fourth quarter of 2022, the Company determined that the PSUs granted in the first quarter of 2021 will vest at a multiple of two, resulting in vesting of 681,204 PSUs. Compensation cost for the service period since the grant date of $27,705 was recognized in the consolidated statements of operations and comprehensive loss. Unrecognized compensation costs if the maximum amount of shares were to vest based on the achievement of the performance condition was $30,864, and the weighted-average remaining vesting period of non-vested PSUs was one year as of December 31, 2020.
2022.
20. | Stockholder’s equity and Members’ equity |
New Fortress Energy Holdings
In January 2018, the Company issued 665,843 common shares (0 par value) to members of New Fortress Energy Holdings for $20,150 in proceeds.
New Fortress Energy LLC, New Fortress Energy Inc.
During the year ended December 31, 2019, the Company issued 2,716,252 shares of Class A shares in exchange for Class B shares, and 53,572 Class A shares were issued for vested RSUs.
As a result of the Exchange Transactions, 144,342,572 Class A shares were issued in exchange for all outstanding Class B shares. As a result of the Conversion, all outstanding Class A shares were converted to Class A common stock. In December 2020, NFE issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs.
The Company declared dividends of $0.10 per share in August and October 2020, totaling $33,742 in dividend payments during the year ended December 31, 2020.
21. | 25. 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, has historically chargedcharges the Company for administrative and general expenses incurred pursuant to its Management Services Agreement (“Management Agreement”). Upon completion of the IPO, the Management Agreement was terminated and replaced by an Administrative Services Agreement (“Administrative Agreement”) to charge the Company for similar administrative and general expenses.. The charges under the Management Agreement and Administrative Agreement that are attributable to the Company totaled $7,291, $7,942$5,845, $5,087 and $5,741 $6,509 for the years ended December 31, 2020, 20192023, 2022 and 2018,2021, respectively. Costs associated with the Management Agreement and Administrative Agreement are included within Selling, general and administrative in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss.Comprehensive Income. As of December 31, 20202023 and 2019, $5,5352022, $5,691 and $5,083$4,629 were due to Fortress, respectively.
In addition to management and administrative services, an affiliate of Fortressentity beneficially owned by Mr. Edens, owns and leases an aircraft that is periodically chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator market rates, charter costs of $2,483 $2,784, $3,714 and $5,367$4,466 for the years ended December 31, 20202023, 2022 and 2019,2021, respectively. In 2018, such charges were incurred under the Management Agreement, and amounts incurredAs of $1,873 for the year ended December 31, 2018 are included in the activity2023 and balances disclosed above. As of December 31, 20202022, $1,095 and 2019, $472 and $4,286$416 was due to this affiliate, respectively.
Fortress affiliated entities
The Company provides certain administrative services to related parties including entities affiliated with Fortress. No costs are incurred for such administrative services by the Company as the Company is fully reimbursed for all costs incurred. The Company has subleased a portion of office space to affiliates of an entities managed by Fortress, and for the years ended December 31, 2023, 2022 and 2021, rent and office related expenses of $913, $857 and $799 were incurred by these affiliates, respectively. As of December 31, 2023 and 2022, $1,547 and $700 were due from affiliates, 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 $2,702, $2,453 and $2,444 for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023 and 2022, $2,702 and $2,455 were due to Fortress affiliated entities, respectively.
Land and office lease
leases
The Company has leased land and office space from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. In April 2019, FECI sold the office building to a non-affiliate, and as such, the lease of the office space is no longer held with a related party. The Company recognized expense related to the land lease still held by a related party of $730, $396$505, $506 and $260$526 during the years ended December 31, 2020, 20192023, 2022 and 2018,2021, respectively, which was included within Operations and maintenance in the consolidated statementsConsolidated Statements of operationsOperations and comprehensive loss. Comprehensive Income. The expense for the period that the building was owned by a related party during the year ended December 31, 2019 totaled $609, of which $386 was capitalized to Construction in progress and $223 was included in Selling, general and administrative in the consolidated statements of operations and comprehensive loss; 0 expense for the office space was incurred prior to 2019. As of December 31, 2020 and 2019, $316 and $0 wasCompany has amounts due to FECI of $92 and $0 as of December 31, 2023 and 2022, respectively. As of December 31, 2020,2023 and 2022, the Company has recorded a lease liability of $3,279$3,368 and $3,340, respectively, within Non-current lease liabilities on the consolidated balance sheet.Consolidated Balance Sheets.
