New Fortress Energy Inc. - Annual Report: 2021 (Form 10-K)

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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

 

 

For the year ended December 31, 2021

OR

 

 

For the transition period from                to_______

Commission File Number:001-38790

New Fortress Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

 

Registrant’s telephone number, including area code: (516) 268-7400

Securities registered pursuant to Section 12(b) of the Act:

 

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  ☒ No ☐

 

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  ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ☒ No ☐

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No  ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ☐ No ☒

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed as of June 30, 2021 (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 $2,754.1 million.

 

At February 24, 2022, the registrant had 206,863,242 shares of Class A common stock outstanding.

 

Documents Incorporated by Reference:

 

Portions of the registrant’s definitive proxy statement for the registrant’s 2022 annual meeting, to be filed within 120 days after the close of the registrant’s fiscal year, are incorporated by reference into Parts II and III of this Annual Report on Form 10-K.

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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

•	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;

•	complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;

•	delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;

•	failure to maintain sufficient working capital for the development and operation of our business and assets;

•	failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;

•	failure to convert our customer pipeline into actual sales;

•	lack of asset, geographic or customer diversification, including loss of one or more of our customers;

•	competition from third parties in our business;

•	failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;

•	cyclical or other changes in the demand for and price of LNG and natural gas;

•	inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;

•	inability to successfully develop and implement our technological solutions;

•	inability to service our debt and comply with our covenant restrictions;

•	inability to obtain additional financing to effect our strategy;

•	inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits, including with respect to the Mergers;

•	economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;

•	weather events or other natural or manmade disasters or phenomena;

•	the extent of the global COVID-19 pandemic or any other major health and safety incident;

•	increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;

•	the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A shares; and

•	other risks described in the “Risk Factors” section of this Annual Report.

Items 1 and 2.

Business and Properties

•

our LNG storage and regasification facility at the Port of Montego Bay, Jamaica (the “Montego Bay Facility”),

•

our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility” and, together with the Montego Bay Facility, the “Jamaica Facilities”),

•

our landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”),

•

our marine LNG storage and regasification facility in Sergipe, Brazil (the “Sergipe Facility”),

•

our LNG receiving facility in La Paz, Mexico (the “La Paz” Facility”), and

•

at our Miami Facility.

•

collecting and analyzing diversity data;

Item 1A.

Risk Factors

•

We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers;

•

We have a limited operating history, which may not be sufficient to evaluate our business and prospects;

•

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;

•

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 operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation;

•

Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction;

•

When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project;

•

Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations;

•

Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements;

•

Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects;

•

Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;

•

Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess;

•

Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;

•

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers;

•

We 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;

•

We have incurred, and may in the future incur, a significant amount of debt;

•

Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms;

•

We may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;

•

Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate;

•

We 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;

•

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;

•

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;

•

A change in tax laws in any country in which we operate could adversely affect us;

•

A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders; and

•

The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all.

•

managing a larger company;

•

attracting, motivating and retaining management personnel and other key employees;

•

the possibility of faulty assumptions underlying expectations regarding the integration process;

•

retaining existing business and operational relationships and attracting new business and operational relationships;

•

consolidating corporate and administrative infrastructure and eliminating duplicative operations;

•

coordinating geographically separate organizations;

•

unanticipated issues in integrating information technology, communications and other systems; and

•

unanticipated changes in federal or state laws or regulations.

•

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 develop cost-effective logistics solutions;

•

failure to manage expanding operations in the projected timeframe;

•

inability to develop infrastructure in a timely and cost-effective manner;

•

increases in competition which could increase our costs and undermine our profits;

•

inability to source LNG and/or natural gas in sufficient quantities and/or at economically attractive prices;

•

failure to anticipate and adapt to new trends in the energy sector;

•

increases in operating costs, including the need for capital improvements, insurance premiums, general taxes, real estate taxes and utilities, affecting our profit margins;

•

failure to win new bids or contracts on the terms, size and within the time frame we need to execute our business strategy;

•

failure to obtain 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.

•

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.

•

performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

•

breakdowns or failures of equipment or shortages or delays in the delivery of supplies;

•

operational errors by trucks, including trucking accidents while transporting natural gas, LNG or any other chemical or hazardous substance;

•

tankers or tug operators;

•

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 that could result in personal injury or loss of life;

•

lack of adequate and qualified personnel;

•

potential labor shortages, work stoppages or labor union disputes;

•

weather-related or natural disaster interruptions of operations;

•

pollution 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.

•

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.

•

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 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.

•

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.

•

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.

•

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.

•

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.

•

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.

Item 1B.

Unresolved Staff Comments.

Item 3.

Legal Proceedings.

Item 4.

Mine Safety Disclosures.

Item 5.

Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

Item 6.

