New Fortress Energy Inc. - Annual Report: 2022 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the year ended December 31, 2022
OR
| 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)
| Delaware | 83-1482060 | ||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||
111 W. 19th Street, 8th Floor New York, NY | 10011 | ||||
| (Address of principal executive offices) | (Zip Code) | ||||
Registrant’s telephone number, including area code: (516) 268-7400
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered on which registered | ||||||
| Class A common stock | NFE | Nasdaq 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer 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) of the Sarbanes-Oxley Act (15 U.S.C. 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 any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). 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, 2022 (the last business day of the registrant’s most recently completed second fiscal quarter), based on the closing price of the Class A shares on the Nasdaq Global Select Market, was $3,928.7 million.
At February 24, 2023, the registrant had 208,770,088 shares of Class A common stock outstanding.
Documents Incorporated by Reference:
Portions of the registrant’s definitive proxy statement for the registrant’s 2023 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.
Table of Contents
GLOSSARY OF TERMS
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:
| ADO | automotive diesel oil | ||||
| Bcf/yr | billion cubic feet per year | ||||
| Btu | the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute pressure of 14.696 pounds per square inch gage | ||||
| CAA | Clean Air Act | ||||
| CERCLA | Comprehensive Environmental Response, Compensation and Liability Act | ||||
| CWA | Clean Water Act | ||||
| DOE | U.S. Department of Energy | ||||
| DOT | U.S. Department of Transportation | ||||
| EPA | U.S. Environmental Protection Agency | ||||
| FTA countries | countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas | ||||
| GAAP | generally accepted accounting principles in the United States | ||||
| GHG | greenhouse gases | ||||
| GSA | gas sales agreement | ||||
| Henry Hub | a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange | ||||
| ISO container | International Organization of Standardization, an intermodal container | ||||
| LNG | natural gas in its liquid state at or below its boiling point at or near atmospheric pressure | ||||
| MMBtu | one million Btus, which corresponds to approximately 12.1 LNG gallons | ||||
| mtpa | metric tons per year | ||||
| MW | megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt. | ||||
| NGA | Natural Gas Act of 1938, as amended | ||||
| non-FTA countries | countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted | ||||
| OPA | Oil Pollution Act | ||||
| OUR | Office of Utilities Regulation (Jamaica) | ||||
| PHMSA | Pipeline and Hazardous Materials Safety Administration | ||||
| PPA | power purchase agreement | ||||
| SSA | steam supply agreement | ||||
| TBtu | one trillion Btus, which corresponds to approximately 12,100,000 LNG gallons | ||||
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CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K for the year ended December 31, 2022 (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;
•the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us
•construction and operational risks related to our facilities and assets, including cost overruns and delays;
•failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;
•complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;
•delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;
•failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;
•failure to maintain sufficient working capital for the development and operation of our business and assets;
•failure to convert our customer pipeline into actual sales;
•lack of asset, geographic or customer diversification, including loss of one or more of our customers;
•competition from third parties in our business;
•cyclical or other changes in the demand for and price of LNG and natural gas;
•inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;
•inability to successfully develop and implement our technological solutions;
•inability to service our debt and comply with our covenant restrictions;
•inability to obtain additional financing to effect our strategy;
•inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits;
•economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;
•weather events or other natural or manmade disasters or phenomena;
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•the extent of the global COVID-19 pandemic or any other major health and safety incident;
•increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;
•the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A shares; and
•other risks described in the “Risk Factors” section of this 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.
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PART I
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, prior to completion of Mergers (as defined herein), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries; and after completion of the Mergers, “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries.
Overview
We are a global energy infrastructure company founded to help address energy poverty and accelerate the world's transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail below under “Sustainability—Toward a Very-Low-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 by entering into long-term supply contracts, which are generally based on an index such as Henry Hub plus a fixed fee component. We acquire our LNG from third party suppliers in open market purchases and long term supply agreements; we also manufacture LNG at our liquefaction and storage facility in Miami, Florida (the “Miami Facility”). Beginning in 2023, we expect to deploy our first offshore liquefaction facility, "Fast LNG" or "FLNG," to provide a source of low-cost supply of LNG.
Shipping – We own or operate a fleet of seven regasification units (“FSRUs”) and eleven liquefied natural gas carriers (“LNGCs”) and floating storage units (“FSUs”). Ten vessels are owned by our joint venture affiliate, Energos, and two are owned by NFE, We also charter vessels to and from third parties as well as from Energos.
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.
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 hydrogen project.
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. Historically, natural gas procurement or liquefaction, transportation, regasification and power generation projects have been developed separately and have required multilateral or traditional financing sources, which has inhibited the introduction 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 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”),
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•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 landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”),
•our LNG receiving facility in La Paz, Mexico (the “La Paz Facility”), and
•at our Miami Facility.
In addition, we are currently developing facilities in Brazil, Nicaragua, Ireland and 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 that we will be able to achieve our target pricing or margins.
Our Facilities
We look to build facilities in locations where the need for LNG is significant. We design and construct LNG and power facilities to meet the supply and demand specifications of our current and potential future customers in the 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. We then seek to convert and supply natural gas to additional power customers. Finally, our goal is to expand within the market by supplying 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 four operational LNG terminal facilities and four under active development, as well as one operational power plant facilities and four under active development, as described below. Our LNG facilities currently operating or under development are expected to be capable of receiving up to 800,000 MMBtu from LNG per day depending upon the needs of our customers and potential demand in the region.
Set forth below is additional detail regarding each 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 61,000 MMBtu from LNG per day and features approximately 7,000 cubic meters of onsite storage. It supplies natural gas to the 145MW power plant (the “Bogue Power Plant”) operated by Jamaica Public Service Company Limited (“JPS”) pursuant to a long-term contract for natural gas equivalent to approximately 25,600 MMBtu from LNG per day. The Montego Bay Facility also supplies numerous on-island industrial users with natural gas or LNG pursuant to offtake contracts of various durations. We have total aggregate contracted volumes of approximately 29,000 MMBtu from LNG per day at our Montego Bay Facility with a weighted average remaining contract length of 17 years as of December 31, 2022. 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.
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 750,000 MMBtu from LNG per day. The Old Harbour Facility is supplying gas to a 190MW 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 30,000 MMBtu from LNG per day, and back-up ADO, for 20 years.
The Old Harbour Facility is also supplying gas to our 150MW dual-fired combined heat and power (“CHP”) facility in Clarendon, Jamaica (the “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 ADO as a backup fuel source. We have executed a suite of agreements in connection with the CHP Plant, including a 20-year agreement to supply steam to an alumina refinery joint venture between affiliates of Noble Group, 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 58,000 MMBtu from LNG per day at our Old Harbour Facility with a weighted average contract length of 17 years as of December 31, 2022. We have the ability to service other
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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.
San Juan, Puerto Rico – Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. In addition, it supplies natural gas to Units 5 and 6 of the San Juan combined cycle power plant (the “PREPA San Juan Power Plant”), which are owned and operated by the Puerto Rico Electric Power Authority (“PREPA”), a public instrumentality of the government of Puerto Rico. We converted Units 5 and 6, which together have a capacity of 440MW, to use natural gas as fuel and expect to supply both Units 5 and 6 with approximately 68,600 MMBtu from LNG per day.
La Paz, Baja California Sur, Mexico – Our La Paz Facility commenced operations in the second quarter of 2021. It is an LNG receiving facility located at the Port of Pichilingue in Baja California Sur, Mexico, receiving LNG via ISO containers on an offshore supply vehicle from a nearby vessel. The La Paz Facility is expected to supply approximately 22,300 MMBtu from LNG per day to our gas-fired modular power units located in La Paz (the “La Paz Power Plant”) for approximately 100MW of power following the start of operations. In addition, in March 2021, we entered into a gas sales agreement with CFEnergia ("CFE"), a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), Mexico’s power utility, for the supply of natural gas to power plants located at Punta Prieta and Coromuel in the State of 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. We expect to sell approximately 41,000 MMBtu from LNG per day under an amended gas sales agreement with CFE.
Puerto Sandino, Nicaragua – We are developing an offshore facility in Puerto Sandino, Nicaragua, consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines (the “Puerto Sandino Facility”). The Puerto Sandino Facility is expected to supply gas to our new approximately 300MW 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 57,500 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.
Barcarena, 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 up to 790,000 MMBtu from LNG per day and storing up to 170,000 cubic meters of LNG. We anticipate that the Barcarena Facility will be anchored by several large-scale industrial and power customer contracts, including gas supply to our new 605MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”). The power plant is supported by multiple 25-year power purchase agreements to supply electricity to the national electricity grid. The Barcarena Power Plant is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025.
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 by the end of 2023. We expect to complete the Barcarena Power Plant and to commence operations in 2025.
Santa Catarina, Brazil – Our facility in Santa Catarina, Brazil (the “Santa Catarina Facility” and, together with the Barcarena Facility, the "Brazil Facilities") will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtu from LNG per day and LNG storage capacity of up to 170,000 cubic meters. We are also developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 1,2 million MMBtu from LNG per day. We expect to complete our Santa Catarina Facility and commence operations in 2023.
Shannon, Ireland – We intend to develop and operate an LNG facility (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
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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”). We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland, and we have undertaken pre-development work that will allow us to complete the Ireland Facility in approximately 9 to 15 months after receiving requisite permits. We currently expect to begin operations in the first half of 2024.
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 2026; 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 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, that are expected to commence in 2026 and 2027. Finally, we plan to commence our Fast LNG production in 2023, when our first FLNG facility is expected to begin operation, and we plan to expand that capacity when additional units come online over the next two years.
The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production expected to commence in 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the 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.
Liquefaction Assets
We constructed the Miami Facility, which commenced full commercial operations in 2016, in fewer than 12 months, at a cost to build of approximately $70 million. The Miami Facility has one liquefaction train, with liquefaction production capacity of approximately 8,300 MMBtu from LNG per day and was 98% dispatchable during 2022. 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, 2022, we delivered approximately 8,200 MMBtu from LNG per day from the Miami Facility pursuant to long-term take-or-pay contracts.
Fast LNG (FLNG)
We are currently developing multiple modular floating liquefaction facilities to provide a source of low-cost supply of LNG. We have designed and are constructing offshore liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. The “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than land-based alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.
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 each solution offshore will provide 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 units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore projects. In partnership with Kiewit, we believe
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we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. We expect to deploy our first Fast LNG unit in the first half of 2023.
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 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. LNG carriers 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 Infrastructure (“Energos”), a joint venture we formed in 2022 and describe in more detail below, we plan to 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.
On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), completed a sales and financing transaction regarding the substantial majority of our Shipping Assets. This sales and financing transaction was comprised of the formation of Energos and the sale or contribution of eleven vessels, including six FSRUs, three FSUs and two LNGCs (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, with the remaining interest owned by the Purchaser.
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 20-year terms expiring between December 2027 and August 2042.
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 | ||||||||||||
| Igloo | FSRU | 170,000 | Energos | Lease | The Netherlands | ||||||||||||
| Celsius | LNGC / FSU | 161,000 | Energos | Lease | Various | ||||||||||||
| Penguin | LNGC / FSU | 161,000 | Energos | Lease | Various | ||||||||||||
| Eskimo | FSRU | 161,000 | Energos | Lease | Kingdom of Jordan | ||||||||||||
| Maria | LNGC / FSU | 146,000 | Energos | Lease | Various | ||||||||||||
| Winter | FSRU | 138,000 | Energos | Lease | Brazil | ||||||||||||
| Methane Princess | LNGC / FSU | 138,000 | Energos | Lease | Various | ||||||||||||
| Mazo | LNGC / FSU | 137,000 | 60% NFE / 40% CPC | Owned | Various | ||||||||||||
| Spirit | FSRU | 129,000 | NFE | Owned | Various | ||||||||||||
| Nusantara Regas Satu | FSRU | 125,000 | Energos | Lease | Indonesia | ||||||||||||
Terminals and Infrastructure Segment:
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| Name | Type | Capacity (cubic meters of LNG) | Owner | Contract Type | Location | ||||||||||||
| Orion sea | LNGC / FSU | 174,000 | JP Morgan | Lease | Various | ||||||||||||
| Hoegh Gallant | FSRU | 170,000 | Hoegh LNG | Lease | Jamaica | ||||||||||||
| Grand | LNGC / FSU | 146,000 | Energos | Lease | Various | ||||||||||||
| Freeze | FSRU | 126,000 | Energos | Lease | Various | ||||||||||||
| CNTIC Vpower Global | LNGC / FSU | 28,000 | CNTIC Vpower Holdings | Lease | Various | ||||||||||||
| Coral Encanto | LNGC / FSU | 30,000 | Anthony Veder | Lease | Various | ||||||||||||
| Avenir Accolade | LNGC / FSU | 7,500 | Avenir | Lease | Various | ||||||||||||
| Coral Anthelia | LNGC / FSU | 6,500 | Anthony Veder | Lease | Various | ||||||||||||
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, 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-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.
Our customer concentration has continually improved. Revenue from two customers constituted 42% of total revenue in 2022. For the years ended December 31, 2021 and 2020, revenue from three significant customers constituted 48% and 88% of the total revenue, respectively.
We have several contracts with government-affiliated entities in the countries in which we operate. In Jamaica, we have gas sales agreements with JPS and SJPC, which have remaining terms of approximately 16 and 17 years, respectively, with mutual options to extend, subject to certain conditions. The Jamaica gas sales agreements represent approximately 50% of Jamaica’s installed power capacity and sales of approximately 79,000 MMBtu from LNG per day at full commercial operations. The aggregate minimum quantities we are required to deliver, and our counterparties are required to purchase, under the Jamaica gas sales agreements initially, total approximately 56,000 MMBtu per day. In Puerto Rico, we have entered into a fuel sale and purchase agreement with PREPA, pursuant to which we expect PREPA to purchase 68,600 MMBtu from LNG per day in connection with the operation of both Units 5 and 6 of the PREPA San Juan Power Plant. In Mexico, we have entered into a gas sales agreement with CFEnergia for the supply of natural gas to CFE Plants. We expect to sell approximately 20,300 MMBtu from LNG per day under the gas sales agreement. In Nicaragua, we have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, some of which are wholly or partially owned or controlled by governmental entities. In Brazil, we have entered into various power purchase agreements with local distribution companies, some of which are 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;
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•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.
In purchasing LNG, we 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 infrastructure 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 Department 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 Free 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. NFEnergía LLC must renew its authorization every two years. Imports of LNG are deemed to be consistent with the public interest under Section 3 of the Natural Gas Act (“NGA”) and applications for such imports must be granted without modification or delay.
FERC Authorization
The Federal Energy Regulatory Commission (“FERC”) regulates the siting, construction and operation of “LNG terminals” under NGA Section 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 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 within 180 days of the order, which was September 15, 2021, but also found that allowing
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operation of the San Juan Facility to continue during the pendency of an application is 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 filed an application for authorization to operate the San Juan Facility, which remains pending.
Pipeline and Hazardous Materials Safety Administration
Many LNG facilities are also subject to regulation by the 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 transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. 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. However, in November 2021, PHMSA issued a proposed rule to rescind the final rule authorizing nationwide transportation. Pursuant to a September 2022 Congressional Interest Status Report, DOT projects that PHMSA would finalize this proposed rule on March 13, 2023. If promulgated along these lines, this rule would suspend authorization of LNG transportation by rail pending completion of a rulemaking evaluating the Hazardous Materials Regulations at 49 C.F.R. Parts 171-180 or by June 30, 2024, whichever is earlier. DOT’s most recent statement contemplates issuing a Notice of Proposed Rulemaking for the rulemaking by March 20, 2023. We have the ability to transport LNG from our Pennsylvania Facility via truck, and this logistical solution is available to us should we be unable to transport by rail.
Environmental Regulation
Our 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 regasification of LNG as well as the generation and transmission of electricity in Mexico. Various federal agencies in Mexico regulate these activities, among others, including the Department of Environment and Natural Resources, Department of Infrastructure, Communication and Transportation, Energy Regulatory Commission, and the Agency for Safety, Energy & Environment, which issues permits for all activities associated with the use of 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
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Mexican law, the project must first complete environmental and social impact assessments according to the requirements of Mexican law. Each such impact assessment 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. This matter is currently under review by the Mexican Supreme Court.
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, 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
The operation of the facilities will be regulated via additional licenses and consents including from the Environmental Protection Agency (EPA); the Commission for Regulation of Utilities (CRU); the Health and Safety Authority (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 provisions of 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 may be subject to administrative or judicial challenges, including by non-governmental groups that act on behalf of citizens. We intend to begin construction of the Ireland Facility after we have obtained planning permission and secured contracts with downstream customers for volumes that are sufficient to support the 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, some other authorizations may be required by environmental authorities on a local (municipal), state and federal level, including permits to suppress vegetation, authorization for fauna management, permission to address and/or otherwise mitigate impacts on affected communities, and others.
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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 cargos 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 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 to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.]
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, from our Miami Facility, and when completed, our Fast LNG solutions and Pennsylvania Facility.
Seasonality
Our operations can be affected by seasonal weather, which can temporarily affect our revenues, the delivery of LNG and the construction of our 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 Facilities 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. Severe weather in the countries where our Facilities are located may delay completion of our Facilities under development and related infrastructure, adversely affect our operations of 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 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.
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Human Capital
We had 577 full-time employees as of December 31, 2022. We depend upon our skilled workforce to manage, operate and plan for our business. Recruitment and retention of talent across our Company enables growth and innovation across 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 is not binding or required.
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 Health, Safety, Security and Environment (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, 2022, 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, Houston, Texas, Rio de Janeiro, Brazil, 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, 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.
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Protect and Preserve the Environment
We 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 liquefied natural gas (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 complement 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 Foundation, we seek to strengthen our communities by (i) investing in education to help support the next generation of leaders; (ii) providing industry training programs to help create and sustain a well-equipped workforce; and (iii) giving financially to community causes that enhance quality of life, including reducing poverty, hunger, and inequities. In 2021, we provided more than 75 higher education scholarships, financial aid to more than 1,000 students, backpacks and supplies to 1,600 students, and supported academic opportunities of more than 5,000 students in the fields of science, technology, engineering and mathematics (STEM). We donated more than 100,000 trees in Jamaica and Africa, supporting more than 500 local farmers. For the holiday season in 2021, we provided approximately 3,700 children with new clothes and toys.
Toward a Very-Low-Carbon Future
As we work to reduce greenhouse gas (GHG) emissions for our customers around the world, our goals are to reach net zero carbon emissions by 2030 and be one of the world’s leading providers of very-low-carbon energy. We believe that natural gas remains a cost-effective and environmentally-friendly complement for intermittent renewable energy, aiding the growth of these technologies. Over time, we believe that hydrogen will play an increasingly significant role as a very-low-carbon fuel to support renewables and displace fossil fuels across power, transportation and industrial markets. To that end, we formed a division, which we call Zero, to evaluate promising technologies and pursue initiatives that will position us to capitalize on this emerging industry.
Available Information
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, 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.
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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.”.
Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to the completion of Mergers, New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries.
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 Our Business
•We have a limited operating history, which may not be sufficient to evaluate our business and prospects;
•Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors;
•We are subject to various construction risks;
•Operation of our infrastructure, facilities and vessels involves significant risks;
•We depend on third-party contractors, operators and suppliers;
•Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;
•We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation;
•Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction;
•When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project;
•Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations;
•Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements;
•Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects;
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•Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;
•We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate;
•Our contracts with our customers are subject to termination under certain circumstances;
•Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess;
•Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers;
•Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses;
•We are dependent on third-party LNG suppliers and may not be able to purchase or receive physical delivery of LNG or natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPAs and SSAs;
•We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve;
•Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all;
•We have incurred, and may in the future incur, a significant amount of debt;
•Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms;
•Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate;
•We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect;
Risks Related to the Jurisdictions in Which We Operate
•We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate;
•Our financial condition and operating results may be adversely affected by foreign exchange fluctuations;
Risks Related to Ownership of Our Class A Common Stock
•A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders;
•The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all;
General Risks
•We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest;
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•We may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;
•We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers; and
•A change in tax laws in any country in which we operate could adversely affect us.
Risks Related to Our Business
We have a limited operating history, which may not be sufficient to evaluate our business and prospects.
We have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the value of our Class A common stock. We commenced operations on February 25, 2014, and we had net losses of approximately $78.2 million in 2018, $204.3 million in 2019, and $264.0 million in 2020. We recognized income of $92.7 million in 2021 and $184.8 million in 2022. Our limited operating history also means that we continue to develop and implement our strategies, policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We cannot give you any assurance that our strategy will be successful or that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate.
Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors.
Our business strategy relies on a variety of factors, including our ability to successfully market LNG, natural gas, steam, and power to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the countries where we operate, and expand our projects and operations to other countries where we do not currently operate, among others. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control, including, among others:
•inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts;
•failure to develop strategic relationships;
•failure to obtain required governmental and regulatory approvals for the construction and operation of these projects and other relevant approvals;
•unfavorable laws and regulations, changes in laws or unfavorable interpretation or application of laws and regulations; and
•uncertainty regarding the timing, pace and extent of an economic recovery in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas.
Furthermore, as part of our business strategy, we target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance.
Our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.
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We are subject to various construction risks.
We are involved in the development of complex small, medium and large-scale engineering and construction projects, including our facilities, liquefaction facilities, power plants, and related infrastructure, which are often developed in multiple stages involving commercial and governmental negotiations, site planning, due diligence, permit requests, environmental impact studies, permit applications and review, marine logistics planning and transportation and end-user delivery logistics. In addition to our facilities, these infrastructure projects can include the development and construction of facilities as part of our customer contracts. Projects of this type are subject to a number of risks including, among others:
•engineering, environmental or geological problems;
•shortages or delays in the delivery of equipment and supplies;
•government or regulatory approvals, permits or other authorizations;
•failure to meet technical specifications or adjustments being required based on testing or commissioning;
•construction accidents that could result in personal injury or loss of life;
•lack of adequate and qualified personnel to execute the project;
•weather interference; and
•potential labor shortages, work stoppages or labor union 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. Delays from such third parties or governmental entities could prevent connection to our projects and generate delays in our ability to develop our own projects. In addition, a primary focus of our business is the development of projects in foreign jurisdictions, including in locations where we have no prior development experience, and we expect to continue expanding into new jurisdictions in the future. These risks can be increased in jurisdictions where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project. See “–Risks Related to the Jurisdictions in Which We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.”
The occurrence of any one of these factors, whatever the cause, could result in unforeseen delays or cost overruns to our projects. Delays in the development beyond our estimated timelines, or amendments or change orders to our construction contracts, could result in increases to our development costs beyond our original estimates, which could require us to obtain additional financing or funding and could make the project less profitable than originally estimated or possibly not profitable at all. Further, any such delays could cause a delay in our anticipated receipt of revenues, a loss of one or more customers in the event of significant delays, and our inability to meet milestones or conditions precedents in our customer contracts, which could lead to delay penalties and potentially a termination of agreements with our customers. We have experienced time delays and cost overruns in the construction and development of our projects as a result of the occurrence of various of the above factors, and no assurance can be given that we will not continue to experience in the future similar events, any of which could have a material adverse effect on our business, operating results, cash flows and liquidity.
Operation of our infrastructure, facilities and vessels involves significant risks.
Our existing infrastructure, facilities and vessels and expected future operations and businesses face operational risks, including, but not limited to, the following:
•performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;
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•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 infrastructure;
•failure to maintain the required government or regulatory approvals, permits or other authorizations;
•accidents, fires, explosions or other events or catastrophes;
•lack of adequate and qualified personnel;
•potential labor shortages, work stoppages or labor union disputes;
•weather-related or natural disaster interruptions of operations;
•pollution, release of or exposure to toxic substances or environmental contamination affecting operation;
•inability, or failure, of any counterparty to any facility-related agreements to perform their contractual obligations;
•decreased demand by our customers, including as a result of the COVID-19 pandemic; and
•planned and unplanned power outages or failures to supply due to scheduled or unscheduled maintenance.
In particular, we are subject to risks related to the operation of power plants, liquefaction facilities, marine and other LNG operations with respect to our facilities, floating storage regasification units ("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 these vessels are being repaired would decrease our results of operations. If a vessel we charter were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage could have a material adverse effect on our reputation, our business, our results of operations and cash flows and weaken our financial condition. Our 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 its 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 affect our results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and results of operations.
We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, our facilities or assets.
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We depend on third-party contractors, operators and suppliers.
We rely on third-party contractors, equipment manufacturers, suppliers and operators for the development, construction and operation of our projects and assets. We have not yet entered into binding contracts for the construction, development and operation of all of our facilities and assets, and we cannot assure you that we will be able to enter into the contracts required on commercially favorable terms, if at all, which could expose us to fluctuations in pricing and potential changes to our planned schedule. If we are unable to enter into favorable contracts, we may not be able to construct and operate these assets as expected, or at all. Furthermore, these agreements are the result of arms-length negotiations and subject to change. There can be no assurance that contractors and suppliers will perform their obligations successfully under their agreements with us. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. For example, each of our vessels is operated and maintained by GLNG or its affiliates pursuant to ship management agreements. Any failure by GLNG or its affiliates in the operation of our vessels could have an adverse effect on our maritime operations and could result in our failure to deliver LNG to our customers as required under our customer agreements. Although some agreements may provide for liquidated damages if the contractor or supplier fails to perform in the manner required with respect to its obligations, the events that trigger such liquidated damages may delay or impair the completion or operation of the facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment, including, among others, any covenants or obligations by us to pay liquidated damages or penalties under our agreements with our customers, development services, the supply of natural gas, LNG or steam and the supply of power, as well as increased expenses or reduced revenue. Such liquidated damages may also be subject to caps on liability, and we may not have full protection to seek payment from our contractors to compensate us for such payments and other consequences. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to its respective agreement. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If we are unable to construct and commission our facilities and assets as expected, or, when and if constructed, they do not accomplish our goals, or if we experience delays or cost overruns in construction, our business, operating results, cash flows and liquidity could be materially and adversely affected.
Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.
Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional or shale natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. Since August 2021, LNG prices have increased materially, and global events, such as the COVID-19 pandemic, Russia's invasion of Ukraine and global inflationary pressures, have generated further energy pricing volatility, which can have an adverse effect on market pricing of LNG and global demand for our products, as well as our ability to remain competitive in the markets in which we operate. Potential expansion in the Caribbean, Latin America and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. In Brazil, hydroelectric power generation is the predominant source of electricity and LNG is one of several other energy sources used to supplement hydroelectric generation. The success of our operations is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to our customers at a lower cost than the cost to deliver other alternative energy sources.
Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean and Latin America, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean, Latin America and other countries where we operate or seek to operate. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to other markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil,
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nuclear, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets. As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect our ability to deliver LNG or natural gas to our customers on a commercial basis, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
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. Certain federal permitting processes may trigger the requirements of the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions that have the potential to significantly impact the environment. Compliance with NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challenges to the adequacy of the NEPA analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. On July 15, 2020, the White House Council on Environmental Quality issued a final rule revising its NEPA regulations. These regulations have taken legal effect, and although they have been challenged in court, they have not been stayed. The Council on Environmental Quality has announced that it is engaged in an ongoing and comprehensive review of the revised regulations and is assessing whether and how the Council may ultimately undertake a new rulemaking to revise the regulations. The impacts of any such future revisions that may be adopted are uncertain and indeterminable for the foreseeable future. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. 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 within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. 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 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
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natural gas, among others, are highly regulated activities at the national, state and local levels and are subject to various approvals and permits. The process to obtain the permits, approvals and authorizations we need to conduct our business, and the interpretations of those rules, is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We may be unable to obtain such approvals on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations. Many of these permits, approvals and authorizations require public notice and comment before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application. We may also be (and have been in select circumstances) subject to local opposition, including citizens groups or non-governmental organizations such as environmental groups, which may create delays and challenges in our permitting process and may attract negative publicity, which may create an adverse impact on our reputation. In addition, such rules change frequently and are often subject to discretionary interpretations, including administrative and judicial challenges by regulators, all of which may make compliance more difficult and may increase the length of time it takes to receive regulatory approval for our operations, particularly in countries where we operate, such as Mexico and Brazil. For example, in Mexico, we have obtained substantially all permits but are awaiting regasification and transmission permits for our power plant and permits necessary to operate our terminal. In connection with our application to the U.S. Maritime Administration ("MARAD") related to our FLNG project off the coast of Louisiana, MARAD announced it had initially paused the statutory 356-day application review timeline on August 16, 2022 pending receipt of additional information, and restarted the timeline on October 28, 2022. MARAD issued a second stop notice on November 23, 2022 and on December 22, 2022, MARAD issued a third data request for supplemental information. Following review of NFE’s response to the December 2022 data requests, MARAD extended the stop clock on February 21, 2023 pending clarification of responses and receipt of additional information. No assurance can be given that we will be able to obtain approval of this application and receive the required permits, approvals and authorizations from governmental and regulatory agencies related to our 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 assure if or when we will 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 potential interventions by third parties that could interfere with our ability to obtain and maintain such permits and authorizations or the terms thereof. Furthermore, we are developing new technologies and operate in jurisdictions that may lack mature legal and regulatory systems and may experience legal instability, which may be subject to regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to our business and new technology, which can result in difficulties and instability in obtaining or securing required permits or authorizations. There is no assurance that we will obtain and maintain these permits and authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and we may not be able to complete our projects, start or continue our operations, recover our investment in our projects and may be subject to financial penalties or termination under our customer and other agreements, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project.