DevTech Investment
In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest iswas reflected as non-controlling interest in the Company’s consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. As of December 31, 2020The Company recognized approximately $424, $408 and 2019, $715$176 in expense within Selling, general and $815 was owed to DevTech on the note payable, respectively. The outstanding note payable due to DevTech is included in Other long-term liabilities on the consolidated balance sheets. The interest expense on the note payable due to DevTech was $77, $94 and $18administrative for the years ended December 31, 2020, 20192023, 2022 and 20182021, respectively.No interest has been paid, and accrued interest has been recognized within Accrued expenses on the consolidated balance sheets. As of December 31, 20202023 and 2019, $3432022, $106 and $443 was$80 were due fromto DevTech, respectively.
Fortress affiliated entities
SincePT Pesona, an Indonesian company, owns 51% of the issued share capital in the Company’s former subsidiary, PTGI, the owner and operator of 2017NR Satu, and prior to completion of the Energos Formation Transaction, provided agency and local representation services for the Company has providedwith respect to NR Satu. PT Pesona and certain administrative services to related parties including Fortress affiliated entities. As of December 31, 2020 and 2019, $1,334 and $1,134 were due from affiliates, respectively. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred.
Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative servicesits subsidiaries also charged vessel management fees to the Company as well as providing office space under a month-to-month non-exclusive license agreement. The Companyfor the provision of technical and commercial management of the vessels; total expenses incurred rentto PT Pesona prior to the completion of the Energos Formation Transaction were $537 and administrative expenses of approximately $2,357, $811 and $903$434 for the years ended December 31, 2020, 20192022 and 2021, respectively.2018, respectively. Additionally,
Hilli guarantees
As part of the GMLP Merger, the Company subleasesagreed to assume a portionguarantee (the “Partnership Guarantee”) of office space50% of the outstanding principal and interest amounts payable by Golar Hilli Corporation, a direct subsidiary of Hilli LLC, under a financing agreement. 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 tolling agreement with its customer. Under the LOC Guarantee, the Company was severally liable for any outstanding amounts that are payable, up to an affiliate of an entity managed by Fortress, and for the year ended December 31, 2020, $204 of rent and office related expenses were incurred by this affiliate. As of December 31, 2020 and 2019, $2,657 and $883 were due to Fortress affiliated entities, respectively.approximately $19,000.
Due to/from Affiliates
The table below summarizes the balances outstanding with affiliates asAs of December 31, 20202022, the amount the Company had guaranteed under the Partnership Guarantee and 2019:the LOC Guarantee was $323,250 and the fair value of debt guarantee after amortization of $2,320 was presented within Other current liabilities. In conjunction with the Hilli Exchange, the Company is no longer a guarantor under these arrangements, and the remaining guarantee liability of $2,286 was derecognized as a reduction to Selling, general and administrative in the Consolidated Statements of Operations and Comprehensive Income.
| | | December 31,
2020 | | | December 31,
2019 | |
| Amounts due to affiliates | | $ | 8,980 | | | $ | 10,252 | |
| Amounts due from affiliates | | | 1,881 | | | | 1,577 | |
22. | 26. Customer concentrations |
For the year ended December 31, 2020,2023, revenue from 3two significant customers constituted 88%47% of the total revenue and 83%revenue; no other customers comprised more than 10% of trade receivables.our revenue. For the year ended December 31, 2019,2022, revenue from 2two significant customers constituted 74%42% of the total revenue and 85% of trade receivables, and forrevenue. For the year ended December 31, 2018, 12021, revenue from three significant customer
customers constituted 87%48% of the total revenue. Prior to the adoption of ASC 842, the Company recognized a direct financing leases withinThese customers’ revenues are included in the Company’s agreement with this customer. As of December 31, 2019, 99% of the Finance leases, net balance was attributed to this significant customer.
During the years ended December 31, 2020, 20192023, 2022 and 2018,2021, revenue from external customers that were derived from customers located in the United States were $135,702, $21,386$1,060,678, $246,628 and $7,214,$203,477, respectively, and from customers outside of the United States were $315,948, $167,739$1,352,618, $2,121,644, and $105,087, respectively, primarily derived from customers in the Caribbean.$1,119,333, respectively. The Company attributes revenue from external customers to the country in which the party to the applicable agreement has its principal place of business.
As of December 31, 20202023 and 2019,2022, long lived assets, which are all non-current assets excluding investment in equity securities, restricted cash, deferred tax assets, andgoodwill, intangible assets and assets held for sale located in the United States were $442,199$1,744,591 and $360,860$1,695,604, respectively, and long lived assets located outside of the United States were $639,370$6,938,199 and $470,749,$3,809,080, respectively, primarily located in Brazil and the Caribbean.