Reserved.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

		Year Ended December 31,
(in millions of gallons)		2021				2020				Change
Old Harbour Facility			211.2				192.2				19.0
Montego Bay Facility			84.0				94.2				(10.2	)
San Juan Power Plant			184.0				129.5				54.5
Other			16.9				12.9				4.0
Total volumes delivered in the current period			496.1				428.8				67.3

		Year Ended December 31,
(in TBtu)		2021				2020				Change
Old Harbour Power Plant			17.5				15.9				1.6
Montego Bay Facility			7.1				7.9				(0.8	)
San Juan Power Plant			14.9				10.7				4.2
Other			2.3				1.1				1.2
Total volumes delivered in the current period			41.8				35.6				6.2

•

Sales at the Old Harbour Facility increased by $46,307 from $189,196 for the year ended December 31, 2020 to $235,503 for the year ended December 31, 2021. The increase in revenue from the Old Harbour Facility was due to an increase in the Henry Hub index used to invoice our customers as compared to the year ended December 31, 2020 and an increase in volumes delivered at the Old Harbour Power Plant.

•

Revenue from the delivery of power and steam increased by $5,833 from $23,415 for the year ended December 31, 2020 to $29,248 for the year ended December 31, 2021, which began during March 2020 under our contracts with JPS and Jamalco.

•

The increase in volumes delivered at the Old Harbour Power Plant was partially offset by a decrease in consumption by the CHP Plant and Jamalco’s boilers. The Jamalco refinery experienced a fire in August 2021, and no gas volumes have been consumed by their boilers since this event. However, steam revenue has been consistent with previous periods as our contract with Jamalco has take-or-pay provisions that allow us to invoice for minimum volumes.

•

Sales at the Montego Bay Facility increased by $4,067 from $93,236 for the year ended December 31, 2020 to $97,303 for the year ended December 31, 2021. The increase in revenue from the Montego Bay Facility was due to an increase in the Henry Hub index used to invoice our customers compared to the year ended December 31, 2020 and increased volume sold to industrial end users. Additional revenue from industrial end users offset the decrease in volumes consumed by the Bogue Power Plant.

•

The decrease in volumes delivered at the Montego Bay Facility of 10.2 million gallons (0.8 TBtu) was driven by a reconfiguration of the Port of Montego Bay where our facility resides required by the port authority. During this reconfiguration, we are unable to deliver volumes to the Bogue Power Plant; we expect this reconfiguration to be completed in the first half of 2022.

•

Cost of LNG purchased from third parties for sale to our customers increased $117,943 for the year ended December 31, 2021 as compared to the year ended December 31, 2020. The increase was primarily attributable to a 16% increase in volumes delivered compared to the year ended December 31, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020 to $0.59 per gallon ($7.09 per MMBtu) for the year ended December 31, 2021.

•

Cost of LNG from the sale of cargos in the market was $191,308 for the year ended December 31, 2021 as compared to $0 for the year ended December 31, 2020. Due to the significant increase in market pricing of LNG in the second half of 2021, we have optimized our supply portfolio to sell a portion of our committed cargos in the market. The weighted-average cost of LNG from the sale of a portion of our cargos was $0.81 per gallon ($9.82 per MMBtu).

•

Subsequent to the acquisition of the Sergipe Facility as part of the Mergers, our share of Cost of sales from our investment in CELSEPAR was $175,847 for the year ended December 31, 2021, which was comprised of LNG costs to fuel the power plant and costs of power to fulfill requirements under the PPAs.

•

The increase for the year ended December 31, 2021 as compared to the year ended December 31, 2020 was also the result of San Juan Facility and the CHP Facility during the year ended December 31, 2021 that were still in development during a portion of the year ended December 31, 2020. Operations and maintenance increased by the costs of operating the San Juan Facility and CHP Plant, and an increase in payroll costs, maintenance costs, insurance costs and port fees.

•

Subsequent to acquisition of the Sergipe Facility as part of the Mergers, our share of Operations and maintenance from our investment in CELSEPAR was $19,108 for the year ended December 31, 2021, which was primarily comprised of costs related to the operation and services agreement for the Nanook, insurance costs and costs for connecting to the transmission system.

•

Subsequent to the completion of the Mergers, our results of operations include depreciation expense primarily for the vessels acquired. We recognized $38,950 of incremental depreciation expense for the acquired vessels during the year ended December 31, 2021;

•

Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $16,658 for the year ended December 31, 2021;

•

Increase in depreciation of $5,179 for the San Juan Facility that went into service in July 2020 for the year ended December 31, 2021; and

•

Increase in depreciation of $2,536 for the CHP Plant that went into service in March 2020 for the year ended December 31, 2021.

•

Gains in investments in equity securities of $8,254 for the year ended December 31, 2021;

•

Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulting additional income of $5,562 for the year ended December 31, 2021.

•

Our historical financial results include the results of operations of Hygo and GMLP only since the completion of the Mergers in April 2021. Upon completion of the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an interest in a floating liquefaction vessel. We also acquired a 50% interest in the Sergipe Facility and the Sergipe Power Plant, as well as the Barcarena Facility and Barcarena Power Plant and the Santa Catarina Facility that are currently in development. The results of operations of Hygo and GMLP began to be included in our financial statements upon the closing of the acquisitions on April 15, 2021. Our results of operations in 2021 also include transaction and integration costs associated with these acquisitions, some of which would not be expected in future periods. Our future results of operations may continue to be impacted by costs to integrate the operations of Hygo and GMLP, including costs to exit or modify transition service agreements or vessel management agreements, all of which may be significant.