A key part of our business strategy is to attract new customers by agreeing to finance and develop new facilities, power plants, liquefaction facilities and related infrastructure in order to win new customer contracts for the supply of natural gas, LNG, steam or power. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell our products and generate fees from customers in the future. When we develop these projects, our required capital expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain. If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects.
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Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.
We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.
Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements.
Our business strategy relies upon our ability to successfully market our products to our existing and new customers and enter into or replace our long-term supply and services agreements for the sale of natural gas, LNG, steam and power. If we contract with our customers on short-term contracts, our pricing can be subject to more fluctuations and less favorable terms, and our earnings are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require us to enter into contracts based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in its cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover its financing costs for related vessels. Our ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. The COVID-19 pandemic could adversely impact our customers through decreased demand for power due to decreased economic activity and tourism, or through the adverse economic impact of the pandemic on their power customers. The impact of the COVID-19 pandemic, including governmental and other third -party responses thereto, on our customers could enhance the risk of nonpayment by such customers under our contracts, which would negatively affect our business, results of operations and financial condition. In particular, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from federal 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 agreements, or if they terminate our agreements prior to the end of the agreed term, our financial condition, results of operations and cash flows could be materially and adversely affected. If any of these customers fails to perform its obligations under its contract for the reasons listed above or for any other reason, our ability to provide products or services and our ability to collect payment could be negatively impacted, which could materially adversely affect our operating results, cash flow and liquidity, even if we were ultimately successful in seeking damages from such customer for a breach of contract.
Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our results of operations for the year ended December 31, 2022, 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 2022, 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 2022 exclude
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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, including the COVID-19 pandemic, severe weather or natural disasters. Due to our current lack of asset and geographic diversification, an adverse development at our operating facilities, in 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 (as defined herein), SJPC (as defined herein) and PREPA (as defined herein), which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant (as defined herein), with us, and Jamalco (as defined herein), which has entered into a long-term SSA with us, and which represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. The loss of any of these customers could have an adverse effect on our revenues and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.
We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate.
We are actively pursuing a significant number of new contracts for the sale of LNG, natural gas, steam, and power with multiple counterparties in multiple jurisdictions. Counterparties commemorate their purchasing commitments for these products in various degrees of formality ranging from traditional contracts to less formal arrangements, including non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responding to requests for proposals with potential customers. These agreements and any award following a request for proposals are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations. We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements. 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
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products to the counterparty, or we may sell much less volume than we estimate, which could result in our inability to generate the revenues and profits we anticipate, having a material adverse effect on our results of operations and financial condition.
Our contracts with our customers are subject to termination under certain circumstances.
Our contracts with our customers contain various termination rights. For example, each of our long-term customer contracts, including the contracts with JPS, SJPC, Jamalco and PREPA, contain various termination rights allowing our customers to terminate the contract, including, without limitation:
•upon the occurrence of certain events of force majeure;
•if we fail to make available specified scheduled cargo quantities;
•the occurrence of certain uncured payment defaults;
•the occurrence of an insolvency event;
•the occurrence of certain uncured, material breaches; and
•if we fail to commence commercial operations or achieve financial close within the agreed timeframes.
We may not be able to replace these contracts on desirable terms, or at all, if they are terminated. Contracts that we enter into in the future may contain similar provisions. If any of our current or future contracts are terminated, such termination could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess.
A substantial majority of our revenue in 2022 was dependent upon our LNG sales to third parties. We operate in the highly competitive industry for LNG and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, in the various markets in which we operate and many of which have been in operation longer than us. Various factors relating to competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all, including , among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•increases in demand for natural gas but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our liquefaction projects;
•increases in the cost to supply LNG feedstock to our facilities;
•decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, heavy fuel oil and automotive diesel oil ("ADO");
•decreases in the price of LNG; and
•displacement of LNG or fossil fuels more broadly by alternate fuels or energy sources or technologies (including but not limited to nuclear, wind, solar, biofuels and batteries) in locations where access to these energy sources is not currently available or prevalent.
In addition, we may not be able to successfully execute on our strategy to supply our existing and future customers with LNG produced primarily at our own liquefaction facilities upon completion of the Pennsylvania Facility or through our Fast LNG solution. Various competitors have and are developing LNG facilities in other markets, which will compete
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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.
Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:
•additions to competitive regasification capacity in North America, Brazil, Europe, Asia and other markets, which could divert LNG or natural gas from our business;
•imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States;
•insufficient or oversupply of natural gas liquefaction or export capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions and natural disasters;
•reduced demand and lower prices for natural gas;
•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities, including shut-ins and possible proration, which may decrease the production of natural gas;
•cost improvements that allow competitors to offer LNG regasification services at reduced prices;
•changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•political conditions in natural gas producing regions;
•adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors, including the timing of the impact of these factors in relation to our purchases and sales of natural gas and LNG could result in increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material
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adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. The COVID-19 pandemic and certain actions by the Organization of Petroleum Exporting Countries ("OPEC") related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long-term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows.
Conversely, current market conditions have increased LNG values to historically high levels. The elevated market values could 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 market 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 an LNG cargo that we have purchased, and if so, we may not be contractually entitled to receive full economic indemnification upon an LNG seller's failure to deliver an LNG cargo to us. Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurance we will achieve our target cost or pricing goals. In particular, because we have not currently procured fixed-price, long-term LNG supply to meet all future customer demand, increases in LNG prices and/or shortages of LNG supply could adversely affect our profitability. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.
Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.
Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas. These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our facilities. If we were to incur a material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows.
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.
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We are dependent on third-party LNG suppliers and may not be able to purchase or receive physical delivery of LNG or natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPAs and SSAs.
Under our GSAs, PPAs and SSAs, we are required to deliver to our customers specified amounts of LNG, natural gas, power and steam, respectively, at specified times and within certain specifications, all of which requires us to obtain sufficient amounts of LNG from third-party LNG suppliers or our own portfolio. We may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide a counterparty with the right to terminate its GSA, PPA or SSA, as applicable, or subject us to penalties and indemnification obligations under those agreements. While we have entered into supply agreements for the purchase of LNG between 2023 and 2030, we may need to purchase significant additional LNG volumes to meet our delivery obligations to our downstream customers. Price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices. Failure to secure contracts for the purchase of a sufficient amount of LNG or at favorable prices could materially and adversely affect our business, operating results, cash flows and liquidity.
Additionally, we are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase LNG on the spot market or receive a sufficient quantity of LNG in order to satisfy our delivery obligations under our GSAs, PPAs and SSAs or at favorable terms. Under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased, as our vessels maybe be too small for those obligations. Any such failure to purchase or receive delivery of LNG or natural gas in sufficient quantities could result in our failure to satisfy our obligations to our customers, which could lead to 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, if, it could have an adverse effect on our business, operating results, cash flows and liquidity, which could in turn materially and adversely affect our liquidity to make payments on our debt or comply with our financial ratios and other covenants. See “—We have incurred, and may in the future incur, a significant amount of debt.”
We may not be able to fully utilize the capacity of our FSRUs and other facilities.
Our FSRU facilities have significant excess capacity that is currently not dedicated to a particular anchor customer. Part of our business strategy is to utilize undedicated excess capacity of our FSRU facilities to serve additional downstream customers in the regions in which we operate. However, we have not secured, and we may be unable to secure, commitments for all of our excess capacity. Factors which could cause us to contract less than full capacity include difficulties in negotiations with potential counterparties and factors outside of our control such as the price of and demand for LNG. Failure to secure commitments for less than full capacity could impact our future revenues and materially adversely affect our business, financial condition and operating results.
LNG that is processed and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage.
LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. Where we have chartered in, but subsequently not outchartered an FSRU, which in turn results in our being unable to transfer risk of loss or damage, we could bear the risk of loss or damage to all those volumes of LNG for the period of time during which those applicable volumes of LNG 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.
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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. Most requirements for new LNG projects continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands. More frequent changes to vessel sizes, propulsion technology and emissions profile, together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the duration of long-term charters could also decrease over time. We may also face increased difficulty entering into long-term time charters upon the expiration or early termination of our contracts. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. If we lose any of our charterers and are unable to re-deploy the related vessel to a NFE terminal or into a new replacement contract for an extended period of time, we will not receive any revenues from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt.
We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer.
In addition to our own fleet of vessels, we rely on third-party ocean-going tankers and freight carriers (for ISO containers) for the transportation of LNG and ship-to-ship kits to transfer LNG between ships. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers on favorable terms or at all, which may result in us not being able to meet our obligations. Our ability to enter into contracts or renew existing contracts will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of charter rates and contract provisions. Fluctuations in rates result from changes in the supply of and demand for capacity and changes in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demand are outside of our control and are highly unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.
Furthermore, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo carrying capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, emissions standards, maritime regulatory changes and other factors not within our control. The availability of the tankers could be delayed to the detriment of our LNG business and our customers because the construction and delivery of LNG tankers require significant capital and long construction lead times. Changes in ocean freight capacity, which are outside our control, could negatively impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers.
The operation of ocean-going tankers and kits carries inherent risks. These risks include the possibility of natural disasters; mechanical failures; grounding, fire, explosions and collisions; piracy; human error; epidemics; and war and terrorism. We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. As a result, if our current equipment fails, is unavailable or insufficient to service our LNG purchases, production, or delivery commitments we may need to procure new equipment, which may not be readily available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Any of these results could have a material adverse effect on our business, financial condition and operating results.
Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings may decline.
Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to current and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a
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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.
Vessel values may fluctuate substantially and, if these values are lower at a time when we are attempting to dispose of vessels, we may incur a loss.
Vessel values can fluctuate substantially over time due to a number of different factors, including:
•prevailing economic conditions in the natural gas and energy markets;
•a substantial or extended decline in demand for LNG;
•increases in the supply of vessel capacity without a commensurate increase in demand;
•the size and age of a vessel; and
•the cost of retrofitting, steel or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.
As our vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on our business and operations if we do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel would be significant.
During the period a vessel is subject to a charter, we will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, we may be unable to re-deploy the affected vessels at attractive rates or for our operations and, rather than continue to incur costs to maintain and finance them, we may seek to dispose of them. When vessel values are low, we may not be able to dispose of vessels at a reasonable price when we wish to sell vessels, and conversely, when vessel values are elevated, we may not be able to acquire additional vessels at attractive prices when we wish to acquire additional vessels, which could adversely affect our business, results of operations, cash flow, and financial condition.
The carrying values of our vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates and the cost of new build vessels. Our vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Although we did not recognize an impairment charge on any vessels for the year ended December 31, 2022, we cannot assure you that we will not recognize impairment losses on our vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect our business, financial condition, or operating results.
Maritime claimants could arrest our vessels, which could interrupt our cash flow.
If we are in default on certain kinds of obligations related to our vessels, such as those to our lenders, crew members, suppliers of goods and services to our vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of our vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in our fleet for claims relating to another of our vessels. The arrest or attachment of one or more of our vessels could interrupt our cash flow and require us to pay to have the arrest lifted. Under some of our present charters, if the vessel is arrested or detained (for as few as 14 days in the case of one of our charters) as a result of a claim against us, we may be in default of our charter and the charterer may terminate the charter. This would negatively impact our revenues and cash flows.
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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.” We are also making investments to develop green hydrogen energy technologies as part of our long-term goal to become one of the world’s leading providers of carbon-free energy. We continue to develop our ISO container distribution systems in the various markets where we operate. We expect to make additional investments in this field in the future. Because these technologies are innovative, we may be making investments in unproven business strategies and technologies with which we have limited or no prior development or operating experience. As an investor in these technologies, it is also possible that we could be exposed to claims and liabilities, expenses, regulatory challenges and other risks. We may not be able to successfully develop these technologies, and even if we succeed, we may ultimately not be able to realize the time, revenues and cost savings we currently expect to achieve from these strategies, which could adversely affect our financial results.
Technological innovation may impair the economic attractiveness of our projects.
The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although we plan to build out our delivery logistics chain in Northern Pennsylvania using proven technologies such as those currently in operation at our Miami Facility, we do not have any exclusive rights to any of these technologies. In addition, such technologies may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others, which could materially and adversely affect our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.
Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all.
We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants. Our ability to create and maintain a competitive position in the natural gas liquefaction industry may be adversely affected by our inability to effectively implement our Fast LNG technology. We are finalizing construction of our first Fast LNG solution, and are therefore subject to construction risks, risks associated with third-party contracting and service providers, permitting and regulatory risks. See “—We are subject to various construction risks” and “—We depend on third-party contractors, operators and suppliers.” Because our Fast LNG technology 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
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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, 2022, we had approximately $4,582 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 effect on our business, results of operation and financial condition.
Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms.
We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in specific markets or the opportunistic sale of one of our non-core assets. We also historically have relied, and in the future will likely rely, on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Our ability to raise additional capital on acceptable terms will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to the COVID-19 pandemic, our progress in executing our business strategy and other factors, many of which are beyond our control, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. Additional debt financing, if available, may subject us to increased restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan, we may be unable to pay or refinance our indebtedness or to fund our other liquidity needs, and our financial condition or results of operations may be materially adversely affected.
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. 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 own 20%. As we do not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the
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agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Because we do not control all of the decisions of our joint ventures, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in its or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by our joint ventures. Additionally, as the joint ventures are separate legal entities, any right we may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities, trade creditors and any other third parties that require such subordination, such as lenders and other creditors).
Moreover, joint venture arrangements involve various risks and uncertainties, such as our commitment to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture. We have provided and may in the future provide guarantees or other forms of credit support to our joint ventures and/or affiliates. Failure by any of our 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 our joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to repay the outstanding borrowings, the relevant lenders may foreclose their liens on the relevant assets or vessels securing the loans or seek repayment of the loan from us, or both. Either of these possibilities could have a material adverse effect on our business. Further, by virtue of our guarantees with respect to our joint ventures and/or affiliates, this may reduce our ability to gain future credit from certain lenders.
The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
We have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or OTC options and swaps with other natural gas merchants and financial institutions. Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect the cost and availability of the swaps that we may use for hedging, including, without limitation, rules setting limits on the positions in certain contracts, rules regarding aggregation of positions, requirements to clear through specific derivatives clearing organizations and trading platforms, requirements for posting of margins, regulatory requirements on swaps market participants. Our counterparties that are also subject to the capital requirements set out by the Basel Committee on the Banking Supervision in 2011, commonly referred to as “Basel III,” may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Our subsidiaries and affiliates operating in Europe and the Caribbean may be subject to the European Market Infrastructure Regulation (“EMIR”) and the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants, which may impose increased regulatory obligations, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data, as well as requiring liquid collateral. These regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to forgo the use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.
We may incur impairments to long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business, or adverse actions by governmental entities, changes to regulation or legislation could lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to
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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.
Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate.
Weather events such as storms and related storm activity and collateral effects, or other disasters, accidents, catastrophes or similar events, natural or manmade, such as explosions, fires, seismic events, floods or accidents, could result in damage to our facilities, liquefaction facilities, or related infrastructure, interruption of our operations or our supply chain, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our onshore and offshore operations. Due to the nature of our operations, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology. In particular, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in locations that are subject to risks posed by hurricanes and similar severe weather conditions or natural disasters or other adverse events or conditions that could severely affect our infrastructure, resulting in damage or loss, contamination to the areas, and suspension of our operations. For example, our operations in coastal regions in southern Florida, the Caribbean, the Gulf of Mexico and Latin America are frequently exposed to natural hazards such as sea-level rise, coastal flooding, cyclones, extreme heat, hurricanes, and earthquakes. These climate risks can affect our operations, potentially even damaging or destroying our facilities, leading to production downgrades, costly delays, reduction in workforce productivity, and potential injury to our people. In addition, jurisdictions with increased political, economic, social and legal instability, lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us to additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. In addition, because of the location of some of our operations, we are subject to other natural phenomena, including earthquakes, such as the one that occurred near Puerto Rico in January 2020, which resulted in a temporary delay of development of our Puerto Rico projects, hurricanes and tropical storms. If one or more tankers, pipelines, facilities, liquefaction facilities, vessels, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our facilities, liquefaction facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe or similar event, our construction projects and our operations could be significantly interrupted, damaged or destroyed. These delays, interruptions and damages could involve substantial damage to people, property or the environment, and repairs could take a significant amount of time, particularly in the event of a major interruption or substantial damage. We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” The occurrence of a significant event, or the threat thereof, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental, social, health and safety laws and regulations could result in increased or more stringent compliance requirements, which may be difficult to comply with or result in additional costs and may otherwise lead to significant liabilities and reputational damage.
Our business is now and will in the future be subject to extensive national, federal, state, municipal and local laws, rules and regulations, in the United States and in the jurisdictions where we operate, relating to the environment, social, health and safety and hazardous substances. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG, natural gas and other substances; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA and the CWA, and analogous laws and regulations in the jurisdictions in which we operate, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities and vessels, and require us to obtain and maintain permits and provide governmental authorities with access to our facilities and vessels for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Changes or new environmental, social, health and safety laws and regulations could cause additional expenditures, restrictions and delays in our business and operations, the extent of which cannot be
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predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in October 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance document was a “rule” subject to the Congressional Review Act (“CRA”). This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the CRA, potentially increasing the likelihood that laws and regulations applicable to our business will become subject to revised interpretations in the future that we cannot predict. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Any failure in environmental, social, health and safety performance from our operations may result in an event that causes personal harm or injury to our employees, other persons, and/or the environment, as well as the imposition of injunctive relief and/or penalties or fines for non-compliance with relevant regulatory requirements or litigation. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain permits and approvals, and otherwise jeopardize our reputation or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. As the owner and operator of our facilities and owner or charteror of our vessels, we may be liable, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment at or from our facilities and for any resulting damage to natural resources, which could result in substantial liabilities, fines and penalties, capital expenditures related to cleanup efforts and pollution control equipment, and restrictions or curtailment of our operations. Any such liabilities, fines and penalties that exceed the limits of our insurance coverage. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets.
Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associated with the processing, transportation, and use of fossil fuels and emission of GHGs. In the United States to date, no comprehensive climate change legislation has been implemented at the federal level, although various individual states and state coalitions have adopted or considered adopting legislation, regulations or other regulatory initiatives, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement, effective February 19, 2021, and other countries where we operate or plan to operate, including Jamaica, Brazil, Ireland, Mexico, and Nicaragua, have signed or acceded to this agreement. However, the scope of future climate and GHG emissions-focused regulatory requirements, if any, remain uncertain. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States and worldwide. For example, based in part on the publicized climate plan and pledges by President Biden, there may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. For example, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve U.S. goals under the Paris Agreement.
Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.
The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs, and thereby reduce demand for or erode value for, the natural gas that we process and market. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases
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in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. Furthermore, political, litigation, and financial risks may result in reduced natural gas production activities, increased liability for infrastructure damages as a result of climatic changes, or an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is subject to these regulations, none of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but regulators and governmental agencies in the jurisdictions in which we operate can impose similar siting, design, construction and operational requirements that can affect our projects, facilities, infrastructure and operations. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change. Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and management of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.
Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. Hydraulic fracturing activities can be regulated at the national, federal or local levels, with governmental agencies asserting authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Such authorities may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).
The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several jurisdictions have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition, some local jurisdictions have adopted or considered adopting land use restrictions, such as city or municipal ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.
Indigenous Communities. Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which states that governments
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are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations, such as are required for our Brazilian operations, are consulted through appropriate procedures and through their representative institutions, particularly using the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for our operations, we are required to comply with the requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: IBAMA, local environmental authorities in the localities in which we operate, 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).
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 third parties from the indigenous territory. We cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact our existing development agreements or negotiations for outstanding development agreements with indigenous communities in the areas in which we operate.
There are several indigenous communities that surround our operations in Brazil. Certain of our subsidiaries have entered into agreements with some of these communities that mainly provide for the use of their land for our operations, provide compensation for any potential adverse impact that our operations may indirectly cause to them, and negotiations with other such communities are ongoing. If we are not able to timely obtain the necessary authorizations or obtain them on favorable terms for our operations in areas where indigenous communities reside, our relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to our operations, we could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.
Offshore operations. Our 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 we operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, the handling and disposal of hazardous substances and wastes and the management of ballast water. The International Maritime Organization (“IMO”) International Convention for the Prevention of Pollution from Ships of 1973, as amended from time to time, and generally referred to as “MARPOL,” can affect operations of our chartered vessels. In addition, our chartered LNG vessels may become subject to the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the “HNS Convention”), adopted in 1996 and subsequently amended by a Protocol to the HNS Convention in April 2010. Other regulations include, but are not limited to, the designation of Emission Control Areas under MARPOL, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as amended from time to time, the International Convention on Civil Liability for Bunker Oil Pollution Damage, the IMO International Convention for the Safety of Life at Sea of 1974, as amended from time to time, the International Safety Management Code for the Safe Operations of Ships and for Pollution Prevention, the IMO International Convention on Load Lines of 1966, as amended from time to time and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004.
In particular, development of offshore operations of natural gas and LNG are subject to extensive environmental, industry, maritime and social regulations. For example, any development and future operation of the potential Lakach
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project, which would be developed as a deepwater natural gas field in Mexico, as well as the development of a new FLNG hub off the coast of Altamira, State of Tamaulipas, would be subject to regulation by Mexico’s Ministry of Energy (Secretaría de Energía) (“SENER”), Mexico's National Hydrocarbon Commission ("CNH"), the National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector ("ASEA"), among other relevant Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidelines as the industry develops. Such regulations are subject to change, so it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. In addition, our operations in waters off the coast of Mexico are subject to regulation by ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidelines as the industry modernizes and adapts to market changes. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.
Moreover, the overall trends are towards more regulations and more stringent requirements which are likely to add to our costs of doing business. For example, IMO regulations, which became applicable on January 1, 2020, limit the sulfur content of fuel oil for ships to 0.5 weight percent starting January 1, 2020, thus increasing the cost of fuel and increasing expenses for us. Likewise, the European Union is considering extending its emissions trading scheme to maritime transport to reduce GHG emissions from vessels. We contract with industry leading vessel providers in the LNG market and look for them to take the lead in maintaining compliance with all such requirements, although the terms of our charter agreements may call for us to bear some or all of the associated costs. While we believe we are similarly situated with respect to other companies that charter vessels, we cannot assure you that these requirements will not have a material effect on our business.
Our chartered vessels operating in U.S. waters, now or in the future, will also be subject to various federal, state and local laws and regulations relating to protection of the environment, including the OPA, the CERCLA, the CWA and the CAA. In some cases, these laws and regulations require governmental permits and authorizations before conducting certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our chartered vessels’ operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, may increase our overall cost of business.
We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation.
We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Latin America, Europe and the other countries in which we seek to do business. We must also comply with trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. For example, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua and between 2018 and 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the government of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in Russia or connected to Russia, including sanctions specifically targeting the Russian oil and gas industry. Although we take precautions to comply with all such laws and regulations, violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to, (i) having to suspend our development or operations on a temporary or permanent basis, (ii) being unable to recuperate prior invested time and capital or being subject to lawsuits, or (iii) investigations or regulatory
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proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.
We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently, or may in the future, operate may present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico or other countries in Latin America, Asia and Africa. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, it is highly challenging to adopt policies and procedures that ensure compliance in all respects with the FCPA, particularly in high-risk jurisdictions. Developing and implementing policies and procedures is a complex endeavor. There is no assurance that these policies and procedures will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire.
If we are not in compliance with trade and economic sanctions laws and anti-corruption laws and regulations, including the FCPA, we may be subject to costly and intrusive criminal and civil investigations as well significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, the imposition of an independent compliance monitor, as well as potential personnel change and disciplinary actions. In addition, non-compliance with such laws could constitute a breach of certain covenants in operational or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers. In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries. Violations of applicable import, export, trade and economic sanctions, and anti-corruption laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with these provisions in the future. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, liquidity and future business prospects. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.
Although we believe that we have been in compliance with all applicable sanctions, embargo and anti-corruption laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism, which could adversely affect our ability to access funding and liquidity, our financial condition and prospects.
Our 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.
None of our vessels have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism. When we charter our vessels to third parties we conduct comprehensive due diligence of the charterer and include prohibitions on the charterer calling on ports in countries subject to comprehensive U.S. sanctions or otherwise engaging in commerce with such countries. However, our vessels may be sub-chartered out to a sanctioned party or call on ports of a sanctioned nation on charterers’ instruction, and without our knowledge or consent. If our charterers or sub-charterers violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, those violations could in turn negatively affect our reputation and cause us to incur significant costs associated with responding to any investigation into such violations.
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Increasing transportation regulations may increase our costs and negatively impact our results of operations.
We are developing a transportation system specifically dedicated to transporting LNG using ISO tank containers and trucks to our customers and facilities. This transportation system may include trucks that we or our affiliates own and operate. Any such operations would be subject to various trucking safety regulations in the various countries where we operate, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to state and/or local safety regulations that mirror federal regulations but also regulate the weight and size dimensions of loads. Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size. In addition to increased costs, fines and penalties, any non-compliance or violation of these regulations, could result in the suspension of our operations, which could have a material adverse effect on our business and consolidated results of operations and financial position.
Our chartered vessels operating in certain jurisdictions, including the United States, now or in the future, may be subject to cabotage laws, including the Merchant Marine Act of 1920, as amended (the “Jones Act”).
Certain activities related to our logistics and shipping operations may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions in which we operate. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act in the U.S., only vessels meeting specific national ownership and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade.” When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as fines or forfeiture of any vessels or their cargo, and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition.
We do not own the land on which our projects are located and are subject to leases, rights-of-ways, easements and other property rights for our operations.
We have obtained long-term leases and corresponding rights-of-way agreements and easements with respect to the land on which various of our projects are located, including the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the Miami Facility, the San Juan Facility and the CHP Plant are situated, facilities in Brazil such as the Garuva-Itapoa pipeline connecting the TBG pipeline to the Sao Francisco do Sul terminal, rights of way to the Petrobras/Transpetro OSPAR oil pipeline facilities, among others. In addition, our operations will require agreements with ports proximate to our facilities capable of handling the transload of LNG direct from our occupying vessel to our transportation assets. We do not own the land on which these facilities are located. As a result, we are subject to the possibility of increased costs to retain necessary land use rights as well as applicable law and regulations, including permits and authorizations from governmental agencies or third parties. If we were to lose these rights or be required to relocate, we would not be able to continue our operations at those sites and our business could be materially and adversely affected. For example, our ability to operate the CHP Plant is dependent on our ability to enforce the related lease. General Alumina Jamaica Limited (“GAJ”), one of the lessors, is a subsidiary of Noble Group, which completed a financial restructuring in 2018. If GAJ is involved in a bankruptcy or similar proceeding, such proceeding could negatively impact our ability to enforce the lease. If we are unable to enforce the lease due to the bankruptcy of GAJ or for any other reason, we could be unable to operate the CHP Plant or to execute on our contracts related thereto. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate our assets as anticipated, or at all, which could negatively affect our business, results of operations and financial condition.
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We could be negatively impacted by environmental, social, and governance (“ESG”) and sustainability-related matters.
Governments, investors, customers, employees and other stakeholders are increasingly focusing on corporate ESG practices and disclosures, and expectations in this area are rapidly evolving. We have announced, and may in the future announce, sustainability-focused goals, initiatives, investments and partnerships. These initiatives, aspirations, targets or objectives reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. Our efforts to accomplish and accurately report on these initiatives and goals present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and stock price.
In addition, the standards for tracking and reporting on ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period. Moreover, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals. In this regard, the criteria by which our ESG practices and disclosures are assessed may change due to the quickly evolving landscape, which could result in greater expectations of us and cause us to undertake costly initiatives to satisfy such new criteria. The increasing attention to corporate ESG initiatives could also result in increased investigations and litigation or threats thereof. If we are unable to satisfy such new criteria, investors may conclude that our ESG and sustainability practices are inadequate. If we fail or are perceived to have failed to achieve previously announced initiatives or goals or to accurately disclose our progress on such initiatives or goals, our reputation, business, financial condition and results of operations could be adversely impacted.
