F-1/A 1 nt10010929x10_f1a.htm F-1/A

As filed with the Securities and Exchange Commission on September 16, 2020

Registration Statement No. 333-248501

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2 to

FORM F-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Hygo Energy Transition Ltd.

(Exact name of registrant as specified in its charter)

Not Applicable

(Translation of Registrant’s name into English)

Bermuda			4924			N/A
(State or other jurisdiction of incorporation or organization)			(Primary Standard Industrial Classification Code Number)			(I.R.S. Employer Identification No.)

2^nd Floor, S.E. Pearman Building,

9 Par-la-Ville Road

Hamilton HM 11, Bermuda

+1 (441) 295-4705

(Address, including zip code, and telephone number, including area code of Registrant’s principal executive offices)

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

David Palmer Oelman

Brenda K. Lenahan

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

J. Michael Chambers

John M. Greer

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

Approximate date of commencement of proposed sale to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933.

Emerging growth company ☒

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, 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 7(a)(2)(B) of the Securities Act. ☐

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered			Amount of Securities to be Registered⁽¹⁾			Proposed Maximum Offering Price⁽²⁾			Proposed Maximum Aggregate Offering Price⁽¹⁾⁽²⁾			Amount of Registration Fee⁽³⁾
Common shares, par value $0.4695 per share			26,565,000			$21.00			$557,865,000.00			$72,410.88

(1)	Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 3,465,000 common shares issuable upon exercise of the underwriters’ option to purchase additional common shares.

(2)	Estimated solely for the purpose of calculating the registration fee.

(3)	The registrant previously paid $12,980 of the total registration fee in connection with previous filings of the Registration Statement.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated September 16, 2020

PRELIMINARY PROSPECTUS

Hygo Energy Transition Ltd.

23,100,000 Common Shares

This is the initial public offering of common shares of Hygo Energy Transition Ltd. We are offering 23,100,000 common shares. We expect the initial public offering price to be between $18.00 and $21.00 per common share.

Prior to this offering, there has been no public market for our common shares. We have applied to list our common shares on the Nasdaq Global Select Market under the symbol “HYGO.”

We are an “emerging growth company” and a “foreign private issuer” as defined under the U.S. federal securities laws and, as such, are eligible for reduced reporting requirements for this prospectus and future filings. Please read “Summary—Our Emerging Growth Company Status” and “Summary—Our Foreign Private Issuer and Controlled Company Status.”

Investing in our common shares involves risks. Please read “Risk Factors” beginning on page 20.

	Per common share	Total
Public Offering Price	$	$
Underwriting Discounts	$	$
Proceeds to us (before expenses)	$	$

(1)	See “Underwriting” for a description of compensation payable to the underwriters.

The underwriters may purchase up to an additional 3,465,000 common shares from us at the public offering price, less the underwriting discount, within 30 days from the date of the underwriting agreement to be entered into in connection with this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common shares to purchasers on or about , 2020 through the book-entry facilities of The Depository Trust Company.

Joint Book-Running Managers

Morgan Stanley

Goldman Sachs & Co. LLC

Citigroup

Barclays

BofA Securities

BTG Pactual

BTIG

Credit Suisse

Itaú BBA

UBS Investment Bank

XP Investimentos

Arctic Securities

DNB Markets

Fearnley Securities

Prospectus dated , 2020

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FORWARD-LOOKING STATEMENTS			iv
SUMMARY			1
RISK FACTORS			20
USE OF PROCEEDS			58
CAPITALIZATION			59
DILUTION			61
DIVIDEND POLICY			62
SELECTED HISTORICAL FINANCIAL DATA			63
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			65
INDUSTRY			85
BUSINESS			90
MANAGEMENT			130
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			136
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			137
DESCRIPTION OF SHARE CAPITAL			144
SHARES ELIGIBLE FOR FUTURE SALE			153
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS			154
BERMUDA TAXATION			161
UNDERWRITING			162
LEGAL MATTERS			168
EXPERTS			168
SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES			168
EXPENSES OF THE OFFERING			168
WHERE YOU CAN FIND MORE INFORMATION			169
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			F-1
GLOSSARY			A-1

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. You should not assume that the information contained in this registration statement is accurate as of any date other than the date on the front cover of this registration statement. Our business, financial condition, results of operations and prospects may have changed since such dates. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Common shares may be offered or sold in Bermuda only in compliance with the provisions of the Investment Business Act of 2003 and the Exchange Control Act 1972, and related regulations of Bermuda which regulate the sale of securities in Bermuda. In addition, specific permission is required from the Bermuda Monetary Authority, or the BMA, pursuant to the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of securities of Bermuda companies, other than in cases where the BMA has granted a general permission. The BMA, in its policy dated June 1, 2005, provides that where any equity securities, including our common shares, of a Bermuda company are listed on an appointed stock exchange, general permission is given for the issue and subsequent transfer of any securities of a company from and/or to a non-resident, for as long as any equities securities of such company remain so listed. The Nasdaq Global Select Market is an appointed stock exchange under Bermuda law. Approvals or permissions given by the Bermuda Monetary Authority do not constitute a guarantee by the Bermuda Monetary Authority as to our performance or our creditworthiness. Accordingly, in granting such permission, the BMA accepts no

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responsibility for our financial soundness or the correctness of any of the statements made or expressed in this prospectus or any prospectus supplement. Neither this prospectus nor any prospectus supplement needs to be filed with the Registrar of Companies in Bermuda in accordance with Part III of the Companies Act 1981 of Bermuda (the “Companies Act”) pursuant to provisions incorporated therein following the enactment of the Companies Amendment Act 2013. Such provisions state that a prospectus in respect of the offer of shares in a Bermuda company whose equities are listed on an appointed stock exchange under Bermuda law does not need to be filed in Bermuda, so long as the company in question complies with the requirements of such appointed stock exchange in relation thereto.

The BMA and the Registrar of Companies accept no responsibility for the financial soundness of any proposal or for the correctness of any of the statements made or opinions expressed in this prospectus.

Industry and Market Data

The data included in this prospectus regarding the industries in which we operate, including trends in the market and our position and the position of our competitors, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information (including the reports and other information our competitors file with the Securities and Exchange Commission (the “SEC”), which we did not participate in preparing and as to which we make no representation), as well as our good-faith estimates, which have been derived from management’s knowledge and experience in the industries in which we operate. Estimates of market size and relative positions in a market are difficult to develop and inherently uncertain. Accordingly, investors should not place undue weight on the industry and market share data presented in this prospectus.

Certain Terms Used in this Prospectus

Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

•

“Barcarena Terminal” refers to the terminal located in Barcarena, State of Pará, Brazil, and consisting of (i) an FSRU, which will be operated by Hygo and deployed in service to CELBA pursuant to a long-term charter; and (ii) associated gas infrastructure, including mooring and offshore and onshore pipelines, wholly owned by Hygo;

•	“Brazilian reais” or “R$” refers to the Brazilian real in plural;

•	“CEBARRA” refers to Centrais Elétricas Barra dos Coqueiros S.A., a joint venture with Ebrasil Energia Ltda., which owns expansion rights with respect to the Sergipe Power Plant; Hygo indirectly owns a 37.5% interest in CEBARRA;

•	“CELBA” refers to Centrais Elétricas Barcarena S.A., our 50/50 joint venture with Evolution, which currently owns the Barcarena Terminal and associated infrastructure and which will be the charterer of the FSRU;

•

“CELBA 2” refers to Centrais Elétricas Barcarena S.A. 2, our joint venture with CELBA, BEP - Brazilian Energy Participações S.A. (“BEP”) and OAK Participações Ltda. (“OAK”), which was incorporated solely to comply with specific requirements of the related power auction in Brazil, and therefore is expected to be party to the Barcarena PPAs. Hygo currently indirectly owns a 50.0% interest in CELBA 2, and BEP, OAK and Evolution own an aggregate indirect 50.0% interest therein;

•	“CELSE” refers to Centrais Elétricas de Sergipe S.A., which is wholly owned by CELSEPAR;

•	“CELSEPAR” refers to Centrais Elétricas de Sergipe Participações S.A., our 50/50 joint venture with Ebrasil Energia Ltda.;

•	“Evolution” refers to Evolution Power Partners S.A.;

•	“Golar LNG” refers to Golar LNG Limited (NASDAQ: GLNG);

•	“Golar Management” refers to Golar Management Limited, a subsidiary of Golar LNG;

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•

“Hygo,” “Company,” “we,” “our,” “us” or like terms refer to Hygo Energy Transition Ltd., formerly known as Golar Power Limited, a Bermuda exempted company, and its subsidiaries, including its equity method investees, such as CELSEPAR and CELBA, as context requires; however, for an explanation of accounting treatment of our equity method investees, please see “Basis of Presentation” below;

•	“Santa Catarina Terminal” refers to the terminal located in Santa Catarina, Brazil that will consist of a newly converted FSRU and associated gas infrastructure;

•

“Sergipe Terminal” refers to the terminal located in Sergipe, Brazil, consisting of (i) the Golar Nanook, a FSRU operated by Hygo in service to CELSE pursuant to a 25-year charter, and (ii) a dedicated gas pipeline connecting to the Porto de Sergipe I power plant, a specialized mooring system and associated gas pipelines, all of which are owned by CELSE, an entity which is wholly owned by CELSEPAR;

•	“Sponsors” means Golar LNG and Stonepeak;

•	“Stonepeak” refers to Stonepeak Associates II LLC and certain funds and other entities managed, advised or controlled by or affiliated with Stonepeak Associates II LLC; and

•	“U.S. dollars,” “dollars” or “$” refers to U.S. dollars.

In addition, we have provided definitions of some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary” on page A-1 of this prospectus.

Basis of Presentation

This is the initial public offering of Hygo. Historically, Hygo’s revenues have been derived primarily from its wholly owned liquefied natural gas (“LNG”) carriers. Hygo’s assets also include a Floating Storage and Regasification Unit (“FSRU”) as well as equity interests in non-controlled and non-consolidated joint ventures, including CELSEPAR and CELBA. Because we generally have between 20% and 50% of the voting rights and do not exercise control, or have the power to control, the financial and operational policies of these entities, our investment in these entities are accounted for by the equity method of accounting. Pursuant to Rule 3-09 of Regulation S-X, we are required to include separate audited financial statements for significant investments in entities that are accounted for under the equity method of accounting (“3-09 Financial Statements”). As of December 31, 2019, we owned interests in one significant investment, CELSEPAR. As our projects mature, we may present 3-09 Financial Statements for other significant equity investments.

In addition, we qualify as a “foreign private issuer” as defined under SEC rules. As such, we are exempt from certain SEC rules that are applicable to U.S. domestic public companies, including the rules requiring domestic filers to issue financial statements prepared under U.S. Generally Accepted Accounting Principles (“U.S. GAAP”). We have elected to present Hygo’s consolidated financial statements in accordance with U.S. GAAP. However, the 3-09 Financial Statements for our investment in CELSEPAR have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IASB”), and we are not required to, and do not, reconcile the 3-09 Financial Statements to U.S. GAAP.

Further, the financial information contained in this prospectus includes both Brazilian real amounts and U.S. dollar amounts. Certain other information presented in this prospectus have been presented in the currency rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.

iii

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FORWARD-LOOKING STATEMENTS

This prospectus and other offering materials include forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this prospectus 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;

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

•	outbreaks, epidemics, pandemics, including the COVID-19 pandemic, or other public health events, and the resulting protocols put into place by federal, state or local governments;

•	the ability to successfully operate our power plant in Sergipe, Brazil;

•	our ability to successfully complete and begin operations at the Barcarena Terminal and the Santa Catarina Terminal, Brazil and associated gas infrastructure and power plants;

•	cost overruns and delays in the completion of the Barcarena Terminal and Santa Catarina Terminal, as well as difficulties in obtaining sufficient financing to pay for such costs and delays;

•	failure of our contract counterparties, including our joint venture co-owners, to comply with their agreements with us;

•	changes in our relationships with our counterparties;

•	loss of one or more of our customers;

•	changes in our relationship with Golar LNG;

•	changes in the performance of our joint ventures or equity method investees, including changes related to potential divestitures, spin-offs or new partnerships;

•	our ability to obtain additional financing on acceptable terms or at all;

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

•	changes to rules and regulations applicable to LNG-to-power infrastructure, FSRUs or other parts of the LNG supply chain;

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

•	competition from third parties in our business;

•	changes to environmental and similar laws and governmental regulations that are adverse to our operations;

•	inability to enter into favorable agreements and obtain necessary regulatory approvals;

•	the tax treatment of us or of an investment in our common shares;

•	a major health and safety incident relating to our business;

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

•	changes in global political or economic conditions generally or in the markets we serve;

•	risks related to the jurisdictions in which we do, or seek to do business, particularly Brazil; and

•	volatility in foreign exchange rates, particularly Brazilian reais in relation to the U.S. dollar.

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When considering forward-looking statements, you should keep in mind the risks set forth under the heading “Risk Factors” and other cautionary statements included in this prospectus. 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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SUMMARY

This summary highlights selected information appearing elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common shares. While this summary highlights what we consider to be the most important information about us, you should read this entire prospectus carefully including, in particular, “Risk Factors,” “Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes included elsewhere in this prospectus. The information presented in this prospectus (i) assumes an initial public offering price of $19.50 per share (the midpoint of the price range set forth on the cover of this prospectus), (ii) assumes, unless otherwise indicated, that the underwriters’ option to purchase additional common shares is not exercised and (iii) does not reflect the settlement of common shares pursuant to the management incentive scheme described under “Management—Compensation—Compensation of Management.” This summary is qualified in its entirety by the more detailed information and consolidated financial statements and notes thereto included elsewhere in this prospectus.

Hygo Energy Transition Ltd.

Overview

We provide integrated downstream LNG solutions to underserved markets by delivering low cost, environmentally sound energy alternatives to consumers around the world. Our business includes (i) our network of existing and development stage marine LNG import terminals, (ii) our ownership of interests in existing and development stage large-scale power plants backed by high quality offtakers, and (iii) the downstream distribution of LNG from our terminals via marine and onshore logistics to major demand centers in Brazil. In addition, we have historically derived the majority of our revenues from our LNG carriers, which we expect to convert into FSRUs to service our terminals. We believe our model of “hub and spoke” LNG infrastructure, anchored by our terminals in Brazil, is a model that is highly replicable to create a global platform. Accordingly, we are also pursuing multiple gas-to-power and distribution opportunities elsewhere around the world, including Latin America, Southeast Asia, the Indian Subcontinent, West Africa and Europe. We seek to unlock underserved markets by introducing LNG and natural gas as cheaper, cleaner and transformative alternatives to traditional fossil fuels, as well as an attractive, reliable complement to growing renewable energy sources.