•

Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2021 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We recently placed a portion of our La Paz Facility into service, and in the fourth quarter of 2021, our revenue and results of operations began to be impacted by operations in Mexico. We are continuing to develop of our La Paz Power Plant and our Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects. Our current results also exclude other developments, including the Suape Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility.

•

Our historical financial results do not reflect new LNG supply agreements, as well as our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 96% of our LNG volumes from third parties for the year ended December 31, 2021. During 2020 and 2021, we entered into LNG supply agreements for the purchase of approximately 601 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. We have now secured supply for LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. We also anticipate that the deployment of Fast LNG floating liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third party suppliers.

•

In January 2020, we borrowed $800,000 under a credit agreement, and repaid our prior term loan facility in full.

•

In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025.

•

In December 2020, we received proceeds of $263,125 from the issuance of $250,000 of additional notes on the same terms as the 2025 Notes (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).

•

In December 2020, we issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs.

•

In April 2021, we issued $1,500,000 of 2026 Notes; we also entered into the $200,000 Revolving Facility that has a term of approximately five years.

•

In August 2021, we entered into the CHP Facility (defined below) and initially drew $100,000, which may be increased to $285,000.

•

In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility (defined below). Under this facility, we borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels.

(in thousands)		Total				Year 1				Years 2 to 3				Years 4 to 5				More than 5 years
Long-term debt obligations		$	4,936,353			$	305,575			$	878,471			$	3,341,677			$	410,630
Purchase obligations			5,265,356				784,060				1,637,783				1,450,817				1,392,696
Lease obligations			420,329				67,131				101,295				68,393				183,510
Total		$	10,622,038			$	1,156,766			$	2,617,549			$	4,860,887			$	1,986,836

Item 7A.

Quantitative and Qualitative Disclosures About Market Risks.

Item 8.

Financial Statements and Supplementary Data.

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

Item 9A.

Controls and Procedures.

Item 9B.

Other Information.

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Item 10.

Directors, Executive Officers and Corporate Governance.

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

Item 14.

Principal Accounting Fees and Services.

Item 15.

Exhibits, Financial Statement Schedules.

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations and Comprehensive Income (Loss)	F-6
Consolidated Statements of Changes in Stockholders’ Equity	F-7
Consolidated Statements of Cash Flows	F-8
Notes to Consolidated Financial Statements	F-9

		Fair value measurements in connection with GMLP and Hygo business combinations
Description of the Matter		As discussed in Note 4 to the consolidated financial statements, on April 15, 2021, the Company completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”) (collectively, the “Acquisitions”) for total consideration of $1.98 billion and $1.15 billion, respectively. The Acquisitions were accounted for as separate business combinations. The Company’s accounting under the acquisition method included determining the fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities. Auditing the Company’s accounting for the Acquisitions was complex due to the significant estimation uncertainty inherent in determining the fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities. The significant estimation uncertainty was primarily due to the sensitivity of the respective fair values to changes in the underlying assumptions. The significant assumptions used to estimate the fair value of these assets, liabilities and noncontrolling interests included: (i.) discount rates applied to the contractual cash flows associated with the acquired equity method investments, contract intangible assets, assumed debt and noncontrolling interests in the acquired entities, (ii.) the estimated replacement cost of the acquired vessels, and (iii.) market day rates used to measure the fair value of vessel charter contracts.

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 business combinations process. This included controls over the valuation of acquired assets, liabilities assumed and noncontrolling interests in the acquired entities and management’s review of the significant assumptions described above.   To test the estimated fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities, we performed audit procedures that included, among others, evaluating the valuation methodologies utilized by management and the significant assumptions described above, as well as testing the completeness and accuracy of the underlying data. For example, we compared the significant assumptions utilized to current market and economic trends and to the historical results of the acquired businesses. We also performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the acquired vessels, contract intangible assets, and equity method investments that would result from changes in the assumptions. We involved our internal valuation specialists to assist in evaluating the valuation methodologies used and the significant assumptions described above, including the discount rates utilized and the replacement costs of the acquired vessels.
		Impairment Assessment of Long-Lived Assets
Description of the Matter		As described in Note 2(j) to the consolidated financial statements, the Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for liquified natural gas (“LNG”) to the Company’s operations, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if long-lived assets or asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value.   Auditing management’s determination of whether impairment indicators exist such that a recoverability test of the Company’s long-lived assets is required, was highly subjective and involves significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.
How We Addressed the Matter in Our Audit		We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups that may have been impacted by the impairment indicators described above.   To test the Company’s evaluation of potential indicators of impairment of its long-lived assets, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company operates and their impact on the recoverability of the related long-lived assets and asset groups.  We also obtained capital budgets and construction bids, among other evidence, to understand management’s plans with respect to in-process development projects.  We considered information about Company’s projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.

PART I

FINANCIAL INFORMATION