Information technology failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected. We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities, liquefaction facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our network systems and storage and other business applications, and the systems and storage and other business applications maintained by our third-party providers, have been in the past, and may be in the future, subjected to attempts to gain unauthorized access to our network or information, malfeasance or other system disruptions.
Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, liquefaction facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.
Our current operations and future projects are subject to the inherent risks associated with construction of energy-related infrastructure, LNG, natural gas, power and maritime operations, shipping and transportation of hazardous substances, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, acts of aggression or terrorism, and other risks or hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the facilities, liquefaction facilities and assets or damage to persons and property. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not generally carry business interruption insurance or political risk insurance with respect to political disruption in the countries in which we operate and that may in the future experience significant political volatility. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses or delays to our development timelines, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Even if we choose to carry insurance for these events in the future, it may not be adequate to protect us from loss, which may
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include, for example, losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain. In addition, our insurance may be voidable by the insurers as a result of certain of our actions. Furthermore, we may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult or costly for us to obtain.
Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.
We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, some of our other executive officers and other key employees. Mr. Edens does not have an employment agreement with us. The loss of the services of Mr. Edens or one or more of our other key executives or employees could disrupt our operations and increase our exposure to the other risks described in this Item 1A. Risk Factors. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.
We are dependent upon the available labor pool of skilled employees for the construction and operation of our facilities and liquefaction facilities, as well as our FSRUs, FLNGs and LNG carriers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our infrastructure and assets and to provide our customers with the highest quality service. In addition, the tightening of the labor market due to the shortage of skilled employees may affect our ability to hire and retain skilled employees, impair our operations and require us to pay increased wages. We are subject to labor laws in the jurisdictions in which we operate and hire our personnel, which can govern such matters as minimum wage, overtime, union relations, local content requirements and other working conditions. For example, Brazil and Indonesia, where some of our vessels operate, require we hire a certain portion of local personnel to crew our vessels. Any inability to attract and retain qualified local crew members could adversely affect our operations, business, results of operations and financial condition. Furthermore, should there be an outbreak of COVID-19 on our facilities or vessels, adequate staffing or crewing may not be available to fulfill the obligations under our contracts. Due to COVID-19, we could face (i) difficulty in finding healthy qualified replacement employees; (ii) local or international transport or quarantine restrictions limiting the ability to transfer infected employees from or to our facilities or vessels, and (iii) restrictions in availability of supplies needed for our projects due to disruptions to third-party suppliers or transportation alternatives. See “—General Risks—We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.” A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.
Our business could be affected adversely by labor disputes, strikes or work stoppages.
Some of our employees, particularly those in our Latin American operations, are represented by a labor union and are covered by collective bargaining agreements pursuant to applicable labor legislation. As a result, we are subject to the risk of labor disputes, strikes, work stoppages and other labor-relations matters. We could experience a disruption of our operations or higher ongoing labor costs, which could have a material adverse effect on our operating results and financial condition. Future negotiations with the unions or other certified bargaining representatives could divert management attention and disrupt operations, which may result in increased operating expenses and lower net income. Moreover, future agreements with unionized and non-unionized employees may be on terms that are note as attractive as our current agreements or comparable to agreements entered into by our competitors. Labor unions could also seek to organize some or all of our non-unionized workforce.
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Risks Related to the Jurisdictions in Which We Operate
We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.
Our projects are located in Jamaica and the United States (including Puerto Rico), the Caribbean, Brazil, Mexico, Ireland, Nicaragua and other geographies and we have operations and derive revenues from additional markets. Furthermore, part of our strategy consists in seeking to expand our operations to other jurisdictions. As a result, our projects, operations, business, results of operations, financial condition and prospects are materially dependent upon economic, political, social and other conditions and developments in these jurisdictions. Some of these countries have experienced political, security, and social economic instability in the recent past and may experience instability in the future, including 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 to date have not been materially impacted by the demonstrations or political changes in Puerto Rico, any substantial disruption in our ability to perform our obligations under any agreements with PREPA could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship with PREPA could change given PREPA’s privatization of its transmission, distribution and power generation system. PREPA may seek to find alternative power sources or purchase substantially less natural gas from us than what we currently expect to sell to PREPA. In addition, we cannot predict how local sentiment and support for our subsidiaries’ operations in Puerto Rico could change following the privatization of Puerto Rico’s power generation systems. 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.
Furthermore, some of the regions in which we operate have been subject to significant levels of terrorist activity and social unrest, particularly in the shipping and maritime industries. Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries. See “—Our Charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.” We do not, nor do we intend to, maintain insurance (such as business interruption insurance or terrorism) against all of these risks and losses. Any claims covered by insurance will be subject to deductibles, which may be significant, and we may not be fully reimbursed for all the costs related to any losses created by such risks. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” As a result, the occurrence of any economic, political, social and other instability or adverse conditions or developments in the jurisdictions in which we operate, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.
While our consolidated financial statements are presented in U.S. dollars, we generate revenues and incur operating expenses and indebtedness in local currencies in the countries where we operate, such as, among others, the euro, the Mexican peso and the Brazilian real. The amount of our revenues denominated in a particular currency in a particular country typically varies from the amount of expenses or indebtedness incurred by our operations in that country given that certain costs may be incurred in a currency different from the local currency of that country, such as the U.S. dollar. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars could result in potential losses and reductions in our margins resulting from currency fluctuations, which may impact our reported consolidated financial
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condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars and elect to intervene by implementing exchange rate regimes, including sudden devaluations, periodic mini devaluations, exchange controls, dual exchange rate markets and a floating exchange rate system. There can be no assurance that non-U.S. currencies will not be subject to volatility and depreciation or that the current exchange rate policies affecting these currencies will remain the same. For example, the Mexican peso and the Brazilian real have experienced significant fluctuations relative to the U.S. dollar in the past. We may choose not to hedge, or we may not be effective in efforts to hedge, this foreign currency risk. See “—Risks Related to our Business—Any use of hedging arrangements may adversely affect our future operating results or liquidity.” Depreciation or volatility of these currencies against the U.S. dollar could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.
Risks Related to Ownership of Our Class A Common Stock
The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.
The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:
•a shift in our investor base;
•our quarterly or annual earnings, or those of other comparable companies;
•actual or anticipated fluctuations in our operating results;
•changes in accounting standards, policies, guidance, interpretations or principles;
•announcements by us or our competitors of significant investments, acquisitions or dispositions;
•the failure of securities analysts to cover our Class A common stock;
•changes in earnings estimates by securities analysts or our ability to meet those estimates;
•the operating and share price performance of other comparable companies;
•overall market fluctuations;
•general economic conditions; and
•developments in the markets and market sectors in which we participate.
Stock markets in the United States have experienced extreme price and volume fluctuations. Market fluctuations, as well as general political and economic conditions such as acts of terrorism, prolonged economic uncertainty, a recession or interest rate or currency rate fluctuations, could adversely affect the market price of our Class A common stock.
We are a “controlled company” within the meaning of Nasdaq rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.
Affiliates of certain entities controlled by Wesley R. Edens, Randal A. Nardone and affiliates of Fortress Investment Group LLC (“Founder Entities”), together with affiliates of Energy Transition Holdings LLC, hold a majority of the voting power of our stock. In addition, pursuant to the Shareholders’ Agreement, dated as of February 4, 2019, by and among the
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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 Energy Transition Holdings LLC are parties to the Shareholders’ Agreement and as of December 31, 2022 hold approximately 12.2% 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 December 31, 2022, affiliates of the Founder Entities own an aggregate of approximately 87,136,768 shares of Class A common stock, representing 41.7% of our voting power, and affiliates of Energy Transition Holdings LLC, party to the Shareholders’ Agreement, own an aggregate of approximately 25,559,846 shares of Class A common stock, representing approximately 12.2% of the voting power of our Class A common 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 these 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, New Fortress Energy Holdings has assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition, our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.
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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 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-party to acquire us. In addition, some provisions of our Certificate of Incorporation and By-Laws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our securityholders. These provisions include:
•dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;
•providing that any vacancies may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (provided that vacancies that results from newly created directors requires a quorum);
•permitting special meetings of our stockholders to be called only by (i) the chairman of our board of directors, (ii) a majority of our board of directors, or (iii) a committee of our board of directors that has been duly designated by the board of directors and whose powers include the authority to call such meetings;
•prohibiting cumulative voting in the election of directors;
•establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of the stockholders; and
•providing that the board of directors is expressly authorized to adopt, or to alter or repeal our certain provisions of our organizational documents to the extent permitted by law.
Additionally, our Certificate of Incorporation provides that we have opted out of Section 203 of the Delaware General Corporation Law. However, our Certificate of Incorporation includes a similar provision, which, subject to certain exceptions, prohibits us from engaging in a business combination with an “interested stockholder,” unless the business combination is approved in a prescribed manner. Subject to certain exceptions, an “interested stockholder” means any person who, together with that person’s affiliates and associates, owns 15% or more of our outstanding voting stock or an affiliate or associate of ours who owned 15% or more of our outstanding voting stock at any time within the previous three years, but shall not include any person who acquired such stock from the Founder Entities or Energy 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 Energy 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 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 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 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
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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 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 or issue equity or equity-related securities to finance our operations, acquisitions or investments. Upon our liquidation, lenders and holders of our debt and holders of our preferred stock (if any) would receive a distribution of our available assets before Class A common stockholders. Any future incurrence or issuance of debt would increase our interest cost and could adversely affect our results of operations and cash flows. We are not required to offer any additional equity securities to existing Class A common stockholders on a preemptive basis. Therefore, additional issuances of Class A common stock, directly or through convertible or exchangeable securities (including limited partnership interests in our operating partnership), warrants or options, will dilute the holdings of our existing Class A common stockholders and such issuances, or the perception of such issuances, may reduce the market price of our Class A common stock. Any preferred stock issued by us would likely have a preference on distribution payments, periodically or upon liquidation, which could eliminate or otherwise limit our ability to make distributions to Class A common stockholders. Because our decision to incur or issue debt or issue equity or equity-related securities in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.
We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.
Our Certificate of Incorporation and 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. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.
Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock.
Sales of substantial amounts of our Class A common stock in the public market, or the perception that such sales might occur, could adversely affect the market price of our Class A common stock. The issuance of our Class A common stock in connection with property, portfolio or business acquisitions or the exercise of outstanding options or otherwise could also have an adverse effect on the market price of our Class A common stock.
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An active, liquid and orderly trading market for our Class A common stock may not be maintained and the price of our Class A common stock may fluctuate significantly.
Prior to January 2019, there was no public market for our Class A common stock. An active, liquid and orderly trading market for our Class A common stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock.
General Risks
We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest.
We conduct our business mainly through our operating subsidiaries and affiliates, including joint ventures and other special purpose entities, which are created specifically to participate in projects or manage a specific asset. Our ability to meet our financial obligations is therefore related in part to the cash flow and earnings of our subsidiaries and affiliates and the ability or willingness of these entities to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments, which are governed by various shareholder agreements, joint venture financing and operating arrangements. In addition, some of our operating subsidiaries, joint venture and special purpose entities are subject to restrictive covenants related to their indebtedness, including restrictions on dividend distributions. Any additional debt or other financing could include similar restrictions, which would limit their ability to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments. Similarly, we may fail to realize anticipated benefits of any joint venture or similar arrangement, which could adversely affect our financial condition and results of operation.
We may engage in mergers, sales and acquisitions, divestments, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value.
In furtherance of our business strategy, we may engage in mergers, purchases or sales, divestments, reorganizations or other similar transactions related to our businesses or assets in the future. Any such transactions may be subject to significant risks and contingencies, including the risk of integration, valuation and successful implementation, and we may not be able to realize the benefits of any such transactions. We may also engage in sales of our assets or sale and leaseback transactions that seek to monetize our assets and there is no guarantee that such sales of assets will be executed at the prices we desire or higher than the values we currently carry these assets at on our balance sheet. We do not know if we will be able to successfully complete any such transactions or whether we will be able to retain key personnel, suppliers or distributors. Our ability to successfully implement our strategy through such transactions depends upon our ability to identify, negotiate and complete suitable transactions and to obtain the required financing on terms acceptable to us. These efforts could be expensive and time consuming, disrupt our ongoing business and distract management. If we are unable to successfully complete our transactions, our business, financial condition, results of operations and prospects could be materially adversely affected.
We are unable to predict the extent to which the global pandemics and health crisis, such as the COVID-19 pandemic, will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.
The COVID-19 pandemic has caused, and is expected to continue to cause, economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil and other commodities. In addition, the pandemic has made, and any future global health crisis or pandemic could make, travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of 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, remains or 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 have been and continue to be taken in response to the COVID-19 pandemic (including restrictions on travel and transport
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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 have been subjected to the COVID-19 pandemic and 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 also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the operations and financial condition of our customers and potential customers, as well as the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.
A change in tax laws in any country in which we operate could adversely affect us.
Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.
We are and may be involved in legal proceedings and may experience unfavorable outcomes.
We are 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
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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 subject to an extensive body of regulations, including certain provisions of the Sarbanes-Oxley Act, the Dodd-Frank Act, regulations of the SEC and Nasdaq requirements. Compliance with these rules and regulations increases our legal, accounting, compliance and other expenses. For example, as a result of becoming a public company, we added independent directors and created additional board committees. We entered into an administrative services agreement with FIG LLC, an affiliate of Fortress Investment Group (which currently employs Messrs. Edens, our chief executive officer and chairman of our Board of Directors, and Nardone, one of our Directors), in connection with the IPO, pursuant to which FIG LLC provides us with certain back-office services and charges us for selling, general and administrative expenses incurred to provide these services. In addition, we may incur additional costs associated with our public company reporting requirements and maintaining directors’ and officers’ liability insurance. It is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate, and the incremental costs may have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our share price could decline.
The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose viability in the financial markets, which in turn could cause our share price or trading volume to decline.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
We are not currently a party to any material legal proceedings. In the ordinary course of business, various legal and regulatory claims and proceedings may be pending or threatened against us. If we become a party to proceedings in the future, we may be unable to predict with certainty the ultimate outcome of such claims and proceedings.
Item 4. Mine Safety Disclosures.
Not applicable.
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PART II
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 Nasdaq Global Select Market under the symbol “NFE.” On February February 24, 2023, 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 per share in March, June, September and December totaling $82,974 during the year ended December 31, 2022. 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 $626,310, representing $3.00 per Class A share, which was paid in January 2023. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our Board of Directors may deem relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2022 in connection with our 2023 annual meeting 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, iShares Global Clean Energy ETF Index (“ICLN”), 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, $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.
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| Cumulative Total Return Percentage | |||||||||||||||||
| Company / Index | January 31, 2019(1) | December 2019(2) | December 2020(2) | December 2021(2) | December 2022(2) | ||||||||||||
| NFE | 100.0% | 19.9% | 312.4% | 88.0% | 233.6% | ||||||||||||
| S&P 500 | 100.0% | 21.7% | 44.1% | 85.4% | 51.8% | ||||||||||||
| iShares Global Clean Energy ETF Index (“ICLN”) | 100.0% | 25.6% | 203.8% | 130.3% | 117.9% | ||||||||||||
| Vanguard Energy ETF (“VDE”) | 100.0% | (2.2)% | (34.5)% | 2.3% | 66.6% | ||||||||||||
Energy Select Sector SPDR Fund ("XLE")(3) | 100.0% | 0.5% | (32.2)% | 4.0% | 70.7% | ||||||||||||
(1)Date of the IPO
(2)Last trading day of the month
Item 6. [Reserved.]
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “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, 2021 and 2020 can be found in our Annual Report on Form 10‑K for the year ended December 31, 2021 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. This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.
Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to the completion of Mergers (defined below), New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries.
Overview
We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable, and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in this Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Very-Low-Carbon Future.”
Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.
Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida. Starting in 2023, we expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply and fleet.
Our Ships segment includes all vessels which are leased to customers under long-term or spot arrangements. The Company’s investments in Hilli LLC, owner and operator of the Hilli, and Energos (defined below) are also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.
Our Current Operations – Terminals and Infrastructure
Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica
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Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), Mexico’s power utility, each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers.
Montego Bay Facility
The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay, Jamaica ("Bogue Power Plant"). Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 61,000 MMBtu from LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.
Old Harbour Facility
The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (the “Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.
La Paz Facility
In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu from LNG per day to our 100MW of power supplied by gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu from LNG per day for up to 135MW of power.
In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE and are in the process of finalizing long-form agreements to commemorate all binding terms. The gas sales and power plant sale agreements are subject to execution of the long-form final agreements and certain conditions precedent, and we expect to execute the long-form final agreements in the first quarter of 2023. We do not expect to recognize a loss on sale upon completion of this transaction.
Miami Facility
Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu from LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.
Our LNG Supply and Cargo Sales
NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts
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expected to commence in 2026; 3) our Miami Facility; and 4) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, that are expected to commence in 2026 and 2027. Finally, we plan to commence our own Fast LNG production in 2023, when our first FLNG facility is expected to begin operation, and we plan to expand that capacity when additional units come online over the next two years.
The recent geopolitical events in Europe have substantially impacted the natural gas and LNG markets with unprecedented price increases and volatility. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production from FLNG facilities expected to commence in 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.
Our Current Operations – Ships
Our Ships segment includes five FSRUs and five LNG carriers, which are leased to customers under long-term or spot arrangements and our investment in Hilli LLC, owner and operator of the Hilli. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. One LNG carrier and FSRU are currently utilized in our terminal operations, and the results of operations of these vessels are reflected in the Terminals and Infrastructure segment. In August 2022, we completed a financing transaction with an affiliate of Apollo Global Management, Inc. collateralized by our vessels. See “—Factors Impacting Comparability of Our Financial Results” for more details about this transaction; the results of operations from charters of vessels included in this transaction continue to be included in our Ships segment as well as our equity method investment in Energos (defined below).
Our Development Projects
Our projects currently under development include our development of a series of modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); and our LNG terminal (“Ireland Facility”) and power plant in Ireland. We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.
The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.
We describe each of our current development projects below.
Fast LNG
We are currently developing multiple modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing offshore liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefication solutions. The “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than land-based alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.
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Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. We expect to deploy our first Fast LNG unit in 2023 and additional units in 2024.
We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.
Altamira
In the fourth quarter of 2022, we finalized short-form agreements, which include conditions to effectiveness that have not been satisfied, with the Comisión Federal de Electricidad (“CFE”) to supply natural gas to two FLNG units located off the coast of Altamira, Tamaulipas, Mexico. These arrangements are subject to finalizing long-form definitive agreements and satisfying certain conditions precedent. Each 1.4 million tons per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. We expect to deploy our first FLNG unit to Altamira in 2023.
Louisiana
In addition, we plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.
Lakach
Also, in the fourth quarter of 2022, we finalized agreements, which include conditions to effectiveness that have not been satisfied, with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. If the agreements become effective, NFE would invest in the continued development of the Lakach field over a two-year period by completing seven offshore wells and to deploy a 1.4 MTPA Fast LNG unit to liquefy the majority of the produced natural gas. Remaining natural gas and associated condensate volumes would be utilized by Pemex in Mexico's onshore domestic market.
Puerto Sandino Facility
We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.
Barcarena Facility
The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to third-party industrial and power customers as well as the Barcarena Power Plant, a new 605MW combined cycle thermal power plant to be located in Pará, Brazil, which we own and which is supported by multiple 25-year power purchase agreements to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025. We substantially completed our Barcarena Facility in 2022 and expect to commence operations by the end of 2023. We expect to complete the Barcarena Power Plant and to commence operations in 2025.
We have financed the development of the Barcarena Power Plant pursuant to a financing agreement. See “—Long-Term Debt and Preferred Stock.”
Santa Catarina Facility
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The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations in 2023.
Ireland Facility
We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland. While the specific timing for receiving the required permits is unknown, we have undertaken pre-development work that will allow us to complete the terminal in approximately 9-15 months after receiving the required permits. We currently expect to begin operations in the first half of 2024.
Recent Developments
On February 6, 2023, we announced an agreement with Golar LNG Limited (“GLNG”) for the sale of our ownership stake in the Hilli Episeyo (the “Hilli”) in exchange for the return of approximately 4.1 million NFE shares and $100.0 million in cash (the "Hilli Exchange"). Pursuant to the transaction, we will no longer have any interest in the 2.4 MTPA floating liquefaction facility Hilli. This transaction is expected to close in the first quarter of 2023 and is subject to customary closing conditions.
Recent market prices of NFE shares and the terms of the Hilli Exchange implied that the fair value of the investment may be lower than the carrying value as of December 31, 2022, which triggered an assessment of the recoverability of the carrying amount of this investment. We estimated the fair value of the investment as of December 31, 2022 and concluded that the estimated fair value was below the carrying value and that this decline was other than temporary. As a result of this recoverability assessment, we recognized an OTTI of the investment in Hilli of $118,558 for the year ended December 31, 2022; this loss was recognized in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). The gain or loss recognized upon the closing of the Hilli Exchange will be determined based upon the share price at closing.
In February 2023, the Revolving Facility (defined below) was amended to increase the facility size by $301.7 million to $741.7 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants. Also, in February 2023, our uncommitted letter of credit and reimbursement agreement was upsized to $325 million; no changes to interest rates or other terms were made as part of this amendment.
Other Matters
On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021, FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC 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 filed an application for authorization to operate the San Juan Facility, which remains pending.
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Factors Impacting Comparability of Our Financial Results
Significant 2022 Transactions
We completed significant transactions in 2022 and 2021, including a significant sales and financing transaction collateralized by certain vessels as further described below, the sale of our investment in entities owning the Sergipe Power Plant (defined below) and our acquisitions of GMLP and Hygo, and these significant transactions impact the comparability of our historical financial results of operations.
Energos Formation Transaction
On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), created a joint venture and completed a sales and financing transaction resulting in cash proceeds of approximately $1.85 billion. This sales and financing transaction comprised (1) the formation of a joint venture doing business as Energos Infrastructure ("Energos"), (2) the sale for cash of eight vessels, along with these vessels' owning and operating entities to the Purchaser, (3) the contribution of acquired vessel-owning entities to Energos by the Purchaser and (4) the Company's contribution of three vessels, along with each vessel's' owning and operating entities, to Energos in exchange for equity in Energos (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, with the remaining interest owned by the Purchaser. We have accounted for the investment in Energos as an equity method investment.
In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for periods of up to 20 years in respect of ten of the eleven vessels, the terms of which will commence upon the expiration of each vessel's existing charter. These charters prevent the recognition of a sale of these ten vessels to Energos, and as such, proceeds associated with these ten vessels have been treated as failed sale leasebacks. These vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and we have recognized this failed sale leaseback financing as debt. Certain vessels included in the Energos Formation Transaction are currently chartered to third parties under operating leases. As we have not recognized the sale of these vessels and proceeds received under the Energos Formation Transaction are collateralized by the cash flows from these charters, revenue generated from these operating leases continues to be recognized as Vessel charter revenue; costs of operating the vessels is included in Vessel operating expenses over the terms of the third-party charters. Cash flows from these third-party charters are included as part of debt service for the sale leaseback financing debt, and we will recognize additional financing costs within Interest expense, net.
We have not entered into a charter agreement to leaseback the Nanook. The Nanook was previously accounted for as a finance lease and proceeds received have been allocated between financing of other vessels and the sale of the Nanook. After closing this transaction, we no longer recognize revenue from the sales-type lease of the Nanook to CELSE and the related operating services agreement.
Sergipe Sale
We acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) as part of the Hygo Merger (defined below); 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"). The Sergipe Power Plant 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, one of our subsidiaries 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 1.7GW of expansion rights adjacent to the Sergipe Power Plant (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). We also entered into a foreign currency forward associated to mitigate foreign currency risk to the expected proceeds from the transaction, and this foreign currency forward settled on October 3, 2022, resulting in a gain of $20.4 million.
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Since the Sergipe Sale in October 2022, we no longer include the results of our equity method investment in CELSEPAR in our financial statements. The results of operations of the Sergipe Power Plant were included in our Terminal and Infrastructure segment results, contributing segment operation margin of $95.6 million for the year ended December 31, 2022. Finally, we have recognized an other than temporary impairment on our investment in CELSEPAR of $369.2 million and an impairment loss on the assets held by CEBARRA of $50.7 million; as the Sergipe Sale closed in 2022, there will be no further impairment loss on this investment in future periods.
Hygo Merger and GMLP Merger
On April 15, 2021, we completed the acquisitions of Hygo (the "Hygo Merger") and GMLP (the "GMLP Merger," and collectively with the Hygo Merger, the “Mergers”) As a result of the Mergers, we acquired a 50% interest in the Sergipe Power Plant and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), the Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. We also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli. The results of operations of the vessels acquired are included in our results of operations for the period after the acquisition date in 2021 and for a full year in 2022; the Nanook is only included in our results of operations in 2022 for the period prior to the Energos Formation Transaction.
Comparability to future periods
Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:
•Our historical financial results do not reflect 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 97% of our LNG volumes from third parties for the year ended December 31, 2022. We anticipate the deployment of Fast LNG facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers.
•Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2022 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed a portion of our La Paz Facility into service, and our revenue and results of operations have begun to be impacted by operations in Mexico. We have executed short-form agreements to extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and are in the process of finalizing long-form agreements to commemorate all binding terms. We are also continuing to develop our Puerto Sandino Facility, and our current results do not include revenue and operating results from this project. Our current results also exclude other developments, including the Barcarena Facility, Santa Catarina Facility and Ireland Facility.
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Results of Operations – Three Months Ended December 31, 2022 compared to Three Months Ended September 30, 2022 and Year Ended December 31, 2022 compared to Year Ended December 31, 2021
Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.
Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income/(loss) from operations, net income/(loss), cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions to facilitate measuring and achieving optimal financial performance of our current operations overall. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.
The tables below present our segment information for the three months ended December 31, 2022 and September 30, 2022, and for the year ended December 31, 2022 and December 31, 2021:
| Three Months Ended December 31, 2022 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure(1) | Ships(2) | Total Segment | Consolidation and Other(3) | Consolidated | |||||||||||||||||||||||||||
| Total revenues | $ | 457,324 | $ | 106,990 | $ | 564,314 | $ | (17,945) | $ | 546,369 | ||||||||||||||||||||||
Cost of sales(4) | 232,436 | — | 232,436 | (96,537) | 135,899 | |||||||||||||||||||||||||||
Vessel operating expenses(5) | — | 19,515 | 19,515 | (6,729) | 12,786 | |||||||||||||||||||||||||||
Operations and maintenance(5) | 28,931 | — | 28,931 | — | 28,931 | |||||||||||||||||||||||||||
| Segment Operating Margin | $ | 195,957 | $ | 87,475 | $ | 283,432 | $ | 85,321 | $ | 368,753 | ||||||||||||||||||||||
| Three Months Ended December 31, 2022 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 332,552 | |||||||||
| Depreciation and amortization | 36,201 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 368,753 | |||||||||
Three Months Ended September 30, 2022 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure(1) | Ships(2) | Total Segment | Consolidation and Other(3) | Consolidated | |||||||||||||||||||||||||||
| Total revenues | $ | 687,437 | $ | 111,660 | $ | 799,097 | $ | (67,167) | $ | 731,930 | ||||||||||||||||||||||
Cost of sales(4) | 402,458 | — | 402,458 | (8,628) | 393,830 | |||||||||||||||||||||||||||
Vessel operating expenses(5) | — | 23,799 | 23,799 | (6,912) | 16,887 | |||||||||||||||||||||||||||
Operations and maintenance(5) | 33,510 | — | 33,510 | (8,046) | 25,464 | |||||||||||||||||||||||||||
| Segment Operating Margin | $ | 251,469 | $ | 87,861 | $ | 339,330 | $ | (43,581) | $ | 295,749 | ||||||||||||||||||||||
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| Three Months Ended September 30, 2022 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 259,956 | |||||||||
| Depreciation and amortization | 35,793 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 295,749 | |||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure⁽¹⁾ | Ships⁽²⁾ | Total Segment | Consolidation and Other⁽³⁾ | 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 | ||||||||||||||||||||||
| Year Ended December 31, 2022 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 1,045,886 | |||||||||
| Depreciation and amortization | 142,640 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 1,188,526 | |||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure⁽¹⁾ | Ships⁽²⁾ | Total Segment | Consolidation and Other⁽³⁾ | Consolidated | |||||||||||||||||||||||||||
| Total revenues | $ | 1,366,142 | $ | 329,608 | $ | 1,695,750 | $ | (372,940) | $ | 1,322,810 | ||||||||||||||||||||||
Cost of sales(4) | 789,069 | — | 789,069 | (173,059) | 616,010 | |||||||||||||||||||||||||||
Vessel operating expenses(5) | 3,442 | 64,385 | 67,827 | (16,150) | 51,677 | |||||||||||||||||||||||||||
Operations and maintenance(5) | 92,424 | — | 92,424 | (19,108) | 73,316 | |||||||||||||||||||||||||||
| Segment Operating Margin | $ | 481,207 | $ | 265,223 | $ | 746,430 | $ | (164,623) | $ | 581,807 | ||||||||||||||||||||||
| Year Ended December 31, 2021 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 483,430 | |||||||||
| Depreciation and amortization | 98,377 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 581,807 | |||||||||
(1)Prior to the completion of the Sergipe Sale, Terminals and Infrastructure included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR. The losses attributable to the investment of $0 and $44.6 million for the three months ended December 31, 2022 and September 30, 2022, respectively and $397.9 million and $17.9 million for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market earnings and loss on derivative instruments of $96.4 million and $6.9 million for the three months ended December 31, 2022 and September 30, 2022, respectively and $106.1 million and $2.8 million for the years ended December 31, 2022 and 2021, respectively, reported in Cost of sales.