Terminals and Floating Storage and Regasification Units

FSRUs represent a flexible, proven, expedient and cost effective means to import LNG. Planning, siting, permitting and constructing a traditional, land-based LNG terminal typically takes several years. In comparison, FSRU-based terminals typically take less than 24 months to complete and have been implemented in as little as six months. In addition, FSRUs are considerably less capital intensive than land-based LNG terminals.

Although our historical operating revenues have primarily consisted of time charter revenues from operating our vessels in the spot/short-term charter market, we expect our results will reflect an increasing proportion of revenues from the long-term charter of our FSRUs in support of our terminals and downstream distribution business as we complete their development.

As of August 2020, we have an operating FSRU terminal in Sergipe, Brazil (the “Sergipe Terminal”), two FSRU terminals in advanced stages of development in Pará, Brazil (the “Barcarena Terminal”) and Santa Catarina, Brazil (the “Santa Catarina Terminal”), and more than fifteen other terminals worldwide that are in various stages of evaluation or development. Our fleet consists of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which are expected to be converted into FSRUs. As of June 30, 2020, we have invested $30 million for the anticipated conversion of one of these vessels into an FSRU for deployment at the Barcarena Terminal once an FID has been made and we anticipate a total investment of $75 million to $85 million for the conversion. We expect to continue the conversion and deployment of FSRUs for utilization as LNG storage, transshipment and regasification terminals as our business continues to grow.

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Upon completion of the Barcarena and Santa Catarina Terminals, we expect to be capable of receiving an aggregate of 2,370,000 MMBtu/d with storage capacity of 500,000 cubic meters, giving us a critical mass of scale in our base infrastructure investment and creating significant barriers to entry in our areas of operation.

Power Generation

We have partnered with local companies to build cleaner and economically advantaged natural gas-fired power generation assets backed by long-term PPAs in our core operating areas. These assets will provide us with relatively stable base cash flows and serve as anchor customers for our LNG terminals. We are currently developing a total of 10.6 GW of fully licensed natural gas-fired power plants with local partners in Latin America, not including (i) the Porto de Sergipe I power plant, a 1.5 GW thermal power station supplied by the Sergipe Terminal (the “Sergipe Power Plant”), which began commercial operations (“COD”) in March 2020, and (ii) the Novo Tempo Barcarena power plant, a 605 MW thermal power station supplied by the Barcarena Terminal (the “Barcarena Power Plant”), which is expected to commence operations in 2025. Please see “—Our Current and Anticipated LNG-to-Power Infrastructure Network—Other Projects—Project Pipeline” for additional information.

Downstream Distribution

Our downstream distribution business is focused on the sale of LNG or natural gas to downstream customers under medium to long-term contracts. We procure LNG from our terminals and other sources and transport via ship, rail or truck using third-party providers. Our current and anticipated downstream customers are a mix of power, utility, industrial, commercial and transportation end-users of LNG and natural gas. We seek to provide our customers with integrated LNG logistics and procurement solutions to increase the accessibility of natural gas and unlock the economic and environmental benefits of LNG, as compared to other fossil fuels.

Our Current and Anticipated LNG-to-Power Infrastructure Network

Sergipe

Terminal. Our Sergipe Terminal located near Aracaju, the state capital of Sergipe, on the northeast coast of Brazil, commenced commercial operations in March 2020 and is a key component in Brazil’s first private-sector LNG-to-power project. The Sergipe Terminal is operated by CELSE, an entity wholly owned by CELSEPAR, a 50/50 joint venture between us and Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. Because CELSEPAR is indirectly jointly owned and operated with Ebrasil, it is treated as an equity method investment in our consolidated financial statements. The terminal’s assets consist of (i) our FSRU, the Golar Nanook, which is under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”), (ii) specialized mooring infrastructure and (iii) a dedicated 8 kilometer pipeline which connects to the adjacent Sergipe Power Plant. The Golar Nanook is financed through a twelve year sale-leaseback transaction with the right and obligation to repurchase the vessel at the end of the lease period. The balance of the infrastructure as well as our interest in the Sergipe Power Plant is owned through our joint venture, CELSEPAR.

Pursuant to the Sergipe FSRU Charter, the Golar Nanook generates approximately $44 million per year in bareboat charter earnings, indexed to the Consumer Price Index (“CPI”), with operating expenditures passed through to CELSE. Pursuant to the terms of the Sergipe FSRU Charter, we expect total revenues less estimated operating costs, without adjusting for inflation, of $1.1 billion over the 25-year term. The charter terminates on December 31, 2044. In addition to the charter, we expect to generate incremental revenue in the Sergipe Terminal from downstream customers. The Sergipe Terminal is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. We expect the terminal to utilize approximately 230,000 MMBtu/d (30% of the terminal’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant at full dispatch. Subject to obtaining required consents, we expect to utilize the terminal’s remaining 560,000 MMBtu/d of capacity to provide natural gas to additional customers, including industrial, commercial, transportation and other end-users via truck loading facilities. See “Business—Detailed Description of our Operating and Advanced Stage Terminals—Sergipe—Description of Contractual Arrangements Related to Sergipe—Sergipe FSRU Charter.” We also intend to construct 30 kilometers of additional pipeline connecting the Sergipe Terminal to the regional natural gas distribution network and other downstream customers. As of the commencement of operations in March 2020, capital expenditures related to the Sergipe Terminal totaled approximately $280 million. While we do not anticipate any additional capital expenditures to complete the Sergipe Terminal, we expect CELSE to invest $20 million to $30 million to complete interconnections to

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the regional natural gas distribution network. CELSE has also entered into a long-term, 25-year supply agreement for LNG for the Sergipe Terminal with Ocean LNG Limited (“Ocean LNG”), an affiliate of Qatar Petroleum (the “Sergipe Supply Agreement”). For the period from April 1, 2020 through June 30, 2020, net revenues generated from the Sergipe Terminal were $13.0 million.

Power Generation. The Sergipe Power Plant, a 1.5 GW combined cycle power plant, receives natural gas from the Sergipe Terminal through a dedicated 8 kilometer pipeline. Owned by CELSE, the Sergipe Power Plant is the largest natural gas-fired thermal power station in South America and was built to provide electricity on demand throughout the region, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region. The Sergipe Power Plant’s gas-fired system is 90% less pollutant as compared to diesel powered plants of similar capacity. The power plant was constructed pursuant to a lump sum turn-key Engineering, Procurement and Construction (“EPC”) agreement with General Electric. CELSE also entered into an operation and maintenance agreement with General Electric pursuant to which General Electric will maintain and operate the Sergipe Power Plant. At full dispatch, the Sergipe Power Plant can supply up to 15% of total current power demand in northeast Brazil, a region with a population of more than 57 million people.

Following its bid award in a government power auction in April 2015, CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant will deliver power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years. These PPAs provide for guaranteed annual capacity payments of R$1.6 billion at an expected contracted EBITDA margin on gross revenue of 61% (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred). The fixed capacity payments are adjusted annually for the Extended National Consumer Price Index (the “IPCA”), the Brazilian inflation-targeting system, which has historically offset changes in the exchange rate between the U.S. dollar and the Brazilian real. Annual revenues less operating costs are expected to be R$1.1 billion. Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$41.0 billion. We also expect to generate incremental variable revenue during periods we elect to dispatch and sell power from the facility. Based on the terms of our PPAs, for the period from its commencement on April 1, 2020 through July 31, 2020, the Sergipe Terminal generated approximately R$527.9 million in fixed payments and R$83.5 million in variable payments.

We anticipate generating incremental earnings through selling merchant power from the Sergipe Power Plant. The sales would be made through CELSE. We can choose to produce merchant power at the Sergipe Power Plant in any period in which power is not being produced pursuant to the PPAs, and sell the power into the electricity grid at spot prices, subject to local regulatory approval. For the six months ended June 30, 2020, the portion of CELSE’s revenue from the sale of merchant power produced at the Sergipe Power Plant attributable to us was R$43.0 million. We intend to take advantage of spot prices in this manner with power produced from not only the Sergipe Power Plant but also from our other assets and operations as opportunities arise.

Future Expansion. We also own 37.5% of Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), our joint venture with Ebrasil, which owns expansion rights with respect to the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for up to 3.2 GW of power generation, including the capacity of the Sergipe Power Plant. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. Our ownership in CEBARRA is also accounted for under the equity method.

Barcarena

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the approximately $75 million to $85 million of capital expenditures required to convert one of our vessels to an FSRU. Contracts will be structured for either regasification of LNG or for the storage of LNG with take-or-pay obligations. In July 2020, we entered into a memorandum of understanding with Norsk Hydro to supply LNG to its Alunorte refinery, which will be the first operational customer for the Barcarena Terminal. We are in what we believe to be the final stages of negotiations with Norsk Hydro for approximately 80,000 MMBtu per day of regasification capacity at an average net tariff to Hygo of approximately $1.30/MMBtu and approximately 45,000 MMBtu per day of storage capacity at an average net tariff of approximately $0.50/MMBtu. Assuming FID on the power plant, CELBA will pay an amount of approximately $10 million annually for their required capacity of the power plant. The fixed capacity payments will be adjusted annually to offset changes in the exchange rate between the U.S. dollar and the Brazilian real. We expect to incur capital expenditures of approximately $13 million per year in connection with the operation of the Barcarena Terminal.

The Barcarena Terminal will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. We expect the Barcarena Terminal to utilize approximately 92,000 MMBtu/d (12% of the terminal’s maximum regasification capacity) to service the Barcarena Power Plant upon commencement of operations in 2025. We have the ability to utilize the terminal’s excess capacity to service additional customers and are in advanced stages of negotiations with industrial offtakers for approximately 125,000 MMBtu/d of LNG from the terminal. We will utilize the remaining 572,000 MMBtu/d of the terminal’s capacity to service other potential customers, including industrial, commercial, transportation and residential end-users. We expect to commence LNG distribution operations from the Barcarena Terminal in the second half of 2021, significantly in advance of the anticipated target start-up date for the Barcarena Power Plant.

Power Generation. In October 2019, CELBA 2, our joint venture with CELBA, BEP and OAK, which was incorporated solely to comply with specific requirements of the related power auction in Brazil, was awarded multiple 25-year PPAs to support the construction of the Barcarena Power Plant, a 605 MW combined cycle thermal power plant to be located in the Brazilian city of Barcarena, State of Pará. The power plant will utilize LNG sourced and processed at the Barcarena Terminal for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019. We anticipate that the Barcarena Power Plant will commence operations in 2025, and we expect total capital expenditures by CELBA of approximately R$2.0 billion in order to complete construction. The PPAs provide for combined revenue from fixed capacity and dispatch charges of R$861 million per year. The fixed capacity charge is annually adjusted for the IPCA, which has historically offset changes in the exchange rate between the U.S. dollar and Brazilian real. The fixed dispatch charge is based on fuel-pass through with a margin. We expect our operations to generate approximately 27% contracted EBITDA margin on gross revenue (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred). Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$21.5 billion.

Santa Catarina

Terminal. We have secured key regulatory and environmental licenses to develop the Santa Catarina Terminal on the southern coast of Brazil, with a regional population of approximately 30 million. We intend to install an FSRU with a processing capacity of 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. The Santa Catarina Terminal is being designed to connect to existing onshore pipeline systems via a 31 kilometer, 20” pipeline to an interconnection point in Garuva, which supplies regional power distribution companies. We will be the sole operator of the FSRU at the Santa Catarina Terminal and will wholly own the balance of the terminal infrastructure. We expect to take FID on the Santa Catarina Terminal in the first half of 2021. The terminal is also expected to supply LNG to the Norte Catarinense power plant, a 600 MW regional power plant (the “Santa Catarina Power Plant”), for which we have an option to purchase up to 100% of the equity interest. We intend to participate in the next planned power auction related to the potential Santa Catarina Power Plant (which has been delayed due to COVID-19). The construction of the Santa Catarina Power Plant is contingent upon winning this power auction and, should we win that auction, we would expect to commence operation of the Santa Catarina Terminal in 2022. We expect to incur approximately $50 million to $75 million in capital expenditures for terminal construction and pipeline interconnection in Garuva, exclusive of the approximately $75 million to $85 million of capital expenditures required to convert one of our vessels to an

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FSRU. While the Santa Catarina Terminal currently has no firm capacity contracts, we believe there is significant demand from multiple potential end-users, including power generation, industrial, commercial, transportation and residential customers, including the potential adjacent Santa Catarina Power Plant.

Suape

Terminal. In March 2020, we signed a Protocol of Intentions with the government of the State of Pernambuco, Brazil to develop an LNG import terminal in the Port of Suape, located in the northeast region of Brazil, which has a population of approximately 57 million (the “Suape Terminal”). We intend to install an LNG carrier with storage capacity of a minimum 125,000 cubic meters to act as a floating storage unit (“FSU”). The Suape Terminal will connect to onshore truck loading facilities to facilitate loading of LNG ISO containers for distribution to industrial, commercial and residential offtakers for regions that are underserved or not served by traditional pipeline networks. We have also secured contracts with Companhia Pernambucana de Gás Natural (“Copergás”) to facilitate the distribution of LNG or natural gas to such offtakers. The terminal will also act as a transshipment location to break bulk for downstream distribution. We expect to take FID on the Suape Terminal in the third quarter of 2020. We estimate initial volumes for onshore distribution to be equivalent to approximately 22,000 MMBtu/d with commencement of operations in the first half of 2021. Final development of the project remains subject to regulatory approvals and finalization of commercial agreements. We expect to incur approximately $10 million to $15 million in capital expenditures required to construct and initiate operations at the Suape Terminal. Subject to securing contracts from offtakers requiring regasification services, we may consider replacing the FSU with an FSRU. In addition, a local distribution company is considering constructing a natural gas pipeline to connect the Suape Terminal to the local distribution network. In its initial phase, we estimate regasification volumes related to the pipeline of up to 500,000 cubic meters/d with regasification operations expected to begin in the second half of 2022.

Other Projects

We are in the evaluation or development stage on more than fifteen other terminals worldwide, including in Brazil, Ivory Coast, Mexico and Vietnam, underserved markets where we believe our “hub and spoke” LNG infrastructure model will differentiate us relative to alternative solutions. Our terminals range from fully integrated LNG-to-power projects with associated onshore downstream distribution to the provision of an FSRU and additional infrastructure, such as moorings and pipelines, to enable access to LNG under charter or lease agreements. In connection with the development of our terminals and onshore LNG distribution infrastructure, including power generation, our strategy centers on securing local partners with expertise in crucial regulatory, environmental and other local and regional requirements. We focus on markets with growing electricity demand, an existing shortage of electricity generation and a lack of existing LNG infrastructure, as well as local support for less expensive and more environmentally friendly energy sources like natural gas. In addition, gas-fired power plants serve as the natural complement to the intermittent nature of growing sources of renewable power in many regions throughout the world. Contract duration for the projects under development ranges from 5 to 25 years. With respect to the FSRUs we deploy globally, we intend to target opportunities with run-rate economics in line with our FSRUs deployed or in advanced stages of development in Sergipe and Barcarena.