23. | Unaudited quarterly financial data |
Summarized quarterly•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. Vessels that are utilized in the Company’s terminal or logistics operations are included in this segment.
Terminals and Infrastructure Operating Margin included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% investment in CELSEPAR; the Company disposed of this investment in the fourth quarter of 2022.
Terminal and Infrastructure segment includes realized gains and losses from the settlement of derivative transactions entered into as economic hedges to reduce market risks associated with commodity prices.
•Ships includes vessels that are leased to customers under long-term arrangements, and as of December 31, 2023, four vessels are included in this segment. The Company’s investment in Energos is also included in the Ships segment.
Ships Operating Margin included our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC prior to the disposition of this investment in first quarter of 2023.
The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial datainstruments recognized at fair value.
Management considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance.
The table below presents segment information for the years ended December 31, 20202023, 2022 and 20192021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| (in thousands of $) | | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Statement of operations: | | | | | | | | | | |
| Total revenues | | $ | 2,141,085 | | | $ | 293,605 | | | $ | 2,434,690 | | | $ | (21,394) | | | $ | 2,413,296 | |
Cost of sales (1) (3) | | 764,828 | | | — | | | 764,828 | | | 112,623 | | | 877,451 | |
| Vessel operating expenses | | — | | | 51,387 | | | 51,387 | | | (5,948) | | | 45,439 | |
| Operations and maintenance | | 166,785 | | | — | | | 166,785 | | | — | | | 166,785 | |
| Segment Operating Margin | | $ | 1,209,472 | | | $ | 242,218 | | | $ | 1,451,690 | | | $ | (128,069) | | | $ | 1,323,621 | |
| Balance sheet: | | | | | | | | | | |
| Total assets | | $ | 9,680,917 | | | $ | 820,328 | | | $ | 10,501,245 | | | $ | — | | | $ | 10,501,245 | |
| Other segmental financial information: | | | | | | | | | | |
Capital expenditures(2) | | $ | 3,461,659 | | | $ | 7,568 | | | $ | 3,469,227 | | | $ | — | | | $ | 3,469,227 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| (in thousands of $) | | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Statement of operations: | | | | | | | | | | |
| Total revenues | | $ | 2,168,565 | | | $ | 444,616 | | | $ | 2,613,181 | | | $ | (244,909) | | | $ | 2,368,272 | |
Cost of sales (1) (3) | | 1,142,374 | | | — | | | 1,142,374 | | | (131,946) | | | 1,010,428 | |
| Vessel operating expenses | | — | | | 90,544 | | | 90,544 | | | (27,026) | | | 63,518 | |
| Operations and maintenance | | 129,970 | | | — | | | 129,970 | | | (24,170) | | | 105,800 | |
| Segment Operating Margin | | $ | 896,221 | | | $ | 354,072 | | | $ | 1,250,293 | | | $ | (61,767) | | | $ | 1,188,526 | |
| Balance sheet: | | | | | | | | | | |
| Total assets | | $ | 5,913,775 | | | $ | 1,791,307 | | | $ | 7,705,082 | | | $ | — | | | $ | 7,705,082 | |
| Other segmental financial information: | | | | | | | | | | |
Capital expenditures(2) | | $ | 1,482,871 | | | $ | 27,127 | | | $ | 1,509,998 | | | $ | — | | | $ | 1,509,998 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 |
| (in thousands of $) | | Terminals and
Infrastructure | | Ships | | Total Segment | | Consolidation and Other(4) | | Consolidated |
| Statement of operations: | | | | | | | | | | |
| Total revenues | | $ | 1,366,142 | | | $ | 329,608 | | | $ | 1,695,750 | | | $ | (372,940) | | | $ | 1,322,810 | |
Cost of sales (1) (3) | | 789,069 | | | — | | | 789,069 | | | (173,059) | | | 616,010 | |
| Vessel operating expenses | | 3,442 | | | 64,385 | | | 67,827 | | | (16,150) | | | 51,677 | |
| Operations and maintenance | | 92,424 | | | — | | | 92,424 | | | (19,108) | | | 73,316 | |
| Segment Operating Margin | | $ | 481,207 | | | $ | 265,223 | | | $ | 746,430 | | | $ | (164,623) | | | $ | 581,807 | |
| Other segmental financial information: | | | | | | | | | | |
Capital expenditures(2) | | $ | 833,910 | | | $ | 8,293 | | | $ | 842,203 | | | $ | — | | | $ | 842,203 | |
(1)Cost of sales in the Company’s segment measure only includes realized gains and losses on derivative transactions that are as follows:an economic hedge of commodity purchases and sales, and realized gains of $139,089 for the year ended