(2)Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of the Hilli Common Units. The loss and earnings attributable to the investment of $120.6 million and $12.8 million for the three months ended December 31, 2022 and September 30, 2022, respectively, and $77.1 million and $32.4 million for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss)
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income from equity method investments in the consolidated statements of operations and comprehensive income (loss).
(3)Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.
(4)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).
(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
| Three Months Ended, | |||||||||||||||||
| (in thousands of $) | December 31, 2022 | September 30, 2022 | Change | ||||||||||||||
| Total revenues | $ | 457,324 | $ | 687,437 | $ | (230,113) | |||||||||||
| Cost of sales (exclusive of depreciation and amortization) | 232,436 | 402,458 | (170,022) | ||||||||||||||
| Operations and maintenance | 28,931 | 33,510 | (4,579) | ||||||||||||||
| Segment Operating Margin | $ | 195,957 | $ | 251,469 | $ | (55,512) | |||||||||||
| Year Ended, | |||||||||||||||||
| (in thousands of $) | December 31, 2022 | December 31, 2021 | Change | ||||||||||||||
| Total revenues | $ | 2,168,565 | $ | 1,366,142 | $ | 802,423 | |||||||||||
| Cost of sales (exclusive of depreciation and amortization) | 1,142,374 | 789,069 | 353,305 | ||||||||||||||
| Vessel operating expenses | — | 3,442 | (3,442) | ||||||||||||||
| Operations and maintenance | 129,970 | 92,424 | 37,546 | ||||||||||||||
| Segment Operating Margin | $ | 896,221 | $ | 481,207 | $ | 415,014 | |||||||||||
Total revenue
Total revenue for the Terminals and Infrastructure Segment decreased by $230.1 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The decrease was primarily driven by decreased revenue from LNG cargo sales and decreases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment. Revenue from cargo sales was $231.1 million for the three months ended December 31, 2022 and $350.6 million for the three months ended September 30, 2022. The average Henry Hub index pricing used to invoice our downstream customers decreased by 24% for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.
Total volumes delivered to downstream customers also contributed to the decrease in revenue for the three months ended December 31, 2022; volumes delivered for the three months ended December 31, 2022 were 11.0 TBtus as compared to 12.9 TBtus for the three months ended September 30, 2022. Volumes delivered decreased primarily due to maintenance at the San Juan Power Plant.
Total revenue for the Terminals and Infrastructure Segment increased by $802.4 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily driven by increased revenue from LNG cargo sales and increases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment. Revenue from cargos sales was $1,175.9 million for the year ended December 31, 2022 as compared to $462.7 million for the year ended December 31, 2021. The average Henry Hub index pricing used to invoice our downstream customers increased by 73% for the year ended December 31, 2022 as compared to the year ended December 31, 2021.
The significant increase in pricing was partially offset by decreases in total volumes delivered to downstream customers; for the year ended December 31, 2022 volumes delivered to downstream customers were 39.5 TBtus as
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compared to 41.8 TBtus for the year ended December 31, 2021. Volumes delivered decreased due to maintenance at the Montego Bay Facility and San Juan Power Plant.
After the completion of the Sergipe Sale, we no longer recognize our share of revenue from our ownership interest in CELSEPAR, and no revenue was recognized for three months ended December 31, 2022. Our share of revenue from our investment in CELSEPAR was $41.3 million for the three months ended September 30, 2022, which was primarily comprised of fixed capacity payments received under CELSE's PPAs. Our share of revenue from our investment in CELSEPAR was $148.3 million for the year ended December 31, 2022 as compared to $299.2 million for the year ended December 31, 2021, which represents our share of revenue for the period after the Mergers. Prior year revenue was higher due to revenue recognized from the emergency dispatch of the Sergipe Power Plant in the third quarter of 2021 due to poor hydrological conditions in Brazil.
Cost of sales
Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.
Cost of sales decreased $170.0 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.
•We recognized $97.8 million during the three months ended December 31, 2022 to acquire cargos sold to third parties, as compared to $185.7 million for the three months ended September 30, 2022. The weighted-average cost of LNG from cargo sales decreased from $18.26 per MMBtu for the three months ended September 30, 2022 to $10.52 per MMBtu for the three months ended December 31, 2022.
•Cost of LNG purchased from third parties for sale to our downstream customers decreased $33.3 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The decrease was primarily attributable to a 15% decrease in volumes delivered compared to the three months ended September 30, 2022, and decreases in LNG cost. The weighted-average cost of LNG purchased from third parties for sale to our customers decreased from $12.17 per MMBtu for the three months ended September 30, 2022 to $10.95 per MMBtu for the three months ended December 31, 2022.
•During the three months ended December 31, 2022, we settled a commodity swap transaction to swap market pricing exposure for a portion of January 2023 deliveries (approximately 1.5 TBtus) for a fixed price of $61.87 per MMBtu, at a gain of $36.5 million.
Cost of sales increased by $353.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021.
•The increase in Cost of sales was primarily due to higher cost of LNG cargos NFE sold into the market. We recognized cost to acquire LNG cargos sold to third parties totaling $485.4 million during the year ended December 31, 2022 compared to $191.3 million for the year ended December 31, 2021.
•Cost of LNG purchased from third parties for sale to our terminal customers increased $141.5 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. While we delivered 6% less volumes to our terminal customers in the current period as compared to the prior year, our cost of LNG was significantly higher in the current period. The weighted-average cost of LNG purchased from third parties increased from $7.09 per MMBtu for the year ended December 31, 2021 to $10.84 per MMBtu for the year ended December 31, 2022.
•Vessel costs increased $53.0 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021 due to additional vessels used in our expanded operations.
•These increases were partially offset by a decrease in our share of cost of sales from our former investment in CELSEPAR from $175.8 million during the year ended December 31, 2021 to $28.6 million during the year ended December 31, 2022. As hydrology conditions have continued to improve in Brazil, the Sergipe Power Plant
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was not dispatched as regularly in 2022 and the investment in CELSEPAR was sold during the fourth quarter of 2022, reducing cost of sales from our share of our investment in CELSEPAR.
The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2022 and December 31, 2021 was $10.42 per MMBtu and $9.71 per MMBtu, respectively.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, and these costs are typically included in the Ships segment. Once we begin to use a vessel in our terminal operations, the costs of the vessel begin to be included in the Terminals and Infrastructure segment. Vessel operating expenses were $3.4 million for the year ended December 31, 2021. We did not incur similar costs in this segment during the year ended December 31, 2022.
Operations and maintenance
Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales.
Operations and maintenance decreased $4.6 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022, which was primarily attributable to the decrease in our share of Operations and maintenance from our former investment in CELSEPAR. After the completion of the Sergipe Sale, we no longer recognize our share of Operations and maintenance from our former ownership interest in CELSEPAR, and no Operations and maintenance costs were recognized for the three months ended December 31, 2022.
Operations and maintenance increased $37.5 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021.
•The increase for the year ended December 31, 2022 as compared to the year ended December 31, 2021 was primarily attributable to maintenance costs at our Montego Bay Facility and San Juan Power Plant, and higher logistics costs associated with our ISO container distribution system. Due to the reconfiguration and partial relocation of our assets at the Port of Montego Bay in 2022, we began to source LNG from our Miami Facility to service industrial end users in Jamaica, and we incurred additional costs to distribute LNG to customers via our ISO container distribution system. Maintenance costs and logistics costs increased by $10.2 million and $18.1 million, respectively.
•Additionally, Operations and maintenance increased $5.1 million due to the inclusion of our share of Operations and maintenance from our former investment in CELSEPAR from $19.1 million for the year ended December 31, 2021 to $24.2 million for the year ended December 31, 2022, which represents the costs for the period after the Merger. These costs are primarily related to the operation and services agreement for the Nanook, insurance costs and costs for connecting to the transmission system.
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Ships Segment
| Three Months Ended, | |||||||||||||||||
| (in thousands of $) | December 31, 2022 | September 30, 2022 | Change | ||||||||||||||
| Total revenues | $ | 106,990 | $ | 111,660 | $ | (4,670) | |||||||||||
| Vessel operating expenses | 19,515 | 23,799 | (4,284) | ||||||||||||||
| Segment Operating Margin | $ | 87,475 | $ | 87,861 | $ | (386) | |||||||||||
| Year Ended, | |||||||||||||||||
| (in thousands of $) | December 31, 2022 | December 31, 2021 | Change | ||||||||||||||
| Total revenues | $ | 444,616 | $ | 329,608 | $ | 115,008 | |||||||||||
| Vessel operating expenses | 90,544 | 64,385 | 26,159 | ||||||||||||||
| Segment Operating Margin | $ | 354,072 | $ | 265,223 | $ | 88,849 | |||||||||||
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.
At the completion of the Mergers, five of the FSRUs and two LNG carriers were on hire under long-term charter agreements, and one LNG carriers, the Grand, was operating in the spot market. In the third quarter of 2021, the Grand, began to be utilized in our terminal and logistics operations, and as such, the results of operations of the Grand are included in the Terminals and Infrastructure segment from the third quarter of 2021 onward. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels.
Total revenue
Total revenue for the Ships segment was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. 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. Revenues from the Ships segment remained substantially consistent as decreased revenue due to the sale of the Nanook was offset by additional sub-charter revenue.
Total revenue for the Ships segment increased $115.0 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021, and the increase in revenue is due to the inclusion of the Ships segment in our results of operations for a full year.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.
Vessel operating expenses decreased by $4.3 million for the three months ended December 31, 2022, compared to the three months ended September 30, 2022. The decrease is related to reduced operating costs and management fees due to the sale of the Nanook as a result of the Energos Formation Transaction.
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Vessel operating expenses increased $26.2 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021, and the increase in vessel operating expenses is due to the inclusion of the Ships segment in our results of operations for a full year.
Other operating results
| Three Months Ended, | Year Ended, | ||||||||||||||||||||||||||||||||||
| (in thousands of $) | December 31, 2022 | September 30, 2022 | Change | December 31, 2022 | December 31, 2021 | Change | |||||||||||||||||||||||||||||
| Selling, general and administrative | $ | 70,099 | $ | 67,601 | $ | 2,498 | $ | 236,051 | $ | 199,881 | $ | 36,170 | |||||||||||||||||||||||
| Transaction and integration costs | 9,409 | 5,620 | 3,789 | 21,796 | 44,671 | (22,875) | |||||||||||||||||||||||||||||
| Depreciation and amortization | 36,201 | 35,793 | 408 | 142,640 | 98,377 | 44,263 | |||||||||||||||||||||||||||||
| Asset impairment expense | 2,550 | — | 2,550 | 50,659 | — | 50,659 | |||||||||||||||||||||||||||||
| Total operating expenses | 118,259 | 109,014 | 9,245 | 451,146 | 342,929 | 108,217 | |||||||||||||||||||||||||||||
| Operating income | 250,494 | 186,735 | 63,759 | 737,380 | 238,878 | 498,502 | |||||||||||||||||||||||||||||
| Interest expense | 80,517 | 63,588 | 16,929 | 236,861 | 154,324 | 82,537 | |||||||||||||||||||||||||||||
| Other (income) expense, net | (16,431) | 10,214 | (26,645) | (48,044) | (17,150) | (30,894) | |||||||||||||||||||||||||||||
| Loss on extinguishment of debt, net | — | 14,997 | (14,997) | 14,997 | 10,975 | 4,022 | |||||||||||||||||||||||||||||
| Income (loss) before income from equity method investments and income taxes | 186,408 | 97,936 | 88,472 | 533,566 | 90,729 | 442,837 | |||||||||||||||||||||||||||||
| (Loss) income from equity method investments | (117,793) | (31,734) | (86,059) | (472,219) | 14,443 | (486,662) | |||||||||||||||||||||||||||||
| Tax provision (benefit) | 2,810 | 9,971 | (7,161) | (123,439) | 12,461 | (135,900) | |||||||||||||||||||||||||||||
| Net income (loss) | $ | 65,805 | $ | 56,231 | $ | 9,574 | $ | 184,786 | $ | 92,711 | $ | 92,075 | |||||||||||||||||||||||
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 was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.
Selling, general and administrative increased $36.2 million for the year ended December 31, 2022, compared to the year ended December 31, 2021. The increase was primarily attributable to higher payroll and professional fees associated with the continued expansion of our operations.
Transaction and integration costs
For the three months ended December 31, 2022, we incurred $9.4 million of transaction and integration costs, as compared to $5.6 million for the three months ended September 30, 2022. For the both the three months ended December 31, 2022 and three months ended September 30, 2022, transaction and integration costs incurred were primarily associated with closing the Sergipe Sale. Additionally, during the third quarter of 2022, we incurred costs to close the Energos Formation Transaction. Certain costs could not be deferred as a reduction of the principal balance of the financing obligation incurred as a result of the Energos Formation Transaction, and these costs were recognized in the third quarter of 2022.
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For the year ended December 31, 2022, we incurred $21.8 million for transaction and integration costs, as compared to $44.7 million for the year ended December 31, 2021. In the current year, we have incurred transaction and integration costs primarily associated with the Sergipe Sale and the Energos Formation Transaction. For the year ended December 31, 2021, we incurred transaction and integration costs in connection with the Mergers, which consisted primarily of financial advisory, legal accounting and consulting costs. We have incurred such integration costs to a lesser extent in the current year as the integration of GMLP and Hygo has progressed since the acquisition date.
Depreciation and amortization
Depreciation and amortization was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we continue to recognize depreciation expense for these vessels, resulting in consistent depreciation quarter over quarter.
Depreciation and amortization increased $44.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily due to the following:
•Our results of operations include depreciation expense for the vessels acquired in the Mergers for a full year. We recognized $20.8 million of incremental depreciation expense for the acquired vessels during the year ended December 31, 2022.
•Amortization of the value recorded for favorable and unfavorable contracts of an additional $18.3 million for the year ended December 31, 2022.
Asset impairment expense
In conjunction with the Sergipe Sale, the assets of CEBARRA met the criteria to be represented as held for sale and stated at fair value. These assets were reviewed for impairment upon classification to held for sale, and we recognized an impairment loss of $50.7 million in Asset impairment expense during the year ended December 31, 2022 in the consolidated statements of operations and comprehensive income (loss).
Interest expense
Interest expense increased by $16.9 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The increase was primarily due to the higher borrowing costs associated with financing obligations incurred as a result of the Energos Formation Transaction. 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 and vessel operating expenses from the charter of these vessels to third parties. The revenue recognized from third-party charters services the financing obligation, resulting in higher interest expense.
Interest expense increased by $82.5 million for the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increase was primarily due to an increase in total principal outstanding, including obligations incurred as a result of the Energos Formation Transaction, under which we incur higher borrowing costs. The total principal balance on outstanding facilities was $4,582.3 million as of December 31, 2022 as compared to total outstanding debt of $3,896.2 million as of December 31, 2021.
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Other (income) expense, net
Other (income) expense, net was $(16.4) million and $10.2 million for the three months ended December 31, 2022 and September 30, 2022, respectively. Other (income) expense, net was $(48.0) million and $(17.2) million for the year ended December 31, 2022 and December 31, 2021, respectively.
Other (income) expense, net recognized in the three months ended December 31, 2022 was primarily comprised of a $20.4 million gain related to the settlement of the foreign currency forward during the fourth quarter of 2022.
Other (income) expense, net recognized in the year ended December 31, 2022 was primarily comprised of a $20.4 million gain related to the settlement of the foreign currency forward during the fourth quarter of 2022 and changes in the fair value of the cross-currency interest rate swap and the interest rate swap resulting in income of $31.0 million.
Loss on extinguishment of debt
Loss on extinguishment of debt was $15.0 million for the year ended December 31, 2022 as a result of the extinguishment of the Vessel Term Loan Facility and sale leaseback financing arrangements with VIEs with proceeds from the Energos Formation Transaction. The Debenture Loan was also extinguished in the third quarter of 2022. There is no additional loss from the three months ended September 30, 2022 to the three months ended December 31, 2022, as there were no such transactions during the fourth quarter of 2022.
Loss on extinguishment of debt was $11.0 million for the year ended December 31, 2021. In November 2021, we exercised our option to terminate the sale leaseback agreement of the Eskimo assumed in the Mergers. The counterparty to this sale leaseback arrangement ("Eskimo SPV") was consolidated in our financial statements subsequent to the Mergers. In connection with the termination of this financing arrangement, we recognized a loss on extinguishment of debt based on the difference between the repurchase price under the sale leaseback arrangement and the carrying value of the net assets of the Eskimo SPV upon deconsolidation.
(Loss) income from equity method investments
We recognized losses from our equity method investments of $117.8 million and $31.7 million and for the three months ended December 31, 2022 and September 30, 2022, respectively. The loss in the fourth quarter of 2022 was primarily the result of the other-than-temporary impairment of our investment in Hilli of $118.6 million, as compared to an additional other-than-temporary impairment of the investment in CELSEPAR of $23.8 million recognized in the third quarter of 2022. Additionally, we began to recognize income from our equity method investment in Energos in the fourth quarter of 2022.
We recognized losses from our equity method investments of $472.2 million for the year ended December 31, 2022. For the year ended December 31, 2021, during the period after the completion of the Mergers, we recognized income from our investments in Hilli and CELSEPAR of $14.4 million. The loss in the current year was primarily driven by an other than temporary impairment of the investment in CELSEPAR and Hilli of $487.8 million recognized in connection with the Sergipe Sale, partially offset by income attributable to our investments in Energos.
Tax provision
We recognized a tax provision for the three months ended December 31, 2022 of $2.8 million compared to a tax provision of $10.0 million for the three months ended September 30, 2022, primarily driven by earnings recognized in jurisdictions with a lower tax rate offset by the realization of deferred tax assets in jurisdictions with a valuation allowance.
The change to the tax provision for the year ended December 31, 2022 resulted principally from the excess benefit on stock compensation, the remeasurement of a deferred income tax liability in conjunction with an internal reorganization and tax benefit associated with the OTTI of the investment in CELSEPAR. 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 Sergipe Sale, our equity method investment in CELSEPAR was directly held by a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil, resulting in a discrete benefit of $76.5 million recognized in the first quarter of 2022. Additionally, in the 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. This increase in tax benefit for the
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year ended December 31, 2022 was partially offset by additional tax expense resulting from an increase in pretax income for certain profitable operations.
Liquidity and Capital Resources
We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund developments and transactions. We have historically funded our developments through proceeds from our IPO, debt and equity financing, asset sales and cash from operations, including (capitalized terms defined in “—Long-Term Debt and Preferred Stock.” below):
•In April 2021, we issued $1,500.0 million of 2026 Notes; we also entered into the $200.0 million Revolving Facility that has a term of approximately five years. In February and May 2022, we amended the Revolving Facility to increase the borrowing capacity by $115.0 million and $125.0 million, respectively, for a total capacity under the Revolving Facility of $440.0 million.
•In January 2022, we entered into an agreement for the issuance of the South Power 2029 Bonds secured by our CHP Plant. In 2022, we received proceeds of $221.8 million from the issuance of South Power 2029 Bonds.
•In August 2022, we completed the Energos Formation Transaction, receiving cash proceeds of approximately $1.85 billion. We used $882.5 million of the proceeds for the repayment of the existing Vessel Term Loan and existing sale leaseback facilities.
•Upon closing of the Sergipe Sale in the fourth quarter of 2022, we received proceeds of approximately $530.0 million, inclusive of approximately $20.4 million of proceeds received from two foreign currency contingent, non-deliverable forwards that were entered into to manage foreign currency impacts of the sale.
•To fund the construction of our Barcarena Power Plant, we borrowed $200.0 million in the third and fourth quarters of 2022 under the Barcarena Term Loan.
We have assumed total committed expenditures for all completed and existing projects to be approximately $3,826 million, with approximately $2,473 million having already been spent through December 31, 2022. This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant and Santa Catarina Facility. We expect fully completed Fast LNG units to cost between $800 million and $900 million per unit. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct 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. 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 borrowings under existing and future debt facilities.
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 Board of Directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our Board of Directors may deem relevant.
As of December 31, 2022, we have spent approximately $128.6 million to develop the Pennsylvania Facility. Approximately $22.5 of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG
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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.
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, 2022:
| (in thousands) | Total | Year 1 | Years 2 to 3 | Years 4 to 5 | More than 5 years | ||||||||||||||||||||||||
| Long-term debt obligations | $ | 7,106,259 | $ | 278,229 | $ | 2,080,532 | $ | 2,039,111 | $ | 2,708,387 | |||||||||||||||||||
| Purchase obligations | 20,833,093 | 2,056,856 | 2,053,995 | 1,928,998 | 14,793,244 | ||||||||||||||||||||||||
| Lease obligations | 497,087 | 74,369 | 135,131 | 104,195 | 183,392 | ||||||||||||||||||||||||
| Total | $ | 28,436,439 | $ | 2,409,454 | $ | 4,269,658 | $ | 4,072,304 | $ | 17,685,023 | |||||||||||||||||||
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, 2022. A portion of the debt service amounts of the Vessel Financing Obligation (defined below) is amounts paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above.
Purchase obligations
The Company is party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. 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, 2022.
We have construction purchase commitments in connection with our development projects, including Fast LNG, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and our Santa Catarina Facility. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.
Lease obligations
Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease.
The Company currently has five vessels under time charter leases with remaining non-cancellable terms ranging from one month to nine years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services.
We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 15 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately 22 years with an automatic renewal term of five years for up to an additional 20 years.
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Office space includes space shared with affiliated companies in New York, as well as offices in Houston, New Orleans, and Rio de Janeiro, which have lease terms between one to nine years.
Cash Flows
The following table summarizes the changes to our cash flows for the year ended December 31, 2022 and 2021, respectively:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | Change | ||||||||||||||
| Cash flows from: | |||||||||||||||||
| Operating activities | $ | 355,111 | $ | 84,770 | $ | 270,341 | |||||||||||
| Investing activities | (82,726) | (2,273,561) | 2,190,835 | ||||||||||||||
| Financing activities | 321,957 | 1,816,944 | (1,494,987) | ||||||||||||||
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $ | 594,342 | $ | (371,847) | $ | 966,189 | |||||||||||
Cash provided by operating activities
Our cash flow provided by operating activities was $355.1 million for the year ended December 31, 2022, which increased by $270.3 million from cash provided by operating activities of $84.8 million for the year ended December 31, 2021. Our net income for the year ended December 31, 2022, when adjusted for non-cash items, increased by $227.3 million from the year ended December 31, 2021. Changes in working capital accounts, primarily increases in accounts payable and accrued liabilities, also increased the cash provided by operating activities in 2022.
Cash used in investing activities
Our cash flow used in investing activities was $82.7 million for the year ended December 31, 2022, which decreased by $2,190.8 million from cash used in investing activities of $2,273.6 million for the year ended December 31, 2021. Cash outflows from investing activities during the year ended December 31, 2022 were used for continued development of our Fast LNG solution, La Paz Facility, Santa Catarina Facility, and Barcarena Facility. Cash outflows for capital expenditures of $1,174.0 million were partially funded from proceeds of $593.0 million from the sale of the finance lease of the Nanook and proceeds of $500.1 million from the Sergipe Sale.
Cash used for the Mergers, net of cash acquired was $1,586.0 million for the year ended December 31, 2021. Cash outflows for investing activities during the year ended year ended December 31, 2021 were also used for continued development of the Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG Solution.
Cash provided by financing activities
Our cash flow provided by financing activities was $322.0 million for the year ended December 31, 2022, which decreased by $1,495.0 million from cash provided by financing activities of $1,816.9 million for the year ended December 31, 2021. Cash provided by financing activities during the year ended December 31, 2022 primarily consisted of proceeds received from issuance of debt of $2,032.0 million, offset by repayments of debt of $1,520.8 million, payment of dividends of $99.1 million and payments related to tax withholding for share-based compensation of $72.6 million.
Cash provided by financing activities during the year ended December 31, 2021 primarily consisted of proceeds received from the borrowings under the 2026 Notes of $1,500.0 million, draw of $200.0 million on the Revolving Facility, and borrowing of $430.0 million under the Vessel Term Loan Facility. The proceeds received were further offset by repayments of debt, primarily the settlement of the sale-leaseback financing arrangement of the Eskimo for a total payment of $190.5 million, financing fees paid in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the year ended December 31, 2021.
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Long-Term Debt and Preferred Stock
2025 Notes
In September 2020, we issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.
We used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.
In December 2020, we issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). As of December 31, 2022 and 2021, remaining unamortized deferred financing costs for the 2025 Notes were $6,649 and $8,804, respectively.
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”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes.
We used the net proceeds from this offering to fund the cash consideration for the Mergers and pay related fees and expenses.
In connection with the issuance of the 2026 Notes, we incurred $25.2 million in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the consolidated balance sheets. As of December 31, 2022 and 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $18.4 million and $22.5 million, respectively.
Vessel Financing Obligation
In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels. 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, on August 15th, 2022, we accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation of $1.4billion for consideration received from the Purchaser.
We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we 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
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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.
The lease terms for the charter agreements were for periods of up to 20 years. In connection with closing the Energos Formation Transaction, we incurred $10.0 million in origination, structuring and other fees, of which $3.0 million was allocated to the sale of the Nanook and recognized as Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss). Financing costs of $7.0 million were allocated and deferred as a reduction of the principal balance of the financing obligation on the consolidated balance sheets. As of December 31, 2022, the remaining unamortized deferred financing costs for the Vessel Financing Obligation was $6.9 million.
South Power 2029 Bonds
In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100.0 million. The CHP Facility was secured by a mortgage over the lease of the site on which our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”) is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285.0 million in South Power 2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. During the year ended December 31, 2022, the Company issued $121,824, of South Power 2029 Bonds for a total amount outstanding of $221,824 as of December 31, 2022.
The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.
South Power 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 are in compliance with all covenants as of December 31, 2022.
In conjunction with obtaining the CHP Facility, we incurred $3.2 million in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional third-party fees associated with such lenders of $0.3 million were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $5.6 million and $3.2 million, respectively.
Barcarena Term Loan
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 will be utilized to fund construction of the Barcarena Power Plant. As of December 31, 2022, the loan has been 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%. Additionally, undrawn balances incur a commitment fee of 1.9%.
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. We are required to comply with customary affirmative and negative covenants, and the Barcarena Term Loan also provides for
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customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2022.
We incurred $4.0 million of structuring and other fees, and such fees have been deferred as a reduction to the principal balance of the Barcarena Term Loan. As of December 31, 2022, the remaining unamortized deferred financing costs for the Barcarena Term Loan was $3.1 million.
Vessel Term Loan Facility
In September 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”). Under this facility, we borrowed an initial amount of $430.0 million. Loans under the Vessel Term Loan Facility had an interest at a rate of LIBOR plus a margin of 3%. The Vessel Term Loan Facility was repaid in quarterly installments of $15.4 million, with the final repayment date in September 2024.
Obligations under the Vessel Term Loan Facility were guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of December 31, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $660.6 million.
On August 3, 2022, we exercised the accordion feature under the Vessel Term Loan Facility, drawing $115.0 million, increasing the total principal outstanding to $498.9 million. Net proceeds of $113.9 million were received, and origination and other fees of $1.2 million were deferred as a reduction to the balance of the Vessel Term Loan Facility. As part of the Energos Formation Transaction, all amounts outstanding under the Vessel Term Loan Facility, including this additional principal draw, were repaid. Unamortized deferred financing costs of $5.4 million were recognized as Loss on extinguishment of debt in the consolidated statements of operations and comprehensive income (loss).
Debenture Loan
As part of the Hygo Merger, we assumed non-convertible Brazilian debentures in the aggregate principal amount of BRL 255.6 million due September 2024 (the “Debenture Loan”) bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65%. The Debenture Loan was recognized at fair value of $44.6 million on the date of the Hygo Merger, and the discount recognized in purchase accounting resulted in additional interest expense until maturity. Interest and principal was payable on the Debenture Loan semi-annually on September 13 and March 13.