São Marcos, Brazil. We have partnered with Eneva S.A. to form Centrais Termelétricas São Marcos S.A. (“São Marcos”), a 50/50 joint venture developing an integrated LNG-to-power terminal in São Luis, State of Maranhão, Brazil (the “São Marcos Terminal”), and a power plant with 3.2 GW of installed capacity. We have applied for preliminary permits and environmental licenses and we anticipate that the São Marcos Terminal would supply natural gas to the power plant, which would be developed if awarded a PPA.

Ivory Coast, Africa. In 2017, we were awarded a 20-year charter of an FSRU off Abidjan, Ivory Coast. The charter will commence upon FID and is expected to generate average annual bareboat earnings of approximately $30.0 million. Golar LNG currently owns a 6% equity interest in the CI-GNL (“Ivory Coast LNG”) terminal consortium, which is in the process of being transferred to us. Our local partners in this project include major integrated independent and state-owned energy companies.

Project Pipeline. The following table sets forth information regarding additional FSRU terminals and other LNG infrastructure projects in our development pipeline. Based on our experience with our existing and anticipated terminals, we anticipate a payback period from our anchor customers of seven to eight years on the capital expenditures required at each terminal.

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Region	Annual Regas Capacity (TBtu)	Expected Anchor Customer	Size of Power Plant (MW)	Expected Anchor Customer Regas Capacity Utilization	Estimated Startup	Estimated Total Capex Required ($MM)
Awaiting FID
West Africa	149	Power Plant	150 - 500	10%	2021-2022	250
Feasibility / FEED Study
Latin America		TBD	TBD		2022-2023	TBD
Latin America		TBD	TBD		2022-2023	TBD
Latin America	186	Pipeline / Power Plant	TBD		2021-2022	310
West Africa	186	Power Plant	1,000 - 2,000	41%	2023+	325
West Africa	47	Power Plant	150 - 500	33%	2021-2022	165
Southeast Asia	186	Power Plant	3,000+	41%	2022	310
South Asia	47	Power Plant	150 - 500	33%	2022	185
Early Stage Development
Latin America	186	Pipeline / Power Plant	TBD		2022	310
Latin America	186	TBD	TBD		2023+	250
Southern Africa	186	Power Plant	1,000 - 2,000	55%	2022	310
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	125
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	125
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	250
Southeast Asia	279	Power Plant	3,000+	92%	2023+	300
South Asia	186	Pipeline / Power Plant	TBD		2022	250
Europe	186	Industrial / Power Plant	TBD		2023	250

In addition, we are currently in discussions to acquire interests in long-term PPAs related to a brownfield opportunity in the State of Bahia, Brazil.

Downstream Distribution

We expect to capitalize on our strategic locations and LNG processing capacity by establishing a broader network of LNG distribution channels to penetrate additional downstream demand. To that end, we are in the process of establishing eight LNG and natural gas distribution hubs across Brazil from which we expect to pursue downstream customers. These eight hubs consist of our Sergipe, Barcarena, Santa Catarina and Suape Terminals as well as small scale receiving terminals in São Paulo, Rio de Janeiro, Itaqui and Pecem. In addition, we have entered into a strategic partnership with Petrobras Distribuidora S.A. (“BR Distribuidora”), Brazil’s leading fuel distribution company, as discussed in more detail below.

In order to facilitate our distribution of LNG through our eight hubs, we have entered into a bareboat charter agreement for one 7,500 cubic meter, small-scale LNG carrier from Avenir LNG Limited. The Avenir vessel is expected to be deployed in Brazil for three years. We anticipate that the vessel will be delivered to us from the shipyard in the first half of 2021.

As a result of designed capacity and delivery capabilities associated with our existing FSRUs and carriers earmarked for conversion, we expect to incur limited additional capital expenditures in establishing our regional distribution hubs. To enable natural gas access to downstream customers, we are utilizing existing technology from equipment suppliers as well as developing bespoke in-house technological solutions. By utilizing our network of terminals and related infrastructure and by leveraging third parties, we expect to be able to displace current high cost fuel sources with LNG at a materially lower distributed cost, allowing us to capture a significant portion of the price differential.

Partnership with BR Distribuidora

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LNG to downstream end-users using a combination of marine and onshore solutions. According to the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (“ANP”), diesel consumption in Brazil stood at 56 million cubic meters (equivalent to approximately 37 million tonnes of LNG) in 2018 with total consumption of diesel, gasoline, LPG, jet fuel, fuel oil and ethanol amounting to 136 million cubic meters (equivalent to approximately 80 million tonnes of LNG). BR Distribuidora reported a total sales volume of 42 million cubic meters in 2018 – making it the largest distributor of fuels in the Brazilian market. In connection with this partnership, we have executed letters of intent with three potential downstream customers with total demand of approximately 4,200 MMBtu/d. Once our downstream logistics systems commence operations we expect to enter into supply contracts in order to secure LNG volumes sufficient to meet our contractual delivery obligations. BR Distribuidora, as a major transportation end-user itself, also intends to replace its hired fleet of approximately 5,000 diesel trucks with LNG-powered vehicles at a stated goal of 20% annually, for which we will serve as the exclusive LNG supplier.

Other Downstream Customers in Brazil

In addition, we are in active discussions with more than 30 individual downstream customers with an aggregated demand of approximately 265,000 MMBtu/d, and we have identified upwards of 200 additional offtakers with an aggregated demand of approximately 585,000 MMBtu/d that would complement our existing distribution network.

The map below illustrates the location of our combined downstream distribution hubs in Brazil.

Other Downstream Opportunities Globally

Beyond Brazil, we have identified key markets and countries of focus where distribution of LNG can be facilitated from the use of terminal infrastructure we are currently developing through our project pipeline. A bespoke study of thirteen focus countries performed by Rystad Energy on the potential for diesel-to-LNG conversion of trucks indicates Mexico, South Africa, Thailand and Colombia, among others, as markets where our approach currently being implemented in Brazil could be replicated. These markets have large fleets of Heavy Commercial Vehicles (“HCV”) and high diesel prices that, when combined, form a strong value proposition for LNG as an alternative fuel. Based on total diesel demand from commercial vehicles and buses in the thirteen focus countries, Rystad Energy estimates diesel consumption in such countries of more than 2.6 million barrels per day with prices ranging from $15 per MMBtu to more than $30 per MMBtu as of February 2020.

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Gas Marketing and Trading

We believe additional opportunities exist to generate incremental earnings from our downstream distribution network through natural gas origination and trading activities. Our strategically located LNG infrastructure creates opportunities to match customer demand with our gas supply capabilities and capture a margin on volumes delivered. We believe our business relationships with participants in various phases of the natural gas and LNG distribution chain, as well as our own industry expertise, provide us with extensive market insight and an understanding of the global physical natural gas and LNG markets that enables us to provide value chain solutions for our customers. Our activities are designed to limit downside exposure while generating upside potential associated with opportunities inherent in volatile market conditions, including opportunities benefitting from fluctuating differentials and market structure. The trades are structured to maintain a position that is substantially balanced with back-to-back offtake and supply commitments and all associated costs are passed through to the customer. The opportunities to earn additional margins vary over time with changing market conditions and accordingly, our results from these activities will fluctuate from period to period.

LNG Technology and Other Initiatives

A key feature of our downstream distribution business model is rapid deployment of assets to provide greater access to LNG. As part of this business model, we are presently developing proprietary technology that will offer faster and more flexible distribution of LNG. The technologies currently under development are innovations related to the transfer of LNG directly from small-scale LNG carriers to ISO containers, flexible storage and fueling solutions and micro-liquefaction units for smaller sources of natural gas.

As part of our efforts to reduce emissions, we have entered into an agreement with Galileo Technologies (“Galileo”), whereby Galileo will deliver two LNG production clusters for the production of biomethane liquefied natural gas (“Bio-LNG”). This technology captures methane produced from the decomposition of organic waste, including from landfills and the residual fibers from crushing sugar cane for sugar production. The clusters will be installed in the State of Bahia and the State of São Paulo, and can produce up to 45 tons of Bio-LNG per day, in aggregate. We expect to commence operations using Galileo’s technology by the end of 2020. Our goal is to have 20% of our natural gas portfolio come from biomethane production.

In addition, we are currently investigating the potential use of hydrogen as a fuel source – on a stand-alone basis for new projects and as a supplemental source of fuel to our existing and planned power plants. The gas turbines installed at the Sergipe Power Plant can use hydrogen as a fuel source after certain upgrades. We are also considering adding hydrogen production facilities to our existing sites to leverage locally available renewable energy sources to produce energy with a reduced carbon footprint.

Natural Gas Market and Market Access

Natural gas is in abundant supply globally and is the fastest growing fossil fuel in terms of demand, representing 24% of global energy demand and 23% of electricity generation in 2019. Innovation in natural gas extraction has resulted in a dramatic decrease in natural gas prices with Henry Hub prices declining from over $13.00 per MMBtu at the end of 2005 to $2.22 at the end of 2019 with an expectation that such prices will stabilize at these lower levels going forward.

Currently, however, much of the world’s natural gas reserves are not directly connected by pipeline to electricity producers and other end-users. An efficient alternative way to facilitate the transportation of natural gas to end-users is by converting natural gas to LNG, a process which involves treating natural gas to remove impurities and then chilling it to approximately negative 162 degrees Celsius, a process generally referred to as “liquefaction.” In LNG form, natural gas is typically transported in bulk by containers or tankers hauled by rail or truck or by marine vessels, such as LNG carriers. Once delivered to its end destination, LNG can be reconverted to natural gas through a process referred to as “regasification.”

Approximately 850 million people still do not have access to electricity, according to the International Energy Agency 2019 World Energy Outlook. Globally, many developing countries lack access to affordable fuel in order to generate electricity and large parts South America, Africa and Asia consume less than 3,000 MWh of electricity per capita because of high costs and lack of infrastructure. According to Bloomberg New Energy Finance (“Bloomberg NEF”), 63 out of 107 reported non-OECD countries have a cost of commercial electricity in excess of $100 per MWh. We believe we are well-positioned to bring low-cost and clean LNG to these countries to fuel further development.

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Economic development, increasing populations and rising standards of living will increase demand for homes, businesses and transportation, and the associated necessary energy use. According to Exxon Mobil’s 2019 Outlook on Energy, global electricity demand is expected to rise 60% by 2040. To satisfy these power needs with gas-fired power would require approximately 310 TBtu of LNG per day (based upon an estimated conversion of 2,500 gallons per day of LNG for every MW of power capacity). We believe that many countries around the world – keenly focused on both cost and environmental concerns – will increasingly look to natural gas to displace more environmentally damaging fuels such as heavy fuel oil (“HFO”), automotive diesel oil (“ADO”) and coal, particularly because natural gas can be significantly less expensive than these higher polluting fuels.

In Brazil, electricity generation has been historically dominated by hydroelectric power, which as of April 2020 accounted for 64% of 171.8 GW of total installed capacity compared to 25% for thermoelectric facilities, 11% for renewables and 1% for nuclear. In 2010, hydroelectricity accounted for approximately 80% of Brazil’s electricity generation; however, environmental regulatory hurdles in Brazil have restricted further expansion of hydroelectric capacity. In addition, hydroelectric facilities in Brazil are subject to substantial reductions in output during periods of drought, resulting in nation-wide energy rationing in 2001 and regional disruptions in 2014. As a result of the limitations of hydroelectric capacity, Brazil’s expanding power needs will be satisfied by alternative sources of energy including thermal, wind and solar power generation. The ten-year energy plan of the Brazilian Energy Research Company (Empresa de Pesquisa Energética, or “EPE”) calls for 60 GW of installed capacity to be added through 2029, of which 20 GW will be thermal, 5 GW hydro, 1 GW nuclear and 33 GW other renewables. Increased thermal power generation capacity, particularly cleaner natural gas generation, will be critical for Brazil to address the intermittent nature of hydroelectric, wind and solar power. There are also compelling reasons for existing non-gas Brazilian plants burning HFO or ADO as fuel to switch to natural gas, including the substantial benefits of using an environmentally cleaner fuel source compared to HFO or ADO, coupled with the cost benefits of LNG ($2.80 per MMBtu versus $11.20 for HFO as of March 2020). Moreover, Brazil has implemented PROCONVE P-8 emission standards to regulate gas and particulate emissions from on-road heavy-duty vehicles increasing the value proposition for LNG-fueled vehicles and driving greater demand for LNG.

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Brazil has only approximately 12,000 km of gas pipelines compared to 30,000 km of gas pipelines in Argentina despite having a landmass three times larger and population more than four times larger than that of Argentina. Most of Brazil’s existing gas infrastructure is located in the south and southeast regions while distribution across the rest of the country is limited. This lack of sufficient infrastructure restricts availability of gas in major demand centers. In addition, local distribution companies have monopolies over gas distribution in their districts which are regulated at the state level. As a result, small scale customers depend primarily on diesel, LPG and HFO for energy. Domestic production accounts for approximately 70% of Brazil’s natural gas supply, with the remainder coming from imported gas via pipelines and LNG. The only major gas import pipeline originates in Bolivia and sources supply from Bolivia’s state-owned oil company (“YPFB”). The long-term supply contract underpinning this pipeline is constrained by available supply from Bolivia. The pipeline has no contracted volumes beyond 2022 with shortfalls expected to be made up partly by LNG imports. Development of sufficient LNG infrastructure will offer an effective way to address supply and distribution constraints and expand natural gas use in the power, industrial, and transportation sectors in Brazil and elsewhere around the world.

We plan to capitalize on this growing supply-demand gap and create new markets for natural gas by developing downstream distribution networks, particularly in areas with significant demand. We design our downstream distribution networks to center around FSRU terminal “hubs”, and we target areas that have historically been underserved by regional pipelines, increasing access to natural gas and LNG via transportation by truck and barge.

LNG Supply

We intend to secure additional long-term supply agreements for LNG for future projects as they near commercial operations. In the absence of such agreements, we will purchase LNG on the spot market, where current pricing is highly favorable. Recent LNG prices have been historically low, which, coupled with ample global supply, affords us flexibility of supply and helps make LNG an even more compelling energy source.

Competitive Strengths

We believe we are well-positioned to execute our business strategies and deliver on our long-term growth objectives based on our competitive strengths:

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A pioneer in providing integrated LNG solutions across the value chain. Our focus on the attractive downstream segments of the LNG value chain is complemented by our Sponsors’ proven expertise in the upstream and midstream LNG segments as well as their core maritime capabilities. As a result of our participation in each link in the energy value chain, we are able to provide highly customized energy solutions to a variety of downstream end-users and maximize value for our shareholders. We believe our fully integrated and broad service offering provides more attractive long-term returns than competitors focusing on a single component of the downstream LNG and power generation value chain.