F-53
| (in thousands of U.S. dollars, except per share data) | |
| | | Three Months Ended | |
| | | March 31, 2020 (1) | | | June 30, 2020 (1, 2) | | | September 30, 2020 | | | December 31, 2020 | |
| | | | | | | | | | | | | |
| Revenues | | $ | 74,530 | | | $ | 94,566 | | | $ | 136,858 | | | $ | 145,696 | |
| Operating loss | | | (36,169 | ) | | | (148,273 | ) | | | 11,053 | | | | 18,031 | |
| Net loss | | | (60,223 | ) | | | (166,587 | ) | | | (36,670 | ) | | | (485 | ) |
| Net (loss) income attributable to stockholders | | | (8,466 | ) | | | (137,493 | ) | | | (36,358 | ) | | | 170 | |
| Basic and diluted (loss) income per share (3) | | | (0.32 | ) | | | (2.40 | ) | | | (0.21 | ) | | | 0.00 | |
| | | Three Months Ended | |
| | | March 31, 2019 | | | June 30, 2019 | | | September 30, 2019 | | | December 31, 2019 | |
| | | | | | | | | | | | | |
| Revenues | | $ | 29,951 | | | $ | 39,766 | | | $ | 49,656 | | | $ | 69,752 | |
| Operating loss | | | (59,337 | ) | | | (43,959 | ) | | | (47,726 | ) | | | (36,253 | ) |
| Net loss | | | (60,292 | ) | | | (51,233 | ) | | | (54,424 | ) | | | (38,370 | ) |
| Net loss attributable to stockholders | | | (13,557 | ) | | | (6,186 | ) | | | (6,723 | ) | | | (7,343 | ) |
| Basic and diluted loss per share (3) | | | (0.96 | ) | | | (0.28 | ) | | | (0.30 | ) | | | (0.30 | ) |
(1) | Operating loss, net loss and net loss attributable to stockholders for the Table of Contentsthree months ended March 31, 2020 and June 30, 2020 reflect the adoption of ASC 326. The Company adopted ASC 326 in the third quarter of 2020 with an effective date of January 1, 2020, due to the loss of EGC status in that quarter. |
(2) | Operating loss, net loss and net loss attributable to stockholders for the three months ended June 30, 2020 includes a termination charge of $105,000 associated with an agreement with one of the Company’s LNG suppliers to terminate the obligation to purchase any LNG from this supplier for the remainder of 2020. |
(3) | Basic and diluted earnings per share are computed independently for each of the quarters presented. Therefore, the sum of quarterly basic and diluted per share information may not equal annual basic and diluted earnings per share. |
On January 13, 2021, NFE, Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”), Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), and Lobos Acquisition Ltd., a Bermuda exempted company and an indirect, wholly-owned subsidiary of NFE (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo MergerDecember 31, 2023 were recognized as a wholly owned subsidiaryreduction to Cost of NFE. Assales in the segment measure. No realized gains or loss for the years ended December 31, 2022 or 2021 were recognized.
The Company recognized unrealized (losses) and earnings of ($106,393), $106,103 and ($2,788) on the mark-to-market value of derivative transactions for the years ended December 31, 2023, 2022 and 2021, respectively, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive Income.
The Company has excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6,232 for the year ended December 31, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive Income. The Company did not incur such costs in the years ended December 31, 2022 and 2021.
(2)Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period.
(3)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive Income.
(4)Consolidation and Other adjusts for the inclusion of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 pereffective share of Hygo,revenues, expenses and Stonepeak owned alloperating margin attributable to the Company's 50% ownership of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.
On January 13, 2021, NFE entered into an Agreement and Plan of Merger (the “GMLP Merger Agreement”) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability companyCELSEPAR and the general partnercommon units of GMLP (the “General Partner”), Lobos AcquisitionHilli LLC a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporated underin the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP surviving the merger as an indirect subsidiary of NFE (the “GMLP Merger”).
At the effective time of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediatelysegment measure prior to the GMLP Effective Time will automatically be converteddisposition of these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments, and the exclusion of non-capitalizable contract acquisition costs.