In the third quarter of 2022, we repaid the outstanding amount of the Debenture Loan of BRL 198.6 million ($39.2 million); unamortized adjustments to the fair value of the Debenture Loan recognized as a result of the Mergers of $0.5 million was recognized as Loss on extinguishment of debt, net in the consolidated statement of operations and comprehensive income (loss).
Revolving Facility
In April 2021, we entered into a $200.0 million senior secured revolving credit facility (the "Revolving Facility"). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). In February and May 2022, the Revolving Facility was amended to increase the borrowing capacity by $115.0 million and $125.0 million, respectively, for a total capacity under the Revolving Facility of $440.0 million. Letters of credit issued under the $100.0 million letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for us to extend the maturity date once in a one-year increment.
Borrowings under the Revolving Facility bear interest at a rate equal to SOFR plus 0.15% plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and SOFR plus 0.15% plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0% SOFR floor. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.
The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries. We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to
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Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 until maturity. We were in compliance with all covenants as of December 31, 2022.
We incurred $5.4 million in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees incurred to expand the facility in 2022. These costs have been capitalized within Other non-current assets on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $5.2 million and $3.8 million, respectively.
In February 2023, the Revolving Credit Facility was amended to increase the facility by $301.7 million, for a total capacity under the Revolving Facility of $741.7 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants.
SPV Leasebacks and Loans
As part of the Mergers, we assumed the following debt of entities that were consolidated as VIEs. We were the primary beneficiary of these VIEs, and therefore these loan facilities were presented as part of our consolidated financial statements until these arrangements were terminated in conjunction with the Energos Formation Transaction.
Nanook SPV facility
In September 2018, the Nanook was sold to a subsidiary of CCB Financial Leasing Corporation Limited, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years. We had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period. The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, had a long-term loan facility due to its parent that was denominated in USD and bore interest at a fixed rate of 2.5%.
Penguin SPV facility
In December 2019, the Penguin was sold to a subsidiary of Oriental Shipping Company, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years. We had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period. The SPV, Oriental Fleet LNG 02 Limited, the owner of the Penguin, had a long-term loan facility that was denominated in USD and bore interest at LIBOR plus a margin of 1.7%.
Celsius SPV facility
In March 2020, the Celsius was sold to a subsidiary of AVIC International Leasing Company Limited, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years. We had options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period. The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, had two long-term loan facilities that were denominated in USD. The first facility was paid in quarterly installments over seven years that bore an interest rate of LIBOR plus a margin of 1.8%. The second facility with its parent bore a fixed interest rate of 4.0%.
As part of the Energos Formation Transaction, we exercised our option to repurchase the Penguin, Celsius, and Nanook vessels for a total payment of $380.2 million. After exercising the repurchase options, we no longer had a controlling financial interest in these VIEs and deconsolidated the VIEs. We recognized a loss of $9.1 million from exiting this financing arrangements in Loss on extinguishment of debt, net in the consolidated statements of operations and comprehensive income (loss).
Series A Preferred Units
The 8.75% Series A Cumulative Redeemable Preferred Units issued by GMLP (the “Series A Preferred Units”) remained outstanding following the GMLP Merger and were recognized as non-controlling interest on the consolidated
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balance sheets. Distributions on the Series A Preferred Units are payable out of amounts legally available therefor at a rate equal to 8.75% per annum of the stated liquidation preference. In the event of a liquidation, dissolution or winding up, whether voluntary or involuntary, holders of Series A Preferred Units will have the right to receive a liquidation preference of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of payment, whether declared or not. At any time on or after October 31, 2022, the Series A Preferred Units may be redeemed, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not.
Golar Hilli Leaseback
We account for our investment in Hilli LLC under the equity method of accounting. The debt obligations of Hilli LLC and its subsidiaries are not reported separately in our consolidated financial statements. Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC and is a party to a Memorandum of Agreement with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). Under the Hilli Facility, Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%. Our 50% share of Hilli Corp’s indebtedness of $646.5 million amounted to $323.3 million as of December 31, 2022.
As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. We also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under its tolling agreement. Certain of our subsidiaries are required to comply with the following covenants and ratios: (i) free liquid assets of at least $30 million throughout the Hilli Leaseback period; (ii) a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; and (iii) a consolidated tangible net worth of $124.0 million. We were in compliance with these covenants as of December 31, 2022.
Letter of Credit Facility
In July 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to $75 million. In July 2022, the 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. The letters of credit bear interest at a rate equal to (i) a base rate equal to the higher of the rate last quoted by The Wall Street Journal as the “Prime Rate” and a rate tied to the Federal Reserve Bank of New York, plus 0.50%, plus (ii) an applicable margin of 2.25%. We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash. A portion of our restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital needs of the business.
In February 2023, the uncommitted letter of credit and reimbursement agreement was upsized to $325 million; no changes to interest rates or other terms were made as part of this amendment.
Summary of Critical Accounting Estimates
The preparation of consolidated financial statements in conformity with GAAP requires us 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. We evaluate our estimates and related assumptions regularly, and 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.
Impairment of equity method investments
Equity method investments are assessed for impairment when events or changes in circumstances indicate a loss in value may have occurred. In 2022, we sold our equity method investment in CELSEPAR, and in the first quarter of 2023, we have announced our intention to exchange our interest in Hilli LLC for cash and NFE shares, and these events have triggered an analysis to review the recoverability of the carrying value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred.
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In the second quarter of 2022, we considered whether there was any indication of impairment of the equity method investment in CELSEPAR and the long-lived assets of CEBARRA due to the Sergipe Sale. NFE determined that there was an OTTI of the CELSEPAR equity method investment and an impairment of CEBARRA long-lived assets. The decline in fair value of these investments was driven by the impact of significant increases in risk-free rates to future cash flows, as well as the country specific risk premium observed in connection with where such investment is held, in the second quarter of 2022.
Our estimate of fair value used in the impairment assessments was based on the purchase price in the SPA, as adjusted by contractual adjustments expected to be made to this purchase price at Closing. Judgments used to estimate the fair value included the estimation of expected adjustment to the purchase price and the allocation of the purchase price between CELSEPAR and CEBARRA.
In connection with our analysis for the recoverability of our interest in Hilli, we estimated the fair value of the investment as of December 31, 2022 based on discounted cash flows using an income approach reflecting certain Level 3 inputs. This fair value was corroborated utilizing the terms of the Hilli Exchange linked to market price of NFE shares. The inputs into an income approach, particularly the discount rate, are judgmental, and we considered a range of results using discount rates from 11.5% to 13.5%. Our corroboration of the calculated impairment to other information validated our chosen assumptions. Judgement is also required to determine if the decline in estimated fair values is other than temporary. The decline in fair value of our interest in Hilli was primarily driven by the impact of increases in risk-free rates to future cash flows.
When an other-than-temporary impairment is identified, the excess of the carrying value over the estimated fair value is recognized as an impairment loss in (Loss) income from equity method investments.
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.
The recent geopolitical events in Europe have substantially impacted natural gas and LNG markets with unprecedented price increases and volatility. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a contractual spread. Additionally, due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. Based on the long-term nature of our supply and customer contracts, the nature of the pricing in these contracts and the market value of our underlying assets, changes in the price of natural gas or LNG do not indicate that a recoverability assessment of our assets is necessary. Further, with our own LNG production from FLNG facilities expected to commence in 2023, we plan to further mitigate our exposure to variability in LNG and natural gas prices.
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. We
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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.
Allocation of Vessel Financing Obligation
To account for the Energos Formation Transaction, we allocated $1.85 billion of proceeds received between the proceeds received for the sale of a financial asset (net investment in lease of the Nanook) and proceeds that are a financing obligation due to the failed sale leasebacks of ten vessels included in the Energos Formation Transaction. The Company allocated the proceeds using estimates of expected cash flows attributable to each vessel from both third party and NFE charters, which were discounted using counterparty market discount rates. The amortization of the financing obligation was calculated using the effective interest rate method. Upon termination of the NFE's charter of the vessels, we will derecognize the value of the vessel recorded in property, plant and equipment and the remaining financing obligation. The effective interest rate was adjusted to ensure that there is no loss recognized at the end of the charter term.
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.
For our PSUs, we reassess the probability of the achievement of the performance metric each reporting period to estimate the amount of shares that will vest. Any increase or decrease in share-based compensation expense resulting from an adjustment in the estimated vesting is treated as a cumulative catch-up in the period of adjustment. Our estimate of whether the performance metric will be met is impacted by the timing of our development projects becoming operational and our ability to achieve the expected results of operations, execution of definitive agreements for new projects, costs of LNG and our ability to execute sale of LNG cargos at favorable pricing and facilitate delivery of these cargos during periods of significant volatility in LNG prices. If any of the assumptions or estimates used change significantly, share-based compensation expense may differ materially from what we have recorded in the current period.
Business combinations and goodwill
We evaluate each purchase transaction to determine whether the acquired assets meet the definition of a business. If substantially all of the fair value of gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, then the set of transferred assets and activities is not a business. If not, for an acquisition to be considered a business, it would have to include an input and a substantive process that together significantly contribute to the ability to create outputs. A substantive process is not ancillary or minor, cannot be replaced without significant costs, effort or delay or is otherwise considered unique or scarce. To qualify as a business without outputs, the acquired assets would require an organized workforce with the necessary skills, knowledge and experience that performs a substantive process.
For acquisitions that are not deemed to be businesses, the assets acquired are recognized based on their cost to us as the acquirer, and no gain or loss is recognized. The cost of assets acquired in a group is allocated to individual assets within the group based on their relative fair values and no goodwill is recognized. Transaction costs related to acquisition of assets are included in the cost basis of the assets acquired.
We account for acquisitions that qualify as business combinations by applying the acquisition method. Transaction costs related to the acquisition of a business are expensed as incurred and excluded from the fair value of consideration transferred. Under the acquisition method of accounting, the identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity are recognized and measured at their estimated fair values. The excess of the fair value of consideration transferred over the fair values of identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity, net of fair value of any previously held interest in the acquired entity, is recorded as goodwill.
The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests. Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, vessel market day rates, and discount rates. The Company estimated the fair value of the vessels acquired in the Mergers using a combination of the
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income approach and the cost approach, which determines the replacement costs for the vessel assets, adjusting for age and condition. Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. As a result, actual results may differ from these estimates. During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill. Upon the conclusion of a measurement period, any subsequent adjustments are recorded to earnings.
We use estimates, assumptions and judgments when assessing the recoverability of goodwill. We test for impairment on an annual basis, or more frequently if a significant event of circumstance indicates the carrying amounts may not be recoverable. The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which the goodwill is assigned is less than the carrying value. If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss.
We completed our annual goodwill impairment evaluation using a qualitative analysis assessment during the fourth quarter of 2022. Under the qualitative assessment, we consider several qualitative factors, including macroeconomic conditions (including changes in interest rates and foreign currency exchange rates), industry and market considerations (including demand for cleaner energy sources and the market price for LNG), the recent and projected financial performance of the reporting unit, as well as other factors.
There was no indication of impairments of goodwill for the year ended December 31, 2022.
Recent Accounting Standards
For descriptions of recently issued accounting standards, refer to “Note 3. Adoption of new and revised standards” of our notes to consolidated financial statements included in this Annual Report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks.
In the normal course of business, the Company encounters several significant types of market risks including commodity and interest rate risks.
Commodity Price Risk
Commodity price risk is the risk of loss arising from adverse changes in market rates and prices. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with 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. To mitigate the effect of fluctuations in LNG prices on our operations, in the third quarter of 2022, we entered into two commodity swap transactions which settled for gains totaling $57.5 million. In addition, during the fourth quarter of 2022, we entered into another commodity swap transaction which will settled in 2023, and we recognized an unrealized $104.8 million gain on this swap.
Interest Rate Risk
The 2025 Notes, 2026 Notes, and South Power 2029 Bonds were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the 2025 Notes, 2026 Notes and South Power 2029 Bonds but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $83.0 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve.
Interest under the Barcarena Term Loan has a component based on Secured Overnight Financing Rate ("SOFR"). A 100-basis point increase or decrease in the market interest rate would decrease or increase our annual interest expense by approximately $2 million.
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Foreign Currency Exchange Risk
After the completion of the Hygo Merger, we began to have more significant transactions, assets and liabilities denominated in Brazilian reais; our Brazilian subsidiaries and investments receive income and pays expenses in Brazilian reais. During the year, the company entered into two foreign currency contingent non-deliverable forwards and settled a cross-currency interest rate swap. Based on our Brazilian reais revenues and expenses for the year, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations.
Outside of Brazil, our operations are primarily conducted in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions other than Brazil that are paid in local currencies, but we expect our international operations to continue to grow in the near term.
Item 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. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2022. 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, 2022 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2022 that has materially affected, or is 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, 2022, 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
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Control – Integrated Framework (2013).” Based on this assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2022.
The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by EY, an independent registered public accounting firm, as stated in their report, which appears herein.
Item 9B. Other Information.
On February 27, 2023, our board of directors appointed Mr. Timothy W. Jay as a director to our board effective as of March 5, 2023. Mr. Jay was elected a Class II director of the Board and will serve until the Company’s 2024 annual meeting of shareholders and until his successor is duly elected and qualified or until his earlier death, resignation or removal.
Mr. Jay, 63, has worked as Head of Government Bond Sales and Rates Trader at CRT Capital Group LLC, a financial services firm, from 2009 until his retirement in 2016. From 2005 to 2008, he served as Co-Managing Partner at Rockridge Advisors LLC, a multi-strategy hedge fund. Prior to 2005, Mr. Jay worked for Lehman Brothers as a Government Bond Trader, Head of Global Government Bond Business and a Liquid Markets Head Trader. During the same time, from 1996 to 2006, Mr. Jay served as both Chairman and Vice Chairman of the Treasury Borrowing Advisory Committee, which regularly advised the U.S. Treasury and the Federal Reserve Board on policy. Mr. Jay has also served as a public company director, having served on the Board of Directors of Intrawest Resorts Holdings from 2013 to 2017.
Mr. Jay will receive the standard annual Board compensation for non-employee directors for 2023 pro-rated for the date that he joined the board. In connection with his election, the Company entered into its customary indemnification agreement with Mr. Jay. There are no transactions between Mr. Jay and the Company that would require disclosure under Item 404(a) of Regulation S-K.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
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Part III
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, 2022 in connection with our 2023 annual meeting of shareholders and is incorporated herein by reference.
Item 11. Executive Compensation
The information required by this Item 11 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2022 in connection with our 2023 annual meeting of shareholders and is incorporated herein by reference.
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 Proxy Statement to be filed with the SEC within 120 days after December 31, 2022 in connection with our 2023 annual meeting of shareholders and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item 13 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2022 in connection with our 2023 annual meeting of shareholders and is incorporated herein by reference.
Item 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 with the SEC within 120 days after December 31, 2022 in connection with our 2023 annual meeting of shareholders and is incorporated herein by reference.
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Part IV
Item 15. Exhibits, Financial Statement Schedules.
The 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 of page F-1.
The report of New Fortress Energy’s independent registered public accounting firm (PCAOB ID:#42) with respect to the above-referenced financial statements and their report on internal control over financial reporting are included in Item 8 and Item 9A of this Form 10-K at the page numbers F-2 and F-4, respectively. Their consent appears as Exhibit 23.1 of this Form 10-K.
(2) Financial Statement Schedules.
(b) Exhibits.
The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.
| Exhibit Number | Description | ||||
| Certificate of Conversion of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). | |||||
| Certificate of Incorporation of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). | |||||
| Bylaws of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 7, 2020). | |||||
| Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.1 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2022). | |||||
| 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, filed with the SEC 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, 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 November 8, 2022). | |||||
| Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardone (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on 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). | |||||
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| Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). | |||||
| 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 Form Current Report on 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 (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019). | |||||
| 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. | |||||
| Indenture, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020). | |||||
| Pledge and Security Agreement, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020). | |||||
85
| First Supplemental Indenture, dated December 17, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on December 18, 2020). | |||||
| Second Supplemental Indenture, dated as of March 1, 2021, between NFE US Holdings LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| Third Supplemental Indenture, dated as of June 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| Fourth Supplemental Indenture, dated as of September 13, 2021, between NFE Mexico Power Holdings Limited and NFE Mexico Terminal Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| Fifth Supplemental Indenture, dated as of November 24, 2021, between NFE International Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| 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. | |||||
| Seventh Supplemental Indenture, dated as of December 27, 2022, between NFE Andromeda Chartering LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| Indenture, dated April 12, 2021, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021). | |||||
| Pledge and Security Agreement, dated April 12, 2021, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021). | |||||
| First Supplemental Indenture, dated as of June 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| 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. | |||||
| Third Supplemental Indenture, dated as of November 24, 2021, between NFE International Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
86
| 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. | |||||
| Fifth Supplemental Indenture, dated as of December 27, 2022, between NFE Andromeda Chartering LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee. | |||||
| Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc,. as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021). | |||||
| 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. 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. | |||||
| Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GLNG and certain other parties thereto (incorporated by reference to Exhibit 10.30 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). | |||||
| Indemnity Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and certain affiliates of Stonepeak (incorporated by reference to Exhibit 10.31 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). | |||||
| Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GMLP, GLNG and certain parties thereto (incorporated by reference to Exhibit 10.32 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). | |||||
87
| Tax Indemnification Agreement, dated as of April 15, 2021, by and between NFE International and GLNG (incorporated by reference to Exhibit 10.33 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021). | |||||
| Share Purchase Agreement, dated as of May 31, 2022, by and among LNG Power Limited, Ebrasil Energia Ltda., the individual DC Energia Sellers set forth therein, collectively as Sellers, Eneva S.A., as Buyer, and Eletricidade do Brasil S.A. -Ebrasil, as guarantor for the obligations of the DC Energia Sellers (incorporated by reference to Exhibit 10.38 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2022). | |||||
| 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). | |||||
| Incremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated February 6, 2023, by and among New Fortress Energy Inc., the guarantors party thereto, Natixis, New York Branch, as Administrative Agent and as Issuing Bank, Credit Agricole Corporate and Investment Bank, as Issuing Bank, and Sumitomo Mitsui Banking Corporation, as Issuing Bank | |||||
| 10.46 | Underwriting Agreement, dated December 14, 2022, by and among New Fortress Energy Inc., Energy Transition Holdings LLC and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on December 16, 2022). | ||||
| Consent of Ernst & Young LLP, independent registered public accounting firm. | |||||
| Certification by Chief Executive Officer pursuant to Rule 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. | |||||
| Certification by Chief Financial Officer pursuant to Rule 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. | |||||
| Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | |||||
| Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | |||||
| 101.INS* | Inline XBRL Instance Document | ||||
| 101.SCH* | Inline XBRL Schema Document | ||||
| 101.CAL* | Inline XBRL Calculation Linkbase Document | ||||
| 101.LAB* | Inline XBRL Label Linkbase Document | ||||
| 101.PRE* | Inline XBRL Presentation Linkbase Document | ||||
88
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||
| 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
89
Item 16. Form 10-K Summary.
None.
90
SIGNATURES
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 1, 2023 | ||||||||
| By: | /s/ Christopher Guinta | |||||||
| Name: | Christopher S. Guinta | |||||||
| 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 | Date | ||||||||||||
| /s/ Wesley R. Edens | Chief Executive Officer and Chairman (Principal Executive Officer) | March 1, 2023 | ||||||||||||
| Wesley R. Edens | ||||||||||||||
| /s/ Christopher S. Guinta | Chief Financial Officer (Principal Financial Officer) | March 1, 2023 | ||||||||||||
| Christopher S. Guinta | ||||||||||||||
| /s/ Yunyoung Shin | Chief Accounting Officer (Principal Accounting Officer) | March 1, 2023 | ||||||||||||
| Yunyoung Shin | ||||||||||||||
| /s/ Randal A. Nardone | Director | March 1, 2023 | ||||||||||||
| Randal A. Nardone | ||||||||||||||
| /s/ C. William Griffin | Director | March 1, 2023 | ||||||||||||
| C. William Griffin | ||||||||||||||
| /s/ John J. Mack | Director | March 1, 2023 | ||||||||||||
| John J. Mack | ||||||||||||||
| /s/ Matthew Wilkinson | Director | March 1, 2023 | ||||||||||||
| Matthew Wilkinson | ||||||||||||||
| /s/ David J. Grain | Director | March 1, 2023 | ||||||||||||
| David J. Grain | ||||||||||||||
| /s/ Desmond Iain Catterall | Director | March 1, 2023 | ||||||||||||
| Desmond Iain Catterall | ||||||||||||||
| /s/ Katherine E. Wanner | Director | March 1, 2023 | ||||||||||||
| Katherine E. Wanner | ||||||||||||||
91
Index to Consolidated Financial Statements
F-1
Report of Independent Registered Public Accounting Firm
To the Stockholders 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, 2022 and 2021, the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 1, 2023 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
F-2
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, 2022, the balance of construction in progress totaled $2,419 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. | |||||||
| 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. | |||||||
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2016.
Philadelphia, Pennsylvania
March 1, 2023
F-3
Report of Independent Registered Public Accounting Firm
To the Stockolders 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, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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, 2022, 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 2022 consolidated financial statements of the Company and our report dated March 1, 2023 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’s Report on Internal Control Over Financial 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 1, 2023
F-4
PART I
FINANCIAL INFORMATION
Item 8. Financial Statements
New Fortress Energy Inc.
Consolidated Balance Sheets
As of December 31, 2022 and 2021
(in thousands of U.S. dollars, except share and per share amounts)
| December 31, 2022 | December 31, 2021 | ||||||||||
| Assets | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 675,492 | $ | 187,509 | |||||||
| Restricted cash | 165,396 | 68,561 | |||||||||
Receivables, net of allowances of $884 and $164, respectively | 280,313 | 208,499 | |||||||||
| Inventory | 39,070 | 37,182 | |||||||||
| Prepaid expenses and other current assets, net | 226,883 | 83,115 | |||||||||
| Total current assets | 1,387,154 | 584,866 | |||||||||
| Construction in progress | 2,418,608 | 1,043,883 | |||||||||
| Property, plant and equipment, net | 2,116,727 | 2,137,936 | |||||||||
| Equity method investments | 392,306 | 1,182,013 | |||||||||
| Right-of-use assets | 377,877 | 309,663 | |||||||||
| Intangible assets, net | 85,897 | 142,944 | |||||||||
| Finance leases, net | 4,601 | 602,675 | |||||||||
| Goodwill | 776,760 | 760,135 | |||||||||
| Deferred tax assets, net | 8,074 | 5,999 | |||||||||
| Other non-current assets, net | 137,078 | 106,378 | |||||||||
| Total assets | $ | 7,705,082 | $ | 6,876,492 | |||||||
| Liabilities | |||||||||||
| Current liabilities | |||||||||||
| Current portion of long-term debt | $ | 64,820 | $ | 97,251 | |||||||
| Accounts payable | 80,387 | 68,085 | |||||||||
| Accrued liabilities | 1,162,412 | 244,025 | |||||||||
| Current lease liabilities | 48,741 | 47,114 | |||||||||
| Other current liabilities | 52,878 | 106,036 | |||||||||
| Total current liabilities | 1,409,238 | 562,511 | |||||||||
| Long-term debt | 4,476,865 | 3,757,879 | |||||||||
| Non-current lease liabilities | 302,121 | 234,060 | |||||||||
| Deferred tax liabilities, net | 25,989 | 269,513 | |||||||||
| Other long-term liabilities | 49,010 | 58,475 | |||||||||
| Total liabilities | 6,263,223 | 4,882,438 | |||||||||
| Commitments and contingencies (Note 22) | |||||||||||
| Stockholders’ equity | |||||||||||
Class A common stock, $0.01 par value, 750.0 million shares authorized, 208.8 million issued and outstanding as of December 31, 2022; 206.9 million issued and outstanding as of December 31, 2021 | 2,088 | 2,069 | |||||||||
| Additional paid-in capital | 1,170,254 | 1,923,990 | |||||||||
| Retained earnings (Accumulated deficit) | 62,080 | (132,399) | |||||||||
| Accumulated other comprehensive (loss) income | 55,398 | (2,085) | |||||||||
| Total stockholders’ equity attributable to NFE | 1,289,820 | 1,791,575 | |||||||||
| Non-controlling interest | 152,039 | 202,479 | |||||||||
| Total stockholders’ equity | 1,441,859 | 1,994,054 | |||||||||
| Total liabilities and stockholders’ equity | $ | 7,705,082 | $ | 6,876,492 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
New Fortress Energy Inc.
Consolidated Statements of Operations and Comprehensive Income (Loss)
For the years ended December 31, 2022, 2021 and 2020
(in thousands of U.S. dollars, except share and per share amounts)
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Revenues | |||||||||||||||||
| Operating revenue | $ | 1,978,645 | $ | 930,816 | $ | 318,311 | |||||||||||
| Vessel charter revenue | 357,158 | 230,809 | — | ||||||||||||||
| Other revenue | 32,469 | 161,185 | 133,339 | ||||||||||||||
| Total revenues | 2,368,272 | 1,322,810 | 451,650 | ||||||||||||||
| Operating expenses | |||||||||||||||||
| Cost of sales (exclusive of depreciation and amortization shown separately below) | 1,010,428 | 616,010 | 278,767 | ||||||||||||||
| Vessel operating expenses | 63,518 | 51,677 | — | ||||||||||||||
| Operations and maintenance | 105,800 | 73,316 | 47,581 | ||||||||||||||
| Selling, general and administrative | 236,051 | 199,881 | 120,142 | ||||||||||||||
| Transaction and integration costs | 21,796 | 44,671 | 4,028 | ||||||||||||||
| Contract termination charges and loss on mitigation sales | — | — | 124,114 | ||||||||||||||
| Depreciation and amortization | 142,640 | 98,377 | 32,376 | ||||||||||||||
| Asset impairment expense | 50,659 | — | — | ||||||||||||||
| Total operating expenses | 1,630,892 | 1,083,932 | 607,008 | ||||||||||||||
| Operating income (loss) | 737,380 | 238,878 | (155,358) | ||||||||||||||
| Interest expense | 236,861 | 154,324 | 65,723 | ||||||||||||||
| Other (income) expense, net | (48,044) | (17,150) | 5,005 | ||||||||||||||
| Loss on extinguishment of debt, net | 14,997 | 10,975 | 33,062 | ||||||||||||||
| Income (loss) before income from equity method investments and income taxes | 533,566 | 90,729 | (259,148) | ||||||||||||||
| (Loss) income from equity method investments | (472,219) | 14,443 | — | ||||||||||||||
| Tax (benefit) provision | (123,439) | 12,461 | 4,817 | ||||||||||||||
| Net income (loss) | 184,786 | 92,711 | (263,965) | ||||||||||||||
| Net loss attributable to non-controlling interest | 9,693 | 4,393 | 81,818 | ||||||||||||||
| Net income (loss) attributable to stockholders | $ | 194,479 | $ | 97,104 | $ | (182,147) | |||||||||||
| Net income (loss) per share – basic | $ | 0.93 | $ | 0.49 | $ | (1.71) | |||||||||||
| Net income (loss) per share – diluted | $ | 0.93 | $ | 0.47 | $ | (1.71) | |||||||||||
| Weighted average number of shares outstanding – basic | 209,501,298 | 198,593,042 | 106,654,918 | ||||||||||||||
| Weighted average number of shares outstanding – diluted | 209,854,413 | 201,703,176 | 106,654,918 | ||||||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Net income (loss) | $ | 184,786 | $ | 92,711 | $ | (263,965) | |||||||||||
| Currency translation adjustment | 68,403 | (3,489) | 2,005 | ||||||||||||||
| Comprehensive income (loss) | 253,189 | 89,222 | (261,960) | ||||||||||||||
| Comprehensive loss attributable to non-controlling interest | 10,795 | 5,615 | 80,025 | ||||||||||||||
| Comprehensive income (loss) attributable to stockholders | $ | 263,984 | $ | 94,837 | $ | (181,935) | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
New Fortress Energy Inc.
Consolidated Statements of Changes in Stockholders’ Equity
For the years ended December 31, 2022, 2021 and 2020
(in thousands of U.S. dollars, except share amounts)
| Class A shares | Class B shares | 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 | Shares | Amount | Shares | Amount | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of January 1, 2020 | 23,607,096 | $ | 130,658 | 144,342,572 | $ | — | — | $ | — | $ | — | $ | (45,823) | $ | (30) | $ | 302,519 | $ | 387,324 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Cumulative effect of accounting changes | — | — | — | — | — | — | — | (1,533) | — | (7,780) | (9,313) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Class A stock issued, net of issuance costs | — | — | — | — | 5,882,352 | 59 | 290,712 | — | — | — | 290,771 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | — | — | (182,147) | — | (81,818) | (263,965) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | — | — | 212 | 1,793 | 2,005 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-based compensation expense | — | 4,430 | — | — | — | — | 4,313 | — | — | — | 8,743 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of shares for vested RSUs | 1,224,436 | — | — | — | 160,317 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares withheld from employees related to share-based compensation, at cost | — | — | — | — | (593,911) | — | (6,468) | — | — | — | (6,468) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Exchange of NFI units | 144,342,572 | 206,587 | (144,342,572) | — | — | — | — | — | — | (206,587) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Conversion from LLC to Corporation | (169,174,104) | (341,675) | — | — | 169,174,104 | 1,687 | 339,988 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | — | (34,011) | — | — | — | (34,011) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2020 | — | — | — | — | 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 | |||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
New Fortress Energy Inc.