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First-mover advantage creates barriers to entry in key geographies. We believe our experience in navigating the Brazilian regulatory environment, negotiating contracts with key customers and working with local developers will allow us to complete projects faster, more efficiently and cost-effectively than new entrants or other competitors. Our foundational investment to develop critical LNG infrastructure and the largest thermal power station in South America, at Sergipe, has established Hygo as a key provider of energy and power in Brazil. Moreover, we have demonstrated that we can successfully replicate our business strategy in new geographies by securing new 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant in Barcarena in north Brazil. We have also secured the applicable licenses required for the current stage of the projects in Santa Catarina and Suape, in addition to Sergipe and Barcarena, providing access to key regions of the Brazilian market and creating a competitive advantage in our catchment areas given the long-lead time required to obtain these licenses.

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Partnerships with key stakeholders across the LNG value chain will strengthen our local presence and enhance our customer value proposition. We have secured critical partnerships with key stakeholders across the LNG value chain. For example, we have entered into a 15-year exclusive strategic partnership with BR Distribuidora, which remains subject to Brazilian regulatory approval, to expand our distribution

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network, increase the accessibility of LNG to major demand centers in Brazil and expand our market share. While BR Distribuidora is not obligated to convert its fleet to LNG-powered vehicles, we expect it will replace its hired fleet of diesel trucks at its stated goal of 20% annually, for which we will serve as the exclusive LNG supplier. We have also established discrete, project-specific partnerships with experienced developers in our power generation projects, such as Ebrasil, one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. Together with our partners, we intend to develop natural gas-fired power plants and offer less expensive and cleaner energy to Brazil’s power grid, including the Sergipe Power Plant. The strength of these partnerships is further enhanced by our Sponsor, Golar LNG, a leading independent maritime LNG asset owner and operator by fleet count, with 27 vessels totaling an aggregate 2,108,687 Dwt and 4,005,000 cubic meters, providing us deep maritime expertise and enhancing our integrated service offering.

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Providing an economically and environmentally attractive product creates a compelling value proposition to customers. Natural gas provides a compelling value proposition as it is a less expensive, more efficient and more environmentally friendly energy source than traditional fossil fuels and provides our customers the ability to promote environmental stewardship, energy security and affordability. In addition to being a more fuel-efficient source of energy, natural gas produces lower emissions than competing fuels. Gas-fired power is complementary to renewable energy, allowing power grids to diversify their sources of energy to renewables while maintaining their flexibility and baseload reliability. Stakeholders are increasingly focused on clean energy through the construction of new natural gas-fired power plants and the decommissioning or conversion of older plants. Our integrated downstream LNG infrastructure model positions us as the natural service provider to meet this need. As a “downstream enabler,” our complete LNG and associated infrastructure offering increases the availability of a cheaper, more environmentally sustainable energy alternative. Our goal is to convert a significant portion of the 40 million barrels per day of traditional distillate fuels consumed globally in 2019 to LNG and natural gas.

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Well-positioned in Brazil, a market we believe is poised for substantial near- and long-term growth in natural gas consumption. We believe Hygo is well-positioned to capitalize on growth in Brazil’s energy demand which is driven by attractive, underserved and diverse end-markets. Demand for electricity in Brazil is forecasted to grow 30% over the next decade. BP’s 2019 Energy Outlook forecasts Brazil’s natural gas consumption to increase 114% (3.4% per annum) from 2017 to 2040 compared to an increase of only 0.4% per annum for coal and 1.4% per annum for oil. We believe our existing and planned LNG infrastructure positions us well to capitalize on a significant oil-to-gas switching opportunity as diesel, HFO and LPG are phased out in favor of cleaner natural gas. Additionally, we believe there is a large addressable market to convert over-the-road transportation assets, such as trucks and buses, to LNG, an opportunity for which we are uniquely positioned. We have established a strategic partnership with BR Distribuidora which we believe enhances our commercial reach, expands our gas distribution channels and will help accelerate the conversion from traditional fossil fuels to LNG.

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Benefits from low LNG prices globally. The substantial global increase in LNG supply over the past ten years has structurally reduced prices and positioned LNG as a more commonly traded and readily available commodity. Global demand for LNG continues to grow both because the delivered cost is anticipated to remain competitive relative to other fuel sources and because greater emphasis is being placed on using cleaner sources of energy. As an integrated downstream gas infrastructure provider, we believe we can unlock a vast and underserved market by introducing LNG as a transformative fuel source.

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Provide environmental and social stewardship through responsible energy generation. Natural gas, as a fuel source, produces lower carbon emissions than other fossil fuels and reduces the marginal impact on the climate. Furthermore, gas-fired power generation emits significantly lower toxins and particulate matter relative to other fossil fuels. Historically, natural gas has exhibited more stable pricing with higher energy efficiency making it more sustainable for energy production than other hydrocarbons. LNG is also safer to transport than most fossil fuels. By providing LNG infrastructure and distribution capabilities in remote and otherwise energy-isolated geographies, our platform benefits local communities and can provide a significant boost to economic development. Construction of large power plants and LNG distribution infrastructure results in additional job creation, further supporting regional development. We are proactive in educating communities and businesses in the regions in which we

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operate regarding the economic and environmental benefits, as compared to other fossil fuels, of the long-term adoption of LNG and natural gas as cleaner and more efficient fuels.

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Experienced management team supported by strong board-level sponsorship. Hygo’s management team has more than 40 years of cumulative experience in the maritime LNG, power generation and infrastructure industries. We are highly focused on efficient management and operations of our assets, planning for future expansion projects and reducing costs to create value for our shareholders. Management is guided by strong and well-established corporate governance standards and has a clear strategy for providing customized and innovative solutions. Additionally, we have demonstrated an ability to leverage the industry expertise and global reach of Stonepeak and Golar LNG to advance our business. Our partnership with Stonepeak will give us access to their long-standing relationships in the energy, power generation, logistics and maritime industries. Golar LNG’s customer relationships and its technical, commercial and managerial expertise allow us to provide a more competitive, bespoke and compelling service offering to our customers.

Business Strategies

Our primary objective is to deliver long-term stakeholder value as an LNG-infrastructure owner and operator by providing downstream distribution and logistics for LNG and an attractive combination of competitive pricing and lower carbon emissions. We intend to achieve this objective by implementing the following strategies:

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Provide our customers with integrated LNG logistics and procurement solutions to unlock the economic and environmental benefits, as compared to other fossil fuels, of natural gas. We will combine our marine LNG regasification terminal infrastructure and gas procurement capabilities to offer economically compelling energy generation and promote acceleration of the global transition to cleaner fuel. In addition to securing long-term gas offtake contracts, we will build or acquire natural gas-fired power generation assets, backed by long-term PPAs, to facilitate the sale and distribution of natural gas from our terminals.

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Continue to develop and deploy marine LNG infrastructure across Brazil. We intend to deploy additional marine LNG import terminals across Brazil in the form of FSRUs as well as the necessary onshore infrastructure to facilitate gas offtake. We believe that our LNG terminal solutions are substantially more competitive than traditional onshore regasification terminals. We seek to lock in long-term gas offtake contracts, charters and terminal use agreements with large scale industrial, commercial, transportation and utility customers to anchor our initial LNG infrastructure investment decision. We plan to convert our remaining LNG carriers into FSRUs and develop additional newbuild FSRUs to expand our footprint and market presence across Brazil.

•

Create additional LNG and natural gas distribution channels to facilitate the consumption of natural gas by a broad spectrum of end-users. Through our downstream distribution business we have identified a broad spectrum of industrial, commercial and retail opportunities in major demand centers across Brazil. We will leverage our existing infrastructure and LNG supply chain expertise to increase the accessibility of LNG and natural gas to downstream end-users. We expect to create a multi-channel distribution network across Brazil by utilizing a combination of marine and onshore infrastructure and distribution solutions, including logistics services provided by third-parties.

•

Pursue new markets globally and offer compelling value to customers exposed to high energy costs. We intend to selectively pursue global expansion opportunities across Latin America, Eastern Europe, Asia, Africa and the Middle East. We will help create new import markets for LNG by providing infrastructure, distribution and power generation solutions for inland and off-grid energy consumption by large industrial, commercial and transportation customers as well as utilities. We intend to displace existing hydrocarbon-based fuels such as coal, LPG, diesel and HFO by marketing the benefits of LNG as a cheaper, more efficient and cleaner fuel source for global energy consumption. Furthermore, we will use our international footprint and leverage the expertise of our two Sponsors to facilitate our expansion efforts across the globe. We will maintain a flexible approach to business opportunities and continue to form partnerships with local industry participants including utilities, transportation companies and energy distributors to establish an integrated presence in new markets.

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Our History and Relationship with Our Sponsors

We were formed in May 2016 by Golar LNG. In June 2016, Stonepeak acquired a 50% common equity interest in us from Golar LNG and 20,000,000 preference shares from us. We will use the net proceeds from this offering to fund capital expenditures for the growth of our business as well as to redeem all of the preference shares held by Stonepeak. Following the completion of this offering, our Sponsors will retain a significant interest in us through their ownership of 100,000,000 common shares, representing approximately 81.2% of the voting power (or approximately 79.0% if the underwriters' option to purchase additional common shares is exercised in full).

Golar LNG is a publicly traded, midstream LNG company engaged primarily in the transportation and regasification of LNG and the liquefaction of natural gas. It is engaged in the acquisition, ownership, operation and chartering of LNG carriers, FSRUs and FLNGs and the development of LNG projects through its subsidiaries, affiliates, joint ventures and equity method investees.

Stonepeak invests in long-lived, hard asset infrastructure businesses with leading market positions and high barriers to entry, which provide essential services to customers primarily in the following sectors: energy, power and renewables, transportation, utilities, water and communications. Founded in 2011 and headquartered in New York, Stonepeak manages $25.2 billion of capital for its investors (as of June 30, 2020). Stonepeak’s assets under management calculation as provided herein is determined by taking into account unfunded capital commitments of its funds, including any feeder funds and co-invest vehicles managed by Stonepeak as of June 30, 2020.

Prior to consummation of this offering, the entity that holds Stonepeak's investment in Hygo (Stonepeak Infrastructure Fund II Cayman (G) Ltd.) will merge with and into Hygo, with Hygo surviving the merger (the “Recapitalization”). Following consummation of this offering, Stonepeak’s investment in Hygo will be held through Stonepeak Golar Power Holdings (Cayman) LP. In connection with the Recapitalization, the preference shares of Hygo held by Stonepeak will be redeemed in exchange for the right to receive an amount of cash equal to the redemption price of such preference shares, with such cash to be paid with a portion of the proceeds of this offering. For additional information regarding the preference shares and the terms thereof, please see “Description of Share Capital—Stonepeak Preference Shares.”

Simplified Organizational and Ownership Structure After this Offering

The following diagram depicts our simplified organizational and ownership structure after giving effect to the offering, assuming no exercise of the underwriters’ option to purchase additional common shares. For more information regarding our subsidiaries and joint ventures, please see “Business—Our History and Development.”

(1)	BR Distribuidora has an option to acquire 50% of this entity, which expires six months after certain conditions precedent have been met. See “Business—BR Distribuidora Partnership.”

(2)

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Our Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

•	provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

•

comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

•	comply with any new audit rules adopted by the PCAOB, unless the SEC determines otherwise;

•	provide certain disclosure regarding executive compensation required of larger public companies; or

•	obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:

•	when we have $1.07 billion or more in annual revenues;

•	the date on which we become a “large-accelerated filer” (i.e., the end of the fiscal year in which the total market value of our common equity securities held by non-affiliates is $700.0 million or more as of the preceding June 30);

•	when we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•	the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”) for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(2) of the JOBS Act, that allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result of this election, our consolidated financial statements may not be comparable to companies that comply with public company effective dates.

Our Foreign Private Issuer and Controlled Company Status

We qualify as a “foreign private issuer” as defined under SEC rules. Even after we no longer qualify as an emerging growth company, as long as we continue to qualify as a foreign private issuer under SEC rules, we are exempt from certain SEC rules that are applicable to U.S. domestic public companies, including:

•	the rules requiring domestic filers to issue financial statements prepared under U.S. GAAP;

•	the sections of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act;

•	the sections of the Exchange Act requiring insiders to file public reports of their share ownership and trading activities and liability for insiders who profit from trades made in a short period of time;

•	the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q containing unaudited financial statements and other specified information, and current reports on Form 8-K upon the occurrence of specified significant events; and

•	the selective disclosure rules by issuers of material nonpublic information under Regulation FD.

Notwithstanding these exemptions, we will file with the SEC, within four months after the end of each fiscal year, or such applicable time as required by the SEC, an annual report on Form 20-F containing financial statements audited by an independent registered public accounting firm.

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We may take advantage of these exemptions until such time as we are no longer a foreign private issuer. We would cease to be a foreign private issuer at such time as more than 50% of our outstanding voting securities are held by U.S. residents and any of the following three circumstances applies: (i) the majority of our executive officers or directors are U.S. citizens or residents, (ii) more than 50% of our assets are located in the United States or (iii) our business is administered principally in the United States.

Both foreign private issuers and emerging growth companies also are exempt from certain more stringent executive compensation disclosure rules. Thus, even if we no longer qualify as an emerging growth company, but remain a foreign private issuer, we continue to be exempt from the more stringent compensation disclosures required of companies that are neither an emerging growth company nor a foreign private issuer.

In addition, because we qualify as a foreign private issuer under SEC rules, we are permitted to follow the corporate governance practices of Bermuda (the jurisdiction in which we are organized) in lieu of certain Nasdaq Global Select Market (“NASDAQ”) corporate governance requirements that would otherwise be applicable to us. For example, under Bermuda law, we are not required to have a board of directors comprised of a majority of directors meeting the independence standards described in the NASDAQ rules.

In the event we no longer qualify as a foreign private issuer, we intend to rely on the “controlled company” exemption under NASDAQ rules. Because our Sponsors will initially hold approximately 81.2% of the voting power of our shares following the completion of this offering (or approximately 79.0% if the underwriters’ option to purchase additional common shares is exercised in full), we expect to be a controlled company as of the completion of the offering under the SEC and NASDAQ rules. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation or nominating and corporate governance committees. As a controlled company, we will remain subject to rules of the SEC and NASDAQ that require us to have an audit committee composed entirely of independent directors.

If at any time we cease to be a foreign private issuer or a controlled company, we will take all action necessary to comply with the SEC and NASDAQ rules, including by appointing a majority of independent directors to our board of directors, subject to a permitted “phase-in” period.

Risk Factors

An investment in our common shares involves risks associated with our business, regulatory and legal matters, our Bermuda company structure and the tax characteristics of our common shares. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common shares. However, this list is not exhaustive. Please read the full discussion of these risks and the other risks described under “Risk Factors” and “Forward-Looking Statements.”

These risks include the following:

•	We have not yet completed contracting, construction and commissioning of some of our facilities in Brazil and other geographies we are active in. There can be no assurance that our facilities will operate as described in this prospectus, or at all.