Consolidated Segment Operating Margin is defined as net income, adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, asset impairment expense, interest expense, other (income) expense, net, loss on extinguishment of debt, net, tax provision (benefit) and income from equity method investments.
The following table reconciles Net income, the most comparable financial statement measure, to Consolidated Segment Operating Margin:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (in thousands of $) | | 2023 | | 2022 | | 2021 |
| Net income | | $ | 548,876 | | | $ | 184,786 | | | $ | 92,711 | |
| Add: | | | | | | |
| Selling, general and administrative | | 205,104 | | | 236,051 | | | 199,881 | |
| Transaction and integration costs | | 6,946 | | | 21,796 | | | 44,671 | |
| Depreciation and amortization | | 187,324 | | | 142,640 | | | 98,377 | |
| Interest expense | | 277,842 | | | 236,861 | | | 154,324 | |
| Other (income) expense, net | | 10,408 | | | (48,044) | | | (17,150) | |
| Gain on sale of assets, net | | (29,378) | | | — | | | — | |
| Tax (benefit) provision | | 115,513 | | | (123,439) | | | 12,461 | |
| Asset impairment expense | | 10,958 | | | 50,659 | | | — | |
| Loss on extinguishment of debt, net | | — | | | 14,997 | | | 10,975 | |
| Loss (income) from equity method investments | | (9,972) | | | 472,219 | | | (14,443) | |
| Consolidated Segment Operating Margin | | $ | 1,323,621 | | | $ | 1,188,526 | | | $ | 581,807 | |
28. Subsequent events
On February 28, 2024, we entered into a commitment letter for the rightCompany to receive $3.55$700 million in cash. Atfinancing secured by our onshore FLNG project in Altamira, Mexico as well as the GMLP Effective Time, each ofcollateral securing the incentive distribution rights of GMLP will be canceled2025 Notes and cease to exist, and no consideration shall be delivered in respect thereof. Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof. Each outstanding unit representing a general partner interest of GMLP that2026 Notes. The commitment letter is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time.
Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP.
The GMLP Merger Agreement may be terminated by NFE or GMLP (which, in the case of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021, and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million.
We have obtained debt financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA for loans in an aggregate principal amount of $1.7 billion, consisting of a $1.5 billion senior secured bridge facility (the “Bridge Loan”) and a $200 million senior secured revolving facility to pay, subject to the termsfinalization of a credit agreement and conditions set forth therein, a portion of the cash purchase pricecustomary closing conditions. The proceeds will be used to complete our onshore FLNG project in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If NFE utilizes the Bridge Loan, the facility will bear a fixed interest rate of 6.25%, subject to a step-up of 50 basis points every three months. The Bridge Loan has a one-year term, is pre-payable without penalty and will automatically be converted into a seven-year term loan if it is not repaid in full at maturity. The senior secured revolving facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.
Suape Development
On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal at the Port of Suape, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecem Energia S.A. (“Pecem”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold certain 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. We will seek to obtain the necessary approvals to transfer the power purchase agreements to the Port of Suape and plan to construct a gas-fired power plant and LNG import terminal at the Port of Suape. The Company paid approximately $9 million at closing in total and will make additional payments to the sellers based on certain contingent considerations.
Schedule II
| Description | | Balance at Beginning of Year | | | Additions(1) | | | Deductions | | | Balance at End of Year | |
| | | | | | | | | | | | | |
| Year ended December 31, 2020 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Allowance for doubtful accounts | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Allowance for expected credit losses | | | 0 | | | | 316 | | | | 0 | | | | 316 | |
| Total allowance | | | 0 | | | | 316 | | | | 0 | | | | 316 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2019 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 257 | | | | 0 | | | | (257 | ) | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2018 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 0 | | | | 257 | | | | 0 | | | | 257 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Description | Balance at
Beginning of Year | | Additions(1) | | Deductions | | Balance at
End of Year |
| | | | | | | |
| Year ended December 31, 2023 | | | | | | | |
| | | | | | | |
| Allowance for expected credit losses | $ | 1,526 | | | $ | — | | | $ | (42) | | | $ | 1,484 | |
| | | | | | | |
| Year ended December 31, 2022 | | | | | | | |
| | | | | | | |
| Allowance for expected credit losses | 2,159 | | | 835 | | | (1,468) | | | 1,526 | |
| | | | | | | |
| Year ended December 31, 2021 | | | | | | | |
| | | | | | | |
| Allowance for expected credit losses | 545 | | | 1,614 | | | — | | | 2,159 | |
NoteNotes:
(1) | Amount expensed in included within Selling, general and administrative. |