Consolidated Statements of Cash Flows
For the years ended December 31, 2022, 2021 and 2020
(in thousands of U.S. dollars)
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Net income (loss) | $ | 184,786 | $ | 92,711 | $ | (263,965) | |||||||||||
| Adjustments for: | |||||||||||||||||
| Amortization of deferred financing costs and debt guarantee, net | 2,536 | 14,116 | 10,519 | ||||||||||||||
| Depreciation and amortization | 143,589 | 99,544 | 33,303 | ||||||||||||||
| Loss (earnings) of equity method investees | 472,219 | (14,443) | — | ||||||||||||||
| Dividends received from equity method investees | 29,372 | 21,365 | — | ||||||||||||||
| Change in fair market value of derivatives | (136,811) | (8,691) | — | ||||||||||||||
| Contract termination charges and loss on mitigation sales | — | — | 19,114 | ||||||||||||||
| Deferred taxes | (279,536) | (8,825) | 2,754 | ||||||||||||||
| Share-based compensation | 30,382 | 37,043 | 8,743 | ||||||||||||||
| Asset impairment expense | 50,659 | — | — | ||||||||||||||
| Earnings recognized from vessels chartered to third parties transferred to Energos | (49,686) | — | — | ||||||||||||||
| Loss on extinguishment of debt | 14,997 | 10,975 | 37,090 | ||||||||||||||
| Loss on sale of net investment in lease | 11,592 | — | — | ||||||||||||||
| Other | (14,186) | (11,177) | 4,341 | ||||||||||||||
| Changes in operating assets and liabilities, net of acquisitions: | |||||||||||||||||
| (Increase) in receivables | (139,938) | (123,583) | (26,795) | ||||||||||||||
| (Increase) Decrease in inventories | (7,933) | (11,152) | 23,230 | ||||||||||||||
| (Increase) in other assets | (30,086) | (1,839) | (35,927) | ||||||||||||||
| Decrease in right-of-use assets | 63,593 | 28,576 | 41,452 | ||||||||||||||
| Increase in accounts payable/accrued liabilities | 67,741 | 17,527 | 55,514 | ||||||||||||||
| (Decrease) in lease liabilities | (63,493) | (36,126) | (42,094) | ||||||||||||||
| Increase (Decrease) in other liabilities | 5,314 | (21,251) | 7,155 | ||||||||||||||
| Net cash provided by (used in) operating activities | 355,111 | 84,770 | (125,566) | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Capital expenditures | (1,174,008) | (669,348) | (156,995) | ||||||||||||||
| 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 the sale of net investment in lease | 593,000 | — | — | ||||||||||||||
| Proceeds received from sale of equity method investment | 500,076 | — | — | ||||||||||||||
| Other investing activities | (1,794) | (9,354) | (636) | ||||||||||||||
| Net cash used in investing activities | (82,726) | (2,273,561) | (157,631) | ||||||||||||||
| Cash flows from financing activities | |||||||||||||||||
| Proceeds from borrowings of debt | 2,032,020 | 2,434,650 | 2,095,269 | ||||||||||||||
| Payment of deferred financing costs | (17,598) | (37,811) | (36,499) | ||||||||||||||
| Repayment of debt | (1,520,813) | (461,015) | (1,490,002) | ||||||||||||||
| Proceeds from issuance of Class A common stock | — | — | 291,992 | ||||||||||||||
| Payments related to tax withholdings for share-based compensation | (72,602) | (30,124) | (6,413) | ||||||||||||||
| Payment of dividends | (99,050) | (88,756) | (33,742) | ||||||||||||||
| Payment of stock issuance costs | — | — | (1,107) | ||||||||||||||
| Net cash provided by financing activities | 321,957 | 1,816,944 | 819,498 | ||||||||||||||
| Impact of changes in foreign exchange rates on cash and cash equivalents | (3,289) | 6,541 | — | ||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | 591,053 | (365,306) | 536,301 | ||||||||||||||
| Cash, cash equivalents and restricted cash – beginning of period | 264,030 | 629,336 | 93,035 | ||||||||||||||
| Cash, cash equivalents and restricted cash – end of period | $ | 855,083 | $ | 264,030 | $ | 629,336 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-8
New Fortress Energy Inc.
Consolidated Statements of Cash Flows
For the years ended December 31, 2022, 2021 and 2020
(in thousands of U.S. dollars)
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash paid for interest, net of capitalized interest | 160,618 | 154,249 | 27,255 | ||||||||||||||
| Cash paid for taxes | 151,210 | 17,319 | 58 | ||||||||||||||
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| 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 | $ | 284,390 | $ | 108,790 | $ | (12,786) | |||||||||||
| Liabilities associated with consideration paid for entities acquired in asset acquisitions | — | 10,520 | — | ||||||||||||||
| Consideration paid in shares for business combinations | — | 1,400,784 | — | ||||||||||||||
| Principal payments on financing obligation paid to Energos by third party charters | (24,949) | — | — | ||||||||||||||
| Investment in Energos | 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, | |||||||||||
| 2022 | 2021 | ||||||||||
| Cash and cash equivalents | 675,492 | 187,509 | |||||||||
| Current restricted cash | 165,396 | 68,561 | |||||||||
| Non-current restricted cash (Note 17) | 2,581 | 7,960 | |||||||||
| Cash and cash equivalents classified as held for sale | 11,614 | — | |||||||||
| Cash, cash equivalents and restricted cash – end of period | $ | 855,083 | $ | 264,030 | |||||||
Cash and cash equivalents as of December 31, 2022 includes $11,614 which have 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.
F-9
1. Organization
New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. The Company owns and operates natural gas and liquefied natural gas (" LNG") infrastructure, ships and logistics assets to rapidly deliver turnkey energy solutions to global markets. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, Brazil and Mexico. The Company has marine operations with vessels operating under time charters and in the spot market globally.
The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business.
2. Significant accounting policies
The principal 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 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.
A variable interest entity (“VIE”) is an entity that by design meets any of the following characteristics: (1) lacks sufficient equity to allow the entity to finance its activities without additional subordinated financial support; (2) as a group, equity investors do not have the ability to make significant decisions relating to the entity’s operations through voting rights, do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of the entity; or (3) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. The primary beneficiary of a VIE is required to consolidate the assets and liabilities of the VIE. The primary beneficiary is the party that has both (1) the power to direct the economic activities of the VIE that most significantly impact the VIE’s economic performance; and (2) through its interest in the VIE, the obligation to absorb the losses or the right to receive the benefits from the VIE that could potentially be significant to the VIE.
Non-controlling interests are classified as a separate component of equity on the consolidated balance sheets and consolidated statements of changes in stockholders’ equity. Additionally, net income (loss) and comprehensive income (loss) attributable to non-controlling interests are reflected separately from consolidated net income (loss) and comprehensive income (loss) in the consolidated statements of operations and comprehensive income (loss) 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 interests, even when the non-controlling interests’ basis has been reduced to zero.
(b)Use of estimates
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 inputs and assumptions to assess the recoverability of equity method investments and long-lived assets, as well as the total consideration and fair value of identifiable net assets related to acquisitions. 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.
F-10
(c)Foreign currencies
The Company has certain foreign subsidiaries in 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 conduct business in currencies other than their respective functional currencies. Transactions are remeasured to the respective subsidiaries’ functional currency at the exchange rate in effect on the respective dates of such transactions. Net realized foreign currency gains or losses relating to the differences between these recorded amounts and the functional currency equivalent actually received or paid are included within Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss). 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 accumulated other comprehensive income (loss). Accumulated foreign currency translation adjustments are reclassified from accumulated 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.
(e)Restricted cash
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.
(f)Receivables
Receivables are 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. 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 statements of operations and comprehensive income (loss).
(g)Inventories
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 statements of operations and comprehensive income (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 statements of operations and comprehensive income (loss) in instances where gas cannot be contained and recycled back into the production process.
F-11
(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. 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. 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
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 (loss); such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses.
Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul.
Drydocking expenditures, including drydocking expenditures related to vessels that were included in the Energos Formation Transaction (defined below), are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years. For vessels, the Company utilizes the “built-in overhaul” method of accounting 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. The cost of the drydocking is capitalized and depreciated until the next drydocking, estimated at five year intervals. If drydocking occurs prior to the expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).
The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:
| Useful life (Yrs) | |||||
| Vessels | 5-30 | ||||
| Terminal and power plant equipment | 4-24 | ||||
| CHP facilities | 4-20 | ||||
| Gas terminals | 5-24 | ||||
| ISO containers and associated equipment | 3-25 | ||||
| LNG liquefaction facilities | 20-40 | ||||
| Gas pipelines | 4-24 | ||||
| Leasehold improvements | 2-20 | ||||
The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.
Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the consolidated statements of operations and comprehensive income (loss). When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal.
F-12
(j)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.
(k)Investments in equity securities
Investments in equity securities are carried at fair value and included in Other non-current assets on the consolidated balance sheets, with gains or losses recorded in earnings in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).
(l)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 statements of operations and comprehensive income (loss).
(m)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, 2022 and 2021.
A goodwill impairment assessment compares the fair value of a respective reporting unit with its carrying amount, including goodwill. The estimate 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, 2022 and 2021.
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(n)Long-term debt and debt issuance costs
Costs directly related to the issuance of debt are reported on the consolidated 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 (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.
(o)Contingencies
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 recognize 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 disclose 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.
(p)Revenue recognition
Terminals and Infrastructure
Within the Terminals and Infrastructure segment, the Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from the Company’s natural gas-fueled infrastructure 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 delivered in containers transported by truck to customer sites but may also be delivered via vessel to an unloading point specified in a contract. Revenue from sales of LNG is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, the Company has presented Operating revenue on an aggregated basis.
The Company has concluded that variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.
The Company’s contracts with customers to supply natural gas or LNG may contain a lease of equipment or vessesls, which may be accounted for as a finance or operating lease. For the Company’s operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated the lease component. The lease component of such operating leases is recognized as in the consolidated statements of operations and comprehensive income (loss). The Company allocates consideration in agreements containing finance leases between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term.
The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net on the 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 income (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
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lease term and included in Other revenue in the consolidated statements of operations and comprehensive income (loss). The principal component of the lease payment is reflected as a reduction to the net investment in the lease.
In addition to the revenue recognized from the finance lease components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as the Company transfers control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and the Company recognizes revenue for the interest income component over the term of the financing as Other revenue.
The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the 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. 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 statements of operations and comprehensive income (loss) on a net basis and, accordingly, such taxes are excluded from reported revenues.
The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.
Ships
Charter contracts, that have a lease term greater than one year, for the use of the FSRUs and LNG carriers are leases as the contracts convey the right to obtain substantially all of the economic benefits from the use of the asset and allow the customer to direct the use of that asset.
At inception, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. 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 (loss). The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the consolidated statements of operations and comprehensive income (loss). The principal component of the lease payment is reflected as a reduction to the net investment in the lease. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the consolidated statements of operations and comprehensive income (loss).
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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 (loss). 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 revenues and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee 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 (loss) over the lease term.
The Company continues to be the accounting owner of vessels included in the Energos Formation Transaction (Note 5), and the Company accounts for third party charters of these vessels under the accounting policies for vessel leases described above. The third party charters of these vessels are operating leases, and revenue is recognized from these charters within Vessel charter revenue in the consolidated statements of operations and comprehensive income (loss).
(q)Leases, as lessee
The Company has entered into lease agreements for the use of LNG vessels, marine port space, office space, land and 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 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 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 Leases.
(r)Share-based compensation
The Company adopted the New Fortress Energy Inc. 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 units (“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 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.
The Company has granted PSUs to certain employees and non-employees. The PSUs contain a performance condition, and vesting is determined based on achievement of a performance metric in the year subsequent to the grant. Compensation
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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.
(s)Lessor expense recognition
Vessel operating expenses are recognized when incurred. Vessel operating expenses include crewing, repairs and maintenance, 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 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.
(t)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.
(u)Contract termination charges and loss on mitigation sales
The Company has long-term supply agreements to purchase LNG, and the Company may incur termination charges to the extent that the Company cancels such contractual arrangements. Further, if the Company 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 line in the consolidated statements of operations and comprehensive income (loss) because such costs are not related to inventory delivered to the Company’s customers.
During the year ended 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. We did not have such transactions during the years ended December 31, 2022 and 2021.
(v)Taxation
The Company accounts for income taxes in accordance with ASC 740, Accounting for Income 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 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 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.
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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, no deferred tax assets or liabilities are recorded related to GILTI.
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 Selling, general and administrative in the consolidated statements of operations and comprehensive income (loss).
(w)Net income (loss) per share
Basic net income (loss) per share (“EPS”) is computed by dividing net income (loss) attributable to Class A common stock by the weighted average number of shares of Class A common stock 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.
(x)Acquisitions
Business combinations are accounted for under the acquisition method. On acquisition, the identifiable assets acquired and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the purchase price over the fair values of the identifiable net assets acquired is recognized as goodwill. Acquisition related costs are expensed as incurred as Transaction and integration costs in the statements of operations and comprehensive income (loss). The results of operations of acquired businesses are included in the Company’s consolidated statements of operations and comprehensive income (loss) from the date of acquisition.
If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values.
(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 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 (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee.
The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss).
In 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.
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(z)Loss of control of subsidiary
When there is a loss of control over a subsidiary, the Company de-consolidates as of the date the Company ceases to have a 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 (loss), 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 also de-recognize any amounts previously recorded in other comprehensive income (loss).
(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.
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
(a)New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2022:
The Company has reviewed recently issued accounting pronouncements and concluded that such pronouncements are either not applicable to the Company or no material impact is expected in the consolidated financial statements as a result of future adoption.
(b)New and amended standards adopted by the Company:
In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity ("ASU 2020-06"). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. ASU 2020-06 is effective for public companies for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption of all amendments in the same period permitted. The adoption of this guidance in the first quarter of 2022 did not have a material impact on the Company’s financial position, results of operations or cash flows.
In December 2022, the FASB issued ASU 2022-06, Deferred of the Sunset Date of Topic 848, Reference Rate Reform, that defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024, after which entities are no longer permitted to apply the contract modification and hedge accounting relief. This ASU was effective upon issuance, and the
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adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.
4. Acquisitions
Hygo Merger
On April 15, 2021, the Company completed the acquisition of all of the outstanding common and preferred shares representing all voting interests of Hygo Energy Transition Ltd. ("Hygo"), a 50-50 joint venture between Golar LNG Limited (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd., a fund managed by Stonepeak Infrastructure Partners (“Stonepeak”), in exchange for 31,372,549 shares of NFE Class A common stock and $580,000 in cash (the "Hygo Merger"). The acquisition of Hygo expanded the Company’s footprint in South America with three gas-to-power projects in Brazil’s large and fast-growing market. The Company acquired included 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:
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| 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 has consolidated. These VIEs are SPVs (both defined below) for the sale and leaseback of certain vessels, and Hygo has no equity investment in these entities. The fair value of NCI was determined based on the valuation of the SPV’s external debt and the lease receivable asset associated with the sales leaseback transaction with Hygo’s subsidiary, using a discounted cash flow method.
The fair value of receivables acquired from Hygo is $8,009, which approximates the gross contractual amount; no material amounts were expected to be uncollectible.
Goodwill was calculated as the excess of the purchase price over the net assets acquired. Goodwill represents access to additional LNG and natural gas distribution systems and power markets, including workforce that will allow the Company to rapidly develop and deploy LNG to power solutions. While the goodwill is not deductible for local tax purposes, it is treated as an amortizable expense for the U.S. GILTI computation.
The Company’s results of operations for the year ended December 31, 2022 include Hygo’s result of operations for the entire period. Revenue and net loss attributable to Hygo during the period was $68,021 and $248,131, 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,
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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, which are expected to help support the Company's existing facilities and international business development pipeline. Acquired FSRUs are operating in Brazil, Indonesia and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market. assets acquired also included an interest in a floating natural gas liquefaction vessel (“FLNG”), the Hilli Episeyo (the "Hilli").
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:
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| GMLP | As of April 15, 2021 | ||||
| Assets Acquired | |||||
| Cash and cash equivalents | $ | 41,461 | |||
| Restricted cash | 24,816 | ||||
| Accounts receivable | 3,195 | ||||
| Inventory | 2,151 | ||||
| Other current assets | 2,789 | ||||
| Equity method investments | 355,500 | ||||
| Property, plant and equipment, net | 1,063,215 | ||||
| Intangible assets, net | 106,500 | ||||
| Deferred tax assets, net | 963 | ||||
| Other non-current assets | 4,400 | ||||
| Total assets acquired: | $ | 1,604,990 | |||
| Liabilities Assumed | |||||
| Current portion of long-term debt | $ | 158,073 | |||
| Accounts payable | 3,019 | ||||
| Accrued liabilities | 17,226 | ||||
| Other current liabilities | 73,774 | ||||
| Deferred tax liabilities, net | 14,907 | ||||
| Other non-current liabilities | 10,630 | ||||
| Total liabilities assumed: | 277,629 | ||||
| Non-controlling interest | 196,156 | ||||
| Net assets to be acquired: | 1,131,205 | ||||
| Goodwill | $ | 15,938 | |||
The fair value of GMLP’s NCI as of April 15, 2021 was $196,156, which represents the fair value of other investors’ interest in the Mazo, GMLP’s preferred units which were not acquired by the Company and the fair value of net assets of an SPV formed for the purpose of a sale and leaseback of the Eskimo. The fair value of GMLP’s preferred units and the valuation of the SPV’s external debt and the lease receivable asset associated with the sale leaseback transaction have been estimated using a discounted cash flow method.
The fair value of receivables acquired from GMLP is $4,797, which approximates 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 (loss) in the second quarter of 2021.
The Company’s results of operations for the year ended December 31, 2022 include GMLP’s result of operations from the entire period. Revenue and net income attributable to GMLP during this period was $157,434 and $134,266, respectively, which excludes revenue generated from the acquired vessels after the Energos Formation Transaction on August 15, 2022.
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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 (loss).
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 result of incurring new debt and extinguishing historical debt, elimination of a pre-existing lease relationship between the Company and GMLP, and a step-up of the equity method investments.
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 be non-recurring. The unaudited pro forma financial information does not give effect to any synergies, operating efficiencies or cost savings that may result from the Mergers.
Asset acquisitions
On January 12, 2021, the Company acquired 100% of the outstanding shares of CH4 Energia Ltda. (“CH4”), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to approximately $3,600. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $3,047 was included as part of the purchase consideration and was recognized in Other long-term liabilities on the consolidated balance sheets.
The purchase of CH4 has been accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $295 were included in the purchase consideration. The total purchase consideration of $5,776, which included a deferred tax liability of $1,531 recognized as a result from the acquisition, was allocated to permits and authorizations acquired and was recorded within Intangible assets, net.
On March 11, 2021, the Company acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold grants to operate as an independent power provider and 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil.
The purchase consideration consisted of $8,041 of cash paid at closing in addition to potential future payments contingent on achieving commercial operations of a gas-fired power plant of up to approximately $10.5 million. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $7,473 was included as part of the purchase consideration and was recognized in Other long-term liabilities on the consolidated balance sheets. The selling shareholders may also receive future payments based on power generated by a power 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
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consideration, $16,585 was allocated to acquired power purchase agreements and was recorded in Intangible assets, net as of December 31, 2021. The intangible assets are now held for sale and recorded in Other non-current assets as of December 31, 2022 on the consolidated balance sheets (see Note 17). The remaining purchase consideration was related to working capital acquired.
5. Energos Formation Transaction
On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), completed a sales and financing transaction resulting in cash proceeds of approximately $1.85 billion. This sales and financing transaction comprised (1) the formation of a limited liability company doing business as Energos Infrastructure ("Energos"), (2) the sale for cash of eight vessels, along with these vessels' owning and operating entities to the Purchaser, (3) the contribution of acquired vessel owning entities to Energos by the Purchaser and (4) the Company's contribution of three vessels, along with each vessels' owning and operating entities, to Energos in exchange for equity in Energos (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, the Company owns approximately a 20% equity interest in Energos, with the remaining interest owned by the Purchaser. The Company has accounted for the investment in Energos as an equity method investment; see Note 13 for further discussion of this investment.
In connection with the Energos Formation Transaction, the Company entered into long-term time charter agreements for periods of up to 20 years in respect of ten of the eleven vessels, the terms of which will commence upon the expiration of each vessel's existing third-party charter. Vessels chartered to the Company at the time of closing were classified as finance leases. These charters prevent the recognition of a sale of these ten vessels to Energos, and as such, proceeds associated with these ten vessels have been treated as failed sale leasebacks. These vessels continue to be recognized on the Company's consolidated balance sheet as Property, plant and equipment, and the Company has recognized the proceeds received from this failed sale leaseback financing as debt ("Vessel Financing Obligation"). Certain vessels included in the Energos Formation Transaction are currently chartered to third parties under operating leases. The Company will begin to charter the vessels immediately should the third-party charter terminate, including in situations where the third-party charter is terminated early. As the Company has not recognized the sale of these vessels and proceeds received from the Energos Formation Transaction are collateralized by the cash flows from long-term and third party time charters, revenue generated from these operating leases continues to be recognized as Vessel charter revenue; costs of operating the vessels is included in Vessel operating expenses over the terms of the third-party charters. Cash flows from the third-party charters are debt service of the Vessel Financing Obligation, and the Company will recognize additional financing costs within Interest expense, net.
The Company has not entered into a charter agreement to leaseback the Nanook, therefore, is accounted for as a sale of the financial asset. The Nanook was previously accounted for as a finance lease; see Note 7 for discussion of derecognition of the finance lease upon the sale of this financial asset.
A portion of proceeds received were utilized to extinguish certain debt, including the Vessel Term Loan (defined below) and the termination of lessor VIE arrangements (discussed in Note 6 below). Upon repayment, the Company recognized a loss on extinguishment of debt of $14,449; see Notes 6 and 20 below for further detail.
6. VIEs
Lessor VIEs
The Company assumed sale leaseback arrangements for four vessels as part of the 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 the 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 it controlled the significant decisions relating to the 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 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.
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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, as discussed in Note 5. 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 statement of operations and comprehensive income (loss) 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 a loss on extinguishment of debt of $9,082 in the consolidated statements of operations and comprehensive income (loss).
For the period subsequent to the completion of the Mergers in 2021, the most significant impact of the lessor VIEs operations on the Company’s statements of operations and comprehensive income (loss) 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 is recognized as a change to non-controlling interest in the consolidated financial statements.
7. Revenue recognition
Operating revenue includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, and the sale of LNG cargos. Included in operating revenue are LNG cargo sales to customers of $1,175,866 and $462,695 for the years ended December 31, 2022 and 2021, respectively; there were no comparable transactions for the year ended December 31, 2020. Other revenue includes revenue for development services as well as interest income from the Company’s finance leases. The table below summarizes the balances in Other revenue:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Development services revenue | $ | — | $ | 125,924 | $ | 129,753 | |||||||||||
| Interest income and other revenue | 32,469 | 35,261 | 3,586 | ||||||||||||||
| Total other revenue | $ | 32,469 | $ | 161,185 | $ | 133,339 | |||||||||||
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, 2022 and 2021, receivables related to revenue from contracts with customers totaled $280,382 and $192,533, respectively, and were included in Receivables, net on the consolidated balance sheets, net of current expected credit losses of $884 and $164, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases which are accounted for outside the scope of ASC 606 and receivables associated with reimbursable costs.
The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are
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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 assets balances as of December 31, 2022 and 2021 are detailed below:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Contract assets, net - current | $ | 8,083 | $ | 7,462 | |||||||
| Contract assets, net - non-current | 28,651 | 36,757 | |||||||||
| Total contract assets, net | $ | 36,734 | $ | 44,219 | |||||||
| Contract liabilities | $ | 12,748 | $ | 2,951 | |||||||
| Revenue recognized in the year from: | |||||||||||
| Amounts included in contract liabilities at the beginning of the year | $ | 2,951 | $ | 8,028 | |||||||
Contract assets are presented net of expected credit losses of $401 and $442 as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, contract assets was comprised of $36,483 and $43,839 of unbilled receivables, respectively, that represent unconditional rights to payment only subject to the passage of time, and the reduction to contract assets in 2022 was primarily due to the invoicing of unbilled receivables.
The Company has recognized costs to fulfill a contract with a significant customer, which primarily consist of expenses required to enhance resources to deliver under the agreement with the customer; these costs will be recognized on a straight-line basis over the expected term of the agreement. As of December 31, 2022, the Company has capitalized $10,377, of which $604 of these costs is presented within Other current assets and $9,773 is presented within Other non-current assets on the consolidated balance sheets. As of December 31, 2021, the Company had capitalized $10,981, of which $604 of these costs was presented within Other current assets and $10,377 was presented within Other non-current assets on the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.
The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements represents the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:
| Period | Revenue | ||||
| 2023 | $ | 262,290 | |||
| 2024 | 506,864 | ||||
| 2025 | 503,038 | ||||
| 2026 | 500,821 | ||||
| 2027 | 497,498 | ||||
| Thereafter | 7,872,779 | ||||
| Total | $ | 10,143,290 | |||
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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 customers, continue to be recognized on the consolidated balance sheet, and as such, the carrying amount of these vessels that are leased to customers under operating leases is as follows:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Property, plant and equipment | $ | 1,292,957 | $ | 1,274,234 | |||||||
| Accumulated depreciation | (80,233) | (31,849) | |||||||||
| Property, plant and equipment, net | $ | 1,212,724 | $ | 1,242,385 | |||||||
The components of lease income from vessel operating leases for the years ended December 31, 2022 and 2021 are shown below. As the Company has not recognized the sale of ten of the eleven vessels included in the Energos Formation Transaction, the operating lease income below includes revenue of $135,899 from third-party charters of vessels included in the Energos Formation Transaction which was recognized after the completion of the Energos Formation Transaction.
| December 31, 2022 | December 31, 2021 | ||||||||||
| Operating lease income | $ | 328,366 | $ | 214,193 | |||||||
| Variable lease income | 22,940 | 11,067 | |||||||||
| Total operating lease income | $ | 351,306 | $ | 225,260 | |||||||
The Company’s charter of the Nanook to CELSE and certain equipment leases provided in connection with the supply of natural gas or LNG are accounted for as finance leases. The Company recognized 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 (income) expense, net in the consolidated statements of operations and comprehensive income (loss).
Prior to the completion of the Energos Formation Transaction, the Company recognized interest income of $28,643 and $32,880 for the years ended December 31, 2022 and 2021, respectively, related to the finance lease of the Nanook, which is included within Other revenue in the consolidated statements of operations and comprehensive income (loss). Prior to the completion of the Energos Formation Transaction, the Company recognized revenue of $5,852 and $5,549 for the years ended December 31, 2022 and 2021, respectively, related to the operation and services agreement and variable charter revenue within Vessel charter revenue in the consolidated statements of operations and comprehensive income (loss).
As of December 31, 2021, there were outstanding balances due from CELSE of $6,428 of which $4,371 was recognized in Receivables, net and a loan to CELSE of $2,057 was recognized in Prepaid expenses and other current assets, net on the consolidated balance sheets. CELSE was an affiliate due to the equity method investment held in CELSE’s parent, CELSEPAR, and as such, these transactions and balances were related party in nature. Subsequent to the Energos Formation Transaction, there were no outstanding balance due from CELSE.
Subsequent to the Energos Formation Transaction, all cash receipts on vessel charters, including the finance lease of the Nanook, will be received by Energos. As such, there are no future cash receipts from operating leases, and the future cash receipts from other finance leases are not significant as of December 31, 2022.
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8. Leases, as lessee
The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.
The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.
As of December 31, 2022 and 2021, right-of-use assets, current lease liabilities and non-current lease liabilities consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| $ | 355,883 | $ | 285,751 | ||||||||
(1) | 21,994 | 23,912 | |||||||||
| Total right-of-use assets | $ | 377,877 | $ | 309,663 | |||||||
| Current lease liabilities: | |||||||||||
| $ | 44,371 | $ | 43,395 | ||||||||
| 4,370 | 3,719 | ||||||||||
| Total current lease liabilities | $ | 48,741 | $ | 47,114 | |||||||
| Non-current lease liabilities: | |||||||||||
| $ | 290,899 | $ | 219,189 | ||||||||
| 11,222 | 14,871 | ||||||||||
| Total non-current lease liabilities | $ | 302,121 | $ | 234,060 | |||||||
(1)Finance lease right-of-use assets are recorded net of accumulated amortization of $2,134 and $622 as of December 31, 2022 and 2021, respectively.