•	We have a limited operating history, and an investment in our common shares is speculative.

•	Our ability to dispatch electricity from our power plants is dependent upon hydrological conditions in Brazil.

•	Our operational and consolidated financial results are partially dependent on the results of the joint ventures, affiliates and special purpose entities in which we invest.

•	We have a limited customer base and expect that a significant portion of our future revenues will be from a limited number of customers, and the loss of any significant customer could adversely affect our operating results.

•	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 are highly dependent upon economic, political, regulatory and other conditions and developments in Brazil and the other jurisdictions in which we operate.

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•	Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.

•	Our Sponsors have the ability to direct the voting of a majority of our shares, and its interests may conflict with those of our other shareholders.

•	Because we are a Bermuda exempted company, our shareholders may have less recourse against us or our directors than shareholders of a U.S. company have against the directors of that U.S. company.

•	Because our offices and assets are outside the United States, our shareholders may not be able to bring a suit against us, or enforce a judgment obtained against us in the United States.

•	Shareholders will experience immediate and substantial dilution of $14.25 per common share based on the midpoint of the price range set forth on the cover of this prospectus.

•	There is no existing market for our common shares and a trading market that will provide you with adequate liquidity may not develop. The price of our common shares may fluctuate significantly, and shareholders could lose all or part of their investment.

•	We are a foreign private issuer within the meaning of the SEC rules, and as such we are exempt from certain provisions applicable to U.S. domestic public companies.

•	U.S. tax authorities could treat us as a “passive foreign investment company”, which could have adverse U.S. federal income tax consequences to U.S. shareholders.

•	Brazilian tax legislation is currently under discussion and tax reform may affect our revenues.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 2^nd Floor, S.E. Pearman Building, 9 Par-la-Ville Road, Hamilton HM 11, Bermuda and our telephone number is +1 (441) 295-4705. Our website is located at www.hygoenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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The Offering

Common shares offered to the public

23,100,000 common shares, or 26,565,000 common shares if the underwriters exercise their option to purchase additional common shares in full.

Common shares outstanding after this offering

123,100,000 common shares, or 126,565,000 common shares if the underwriters exercise their option to purchase additional common shares in full.

Use of proceeds

If the underwriters exercise their option to purchase additional common shares in full, the additional net proceeds will be approximately $63.8 million. The net proceeds from any exercise of such option will be used for general corporate purposes, including the development of future projects, such that a total of $184.7 million of the net proceeds of this offering will be used for working capital and general corporate purposes.

Dividend policy

We do not currently anticipate paying any dividends on our common shares. See “Dividend Policy.”

Exchange listing

We have applied to list our common shares on NASDAQ, under the symbol “HYGO.”

Transfer agent

Broadridge Corporate Issuer Solutions, Inc.

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common shares.

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Summary Historical Financial Data

The following table presents our summary historical financial data for the periods and as of the dates indicated. The summary historical financial data as of and for the years ended December 31, 2019 and 2018 was derived from the audited historical consolidated financial statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited, included elsewhere in this prospectus. The summary historical financial data as of June 30, 2020 and for the six months ended June 30, 2020 and 2019 was derived from the unaudited historical financial statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited, included elsewhere in this prospectus and which, in the opinion of management, contain all normal recurring adjustments necessary for a fair statement of the results for the unaudited interim periods and have been prepared on the same basis as the associated audited consolidated financial statements.

You should read the information set forth below together with “Use of Proceeds,” “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this prospectus. We expect our historical results of operations and cash flows, including our audited consolidated financial statements, to differ materially from our future operations and cash flows as our business and projects mature. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Historical and Anticipated Future Operating Results Will Differ Materially” for further information. Accordingly, our historical financial results are not necessarily indicative of results to be expected for any future periods.

	Six Months Ended June 30,		Year Ended December 31,
	2020	2019	2019	2018
	(in thousands except share and per share data)
Statements of Operations Data:
Operating revenues
Time charter revenues	$22,787	$14,425	$35,601	$47,968
Time charter revenues – collaborative arrangement	—	9,622	9,622	30,681
Management fees	—	—	—	83
Total operating revenues	22,787	24,047	45,223	78,732
Operating expenses
Vessel operating expenses	6,622	6,531	12,638	11,499
Voyage, charter-hire and commission expenses	770	2,882	5,912	3,160
Voyage, charter-hire and commission expenses – collaborative arrangement	—	9,825	9,825	39,836
Administrative expenses	11,849	7,285	16,126	17,652
Depreciation and amortization	5,640	5,579	11,212	11,180
Total operating expenses	24,881	32,102	55,713	83,327
Other operating income (loss)	3,714	—	1,100	—
Operating income (loss)	1,620	(8,055)	(9,390)	(4,595)
Other non-operating income (loss)
Loss on disposal of asset under development	(25,981)	—	—	—
Unrealized gain on derivative instrument	5,127	—	9,990	—
Other non-operating income	—	—	—	5,000
Net gain on loss of control of subsidiary	—	—	—	72
Total non-operating income (loss)	(20,854)	—	9,990	5,072
Financial income (expense)
Interest income	10,839	489	795	1,336
Interest expense	(5,669)	—	(2)	(912)
Other financial items, net	2,011	(1,144)	(1,659)	(5,245)
Net financial income (expense)	7,181	(655)	(866)	(4,821)
Loss before equity in net losses of affiliates, income taxes and non-controlling interest	(12,053)	(8,710)	(266)	(4,344)
Income taxes	(2,522)	(33)	(4,152)	(110)
Equity in net loss of affiliates	(37,276)	(778)	(2,510)	(5,748)
Net loss	(51,851)	(9,521)	(6,928)	(10,202)
Net income attributable to non-controlling interest	(3,346)	(2,806)	(5,549)	(1,541)
Preferred dividends	(5,652)	(4,250)	(11,875)	(8,500)
Net loss attributable to common shareholders	$(60,849)	(16,577)	$(24,352)	$(20,243)
Net loss per share – basic and diluted	$(1.30)	$(0.35)	$(0.52)	$(0.43)
Weighted average number of shares outstanding – basic and diluted	46,950,154	46,950,154	46,950,154	46,950,154

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	As of June 30	As of December 31,
	2020	2019	2018
	(in thousands)
Balance Sheet Data (at period end):
Vessels and equipment, net	$354,645	$360,143	$363,893
Total assets	1,042,620	1,154,792	1,034,129
Long-term debt	378,885	337,686	372,256
Total liabilities	555,575	570,551	434,561

	Six Months Ended June 30		Year Ended December 31,
	2020	2019	2019	2018
	(in thousands)
Statements of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$11,724	$15,854	$13,755	$(12,947)
Investing activities	(18,109)	(13,466)	(71,447)	(310,794)
Financing activities	43,614	(10,721)	80,030	324,436

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RISK FACTORS

Investing in our common shares involves risks. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common shares. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business. This prospectus includes forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. As a result, you should not place undue reliance on any such statements included in this prospectus or any other offering materials.

If any of the following risks were to occur, our business, financial condition and results of operations could be materially adversely affected. In that case, the trading price of our common shares could decline and you could lose all or part of your investment.

Risks Related to Our Business

Only one of our terminals has commenced commercial operations. Our other planned terminals are in various stages of contracting customers, construction, permitting and commissioning. There can be no assurance that our planned terminals will commence operations timely, as described in this prospectus or at all.

Our Sergipe Terminal commenced commercial operations in March, 2020. However, we have not yet commenced commercial operations or entered into binding construction contracts or obtained all necessary environmental, regulatory, construction and zoning permissions for any of our other facilities. We expect to convert the Golar Celsius or the Golar Penguin into a FSRU to service our Barcarena Terminal, but have not yet reached FID for the deployment and conversion of such vessel. In addition, although we have been awarded environmental and regulatory licenses for our Santa Catarina Terminal, we have not secured any commercial projects nor obtained all remaining necessary approvals. We also have various agreements in place that remain subject to final investment decisions, such as our agreement to provide an FSRU to CI-GNL in the Ivory Coast. There can be no assurance that we will be able to enter into the contracts required for the development of our facilities on commercially favorable terms, if at all, or that we will be able to obtain all of the environmental, regulatory, construction and zoning permissions we need in Brazil and elsewhere.

In particular, we 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. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate these assets as described in this prospectus, or at all. In addition, to develop future projects we will, in many cases, have to secure the use of suitable vessels and, as required, convert them. Finally, the construction of facilities is inherently subject to the risks of cost overruns and delays. For example, the construction of our Sergipe Power Plant experienced a two-month delay related to the installation of various offshore equipment.

If we are unable to construct, commission and operate all of our facilities as described in this prospectus, or, when and if constructed, they do not accomplish the goals described in this prospectus, or if we experience delays or cost overruns in construction, our business, operating results, cash flows and liquidity could be materially and adversely affected. Expenses related to our pursuit of contracts and regulatory approvals related to our facilities still under development may be significant and will be incurred by us regardless of whether these assets are ultimately constructed and operational.

There is no existing market in Brazil for the sale of LNG as a fuel source for trucking or vehicles generally. BR Distribuidora does not currently distribute, nor is obligated to commence distribution of, LNG through its distribution and fuel centers. Additionally, BR Distribuidora is not obligated to, and may not, convert any portion of its existing fleet of diesel trucks. Moreover, our agreement with BR Distribuidora is subject to regulatory approval and other uncertainties. We may be unable to realize the anticipated benefits of this partnership.

The transportation industry in Brazil currently relies on traditional fuels such as gasoline and diesel. And although there is wide acknowledgement in the industry that LNG represents a less expensive and more environmentally friendly alternative to these fuels, no significant portion of the transportation industry is currently utilizing LNG. We cannot predict when, or even if, any meaningful portion of the transportation industry within Brazil will convert to LNG powered vehicles. Our agreement with BR Distribuidora does not contractually obligate it to convert any portion of its fleet of diesel trucks to LNG-powered vehicles. Unless and until there is a significant conversion to LNG-powered vehicles within Brazil, we will not realize the anticipated benefits of our partnership, which could adversely impact our future revenues.

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In addition, our agreement with BR Distribuidora is subject to approval by Brazilian antitrust authorities and our activities with respect to the sale of LNG are subject to the approval of other regulatory authorities, including ANP. There can be no assurance as to whether regulatory approvals will be received or that they will be granted in a timely manner. Until we receive these approvals, we will be unable to make sales through BR Distribuidora’s distribution channels or other channels. Accordingly, we have not yet made any sales pursuant to this arrangement.

Our cash flow will be dependent upon the ability of our operating subsidiaries and joint ventures to make cash distributions to us, the amount of which will depend on various factors.

We currently anticipate that a major source of our earnings will be cash distributions from our operating subsidiaries and joint ventures. The amount of cash that our operating subsidiaries and joint ventures can distribute each quarter to their owners, including us, principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things:

•	the amount of LNG or natural gas sold to customers;

•	market price of LNG;

•	the level of dispatch of the Sergipe Power Plant and our future power plants;

•	any restrictions on the payment of distributions contained in covenants in their financing arrangements and joint venture agreements;

•	the levels of investments in each of our operating subsidiaries, which may be limited and disparate;

•	the levels of operating expenses, maintenance expenses and general and administrative expenses;

•	regulatory action affecting: (i) the supply of, or demand for electricity in Brazil, (ii) operating costs and operating flexibility; and

•	prevailing economic conditions.

In addition, we do not wholly own all of our operating subsidiaries and joint ventures. As a result, if such operating subsidiaries and joint ventures make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners.

We may not be able to fully utilize the capacity of our terminals, which could impact our future revenues and materially harm our business, financial condition and operating results.

Our FSRU terminals 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 terminals 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 harm our business, financial condition and operating results.

In addition, CELSE has the right to utilize 100% of the capacity at our Sergipe Terminal pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Terminal, we will need the consent of CELSE and the senior lenders under CELSE’s financing arrangements. If we are unable to obtain the necessary consents to utilize the excess capacity of the Sergipe Terminal, our business, financial condition and operating results may be adversely affected.

Failure of LNG to be a competitive source of energy in the markets in which 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 particular, hydroelectric power generation is the predominant source of electricity in Brazil and LNG is one of several other energy sources used to supplement hydroelectric generation. Potential expansion in other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. Likewise, recent declines in the cost of crude oil, if sustained, will make crude oil and its derivatives a more competitive fuel source to LNG.

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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 or other locations on a commercial basis.

Our business plan requires the conversion of our LNG carriers to FSRUs. We have not yet made the final investment decision with respect to the conversion of either such carriers.

In the near term, we expect to convert the Golar Celsius or the Golar Penguin into a FSRU. To date, we have invested approximately $30 million in anticipation of a conversion of at least one of these carriers. However, our final investment decision to convert either of these carriers is subject to a variety of conditions, including, most importantly, obtaining an anchor customer with respect to certain of our planned projects. Additionally, the remaining expense of any such conversion will require project specific financing based on the value of the as-converted FSRU.

We cannot guarantee that any of our additional projects will be commenced on a timely basis, or at all, or that we will be able to obtain the necessary project financing for the conversion on favorable terms or at all. A delay in the conversion of the Golar Celsius or Golar Penguin may materially and adversely affect our ability to secure and commence future projects.

CELSE is subject to risk of loss or damage to LNG that is processed and/or stored at its FSRUs and transported via pipeline.

LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. For the period of time during which LNG is stored on an FSRU or is dispatched to a pipeline, CELSE, in the case of the Sergipe Terminal, bears the risk of loss or damage to all such LNG. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at the Sergipe Power Plant. If CELSE cannot generate energy at the Sergipe Power Plant by burning natural gas, its revenues, financial condition and results of operations may be materially and adversely affected.

Our ability to implement our business strategy may be materially and adversely affected by many factors, including our ability to identify future projects, obtain sufficient financing for such projects and develop and operate energy-related infrastructure.

Our business is subject to a variety of risks, including, among others, any inability to identify and enter into appropriate projects, any inability to obtain sufficient financing for any project we identify, any failure of upstream and downstream LNG producing and consuming projects connected with our activities, and other industry, regulatory, economic and political risks.

Our business strategy relies upon our future ability to successfully market natural gas to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in Brazil and other emerging and developing countries where we do not currently operate. Our strategy assumes that we will be able to expand our operations into other countries, enter into long-term agreements with end-users, develop infrastructure into efficient and profitable operations in a timely and cost-effective way, obtain approvals from all relevant federal, state and local authorities, as needed, for the construction and operation of these projects and other relevant approvals and obtain long-term capital appreciation and liquidity with respect to such investments. We cannot assure you if or when we will enter into contracts for the sale of LNG and/or natural gas in connection with our downstream distribution business, or, if we are able to enter into contracts, whether such contracts will materialize. In addition, there is no certainty as to the price at which we will be able to sell LNG and/or natural gas or our costs for such LNG and/or natural gas.

Thus, there can be no assurance that we will achieve our target pricing, costs or margins. Our strategy may also be affected by future governmental laws and regulations, which are subject to change in emerging countries, such as Brazil. Our strategy also assumes that we will be able to enter into strategic relationships with energy end-users, power utilities, LNG providers, shipping companies, infrastructure developers, financing counterparties and other partners. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control. Additionally, in

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furtherance of our business strategy, we may acquire operating businesses or other assets in the future. Any such acquisitions would be subject to significant risks and contingencies, including the risk of integration and we may not be able to realize the benefits of any such acquisitions.

Additionally, our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our business. Any one or more of the following factors may have a material adverse effect on our ability to implement our strategy and achieve our targets:

•	failure to develop cost-effective logistics solutions;

•	failure to manage expanding operations in the projected time frame;

•	inability to develop infrastructure, including our Barcarena and Santa Catarina Projects, as well as other future projects, in a timely and cost-effective manner;

•	inability to attract and retain personnel in a timely and cost-effective manner;

•	failure of investments in technology and machinery, such as LNG regasification technology, to perform as expected;

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

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

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

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

•	inability to raise significant additional debt and equity capital in the future to implement our strategy as well as to operate and expand our business;

•	general economic, political and business conditions in Brazil and in the other geographic areas in which we operate or intend to operate;

•	public health crises, such as coronavirus which began in early 2020, which has significantly impacted global economic conditions;

•	inflation, depreciation of the currencies of the countries in which we operate and fluctuations in interest rates;

•	failure to obtain approvals from local authorities for the construction and operation of our facilities;

•	failure to win new bids or contracts;

•	failure to obtain approvals from governmental regulators and relevant local authorities for the construction and operation of potential future projects and other relevant approvals;

•	existing and future governmental laws and regulations; or

•	inability, or failure, of any customer or contract counterparty to perform their contractual obligations to us.

If we experience any of these failures, such failure may adversely affect our financial condition, results of operations and ability to execute our business strategy.

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The scale and scope of the recent COVID-19 outbreak, the resulting pandemic, and the impact on the financial markets is unknown and could adversely affect our business, financial condition and results of operation at least for the near term. The rapid spread of COVID-19 globally has also resulted in increased travel restrictions and disruption and shutdown of certain businesses around the world, including our own. For example, there is an increased risk that FID of our Barcarena and Santa Catarina terminals may be delayed due to severe restrictions on travel within Brazil, which have prevented personnel from traveling between states to execute contracts and which have impacted the timing of inspections and permitting. In addition, the planned power auction related to the Santa Catarina Power Plant has been further postponed due to COVID-19. We continue to ask the majority of our non-essential workforce to work remotely, avoid public transportation and wear face coverings, and travel to other regions has been limited to essential personnel only. If COVID-19 were to affect a significant amount of our workforce, we may experience delays or the inability to fulfill our supply obligations to our customers on a timely basis. We will closely monitor this global health crisis and will reassess our strategy and operational activities on a regular, ongoing basis as the situation evolves.

The spread of COVID-19 has caused severe disruptions in the worldwide economy, including a significant decrease in the demand for LNG and natural gas, which could in turn disrupt our and our customers’ businesses, activities, and operations, including the marketability of our products. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the U.S., which could limit our ability to access capital and sources of liquidity at attractive rates or at all, adversely affecting our business, financial condition, liquidity and results of operations. The global scale and scope of COVID-19 is unknown and the duration of the business disruption and related financial impact cannot be reasonably estimated at this time.

The extent to which COVID-19 impacts our results will ultimately depend on future developments, which are highly uncertain, and will include emerging information concerning the severity of COVID-19 and the actions taken by governments and private businesses to attempt to contain COVID-19. However, we believe COVID-19 could adversely affect our business, financial condition and results of operations at least for the near term. See “Management's Discussion and Analysis of Results of Operations and Financial Condition—Our Historical and Anticipated Future Operating Results Will Differ Materially—Impact of COVID-19.”

We have a limited operating history, anticipate significant capital expenditures and an investment in our common shares is speculative.

We have a limited operating history and track record. As a result, our prior operating history and historical consolidated financial statements may not be a reliable basis for evaluating our business prospects or the future value of our common shares. We commenced operations on May 19, 2016, and we had net losses attributable to common shareholders of approximately $7.3 million for the period from May 19, 2016 to December 31, 2017, $20.2 million in 2018, $24.3 million in 2019 and $60.8 million for the six months ended June 30, 2020. In addition, we have historically derived our revenues from the operation of our vessels in the Cool Pool, but we expect the majority of our future revenues to be derived from our LNG-to-power projects. Our strategy may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner. We cannot give you any assurance that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate. Accordingly, your investment in our common shares is speculative and subject to a high degree of risk. Prior to investing in our common shares, you should understand that there is a possibility of the loss of your entire investment. Our limited history also means that we continue to develop and implement various policies and procedures including those related to data privacy and other matters. We will need to continue to build our team to implement our strategies.

We will continue to incur significant capital and operating expenditures while we develop our network of downstream LNG infrastructure, including for the completion of the Sergipe Terminal, the Barcarena Terminal, the Santa Catarina Terminal and other projects in Brazil currently under construction, as well as other future projects in our project pipeline. We will need to invest significant amounts of additional capital to implement our strategy. We have not completed constructing all of our facilities and our strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Our future liquidity may also be

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affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under our customer contracts in relation to the incurrence of project and operating expenses. Our ability to generate any positive operating cash flow and achieve profitability in the future is dependent on, among other things, our ability to successfully and timely complete necessary infrastructure, including our Barcarena and Santa Catarina Terminals and other projects in Brazil currently under construction, and fulfill our delivery obligations under our customer contracts.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:

•	insufficient supply or oversupply of natural gas;

•	insufficient LNG tanker capacity;

•	weather conditions and natural disasters;

•	reduced demand for natural gas;

•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•	decreased oil and natural gas exploration activities, which may decrease the production and increase the price 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 or LNG.

Adverse trends or developments affecting any of these factors could result in decreases in the prices at which we are able to sell LNG and natural gas or increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. 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 for some of our terminals, increases in LNG prices and/or shortages of LNG supply could be material and adverse to our business. 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.

In addition, the spread of COVID-19 across the globe has negatively affected worldwide economic and commercial activity, disrupted global supply chains, reduced global demand for oil, natural gas and LNG, and created significant volatility and disruption of financial and commodity markets. Other factors expected to impact crude oil and natural gas demand include production cuts and freezes implemented by OPEC members, other large oil producers such as Russia, and certain state regulators in the U.S. For example, during the first quarter of 2020, OPEC and Russia failed to agree on a plan to cut production of oil and related commodities. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. In response to the oversupply of crude oil caused by COVID-19 and the actions of OPEC, Saudi Arabia and Russia, certain

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state regulators in the U.S. are considering prorating production of hydrocarbons. These events, combined with the outbreak of the COVID-19 pandemic that has reduced economic activity and the related demand for oil, have contributed to a sharp drop in prices for crude oil, natural gas and LNG in the first half of 2020.

Any future liquidation proceeding of us or our subsidiaries may be conducted on a consolidated basis.

The Brazilian judiciary, our creditors and/or our subsidiaries may determine that any future liquidation proceeding of us or our subsidiaries be conducted as if we and our subsidiaries were a single company pursuant to the substantial consolidation theory. Should this happen, our shareholders may be adversely affected by the loss of value of the Company in the event our equity is allocated to pay the creditors of one or more of our subsidiaries.

Our power generation projects may depend on the construction and operation of transmission and interconnection facilities by third parties.

Our power generation projects must interconnect to Brazil’s transmission system and such projects may depend on the completion of new lines and/or increases in the capacity of existing facilities by the applicable power transmission concessionaires in order to interconnect and become fully operational. Delays from such concessionaires in the completion of the necessary interconnection and associated facilities may affect the ability of our power generation projects to start commercial operation and/or fulfill power delivery commitments under the PPAs.

Our ability to dispatch electricity from our power plants is dependent upon hydrological and other grid conditions in Brazil.

Historically, Brazil’s electricity generation has been dominated by hydroelectricity plants, which currently represent 64% of 171.8 GW of total installed capacity compared to 25% for thermoelectric facilities, 10% for renewables, and 1% for nuclear. There are substantial seasonal variations in monthly and annual flows to the plants, which depend fundamentally on the volume of rain that falls in each rainy season. When hydrological conditions are poor, the National Electricity System Operator (Operador Nacional do Sistema, or “ONS”) dispatches thermoelectric power plants, including those that we operate, to top up hydroelectric generation and maintain the electricity supply level.

The ONS Grid Code allows the ONS to dispatch thermoelectric power plants for the following reasons or under the following circumstances:

(i)	when marginal operation cost is the same as the variable unit cost of such power plant;

(ii)	due to inflexibility or necessity of the generator;

(iii)

when dispatch of such power plant is needed in order to maintain the stability of the system;

(iv)	as determined by the Energy Industry Monitoring Committee where extraordinary circumstances exist;

(v)	due to accelerated and/or replacement generation as proposed by the generator in order to make up for the unavailability of fuel; and

(vi)	for purposes of exportation of power to foreign markets.

As a result, the amount of electricity generated by thermoelectric power plants, including our power plants that are already contracted and our power plants under development, can vary significantly in response to the hydrological and other grid conditions in Brazil. If our power plants are not dispatched or are dispatched at levels lower than expected, our operations and financial results may be adversely affected.

Our growth depends on continued growth in demand for the services we provide.

Our growth strategy focuses on expansion in the floating storage and regasification sector and the transportation sector within the LNG transportation, storage and regasification industry. The rate of LNG growth has fluctuated due to several reasons, including the global economic crisis and the continued increase in natural gas production from unconventional sources in regions such as North America. Accordingly, our growth depends on continued growth in world and regional demand for LNG, FSRUs and other LNG infrastructure assets, which could be negatively affected by a number of factors, including:

•	increases in the cost of LNG;

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•	increases in the production levels of low-cost natural gas in domestic, natural gas-consuming markets, which could further depress prices for natural gas in those markets and make LNG uneconomical;

•

decreases in the cost, or increases in the demand for, conventional land-based regasification systems, which could occur if providers or users of regasification services seek greater economies of scale than FSRUs can provide or if the economic, regulatory or political challenges associated with land-based activities improve;

•	decreases in the cost of alternative technologies or development of alternative technologies for vessel-based LNG regasification;

•	increases in the production of natural gas in areas linked by pipelines to consuming areas, the extension of existing, or the development of new, pipeline systems in markets we may serve, or the conversion of existing non-natural gas pipelines to natural gas pipelines in those markets;

•	decreases in the consumption of natural gas due to increases in its price relative to other energy sources or other factors making consumption of natural gas less attractive;

•	availability of new, alternative energy sources, including compressed natural gas; and

•	negative global or regional economic or political conditions (including the ongoing global economic effects of COVID-19), particularly in LNG consuming regions, which could reduce energy consumption or its growth.

Reduced demand for LNG, FSRUs or other LNG infrastructure assets would have a material adverse effect on our future growth and could harm our business, financial condition and results of operations.

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.

A portion of the net proceeds from this offering will be used to redeem the preference shares held by Stonepeak, with the remaining portion used to fund future capital expenditures. After giving effect to this offering, assuming the accuracy of our assumptions relating to construction, we believe that our cash resources will be sufficient to meet projected capital expenditures, financing obligations and operating requirements related to the construction and development of our assets and LNG facilities. In the future, we expect to incur additional indebtedness to assist us in developing our operations, including to finance the conversion of our existing LNG carriers to FSRUs. If we are unable to secure additional funding, or if it is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan and our business, financial condition or results of operations may be adversely affected. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the availability of such additional funding. Our ability to raise additional capital will depend on financial, economic and market conditions and other factors, many of which are beyond our control. We cannot assure you that such additional funding will be available on acceptable terms, or at all. To the extent that we raise additional equity capital by issuing additional securities at any point in the future, our then-existing shareholders may experience dilution. Debt financing, if available, may subject us to restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. If we are unable to comply with these covenants and service our debt, we may lose control of our business and be forced to reduce or delay planned investments or capital expenditures, sell assets, restructure our operations or submit to foreclosure proceedings, all of which could result in a material adverse effect upon our business and reduce the value of your investment.

A variety of factors beyond our control could impact the availability or cost of capital, including the valuations of our assets, domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.

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We may not be profitable for an indeterminate period of time.

We have a limited operating history and did not commence revenue-generating activities until 2016, and therefore did not achieve profitability as of June 30, 2020. We will need to make a significant capital investment to construct and begin operations of the Barcarena Terminal, the Santa Catarina Terminal, our downstream distribution hubs and our other LNG-to-power projects in Brazil, and we will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects. We also expect to incur significant expenses in connection with the launch and growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. We will need to raise significant additional debt and/or equity capital to achieve our goals.

We may not be able to achieve profitability, and if we do, we cannot assure you that we would be able to sustain such profitability in the future. Our failure to achieve or sustain profitability would have a material adverse effect on our business and the value of our common shares.

Our operational and consolidated financial results are partially dependent on the results of the joint ventures, affiliates and special purpose entities in which we invest.

We conduct our business mainly through our operating subsidiaries. In addition, we and our subsidiaries conduct some of our business through joint venture and other special purpose entities, which are created specifically to participate in public auctions for enterprises in the generation and transmission segments. Our ability to meet our financial obligations is therefore related in part to the cash flow and earnings of our subsidiaries and joint ventures and the distribution or other transfers of earnings to us in the form of dividends, loans or other advances and payments that are governed by various joint venture financing and operating arrangements. For the purposes of Rule 3-09 of Regulation S-X, for the years ended December 31, 2019 and 2018, only CELSEPAR, whose sole material asset is its interest in CELSE, was considered a material investment.

We have a limited customer base and expect that a significant portion of our future revenues will be from a limited number of customers, and the loss of any significant customer could adversely affect our operating results.

A limited number of customers currently represent a substantial majority of our future income. Our operating results will be contingent on our ability to maintain sales to these customers. At least in the short term, we expect that a substantial majority of our sales will continue to arise from a concentrated number of customers, such as power utilities and industrial end-users. We expect the substantial majority of our revenue for the near future to be derived from our Sergipe Terminal and Sergipe Power Plant and as a result, are subject to any risks specific to those entities and the jurisdictions and markets in which they operate. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.

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 contains various termination rights allowing our customers to terminate the contract, including, without limitation:

•	the revocation of certain legal, governmental or regulatory authorizations or licenses;

•	our termination from Câmara de Comercialização de Energia Elétrica (the Electric Energy Trading Chamber or “CCEE”);

•	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 other milestones within the agreed timeframes.

In addition, we may be subject to a penalty upon termination equal to one year of sales revenue as calculated in accordance with the terms of the PPAs and may be required to indemnify the losses of off-takers.

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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.