For the years ended December 31, 2022 and 2021, the Company’s operating lease cost recorded within the consolidated statements of operations and comprehensive income (loss) were as follows:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Fixed lease cost | $ | 75,771 | $ | 41,054 | |||||||
| Variable lease cost | 2,203 | 1,711 | |||||||||
| Short-term lease cost | 20,129 | 6,974 | |||||||||
| Lease cost - Cost of sales | $ | 87,610 | $ | 41,147 | |||||||
| Lease cost - Operations and maintenance | 3,681 | 2,343 | |||||||||
| Lease cost - Selling, general and administrative | 6,812 | 6,249 | |||||||||
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For the years ended December 31, 2022 and 2021, the Company has capitalized $20,403 and $15,568 of lease costs, respectively. Capitalized costs include vessels and port space used during the commissioning of development projects in addition to short-term lease costs for vessels chartered by the Company to transport inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.
Beginning in the second quarter of 2021, leases for ISO tanks and a parcel of land that transfer the ownership in underlying assets to the Company at the end of the lease have commenced, and these leases are treated as finance leases.
For the years ended December 31, 2022 and 2021, the Company’s finance interest expense and amortization recorded in Interest expense and Depreciation and amortization, respectively, within the consolidated statements of operations and comprehensive income (loss) were as follows:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Interest expense related to finance leases | $ | 852 | $ | 409 | |||||||
| Amortization of right-of-use asset related to finance leases | 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 years ended December 30, 2022 and 2021:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Operating cash outflows for operating lease liabilities | $ | 96,698 | $ | 46,066 | |||||||
| Financing cash outflows for finance lease liabilities | 3,697 | 2,156 | |||||||||
| Right-of-use assets obtained in exchange for new operating lease liabilities | 135,075 | 172,996 | |||||||||
| Right-of-use assets obtained in exchange for new finance lease liabilities | — | 24,533 | |||||||||
The future payments due under operating and finance leases as of December 31, 2022 are as follows:
| Operating Leases | Financing Leases | ||||||||||
| 2023 | $ | 69,305 | $ | 5,064 | |||||||
| 2024 | 67,414 | 4,380 | |||||||||
| 2025 | 58,957 | 4,380 | |||||||||
| 2026 | 50,978 | 2,625 | |||||||||
| 2027 | 50,503 | 89 | |||||||||
| Thereafter | 182,451 | 941 | |||||||||
| Total Lease Payments | $ | 479,608 | $ | 17,479 | |||||||
| Less: effects of discounting | 144,338 | 1,887 | |||||||||
| Present value of lease liabilities | $ | 335,270 | $ | 15,592 | |||||||
| Current lease liability | $ | 44,371 | $ | 4,370 | |||||||
| Non-current lease liability | 290,899 | 11,222 | |||||||||
As of December 31, 2022, the weighted-average remaining lease term for operating leases was 8.3 years and finance leases was 4.3 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of December 31, 2022 and 2021 was 8.5% and 8.7%, respectively. The weighted average discount rate associated with finance leases as of December 31, 2022 and 2021 was 5.1%.
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9. Financial instruments
Interest rate and currency risk management
In connection with the Mergers, 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 Company does not hold or issue instruments for speculative purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties.
The following table summarizes the terms of interest rate swap as of December 31, 2022:
| Instrument | Notional Amount (in thousands) | Maturity Dates | Fixed Interest Rate | ||||||||||||||||||||
| Interest rate swap: Receiving floating, pay fixed | $ | 323,250 | March 2026 | 2.86% | |||||||||||||||||||
The mark-to-market gain or loss on the interest rate swap and other derivative instruments that are not intended to mitigate commodity risk are reported in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).
Commodity risk management
During 2022, we began to enter into commodity swap transactions to manage our exposure to changes in market pricing of natural gas or LNG. Realized and unrealized gains and losses on these transactions have been recognized in Cost of sales in the consolidated statements of operations and comprehensive income (loss).
•During the third quarter of 2022, the Company entered into a commodity swap transaction to swap market pricing exposure for a portion of January 2023 deliveries (approximately 1.5 TBtus) for a fixed price of $61.87 per MMBtu. The swap settled in December 2022, at a gain of $36,479.
•During the third quarter of 2022, the Company entered into a commodity swap transaction to swap market pricing exposure for a portion of November 2022 deliveries (approximately 3.3 TBtus). The swap was settled in September 2022 at a gain of $20,996.
•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 will settle in 2023, and mark-to-market gains on this instrument have been recognized as a reduction to Cost of sales in the amount of $104,797.
Fair value
Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:
•Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.
•Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.
•Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.
The valuation techniques that may be used to measure fair value are as follows:
•Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
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•Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.
•Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The Company uses the market approach when valuing investment in equity securities which is recorded in Other non-current assets on the consolidated balances sheets as of December 31, 2022 and 2021.
The Company uses the income approach when valuing the following financial instruments:
•Interest rate swap is recorded within Other non-current assets, net on the consolidated balance sheets as of December 31, 2022 and was recorded within Other current liabilities as of December 31, 2021.
•The assets associated with the commodity swap are recorded within Prepaid expenses and other current assets on the consolidated balance sheets as of December 31, 2022. No commodity swaps were outstanding as of December 31, 2021.
•The contingent consideration derivative liability represents consideration due to the sellers in asset acquisitions when certain contingent events occur. The liability associated with these derivative liabilities is recorded within Other current liabilities and Other long-term liabilities on the consolidated balance sheets as of December 31, 2022 and 2021.
The fair value of certain derivative instruments, including the interest rate swap and commodity swaps is estimated considering current interest rates, quoted closing and forward market prices and the creditworthiness of counterparties. The Company estimates fair value of the contingent consideration derivative liabilities using a discounted cash flows method with discount rates based on the average yield curve for bonds with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent events occurring.
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The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of December 31, 2022 and 2021:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||
| 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 | ||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||
| Investment in equity securities | $ | 11,195 | $ | — | $ | 7,678 | $ | 18,873 | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||
| Contingent consideration derivative liabilities | $ | — | $ | — | $ | 48,849 | $ | 48,849 | ||||||||||||||||||
| Cross-currency interest rate swap | — | 2,167 | — | 2,167 | ||||||||||||||||||||||
| Interest rate swap | — | 19,762 | — | 19,762 | ||||||||||||||||||||||
The Company believes the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value as of December 31, 2022 and 2021 and are classified as Level 1 within the fair value hierarchy.
The table below summarizes the fair value adjustment to the contingent consideration derivative liabilities measured at Level 3 in the fair value hierarchy. These adjustments have been recorded within Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss) for the years ended December 31, 2022, 2021 and 2020:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Contingent consideration derivative liabilities - Fair value adjustment - loss (gain) | $ | 703 | $ | (341) | $ | 4,408 | |||||||||||
During the years ended December 31, 2022 and 2021, the Company had no financial instruments transfer in or out of Level 3 in the fair value hierarchy.
Under the Company’s interest rate swap, the Company is required to provide cash collateral, and as of December 31, 2022, and 2021, $2,500 and $12,500, respectively, of cash collateral is presented as restricted cash on the consolidated balance sheets. The interest rate swap has a credit arrangement which requires the Company to provide cash collateral when the market value of the instrument falls below a specified threshold, up to $12,500.
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10. Restricted cash
As of December 31, 2022 and 2021, restricted cash consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Cash restricted under the terms of loan agreements | $ | 124,085 | $ | — | |||||||
| Cash held by lessor VIEs | — | 35,651 | |||||||||
| Collateral for letters of credit and performance bonds | 41,392 | 27,614 | |||||||||
| Collateral for interest rate swaps | 2,500 | 12,500 | |||||||||
| Other restricted cash | — | 756 | |||||||||
| Total restricted cash | $ | 167,977 | $ | 76,521 | |||||||
| Current restricted cash | $ | 165,396 | $ | 68,561 | |||||||
| Non-current restricted cash (Note 17) | 2,581 | 7,960 | |||||||||
Uses of cash proceeds under the Barcarena Term Loan (see Note 20) are restricted to certain payments to construct the Barcarena Power Plant. Non-current restricted cash is presented in Other non-current assets, net on the consolidated balance sheets.
11. Inventory
As of December 31, 2022 and 2021, inventory consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| LNG and natural gas inventory | $ | 15,398 | $ | 16,815 | |||||||
| Automotive diesel oil inventory | 8,164 | 4,789 | |||||||||
| Bunker fuel, materials, supplies and other | 15,508 | 15,578 | |||||||||
| Total inventory | $ | 39,070 | $ | 37,182 | |||||||
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 statements of operations and comprehensive income (loss). No adjustments were recorded during the years ended December 31, 2022, 2021 and 2020.
12. Prepaid expenses and other current assets
As of December 31, 2022 and 2021, prepaid expenses and other current assets consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Prepaid expenses | $ | 56,380 | $ | 19,951 | |||||||
| Recoverable taxes | 37,504 | 33,053 | |||||||||
| Commodity swap | 104,797 | — | |||||||||
| Due from affiliates | 698 | 3,299 | |||||||||
| Other current assets | 27,504 | 26,812 | |||||||||
| Total prepaid expenses and other current assets, net | $ | 226,883 | $ | 83,115 | |||||||
Prepaid expenses includes $34,882 of prepaid LNG inventory as of December 31, 2022; the Company did not have any prepaid LNG inventory as of December 31, 2021. Other current assets as of December 31, 2022 and 2021 primarily consists of deposits, as well as the current portion of contract assets (Note 7).
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13. Equity method investments
As a result of the Mergers, the Company acquired investments in CELSEPAR and Hilli LLC, representing a 50% ownership interest in both entities, 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 are reflected in the Ships segment.
Changes in the balance of the Company’s equity method investments is as follows:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Equity method investments as of beginning of period | $ | 1,182,013 | $ | — | |||||||
| Acquisition of equity method investments in the Mergers | — | 1,179,021 | |||||||||
| Capital contributions | 133,314 | — | |||||||||
| Dividends | (29,372) | (21,364) | |||||||||
| Equity in earnings of investees | 15,546 | 14,443 | |||||||||
| Other-than-temporary impairment | (487,765) | — | |||||||||
| Sergipe Sale | (500,076) | — | |||||||||
| Foreign currency translation adjustment | 78,646 | 9,913 | |||||||||
| Equity method investments as of end of period | $ | 392,306 | $ | 1,182,013 | |||||||
Capital contributions primarily consisted of $129,518 of contribution of assets to Energos in conjunction with the Energos Formation Transaction (Note 5).
The carrying amount of equity method investments as of December 31, 2022 and 2021 is as follows:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Hilli LLC | $ | 260,000 | $ | 366,504 | |||||||
| CELSEPAR | — | 815,509 | |||||||||
| Energos | 132,306 | — | |||||||||
| Total | $ | 392,306 | $ | 1,182,013 | |||||||
As of December 31, 2022 and 2021, 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 $792,995, respectively, and the basis difference attributable to amortizable net assets is amortized to (Loss) income from equity method investments over the remaining estimated useful lives of the underlying assets.
CELSEPAR
CELSEPAR 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
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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 (income) expense, net in the consolidated statements of operations and comprehensive income (loss).
As a result of the announcement of the Sergipe Sale, the Company has recognized an other than temporary impairment ("OTTI") of the investment in CELSEPAR totaling $369,207 for the year ended December 31, 2022, and this loss was recognized in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). Nonrecurring, Level 2 inputs were used to estimate the fair value of the investment for the purpose of recognizing the OTTI.
Hilli LLC
The Company acquired 50% of the common units of Hilli LLC (“Hilli Common Units”) as part of the GMLP Merger. Hilli LLC owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Hilli is currently operating under an 8-year liquefaction tolling agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures.
The ownership interests in Hilli LLC are represented by three classes of units, Hilli Common Units, Series A Special Units and Series B Special Units. The Company did not acquire any of the Series A Special Units or Series B Special Units. The Company determined that Hilli LLC is a VIE, and the Company is not the primary beneficiary of Hilli LLC. Thus, Hilli LLC has not been consolidated into the financial statements. The Hilli Common Units provide the Company with significant influence over Hilli LLC and the investment in Hilli Common Units has been recognized as an equity method investment.
Within 60 days after the end of each quarter, GLNG, the managing member of Hilli LLC, determines the amount of Hilli LLC’s available cash and appropriate reserves, and Hilli LLC makes a distribution to the unitholders of Hilli LLC of the available cash, subject to such reserves. Hilli LLC makes distributions when declared by GLNG, provided that no distributions may be made on the Hilli Common Units unless current and accumulated Series A Distributions and Series B Distributions have been paid.
The Company is required to reimburse other investors in Hilli LLC or may receive reimbursements from other investors in Hilli LLC for 50% of the amount, if any, by which certain operating expenses and withholding taxes of Hilli LLC are above or below an annual threshold. During the year ended December 31, 2022, distributions made by Hilli LLC included $2,000 of operating expense reimbursements.
Hilli Corp is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). The Hilli Leaseback provided post construction financing for the Hilli in the amount of $960 million. Under the Hilli Leaseback, Hilli Corp will pay to Fortune forty consecutive equal quarterly repayments of 1.375% of the construction cost, plus interest based on LIBOR plus a margin of 4.15%.
As of December 31, 2022 the maximum exposure as a result of the Company’s ownership in the Hilli LLC is the carrying value of the equity method investment and the outstanding portion of the Hilli Leaseback which have been guaranteed by the Company.
On February 6, 2023, the Company announced an agreement with GLNG for the sale of the Company's Hilli Common Units in exchange for the return of approximately $4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"), and after the transaction, the Company will no longer have any ownership interest in the Hilli. The Hilli Exchange is expected to close in the first quarter of 2023 and is subject to customary closing conditions.
Recent market prices of NFE shares and the terms of the Hilli Exchange implied that the fair value of the investment may be lower than the carrying value as of December 31, 2022, which triggered an assessment of the recoverability of the
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carrying amount of this investment. The Company estimated the fair value of the investment as of December 31, 2022 based on discounted cash flows using an income approach reflecting certain Level 3 inputs, reflecting a range of discount rates between 11.5% and 13.5%. The fair value of $260,558 was corroborated utilizing the terms of the Hilli Exchange linked to estimated market prices of NFE shares. The decreased fair value was primarily the result of increases in risk-free rates. The Company concluded that the estimated fair value was below the carrying value and that this decline was other than temporary. As a result of this recoverability assessment, the Company recognized an OTTI of the investment in Hilli of $118,558 for the year ended December 31, 2022; this loss was recognized in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss) in the Terminals and Infrastructure segment.
Energos
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 provides certain rights, including representation on the Energos board of directors, that give the Company significant influence over the operations of Energos, and as such, the investment has been accounted for under the equity method. Energos is also an affiliate, and all transactions with Energos are transactions with an affiliate. Due to the timing and availability of financial information of Energos, the Company recognizes its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. For the year ended December 31, 2022, the Company has recognized earnings from Energos of $2,788.
14. Construction in progress
The Company’s construction in progress activity during the years ended December 31, 2022 and 2021 is detailed below:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Balance at beginning of period | $ | 1,043,883 | $ | 234,037 | |||||||
| Acquisition of construction in progress from business combinations | — | 128,625 | |||||||||
| Additions | 1,482,871 | 790,395 | |||||||||
| Asset impairment expense | (50,659) | — | |||||||||
| Impact of currency translation adjustment | 5,580 | (6,428) | |||||||||
| Transferred to property, plant and equipment, net or finance leases | (63,067) | (102,746) | |||||||||
| Balance at end of period | $ | 2,418,608 | $ | 1,043,883 | |||||||
Interest expense of $94,454, $30,093 and $25,924, inclusive of amortized debt issuance costs, was capitalized for the years ended December 31, 2022, 2021 and 2020, respectively.
The Company has significant development activities in Latin America and for the Company's Fast LNG floating 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, 2022 were primarily focused on Fast LNG; additions to construction in progress in 2022 of $1,218,101 were to develop Fast LNG projects
The assets of CEBARRA primarily consisted of construction in progress, and in conjunction with the Sergipe Sale, the assets of CEBARRA met the criteria to be presented as held for sale. These assets were measured at fair value, less costs to sell, upon classification to held for sale in the second quarter of 2022, and the Company recognized an impairment loss of $50,659 in Asset impairment expense in the consolidated statements of operations and comprehensive income (loss) in the Terminals and Infrastructure Segment. Nonrecurring, Level 2 inputs were used to estimate the fair value of the investment for the purpose of recognizing the asset impairment. As of December 31, 2022, no other indicators of impairment have been identified.
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15. Property, plant and equipment, net
As of December 31, 2022 and 2021, the Company’s property, plant and equipment, net consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Vessels | $ | 1,518,839 | $ | 1,461,211 | |||||||
| Terminal and power plant equipment | 218,296 | 206,889 | |||||||||
| CHP facilities | 123,897 | 122,777 | |||||||||
| Gas terminals | 177,780 | 167,614 | |||||||||
| ISO containers and other equipment | 134,324 | 134,775 | |||||||||
| LNG liquefaction facilities | 63,316 | 63,213 | |||||||||
| Gas pipelines | 65,985 | 58,987 | |||||||||
| Land | 52,995 | 55,008 | |||||||||
| Leasehold improvements | 9,377 | 9,377 | |||||||||
| Accumulated depreciation | (248,082) | (141,915) | |||||||||
| Total property, plant and equipment, net | $ | 2,116,727 | $ | 2,137,936 | |||||||
The book value of the vessels that were recognized due to the failed sale leaseback in the Energos Formation Transaction as of December 31, 2022 was $1,328,553.
Depreciation for the years ended December 31, 2022, 2021 and 2020 totaled $104,823, $80,220 and $32,116, respectively, of which $954, $1,167 and $927, respectively, is included within Cost of sales in the consolidated statements of operations and comprehensive income (loss).
16. Goodwill and intangible assets
Goodwill
The following table summarizes the changes in the carrying amount of goodwill in the Terminals and Infrastructure segment as of December 31, 2022 and 2021:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Balance at beginning of period | $ | 760,135 | $ | — | |||||||
| Acquired in the Mergers | — | 760,135 | |||||||||
| Adjustments | 16,625 | — | |||||||||
| Balance at end of period | $ | 776,760 | $ | 760,135 | |||||||
The Company performed its annual goodwill impairment test as of October 1, 2022 and 2021 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, 2022 and 2021.
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Intangible assets
The following tables summarize the composition of intangible assets as of December 31, 2022 and 2021:
| 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 | |||||||||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Currency Translation Adjustment | Net Carrying Amount | Weighted Average Life | |||||||||||||||||||||||||
| Definite-lived intangible assets | |||||||||||||||||||||||||||||
| Favorable vessel charter contracts | $ | 106,500 | $ | (27,074) | $ | — | $ | 79,426 | 3 | ||||||||||||||||||||
| Permits and development rights | 48,217 | (3,311) | (119) | 44,787 | 38 | ||||||||||||||||||||||||
| Acquired power purchase agreements | 16,585 | (750) | 406 | 16,241 | 17 | ||||||||||||||||||||||||
| Easements | 1,556 | (243) | — | 1,313 | 30 | ||||||||||||||||||||||||
| Indefinite-lived intangible assets | |||||||||||||||||||||||||||||
| Easements | 1,191 | — | (14) | 1,177 | n/a | ||||||||||||||||||||||||
| Total intangible assets | $ | 174,049 | $ | (31,378) | $ | 273 | $ | 142,944 | |||||||||||||||||||||
Intangible assets associated with the acquired power purchase agreements have been classified as held for sale as of December 31, 2022; no impairment loss was recognized upon classification as held for sale (See Note 17).
As of December 31, 2022 and 2021, the weighted-average remaining amortization periods for the intangible assets were 18.0 years and 14.7 years, respectively. Amortization expense for the years ended December 31, 2022 and 2021 totaled $37,162 and $18,609, respectively which were inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed in the Mergers. Amortization expense for the year ended December 31, 2020 totaled $1,120.
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 ended December 31: | |||||
| 2023 | $ | 25,146 | |||
| 2024 | 16,345 | ||||
| 2025 | 3,528 | ||||
| 2026 | 1,272 | ||||
| 2027 | 1,272 | ||||
| Thereafter | 37,226 | ||||
| Total | $ | 84,789 | |||
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17. Other non-current assets, net
As of December 31, 2022 and 2021, Other non-current assets consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Assets held for sale | $ | 40,685 | $ | — | |||||||
| Contract asset, net (Note 7) | 28,651 | 36,757 | |||||||||
| Investments in equity securities | 17,806 | 18,873 | |||||||||
| Cost to fulfill (Note 7) | 9,773 | 10,377 | |||||||||
| Upfront payments to customers | 9,158 | 9,748 | |||||||||
| Other | 31,005 | 30,623 | |||||||||
| Total other non-current assets | $ | 137,078 | $ | 106,378 | |||||||
The Company recognized unrealized (losses) gains on its investments in equity securities of $(1,067), $8,254 and $(2,284) for the years ended December 31, 2022, 2021 and 2020, respectively, within Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss). Investments in equity securities include investments without a readily determinable fair value of $7,678 as of December 31, 2022 and 2021.
Upfront payments to customers consist of amounts the Company has paid in relation to two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own. Other includes $2,581 of non-current restricted cash.
Assets held for sale
In the third quarter of 2022, NFE Brazil Holdings LLC ("Brazil Holdings"), a consolidated indirect subsidiary of NFE and indirect owner of Pecém and Muricy, and Centrais Elétricas de Pernambuco S.A. – EPESA (“EPESA”), entered into a Share Purchase Agreement pursuant to which Brazil Holdings agreed to sell 100% of the shares of Pecém and Muricy to EPESA, following an internal reorganization. The sale price includes an initial cash payment of approximately BRL 59 million (approximately $11 million using the exchange rate as of December 31, 2022), as well as additional consideration for the satisfaction of milestones. Consideration under this agreement also includes potential future earnout payments based on the revenue generated from the PPAs by EPESA.The sale of Pecém and Muricy is subject to regulatory approval as well as the customary terms and conditions and conditions precedent prior to closing.
All assets and liabilities of Pecém and Muricy were classified as held for sale as of December 31, 2022. The estimated fair value of these entities based on the consideration in the agreement was in excess of the carrying value, and no impairment loss was recognized upon classification as held for sale. The assets and liabilities held for sale have not been classified as a separate financial statement line item on the consolidated balance sheets and are presented as other non-current assets. Liabilities held for sale of $23,543 are presented as other long-term liabilities. Assets held for sale include a cash balance of $11,614, which has been included in the ending cash and cash equivalents on the condensed consolidated statement of cash flows.
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18. Accrued liabilities
As of December 31, 2022 and 2021, accrued liabilities consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Accrued development costs | $ | 364,157 | $ | 101,177 | |||||||
| Accrued interest | 51,994 | 61,630 | |||||||||
| Accrued bonuses | 37,739 | 27,591 | |||||||||
| Accrued vessel operating and drydocking expenses | — | 12,767 | |||||||||
| Accrued dividend | 626,310 | 333 | |||||||||
| Other accrued expenses | 82,212 | 40,527 | |||||||||
| Total accrued liabilities | $ | 1,162,412 | $ | 244,025 | |||||||
As of December 31, 2022, the balance presented as Other accrued expenses includes accruals of $45,511 for inventory purchases completed in the fourth quarter of 2022.
19. Other current liabilities
As of December 31, 2022 and 2021, Other current liabilities consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Derivative liabilities | $ | 19,458 | $ | 40,092 | |||||||
| Deferred revenue | 12,748 | 28,662 | |||||||||
| Income tax payable | 6,261 | 8,881 | |||||||||
| Due to affiliates | 7,499 | 9,088 | |||||||||
| Other current liabilities | 6,912 | 19,313 | |||||||||
| Total other current liabilities | $ | 52,878 | $ | 106,036 | |||||||
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20. Debt
As of December 31, 2022 and 2021, debt consisted of the following:
| December 31, 2022 | December 31, 2021 | ||||||||||
Senior Secured Notes, due September 2025 | $ | 1,243,351 | $ | 1,241,196 | |||||||
Senior Secured Notes, due September 2026 | 1,481,639 | 1,477,512 | |||||||||
Vessel Financing Obligation, due August 2042 | 1,406,091 | — | |||||||||
South Power 2029 Bonds, due May 2029 | 216,177 | 96,820 | |||||||||
Barcarena Term Loan, due February 2024 | 194,427 | — | |||||||||
Vessel Term Loan Facility, due September 2024 | — | 408,991 | |||||||||
Debenture Loan, due September 2024 | — | 40,665 | |||||||||
| Revolving Facility | — | 200,000 | |||||||||
| Subtotal (excluding lessor VIE loans) | 4,541,685 | 3,465,184 | |||||||||
Nanook SPV facility, due September 2030 | — | 186,638 | |||||||||
Penguin SPV facility, due December 2025 | — | 90,035 | |||||||||
Celsius SPV facility, due September 2023/ May 2027 | — | 113,273 | |||||||||
| Total debt | $ | 4,541,685 | $ | 3,855,130 | |||||||
| Current portion of long-term debt | $ | 64,820 | $ | 97,251 | |||||||
| Long-term debt | 4,476,865 | 3,757,879 | |||||||||
Long-term debt is recorded at amortized cost on the consolidated balance sheets. The fair value of the Company's long-term debt is $4,327,311 and $3,910,425 as of December 31, 2022 and 2021, respectively, and is classified as Level 2 within the fair value hierarchy.
Our outstanding debt as of December 31, 2022 is repayable as follows:
| December 31, 2022 | |||||
| 2023 | $ | 64,820 | |||
| 2024 | 269,817 | ||||
| 2025 | 1,307,972 | ||||
| 2026 | 1,565,068 | ||||
| 2027 | 140,247 | ||||
| Thereafter | 1,234,361 | ||||
| Total debt | $ | 4,582,285 | |||
| Less: deferred finance charges | (40,600) | ||||
| Total debt, net deferred finance charges | $ | 4,541,685 | |||
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
In September 2020, the Company issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. The Company may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
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The 2025 Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The 2025 Notes may limit the Company’s ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.
The Company used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.
In December 2020, the Company issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). As of December 31, 2022 and 2021, remaining unamortized deferred financing costs for the 2025 Notes were $6,649 and $8,804, respectively.
2026 Notes
In April 2021, the Company issued $1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. 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.
The Company used the net proceeds from this offering to fund the cash consideration for the Mergers and pay related fees and expenses.
In connection with the issuance of the 2026 Notes, the Company incurred $25,217 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the consolidated balance sheets. As of December 31, 2022 and 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $18,361 and $22,488, 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. 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 from the Purchaser.
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; the effective interest rate on this financing obligation of approximately 15.9% includes the cash flows that Energos receives from these third-party charters.
The lease terms for the charter agreements were for periods of up to 20 years. 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 Nanook and recognized as Other (income), net in the consolidated statements of operations and comprehensive income (loss). Financing costs of $7,015 were allocated and deferred as a reduction of the principal balance
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of the financing obligation on the consolidated balance sheets. As of December 31, 2022, the remaining unamortized deferred financing costs for the Vessel Financing Obligation was $6,866.
South Power 2029 Bonds
In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000. The CHP Facility was secured by a mortgage over the lease of the site on which the Company’s combined heat and power plant in Clarendon, Jamaica (“CHP Plant”) is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285,000 in South Power 2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. During the year ended December 31, 2022, the Company issued $121,824, of South Power 2029 Bonds for a total amount outstanding of $221,824 as of December 31, 2022.
The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.
South Power 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. The Company is in compliance with all covenants as of December 31, 2022.
In conjunction with obtaining the CHP Facility, the Company incurred $3,243 in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional third-party fees associated with such lenders of $258 were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $5,647 and $3,180, respectively.
Barcarena Term Loan
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 will be utilized to fund construction of the Barcarena Power Plant. As of December 31, 2022, the loan has been 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%. Additionally, undrawn balances incur a commitment fee of 1.9%.
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 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 Company 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, 2022.
The Company incurred $4,011 of structuring and other fees, and such fees have been deferred as a reduction to the principal balance of the Barcarena Term Loan. As of December 31, 2022, the remaining unamortized deferred financing costs for the Barcarena Term Loan was $3,077.
Vessel Term Loan Facility
In September 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed the Vessel Term Loan Facility. Under this facility, the Company borrowed an initial amount of $430,000. Loans under the Vessel Term Loan Facility had an interest rate of LIBOR plus a margin of 3%. The Vessel Term Loan Facility was repaid in quarterly installments of $15,357, with the final repayment date in September 2024. In connection with the closing of the Vessel Term Loan
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Facility, the Company incurred $6,324 in organization, structuring and other fees, which was deferred as a reduction of the principal balance of the Vessel Term Loan on the consolidated balance sheet.