We depend on a limited number of key suppliers and vendors to provide the necessary equipment to operate our businesses and construct our projects, and any failure by our key suppliers and vendors to supply the necessary equipment on a timely basis or at all could materially adversely affect our current and future projects.

We depend on a limited number of key suppliers and vendors to provide the equipment and other services necessary for the construction and operation of our projects in various jurisdictions. Although we contract with most of our suppliers and vendors at fixed prices and require them to pay delivery delay penalties, our suppliers may, among other things, extend delivery times, raise contract prices and limit supply due to their own shortages and business requirements. If our suppliers or vendors fail to provide the necessary equipment or services on a timely basis, we could experience disruptions in our operations, which could have a material adverse effect on our business and operations.

Our sale and leaseback agreements contain restrictive covenants that may limit our liquidity and corporate activities, and could have an adverse effect on our financial condition and results of operations.

Our sale and leaseback agreements for the Golar Nanook, Golar Penguin and Golar Celsius contain, and any future sale and leaseback agreements we may enter into are expected to contain, customary covenants and event of default clauses, including cross-default provisions and restrictive covenants and performance requirements that may affect our operational and financial flexibility. In addition, we also assign the shares in our subsidiaries which are the charterers of these vessels to the owners/lessors. Such restrictions could affect, and in many respects limit or prohibit, among other things, our ability to incur additional indebtedness, create liens, sell assets, or engage in mergers or acquisitions. These restrictions could also limit our ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities. There can be no assurance that such restrictions will not adversely affect our ability to finance our future operations or capital needs.

Certain of our sale and leaseback agreements contain cross-default clauses and require us to maintain specified financial ratios, satisfy certain financial covenants and/or assign equity interests in our subsidiaries to third parties, including, among others, the following requirements:

•	that we maintain Free Liquid Assets (as defined in the Penguin Leaseback) of at least $50.0 million; and

•	that we assign the shares in each of Golar Hull M2026 Corp., Golar Hull M2023 Corp. and Golar FSRU 8 Corp., our subsidiaries that are the charterers under our sale and leaseback agreements, to the applicable vessel owners.

As of December 31, 2019, we are in compliance with the consolidated leverage ratio and the minimum free liquidity covenants in our sale and leaseback agreements.

As a result of the restrictions in our sale and leaseback agreements, or similar restrictions in our future sale and leaseback agreements, we may need to seek permission from the owners of our leased vessels in order to engage in certain corporate actions. Their interests may be different from ours and we may not be able to obtain their permission when needed. This may prevent us from taking actions that we believe are in our best interest, which may adversely impact our revenues, results of operations and financial condition.

A failure by us to meet our payment and other obligations, including our financial covenant requirements, could lead to defaults under our sale and leaseback agreements or any future sale and leaseback agreements. If we are not in compliance with our covenants and we are not able to obtain covenant waivers or modifications, the current or future owners of our leased vessels, as appropriate, could retake possession of our vessels or require us to pay down our indebtedness to a level where we are in compliance with our covenants or sell vessels in our fleet. We could lose our vessels if we default on our bareboat charters in connection with the sale and leaseback agreements, which would negatively affect our revenues, results of operations and financial condition.

There are risks and uncertainties relating to our sale and leaseback transactions.

On closing of our sale and leaseback transactions, we transferred our ownership interests in each of the Golar Nanook, the Golar Penguin and the Golar Celsius. Although the operation of these vessels is expected to continue in the ordinary course, the bareboat charters in connection with the sale and leaseback transactions may, in certain

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circumstances, be terminated. Any such termination could have a significant adverse effect on our business, financial condition and results of operations of our vessels. The sale and leaseback agreements will also require significant periodic cash payments in respect of the required rent thereunder, which we have not historically incurred for the Golar Celsius or, prior to December 2019, the Golar Penguin, and other allocated operating and maintenance costs. The increase in our lease expense may have an adverse impact on our future operations and profitability.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our existing or future debt obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control. We may be unable to maintain a level of cash flows from operating activities sufficient to permit us to fund our day-to-day operations or to pay the principal, premium, if any, and interest on our indebtedness. As of December 31, 2019 and June 30, 2020, we had $469.2 million and $494.4 million of total indebtedness outstanding, respectively, excluding deferred financing costs.

If our cash flows and capital resources are insufficient to fund our debt service obligations and other cash requirements, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to sell assets or operations, seek additional capital or restructure or refinance our indebtedness or operations. We may not be able to affect any such alternative measures, if necessary, on commercially reasonable terms or at all and, even if successful, such alternative actions may not allow us to meet our scheduled debt service obligations. The agreements that govern our indebtedness restrict our ability to dispose of assets and use the proceeds from any such dispositions and our ability to raise debt capital to be used to repay our indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to meet any debt service obligations then due.

Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, would materially and adversely affect our financial position and results of operations and our ability to satisfy our obligations. In addition, obligations under certain of our financing arrangements are secured by certain of our vessels and guaranteed by our subsidiaries holding the interests in our vessels, and if we are unable to repay debt under our financing arrangements, the lenders or lessors could seek to foreclose on those assets.

If we cannot make scheduled payments on our debt, we will be in default and, as a result, lenders under any of our existing and future indebtedness could declare all outstanding principal and interest to be due and payable, the lenders under our debt instruments could terminate their commitments to loan money, our secured lenders could foreclose against the assets securing such borrowings and we could be forced into bankruptcy or liquidation, in each case, which could result in your losing your investment.

Reforms, including the potential phasing out of LIBOR after 2021, may adversely affect us.

We have floating rate debt, the interest rate of which is determined based on the London Interbank Offered Rate (“LIBOR”). LIBOR and other “benchmark” rates are subject to ongoing national and international regulatory scrutiny and reform. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it will no longer persuade or compel banks to submit rates for the calculation of the LIBOR rates after 2021 (the “FCA Announcement”). The Alternative Reference Rate Committee, a committee convened by the Federal Reserve that includes major market participants, has proposed an alternative rate to replace U.S. dollar LIBOR: the Secured Overnight Financing Rate, or “SOFR.”

We are unable to predict the effect of the FCA Announcement or other reforms, whether currently enacted or enacted in the future. They may result in the phasing out of LIBOR as a reference rate. The impact of such transition away from LIBOR could be significant for us because of the number of our financing arrangements that are linked to LIBOR and our indebtedness. The outcome of reforms may result in increased interest expense to us, may affect our ability to incur debt on terms acceptable to us and may result in increased costs related to amending our existing debt instruments, which could adversely affect our business, results of operations and financial condition.

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We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility.

We have entered into joint ventures to acquire and develop LNG infrastructure projects and may in the future enter into additional joint venture arrangements with third parties. As we do not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Because we do not control all of the decisions of our joint ventures, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our 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 and trade creditors). Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us 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. Our results of operations depend on the performance of these joint ventures and their ability to distribute funds to us, and we may be unable to control the amount of cash we will receive from their operations or the timing of capital expenditures, which could adversely affect our financial condition.

We may guarantee the indebtedness of our joint ventures and/or affiliates.

We may provide guarantees to certain banks with respect to commercial bank indebtedness of 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 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.

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.

We operate two of our vessels, through the Cool Pool, in the spot/short-term charter market, which is subject to volatility. Failure by the Cool Pool to find profitable employment for these vessels could adversely affect our operations.

As of June 30, 2020, we had two LNG carriers operating in the spot market within the Cool Pool. We anticipate that one or both of these vessels may be converted to FSRUs, but until such time they will remain in the pool. Please see “Business—Our Vessels” for further detail. The spot market refers to charters for periods of up to twelve months. Spot/short-term charters expose the Cool Pool to the volatility in spot charter rates, which can be significant. In contrast, medium to long-term time charters generally provide reliable revenues, but they also limit the portion of our fleet available to the spot/short-term market during an upswing in the LNG industry cycle, when spot/short-term market voyages might be more profitable. The charter rates payable in the spot market are uncertain and volatile and will depend upon, among other things, economic conditions in the LNG market.

If we do not reach FID on the conversion of our LNG carriers to FSRUs, they will operate within the Cool Pool. If the Cool Pool is unable to find profitable employment or re-deploy ours or any of the other Cool Pool participants’ vessels, we will not receive any revenues from the Cool Pool, but we may be required to pay

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expenses necessary to maintain that vessel in proper operating condition. A sustained decline in charter or spot rates or a failure by the Cool Pool to successfully charter its participating vessels could have a material adverse effect on our results of operations and our ability to meet our financing obligations.

We are dependent upon Golar LNG and its affiliates for the operation and maintenance of our vessels.

Each of our vessels is operated and maintained by Golar LNG or its affiliates pursuant to ship management agreements. These agreements are the result of arms-length negotiations and subject to change. If Golar LNG or any of its affiliates that provide services to us fails to perform these services satisfactorily or the terms of the ship management agreements change, it could have a material adverse effect on our business, results of operations and financial condition.

Operation of our LNG infrastructure and other facilities that we may construct involves significant risks.

As more fully discussed in this prospectus, our existing facilities and expected future facilities face operational risks, including the following: performing below expected levels of efficiency, breakdowns or failures of equipment, operational errors by tankers or tug operators, operational errors by us or any contracted facility operator, labor disputes and weather-related or natural disaster interruptions of operations, including ship-to-ship transfers. Any of these risks could disrupt our operations and increase our costs, which would adversely affect our business, operating results, cash flows and liquidity.

In particular, the operation of the Sergipe Power Plant will involve particular, significant risks, including, among others: failure to maintain the required license(s) and other permits required to operate the Sergipe Power Plant in Brazil; pollution or environmental contamination affecting operation of the Sergipe Power Plant; the inability, or failure, of any counterparty to any plant-related agreements to perform their contractual obligations to us including, but not limited to, planned and unplanned power outages due to maintenance, expansion and refurbishment. We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, the Sergipe Power Plant. If the Sergipe Power Plant is unable to generate or deliver power to its end-users, pursuant to its PPAs, such counterparties may not be required to make payments under their respective agreements so long as the event continues, and the Sergipe Power Plant may be required to pay penalties due to the unavailability of power. The counterparties to the PPAs and any other key plant-related agreements may have the right to terminate those agreements for certain failures to generate or deliver power. In addition under Brazilian law, we are strictly liable for direct and indirect damages resulted from the inadequate supply of electricity, such as abrupt interruptions or problems related to generation, transmission or distribution systems. As a consequence, there may be reduced or no revenues from the Sergipe Power Plant which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The operation of FSRUs and LNG carriers is inherently risky, and our vessels face a number of industry risks and events which could cause damage or loss of a vessel, loss of life or environmental consequences that could harm our reputation and ongoing business operations.

Our vessels and their cargoes are at risk of being damaged or lost because of events such as marine disasters, acts of piracy, environmental accidents, bad weather, mechanical failures, grounding, fire, explosions and collisions, human error, national emergency and war and terrorism. Incidents such as these have historically affected companies in our industry, and such an event or accident involving any of our vessels could result in any of the following:

•	death or injury to persons, loss of property or environmental damage;

•	delays in the delivery of cargo;

•	loss of revenues from or termination of charter contracts;

•	governmental fines, penalties or restrictions on conducting business;

•	a government requisitioning for title or seizing our vessels (e.g. in a time of war or national emergency);

•	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.

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Our construction of energy-related infrastructure is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

The construction of energy-related infrastructure, including our Barcarena Terminal, the Santa Catarina Terminal and other assets in Brazil, as well as other future projects, involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital during construction and thereafter. These potential risks include, among other things, the following:

•	we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents or weather conditions;

•	we may change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give our customers the right to cause us to enter into change orders or resulting from changes with which we otherwise agree;

•	we will not receive any material increase in operating cash flows until a project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

•	we may construct facilities to capture anticipated future energy consumption growth in a region in which such growth does not materialize;

•	the completion or success of our construction project may depend on the completion of a third-party construction project (e.g., additional public utility infrastructure projects) that we do not control and that may be subject to numerous additional potential risks, delays and complexities;

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we may not be able to obtain key permits or land use approvals including those required under environmental laws, at all or on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations. There may be delays in obtaining such permits or approvals, perhaps substantial in length, such permits or approvals may be nullified or additional compensatory investments and/or obligations to perform remediation actions may be imposed, such as in the event of challenges by environmental authorities, public attorneys, citizens groups or non-governmental organizations, including those opposed to fossil fuel energy sources;

•	we may be (and have been in select circumstances) subject to local opposition in Brazil and elsewhere, including the efforts by environmental groups, which may attract negative publicity or have an adverse impact on our reputation; and

•	we may be unable to obtain rights-of-way to construct additional energy-related infrastructure or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from future projects, which could have a material adverse effect on our business, financial condition and results of operations.

Natural or manmade disasters could result in an interruption of our operations, a delay in the completion of our infrastructure projects, higher construction costs or the deferral of the dates on which payments are due under our customer contracts, all of which could adversely affect us.

Storms and related storm activity and collateral effects, or other disasters such as explosions, fires, seismic events, floods or accidents, could result in damage to, or interruption of operations in our supply chain, including at our facilities or related infrastructure, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our marine and coastal operations.

If one or more tankers, terminals, pipelines, facilities, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our facilities and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist or cyber-attack or event, our operations and construction projects could be delayed and significantly interrupted. These delays and interruptions could involve significant damage to people, property or the environment, and repairs could take a week or less for a minor

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incident to six months or more for a major interruption. Any such event that interrupts the revenues generated by our operations, or that causes us to make significant expenditures not covered by insurance, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

Our current operations and future projects are subject to the inherent risks associated with LNG, natural gas and power operations, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the our facilities and assets or damage to persons and property. In addition, such operations and the vessels of third parties on which our current operations and future projects may be dependent face possible risks associated with acts of aggression or terrorism. If our vessels suffer damage, they may need to be repaired. The costs of vessel repairs are unpredictable and can be substantial. We may have to pay repair costs that our insurance policies do not cover.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not carry business interruption insurance for hurricanes and other natural disasters. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Although we carry insurance, all risks may not be adequately insured against, and any particular claim may not be paid. Any claims covered by insurance would be subject to deductibles, and since it is possible that a large number of claims may be brought, the aggregate amount of these deductibles could be material. In addition, we may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic release of natural gas, marine disaster or natural disasters could result in losses that exceed our insurance coverage, which could harm our business, financial condition and operating results. Our insurance may be voidable by the insurers as a result of certain of our actions and any uninsured or underinsured loss could harm our business and financial condition.

Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult for us to obtain. In addition, the insurance that may be available may be significantly more expensive than our existing coverage.

From time to time, we may be involved in legal proceedings and may experience unfavorable outcomes.

In the future we and our subsidiaries may be subject to material legal proceedings in the course of our business, including, but not limited to, actions relating to contract disputes, business practices, intellectual property and other commercial and tax matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time consuming and expensive. Further, if any such proceedings were to result in an unfavorable outcome, it could have a material adverse effect on our business, financial position and results of operations.