Obligations under the Vessel Term Loan Facility were guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of December 31, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $660,567.
On August 3, 2022, the Company exercised the accordion feature under the Vessel Term Loan Facility, drawing $115,000, increasing the total principal outstanding to $498,929. Net proceeds of $113,850 were received, and origination and other fees of $1,150 were deferred as a reduction to the balance of the Vessel Term Loan Facility. As part of the Energos Formation Transaction, all amounts outstanding under the Vessel Term Loan Facility, including this additional principal draw, were repaid. Unamortized deferred financing costs of $5,367 were recognized as Loss on extinguishment of debt in the consolidated statements of operations and comprehensive income (loss).
Debenture Loan
As part of the Hygo Merger, the Company assumed non-convertible Brazilian debentures in the aggregate principal amount of BRL 255.6 million due September 2024 (the “Debenture Loan”) bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65%. The Debenture Loan was recognized at fair value of $44,566 on the date of the Hygo Merger, and the discount recognized in purchase accounting resulted in additional interest expense until maturity. Interest and principal was payable on the Debenture Loan semi-annually on September 13 and March 13.
In the third quarter of 2022, the Company repaid the outstanding amount of the Debenture Loan of BRL 198.6 million ($39.2 million); unamortized adjustments to the fair value of the Debenture Loan recognized as a result of the Mergers of $548 was recognized as Loss on extinguishment of debt, net in the consolidated statement of operations and comprehensive income (loss).
Revolving Facility
In April 2021, the Company entered into a $200,000 senior secured revolving credit facility (the "Revolving Facility"). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). In February and May 2022, the Revolving Facility was amended to increase the borrowing capacity by $115,000 and $125,000, respectively, for a total capacity under the Revolving Facility of $440,000. Letters of credit issued under the $100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for the Company to extend the maturity date once in a one-year increment.
Borrowings under the Revolving Facility bear interest at a rate equal to SOFR plus 0.15% plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and SOFR plus 0.15% plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0% SOFR floor. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.
The obligations under the Revolving Facility are guaranteed by certain of the Company's subsidiaries. The Company is required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 until maturity. The Company was in compliance with all covenants as of December 31, 2022.
The Company incurred $5,398 in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees incurred to expand the facility in 2022. These costs have been capitalized within Other non-current assets on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $5,172 and $3,807, respectively.
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VIE loans
The Company assumed the following debt of entities that were consolidated as VIEs. The Company was the primary beneficiary of these VIEs, and therefore these loan facilities were presented as part of the consolidated financial statements until these arrangements were terminated in conjunction with the Energos Formation Transaction.
Nanook SPV facility
In September 2018, the Nanook was sold to a subsidiary of CCB Financial Leasing Corporation Limited, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years. The Company had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period. The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, had a long-term loan facility due to its parent that was denominated in USD and bore interest at a fixed rate of 2.5%.
Penguin SPV facility
In December 2019, the Penguin was sold to a subsidiary of Oriental Shipping Company, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years. The Company had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period. The SPV, Oriental Fleet LNG 02 Limited, the owner of the Penguin, had a long-term loan facility that was denominated in USD and bore interest at LIBOR plus a margin of 1.7%.
Celsius SPV facility
In March 2020, the Celsius was sold to a subsidiary of AVIC International Leasing Company Limited, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years. The Company had options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period. The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, had two long-term loan facilities that were denominated in USD. The first facility was paid in quarterly installments over seven years that bore an interest rate of LIBOR plus a margin of 1.8%. The second facility with its parent bore a fixed interest rate of 4.0%.
As part of the Energos Formation Transaction, the Company exercised its option to repurchase the Penguin, Celsius, and Nanook vessels for a total payment of $380,176. After exercising the repurchase options, the Company no longer had a controlling financial interest in these VIEs and deconsolidated the VIEs. The Company has recognized a loss of $9,082 from exiting this financing arrangements in Loss on extinguishment of debt, net in the consolidated statements of operations and comprehensive income (loss).
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, 2022, 2021 and 2020 consisted of the following:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Interest per contractual rates | $ | 227,960 | $ | 175,420 | $ | 76,176 | |||||||||||
| Interest expense on Vessel Financing Obligation | 91,405 | — | — | ||||||||||||||
| Amortization of debt issuance costs, premiums and discounts | 11,098 | 8,588 | 15,471 | ||||||||||||||
| Interest expense incurred on finance lease obligations | 852 | 409 | — | ||||||||||||||
| Total interest costs | $ | 331,315 | $ | 184,417 | $ | 91,647 | |||||||||||
| Capitalized interest | 94,454 | 30,093 | 25,924 | ||||||||||||||
| Total interest expense | $ | 236,861 | $ | 154,324 | $ | 65,723 | |||||||||||
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Interest expense on the Vessel Financing Obligations includes non-cash expense of $84,517 related to payments received by Energos from third party charterers.
21. Income taxes
The components of the Company’s income (loss) before income taxes for the years ended December 31, 2022, 2021 and 2020 were as follows:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| United States | $ | 551,500 | $ | (283,363) | $ | (166,571) | |||||||||||
| Foreign | (490,153) | 388,535 | (92,577) | ||||||||||||||
| Income (loss) before taxes | $ | 61,347 | $ | 105,172 | $ | (259,148) | |||||||||||
Income tax expense is comprised of the following for the years ended December 31, 2022, 2021 and 2020:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Current: | |||||||||||||||||
| Domestic | $ | 37,831 | $ | 311 | $ | — | |||||||||||
| Foreign | 118,266 | 20,975 | 2,063 | ||||||||||||||
| Total current tax expense | 156,097 | 21,286 | 2,063 | ||||||||||||||
| Deferred: | |||||||||||||||||
| Domestic | 5,794 | — | — | ||||||||||||||
| Foreign | (285,330) | (8,825) | 2,754 | ||||||||||||||
| Total deferred tax (benefit) expenses | (279,536) | (8,825) | 2,754 | ||||||||||||||
| Total (benefit from) provision for income taxes | $ | (123,439) | $ | 12,461 | $ | 4,817 | |||||||||||
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, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Income tax at the statutory rate | 21.0 | % | 21.0 | % | 21.0 | % | |||||||||||
| Foreign tax rate differential | (25.5) | (33.8) | 2.9 | ||||||||||||||
| US taxation on foreign earnings | 25.5 | 9.6 | (2.9) | ||||||||||||||
| Impact from foreign operations | (10.7) | 1.5 | — | ||||||||||||||
| Change in valuation allowance | (22.9) | 14.7 | (14.1) | ||||||||||||||
| Income attributable to non-controlling interest | 1.3 | 0.8 | (6.4) | ||||||||||||||
| Effects of share based compensation | (39.8) | (8.5) | — | ||||||||||||||
| Withholding taxes | 12.6 | 9.5 | — | ||||||||||||||
| Income tax credits | (0.3) | (2.4) | — | ||||||||||||||
| Sergipe Sale | (165.4) | — | — | ||||||||||||||
| Outside basis differences | (3.2) | 2.6 | (0.5) | ||||||||||||||
| Other | 6.2 | (3.2) | (1.9) | ||||||||||||||
| Effective income tax rate | (201.2 | %) | 11.8 | % | (1.9 | %) | |||||||||||
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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 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, 2022 and 2021 are as follows:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Deferred tax assets: | |||||||||||
| Accrued interest | $ | 33,262 | $ | 26,408 | |||||||
| IRC Section 163(j) interest carryforward | 19,251 | 21,782 | |||||||||
| Federal and state net operating loss carryforward | 2,900 | 19,061 | |||||||||
| Foreign net operating loss carryforward | 100,614 | 43,735 | |||||||||
| Debt | 300,834 | — | |||||||||
| Lease liability | 70,241 | 60,967 | |||||||||
| Goodwill | 51,315 | 55,394 | |||||||||
| Other | 17,141 | 26,547 | |||||||||
| Total deferred tax assets | 595,558 | 253,894 | |||||||||
| Valuation allowance | (130,649) | (146,269) | |||||||||
| Deferred tax assets, net of valuation allowance | 464,909 | 107,625 | |||||||||
| Deferred tax liabilities: | |||||||||||
| Equity method investments | — | (252,224) | |||||||||
| Property and equipment | (355,596) | (47,205) | |||||||||
| Right-of-use assets | (74,289) | (62,403) | |||||||||
| Investments | (2,687) | — | |||||||||
| Commodity swap | (22,421) | — | |||||||||
| Deferred income | (22,414) | — | |||||||||
| Other | (5,417) | (9,307) | |||||||||
| Total deferred tax liabilities | $ | (482,824) | $ | (371,139) | |||||||
| Net deferred tax liabilities | $ | (17,915) | $ | (263,514) | |||||||
As a result of the Sergipe Sale, the Deferred tax liability for equity method investments was eliminated. The Deferred tax asset related to debt and the increase in the property and equipment deferred tax liability are largely the result of the Energos Formation Transaction.
As a result of the Mergers, the Company recognized net deferred tax liabilities of $269,856 that reflect the impact of the financial statement fair value adjustments, principally the increased value of equity method investments. The Company acquired tax attribute carryforwards including net operating losses in certain jurisdictions which were recorded and offset with a valuation allowance as a result of cumulative losses and the developmental status of the entities with the exception of net operating losses that are realizable as a result of taxable temporary differences related to an equity method investment.
Tax Attributes
United States
As of December 31, 2022, NFE has approximately $13,447 of federal and $1,983 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.
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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 the 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, 2022, the Company’s foreign subsidiaries have approximately $401,369 of net operating loss carry forwards, of which $75,999 will expire, if unused beginning in 2028, and the remaining 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, 2022 and 2021:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Balance at the beginning of the period | $ | 146,269 | $ | 132,497 | |||||||
| Change in valuation allowance | (15,620) | 13,772 | |||||||||
| Balance at the end of the period | $ | 130,649 | $ | 146,269 | |||||||
NFE recorded a valuation allowance against its 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, 2022, 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 for the amount not supported by reversing taxable temporary differences.
The Company recorded a valuation allowance against certain foreign deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized, generally based on cumulative losses in certain development stage jurisdictions.
Uncertain Taxes
The following table summarizes the changes in the Company’s unrecognized tax benefits for the years ended December 31, 2022 and 2021:
Year Ended December 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Balance at the beginning of the period | $ | 12,474 | $ | — | |||||||
| Assumed in the Mergers | — | 12,705 | |||||||||
| Recognized in the income tax provision | — | (231) | |||||||||
| Reduction as a result of Energos Formation Transaction | (12,474) | — | |||||||||
| Balance at the end of the period | $ | — | $ | 12,474 | |||||||
As of December 31, 2021, the liability for unrecognized tax benefits was included in Other non-current liabilities on the consolidated balance sheets. The Company accrued $1,371 of interest expense during 2021 and had total interest accrued of $3,667 as of December 31, 2021. In addition to the liabilities for unrecognized income tax benefits assumed in the Mergers, the Company assumed liabilities related to potential employment tax obligations that were accounted for under ASC 450 of $6,309 as of December 31, 2021. This liability was also included in Other non-current liabilities on the consolidated balance sheets as of December 31, 2021 and was derecognized in conjunction with the Energos Formation Transaction.
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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 2019, 2020 and 2021 are open for examination. The Company is generally open to tax examinations in other foreign jurisdictions for a period of 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, 2022. 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.
The Company’s Puerto Rican operations received a tax decree from the Puerto Rico government that affords the Company a 4 percent tax rate on qualifying income until 2035. The effect of the earnings taxed at a 4 percent foreign tax rate is included in the foreign rate differential line in the Company’s effective tax rate. For the years ended December 31, 2022 and 2021, the income tax benefits attributable to the tax decree, before taking into consideration the impact on U.S. taxation and the associated U.S. foreign tax credits, are estimated to be approximately $10,605 ($0.05 per share of issued and outstanding Class A common stock on a diluted basis) and $14,047 ($0.07 per share of issued and outstanding Class A common stock on a diluted basis), respectively.
22. Commitments and contingencies
The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
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23. Earnings per share
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Basic | |||||||||||||||||
| Numerator: | |||||||||||||||||
| Net income (loss) | $ | 184,786 | $ | 92,711 | $ | (263,965) | |||||||||||
| Less: net income (loss) attributable to non-controlling interests | 9,693 | 4,393 | 81,818 | ||||||||||||||
| Net income (loss) attributable to Class A common stock | $ | 194,479 | $ | 97,104 | $ | (182,147) | |||||||||||
| Denominator: | |||||||||||||||||
| Weighted-average shares - basic | 209,501,298 | 198,593,042 | 106,654,918 | ||||||||||||||
| Net income (loss) per share - basic | $ | 0.93 | $ | 0.49 | $ | (1.71) | |||||||||||
| Diluted | |||||||||||||||||
| Numerator: | |||||||||||||||||
| Net income (loss) | $ | 184,786 | $ | 92,711 | $ | (263,965) | |||||||||||
| Less: net income (loss) attributable to non-controlling interests | 9,693 | 4,393 | 81,818 | ||||||||||||||
| Less: adjustments attributable to dilutive securities | — | 2,861 | — | ||||||||||||||
| Net income (loss) attributable to Class A common stock | $ | 194,479 | $ | 94,243 | $ | (182,147) | |||||||||||
| Denominator: | |||||||||||||||||
| Weighted-average shares - diluted | 209,854,413 | 201,703,176 | 106,654,918 | ||||||||||||||
| Net income (loss) per share - diluted | $ | 0.93 | $ | 0.47 | $ | (1.71) | |||||||||||
The following table presents potentially dilutive securities excluded from the computation of diluted net income (loss) per share for the years ended December 31, 2022 and 2020 because its effects would have been anti-dilutive. All potentially dilutive securities are included in the computation of diluted net income for the year ended December 31, 2021.
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
Unvested RSUs(1) | — | — | 1,538,060 | ||||||||||||||
Equity agreement shares(2) | 458,696 | — | 428,275 | ||||||||||||||
| Total | 458,696 | — | 1,966,335 | ||||||||||||||
(1)Represents the number of instruments outstanding at the end of the period.
(2)Class A common stock that would be issued in relation to an agreement to issue shares executed in conjunction with a prior year asset acquisition.
The Company declared and paid quarterly dividends totaling $82,974 during the year ended December 31, 2022, 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. In connection with the dividend policy update, the Board 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, 2022, the Company paid dividends of $12,076 to holders of GMLP’s 8.75% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). As these equity interests have been issued by the Company’s consolidated subsidiary, the value of the Series A Preferred Units is recognized as non-controlling interest in the consolidated financial statements.
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24. Share-based compensation
Performance Share Units (“PSUs”)
The Company has granted PSUs to certain employees and non-employees that contain a performance condition under the Incentive Plan. Vesting is determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. During the fourth quarter of 2022, the Company determined that the PSUs granted in the first quarter of 2021 ("2021 Grant") 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 2022.
As of December 31, 2022, the Company determined that it was not probable that the performance condition required for PSUs granted in the fourth quarter of 2022 ("2022 Grant") to vest would be achieved, and as such, no compensation expense has been recognized for this award.
| PSUs Granted | Units Granted | Range of Vesting | Units Vested / Probable of Vesting | Unrecognized Compensation Cost⁽¹⁾ | Weighted Average Remaining Vesting Period | |||||||||||||||||||||||||||
| 2021 Grant | 400,507 | 0 to 801,014 | 681,204 | — | 0 | |||||||||||||||||||||||||||
| 2022 Grant | 742,073 | 0 to 1,484,146 | — | 66,935 | 1 year | |||||||||||||||||||||||||||
(1)Unrecognized compensation cost is based upon the maximum amount of shares that could vest.
Restricted Stock Units ("RSUs")
The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the Incentive Plan. The fair value of RSUs on the grant date is estimated based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model.
The following table summarizes the RSU activity for the year ended December 31, 2022:
| Restricted Stock Units | Weighted-average grant date fair value per share | ||||||||||
Non-vested RSUs as of December 31, 2021 | 676,338 | $ | 13.49 | ||||||||
| Granted | 12,196 | 29.89 | |||||||||
| Vested | (688,534) | 13.81 | |||||||||
| Forfeited | — | — | |||||||||
Non-vested RSUs as of December 31, 2022 | — | $ | — | ||||||||
The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the years ended December 31, 2022, 2021 and 2020:
Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Operations and maintenance | $ | 4 | $ | 848 | $ | 800 | |||||||||||
| Selling, general and administrative | 2,673 | 5,728 | 7,943 | ||||||||||||||
| Total share-based compensation expense | $ | 2,677 | $ | 6,576 | $ | 8,743 | |||||||||||
For the year ended December 31, 2022, no cumulative compensation expense was recognized for forfeited RSU awards. For the years ended December 31, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards
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of $212 and $914, 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.
25. Related party transactions
Management services
Messrs. Edens, chief executive officer and chairman of the Board of Directors and Nardone, member of the Board of Directors, are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $5,087, $6,509, and $7,291 for the years ended December 31, 2022, 2021 and 2020, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2022 and 2021, $4,629 and $5,700 were due to Fortress, respectively.
In addition to administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator rates, charter costs of $3,714, $4,466 and $2,483 for the years ended December 31, 2022, 2021 and 2020, respectively. As of December 31, 2022 and 2021, $416 and $944 was due to this affiliate, respectively.
Land lease
The Company has leased land from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $506, $526 and $730 during the years ended December 31, 2022, 2021 and 2020, respectively, which was included within Operations and maintenance in the consolidated statements of operations and comprehensive income (loss). The Company did not have any amounts due to FECI as of December 31, 2022 and 2021. As of December 31, 2022 and 2021, the Company has recorded a lease liability of $3,340 and $3,314 , respectively, within Non-current lease liabilities on the consolidated balance sheets.
DevTech
In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest was reflected as non-controlling interest in the Company’s consolidated financial statements. DevTech also purchased 10% of a note payable due to an affiliate of the Company. During the third quarter of 2021, the Company settled all outstanding amounts due under notes payable; the consulting agreement was also restructured to settle all previous amounts owed to DevTech and to include a royalty payment based on certain volumes sold in Jamaica. The Company paid $988 to settle these outstanding amounts. Subsequent to the restructuring of the consulting agreement, the Company recognized approximately $408 and $176 in expense for the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, $80 and $88 were due to DevTech, 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. Beginning in the fourth quarter of 2020, the Company began to sublease a portion of office space to an affiliate of an entity managed by Fortress, and for the years ended December 31, 2022, 2021 and 2020, rent and office related expenses of $857, $799 and $204 were incurred by this affiliate, respectively. As of December 31, 2022 and 2021, $700 and $1,241 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 $2,453, $2,444 and $2,357 for the years ended December 31, 2022, 2021 and 2020, respectively. As of December 31, 2022 and 2021, $2,455 and $2,444 were due to Fortress affiliated entities, respectively.
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Agency agreement with PT Pesona Sentra Utama (or PT Pesona)
PT Pesona, an Indonesian company, owns 51% of the issued share capital in the Company’s former subsidiary, PTGI, the owner and operator of NR Satu, and prior to completion of the Energos Formation Transaction, provided agency and local representation services for the Company with respect to NR Satu. PT Pesona and certain of its subsidiaries also charged vessel management fees to the Company for the provision of technical and commercial management of the vessels; total expenses incurred to PT Pesona prior to the completion of the Energos Formation Transaction were $537 and $434 for the years ended December 31, 2022 and 2021, respectively.
Hilli guarantees
As part of the GMLP Merger, the Company agreed to assume a guarantee (the “Partnership Guarantee”) of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. The Company also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under the LTA. Under the LOC Guarantee, the Company is severally liable for any outstanding amounts that are payable, up to approximately $19,000.
Under the Partnership Guarantee and the LOC Guarantee NFE’s subsidiary, GMLP, is required to comply with the following covenants and ratios:
•free liquid assets of at least $30 million throughout the Hilli Leaseback period;
•a maximum net debt to EBITDA ratio for the previous 12 months of 6.5 1; and
•a consolidated tangible net worth of $124.0 million.
As of December 31, 2022 and 2021, the amount the Company has guaranteed under the Partnership Guarantee and the LOC Guarantee is $323,250 and $356,250, respectively. As of December 31, 2022, the fair value of debt guarantee after amortization of $2,320 is presented within Other current liabilities. As of December 31, 2021, the fair value of debt guarantee after amortization, presented within Other current liabilities and Other long-term liabilties amounted to $4,918 and $2,320, respectively. As of December 31, 2022 the Company was in compliance with the covenants and ratios for both Hilli guarantees.
After the completion of the disposition of our interest in Hilli expected to be completed in the first quarter of 2023 (see note 28), the Company will no longer provide the Partnership Guarantee and LOC Guarantee.
CELSE inventory purchases
During the fourth quarter of 2021, the Company purchased 3.1 TBtus of LNG from CELSE for $35,173. The inventory purchased from CELSE was subsequently sold prior to December 31, 2021. As of December 31, 2021, there were no outstanding amounts payable to CELSE for the purchase of LNG. After the Sergipe Sale, CELSE is no longer a related party.
26. Customer concentrations
For the year ended December 31, 2022, revenue from two significant customers constituted 42% of total revenue. For the year ended December 31, 2021, revenue from three significant customers constituted 48% of the total revenue; no other customers comprised more than 10% of our revenue. For the year ended December 31, 2020, revenue from three significant customers constituted 88% of the total revenue. These customers’ revenues are included in the Company’s Terminals and Infrastructure segment.
During the years ended December 31, 2022, 2021 and 2020, revenue from external customers that were derived from customers located in the United States were $246,628, $203,477 and $135,702, respectively, and from customers outside of the United States were $2,121,644, $1,119,333, and $315,948. The Company attributes revenue from customers to the country in which the party to the applicable agreement has its principal place of business.
As of December 31, 2022 and 2021, long lived assets, which are all non-current assets excluding investment in equity securities, restricted cash, deferred tax assets, goodwill, intangible assets and assets held for sale located in the United
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States were $1,695,604 and $633,125, respectively, and long lived assets located outside of the United States were $3,809,080 and $4,722,589, respectively, primarily located in Brazil and the Caribbean.
27. Segments
As of December 31, 2022, the Company operates in two reportable segments: Terminals and Infrastructure and Ships:
•Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. Vessels that are utilized in the Company’s terminal or logistics operations are included in this segment.
•Ships includes FSRUs and LNG carriers that are leased to customers under long-term or spot arrangements. FSRUs are stationed offshore for customer’s operations to regasify LNG; five of the Company's FSRUs are included in this segment. LNG carriers are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally. Five of the Company's LNG carriers are included in this segment. The Company’s investments in Hilli LLC and Energos are also included in the Ships segment.
The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value. Prior to the completion of the Sergipe Sale, Terminals and Infrastructure Segment Operating Margin included our effective share of revenue, expenses and segment operating margin attributable to our 50% ownership of CELSEPAR. Ships Operating Margin includes our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC. We continue to include the results of operations of vessels included in the Energos Formation Transaction in the consolidated statements of operations and comprehensive income (loss), and revenue and vessel operating expenses from these vesesls is included in Ships Operating Margin.
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, 2022, 2021 and 2020:
Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure⁽¹⁾ | Ships⁽²⁾ | Total Segment | Consolidation and Other⁽³⁾ | Consolidated | |||||||||||||||||||||||||||
| Statement of operations: | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 2,168,565 | $ | 444,616 | $ | 2,613,181 | $ | (244,909) | $ | 2,368,272 | ||||||||||||||||||||||
Cost of sales (6) | 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(4) | $ | 5,913,775 | $ | 1,791,307 | $ | 7,705,082 | $ | — | $ | 7,705,082 | ||||||||||||||||||||||
| Other segmental financial information: | ||||||||||||||||||||||||||||||||
Capital expenditures(5) | $ | 1,482,871 | $ | 27,127 | $ | 1,509,998 | $ | — | $ | 1,509,998 | ||||||||||||||||||||||
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Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure⁽¹⁾ | Ships⁽²⁾ | Total Segment | Consolidation and Other⁽³⁾ | Consolidated | |||||||||||||||||||||||||||
| Statement of operations: | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 1,366,142 | $ | 329,608 | $ | 1,695,750 | $ | (372,940) | $ | 1,322,810 | ||||||||||||||||||||||
Cost of sales (6) | 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 | ||||||||||||||||||||||
| Balance sheet: | ||||||||||||||||||||||||||||||||
Total assets(4) | $ | 4,775,392 | $ | 2,101,100 | $ | 6,876,492 | $ | — | $ | 6,876,492 | ||||||||||||||||||||||
| Other segmental financial information: | ||||||||||||||||||||||||||||||||
Capital expenditures(5) | $ | 833,910 | $ | 8,293 | $ | 842,203 | $ | — | $ | 842,203 | ||||||||||||||||||||||
Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||
| (in thousands of $) | Terminals and Infrastructure⁽¹⁾ | Ships⁽²⁾ | Total Segment | Consolidation and Other⁽³⁾ | Consolidated | |||||||||||||||||||||||||||
| Statement of operations: | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 451,650 | $ | — | $ | 451,650 | $ | — | $ | 451,650 | ||||||||||||||||||||||
Cost of sales (6) | 278,767 | — | 278,767 | — | 278,767 | |||||||||||||||||||||||||||
| Vessel operating expenses | — | — | — | — | — | |||||||||||||||||||||||||||
| Operations and maintenance | 47,581 | — | 47,581 | — | 47,581 | |||||||||||||||||||||||||||
| Segment Operating Margin | $ | 125,302 | $ | — | $ | 125,302 | $ | — | $ | 125,302 | ||||||||||||||||||||||
| Other segmental financial information: | ||||||||||||||||||||||||||||||||
| Capital expenditures⁽⁵⁾ | $ | 340,603 | $ | — | $ | 340,603 | $ | — | $ | 340,603 | ||||||||||||||||||||||
(1)Prior to the completion of the Sergipe Sale, Terminals and Infrastructure included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR. The losses attributable to the investment of $397,874 and $17,925 for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market earnings and loss on derivative instruments of $106,103 and $2,788 for the years ended December 31, 2022 and 2021, respectively, reported in Cost of sales.
(2)Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of the Hilli Common Units. The loss and earnings attributable to the investment of $77,132 and $32,368 for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss).
(3)Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR and Hilli Common Units in the segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.
(4)Total assets and capital expenditure by segment refers to assets held and capital expenditures related to the development of the Company’s terminals and vessels. The Terminals and Infrastructure segment includes the net book value of vessels utilized within the Terminals and Infrastructure segment.
(5)Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period.
(6)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).
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Consolidated Segment Operating Margin is defined as net income (loss), adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, interest expense, other (income) expense, income from equity method investments and tax expense.
The following table reconciles Net income (loss), the most comparable financial statement measure, to Consolidated Segment Operating Margin:
Year Ended December 31, | ||||||||||||||||||||
| (in thousands of $) | 2022 | 2021 | 2020 | |||||||||||||||||
| Net income (loss) | $ | 184,786 | $ | 92,711 | $ | (263,965) | ||||||||||||||
| Add: | ||||||||||||||||||||
| Selling, general and administrative | 236,051 | 199,881 | 120,142 | |||||||||||||||||
| Transaction and integration costs | 21,796 | 44,671 | 4,028 | |||||||||||||||||
| Contract termination charges and loss on mitigation sales | — | — | 124,114 | |||||||||||||||||
| Depreciation and amortization | 142,640 | 98,377 | 32,376 | |||||||||||||||||
| Interest expense | 236,861 | 154,324 | 65,723 | |||||||||||||||||
| Other (income) expense, net | (48,044) | (17,150) | 5,005 | |||||||||||||||||
| Tax (benefit) provision | (123,439) | 12,461 | 4,817 | |||||||||||||||||
| Asset impairment expense | 50,659 | — | — | |||||||||||||||||
| Loss on extinguishment of debt, net | 14,997 | 10,975 | 33,062 | |||||||||||||||||
| Loss (income) from equity method investments | 472,219 | (14,443) | — | |||||||||||||||||
| Consolidated Segment Operating Margin | $ | 1,188,526 | $ | 581,807 | $ | 125,302 | ||||||||||||||
28. Subsequent events
On February 7, 2023, the Company entered into an amendment to the Revolving Facility to increase the commitments thereunder by $301,700, for a total capacity under the Revolving Facility of $741,700. The interest rate per annum and the Applicable Margin for borrowings under the Revolving Facility based on the current usage of the facility have not changed. No changes were made to the maturity date or covenants.
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Schedule II
| Description | Balance at Beginning of Year | Additions(1)(2) | Deductions | Balance at End of Year | |||||||||||||||||||
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 | |||||||||||||||||||
Year ended December 31, 2020 | |||||||||||||||||||||||
| Allowance for doubtful accounts | — | 545 | — | 545 | |||||||||||||||||||
Notes:
(1)Amount expensed is included within Selling, general and administrative.
(2)Additions in 2020 include the cumulative effect of accounting change upon adoption of ASC 326 of $229 which is included within Accumulated deficit.
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