We may be unable to attract and retain key management personnel in the LNG industry, which may negatively impact the effectiveness of our management and our results of operations.

Significant demands are placed on our management as a result of our growth. As we expand our operations, we must manage and monitor our operations, control costs and maintain quality and control. Our success depends, to a significant extent, upon the abilities and the efforts of our senior executives. While we believe that we have an experienced management team, the loss or unavailability of one or more of our senior executives for any extended period of time could have an adverse effect on our business and results of operations.

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We expect to be dependent on our primary building contractors and other contractors for the successful completion of our energy-related infrastructure.

Timely and cost-effective completion of our energy-related infrastructure, including our Sergipe Terminal, the Barcarena Terminal and the Santa Catarina Terminal, as well as future projects, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our primary building contractor and our other contractors under our agreements with them. For example, the construction of the Sergipe Power Plant was not completed on schedule, and we were forced to purchase energy in the spot market to avoid a breach of our obligations under the original PPAs. The ability of our primary building contractors and our other contractors to perform successfully under their agreements with us is dependent on a number of factors, including their ability to:

•	design and engineer each of our facilities to operate in accordance with specifications;

•	engage and retain third-party subcontractors and procure equipment and supplies;

•	respond to difficulties such as equipment failure, delivery delays, schedule changes and failures to perform by subcontractors, some of which are beyond their control;

•	attract, develop and retain skilled personnel, including engineers;

•	post required construction bonds and comply with the terms thereof;

•	manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

•	maintain their own financial condition, including adequate working capital.

Until we have entered into an EPC contract for a particular project, in which the EPC contractor agrees to meet our planned schedule and projected total costs for a project, we are subject to potential fluctuations in construction costs and other related project costs. Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of our primary building contractor and our other contractors to pay liquidated damages under their agreements with us are subject to caps on liability, as set forth therein. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are relying on third party engineers to estimate the future rated capacity and performance capabilities of our existing and future facilities, and these estimates may prove to be inaccurate.

We are relying on third parties for the design and engineering services underlying our estimates of the future rated capacity and performance capabilities of our Sergipe Terminal, the Barcarena Terminal and the Santa Catarina Terminal, as well as other future projects. If any of these facilities, when actually constructed, fails to have the rated capacity and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our existing or future facilities to achieve our intended future capacity and performance capabilities could prevent us from achieving the commercial start dates under our customer contracts and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of natural gas or LNG in sufficient quantities and/or at economically attractive prices to supply the Sergipe Power Plant and satisfy our delivery obligations under the PPAs, which could have a material adverse effect on us.

Under the PPAs related to the Sergipe Power Plant and our other LNG-to-power facilities, we are required to deliver power, which also requires us to obtain sufficient amounts of LNG. However, we may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may subject us

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to certain penalties and provide our counterparties with the right to terminate their PPAs. With respect to the Sergipe Power Plant, we have entered into a supply agreement with Ocean LNG, an affiliate of Qatar Petroleum. If Ocean LNG fails to deliver sufficient LNG to Sergipe, we would be forced to purchase LNG on the spot market, which may be on less favorable terms. In addition, price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items for our other customers.

We are dependent upon third party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Additionally, under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to purchase or receive a sufficient quantity of natural gas in order to supply the Sergipe Power Plant and satisfy our delivery obligations under our PPAs. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported to our facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.

Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third party LNG suppliers and shippers negatively impacts 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.

Under certain circumstances, we may be required to make payments under our gas supply agreements.

If we fail to take delivery of contracted volumes under our gas supply agreements, we may be required to make payments to counterparties under such agreements. For example, CELSE entered into a 25-year LNG supply agreement with Ocean LNG for the supply of LNG to the Sergipe Terminal. Pursuant to the terms of the Sergipe Supply Agreement, CELSE is required to take delivery of a specified base quantity of LNG each year, subject to certain adjustments. If CELSE takes less than the full number of scheduled cargoes per year under the Sergipe Supply Agreement, CELSE will be required to pay Ocean LNG a cancellation fee per cargo according to a formula based on the number of the cargoes not taken, subject to a cap of $110 million for every five-year period, or an aggregate of $550 million over the 25-year term. For additional information regarding our relationship with Ocean LNG and the Sergipe Supply Agreement, please see “Business—Detailed Description of our Operating and Advanced Stage Terminals—Description of Contractual Arrangements Related to Sergipe—The Sergipe LNG Supply Agreement.”

We face competition based upon the international market price for LNG or natural gas.

Our business is subject to the risk of natural gas and LNG price competition at times when we need to replace any existing customer contract, whether due to natural expiration, default or otherwise, or enter into new customer contracts. 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. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for natural gas from our business are diverse and include, among others:

•	increases in the cost to supply LNG to our customers;

•	decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, HFO and diesel; 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.

Technological innovation may render our processes obsolete.

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 industry. Our technologies may be rendered obsolete or

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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.

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

We plan to operate in the highly competitive area of 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, many of which have been in operation longer than us.

We may face competition from major energy companies and others in pursuing our proposed business strategy. In addition, competitors have and are developing LNG import terminals in other markets, which may compete with our LNG facilities. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us.

We are dependent upon the available labor pool of skilled employees, including technically skilled officers and crew. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to crew our vessels, construct and operate our energy-related infrastructure and to provide our customers with the highest quality service. In particular, our vessels require a technically skilled officer staff with specialized training. If we are unable to employ technically skilled staff and crew, we will not be able to adequately staff our vessels. We are subject to applicable labor regulations in the jurisdictions in which we operate, including Brazil. We may face challenges and costs in hiring, retaining and managing our Brazilian and other employee base. A shortage in the labor pool of skilled workers, particularly of skilled officers, 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.

Labor strikes or general labor unrest could adversely affect our business.

A work stoppage or strike could occur in the future. Since initiation of construction of the Sergipe Power Plant, there have been numerous labor demonstrations and other forms of labor unrest by unemployed workers and union groups in the State of Sergipe, some of which were directed towards CELSE. Labor unrest, as well as any strikes, could cause interruptions or delays our projects or their operations.

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

The substantial majority of our anticipated revenue in 2020 will be dependent upon our assets and customers in Brazil. Brazil has historically experienced economic volatility and the general condition and performance of the Brazilian economy, over which we have no control, may affect our business, financial condition and results of operations. Due to our current lack of asset and geographic diversification, an adverse development at any of our facilities in Brazil, in the energy industry or in the economic conditions in Brazil, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

We may incur impairments to long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, declines in our market capitalization, reduced estimates of future cash flows for our reportable segments or

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disruptions to our business could lead to an impairment charge of our long-lived assets, including our vessels. 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. For example, as of December 31, 2019 and June 30, 2020, we determined that our vessels had a market value that was less than their carrying value but because estimated future undiscounted cash flows related to these vessels were significantly greater than the respective carrying values, we did not record an impairment. There can be no assurance that we will not record an impairment with respect to these vessels or any other assets in the future. Projections of future operating results and cash flows may vary significantly from results and we may recognize an impairment in the future. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.

A major health and safety incident involving LNG or the energy industry more broadly or relating to our business may lead to more stringent regulation of LNG operations or the energy business generally, could result in greater difficulties in obtaining permits, including under environmental laws, on favorable terms, and may otherwise lead to significant liabilities and reputational damage.

Health and safety performance is critical to the success of all areas of our business. Any failure in 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 for non-compliance with relevant regulatory requirements or litigation. Any such failure that results in a significant health and safety incident may be costly in terms of potential liabilities, and may result in liabilities that exceed the limits of our insurance coverage. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG 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. Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets. Similarly, such developments could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

A cyber-attack could materially disrupt our business.

We rely on information technology systems and networks, the majority of which are provided by Golar Management, in our operations and the administration of our business. Our business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations and the availability of our vessels and facilities or lead to unauthorized release of information or alteration of information in our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.

We are subject to laws, directives and regulations relating to the collection, use, retention, disclosure, security and transfer of personal data. These laws, directives, and regulations, and their interpretation and enforcement continue to evolve and may be inconsistent from jurisdiction to jurisdiction. For example, the General Data Protection Regulation (“GDPR”), which regulates the use of personally identifiable information, went into effect in the European Union (“EU”) on May 25, 2018, applies globally to all of our activities conducted from an establishment in the EU, to related products and services that we offer to EU customers and to non-EU customers which offer services in the EU. Complying with the GDPR and similar emerging and changing privacy and data protection requirements may cause us to incur substantial costs or require us to change our business practices. Noncompliance with our legal obligations relating to privacy and data protection could result in penalties, fines, legal proceedings by governmental entities or others, loss of reputation, legal claims by individuals and customers and significant legal and financial exposure and could affect our ability to retain and attract customers.

Changes in the nature of cyber-threats and/or changes to industry standards and regulations might require us to adopt additional procedures for monitoring cybersecurity, which could require additional expenses and/or capital expenditures. However, the impact of such regulations is hard to predict at this time.

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Risks Relating to Applicable Laws and Regulations

Global climate change may in the future increase the frequency and severity of weather events and the losses resulting therefrom, which could have a material adverse effect on the economies in the markets in which we operate or plan to operate in the future and therefore on our business.

Over the past several years, changing weather patterns and climatic conditions, such as global warming, have added to the unpredictability and frequency of natural disasters in certain parts of the world, including the markets in which we operate and intend to operate, and have created additional uncertainty as to future trends. There is a growing consensus today that climate change increases the frequency and severity of extreme weather events and, in recent years, the frequency of major weather events appears to have increased. We cannot predict whether or to what extent damage that may be caused by natural events, such as severe tropical storms and hurricanes, will affect our operations or the economies in our current or future market areas, but the increased frequency and severity of such weather events could increase the negative impacts to economic conditions in these regions and result in a decline in the value or the destruction of our liquefiers and downstream facilities or affect our ability to transmit LNG. In particular, if one of the regions in which our terminals are operating or under development is impacted by such a natural catastrophe in the future, it could have a material adverse effect on our business. Further, the economies of such impacted areas may require significant time to recover and there is no assurance that a full recovery will occur. Even the threat of a severe weather event could impact our business, financial condition or the price of our common shares.

We are subject to comprehensive regulation of our business, which fundamentally affects our financial performance.

Our business is subject to extensive regulation by various Brazilian regulatory authorities, particularly ANEEL, ANP and ANTAQ. ANEEL regulates and oversees various aspects of our business and establishes our tariffs. If we are obligated by ANEEL to make additional and unexpected capital investments and are not allowed to adjust our tariffs accordingly, if ANEEL does not authorize the recovery of all costs or if ANEEL modifies the regulations related to tariff adjustments, we may be adversely affected. ANP regulates the import and export of LNG and the transportation and distribution of natural gas activities, including our downstream distribution business. ANTAQ regulates and oversees port activities in Brazil.

In addition, both the implementation of our strategy for growth and our ordinary business may be adversely affected by governmental actions such as changes to current legislation, the termination of federal and state concession programs, creation of more rigid criteria for qualification in public energy auctions, or a delay in the revision and implementation of new annual tariffs.

If regulatory changes require us to conduct our business in a manner substantially different from our current operations, our operations, financial results and our capacity to fulfill our contractual obligations may be adversely affected.

CELSE and CELBA could be penalized by ANEEL for failing to comply with the terms of their respective authorizations and applicable legislation and CELSE and CELBA may not recover the full value of their respective investments if such authorizations are terminated.

CELSE and CELBA will carry out their respective power generation activities in accordance with the authorizations granted by the Brazilian government through the MME (the “MME Authorizations”). CELSE’s authorization expires in November 2050, and CELBA’s authorization, which is in the process of being granted, is expected to expire in 2055. ANEEL may impose penalties on CELSE and CELBA if they fail to comply with any provision of the MME Authorizations or with the legislation and regulations applicable to the Brazilian power industry. Depending on the extent of the non-compliance, these penalties could include:

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warnings;

•	substantial fines (in some cases up to 2% of gross revenues arising from the generation activity in the 12-month period immediately preceding the assessment);

•	prohibition on operations;

•	bans on the construction of new facilities or the acquisition of new projects;

•	restrictions on the operation of existing facilities and projects; or

•	restrictions on operations (including the exclusion from participating in upcoming auctions), temporary suspension of participation in auctions and bidding processes for new concessions and authorizations.

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ANEEL may also terminate the MME Authorizations prior to their expiration in the event that CELSE or CELBA fails to comply with the provisions of the MME Authorizations, is declared bankrupt or is dissolved. In the event of non-compliance by CELSE and/or CELBA, ANEEL may also impose certain of the penalties (in particular, bans and restrictions) on affiliates of CELSE and CELBA.

CELSE and CELBA are subject to extensive legislation and regulations imposed by the Brazilian government and ANEEL, and cannot predict the effect of any changes to the legislation or regulations currently in force regarding their respective businesses.

The implementation of our business strategy and our ability to carry out our activities may be adversely affected by certain governmental actions.

We may be subject to new regulations enacted by the Brazilian government that could retroactively affect the rules for renewal of our concessions and authorizations.

The non-renewal of any of our authorizations, as well as the non-renewal of our energy supply contracts, could have a material adverse effect on our financial condition, results of operations and our capacity to fulfill our contractual obligations.

The regulatory framework under which we operate is subject to legal challenge.

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the Lei do Novo Modelo do Setor Elétrico, or New Regulatory Framework. Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed. It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our business and results of operations. Due to the duration of the lawsuit, it is possible that the Brazilian Federal Supreme Court will not give retroactive effect to its decision, but rather preserve the validity of past acts applying a judicial practice known as modulation of effects.

If the regulatory framework under which we operate is revised in a way that results in us being required to conduct our business in a manner substantially different from our current operations, our operations, financial results and our capacity to fulfill our contractual obligations may be adversely affected.

Commercialization activity is subject to potential losses due to short-term variations in energy prices on the spot market.

Sellers in the Free Market are subject to potential differences in the settlement between the energy delivered and the energy sold, and buyers in the Free Market are subject to potential differences in the settlement between the energy consumed and the energy acquired. The differences are settled by the CCEE at the spot price, or the PLD. The PLD is based on the energy traded in the spot energy market. It is calculated for each submarket and load level on a weekly basis and is based on the marginal cost of operation. The maximum and the minimum value of the PLD are set every year by ANEEL. Short-term variations in energy prices on the spot energy market may lead to potential losses in our commercialization activity.

We are uncertain as to the review of the Physical Guarantee of our generation power plants.

The “Physical Guarantee” is the amount of power that a plant is expected to contribute to the electricity grid over the life of a PPAs. We cannot be certain if future events could affect the Physical Guarantee of each of our individual power plants. When the Physical Guarantee of a power plant is decreased, our ability to supply electricity under that plant’s PPAs is adversely affected, which can lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere.

We are subject to environmental, health and safety regulations that may become more stringent in the future and may result in increased liabilities and increased capital expenditures.

Our activities are subject to comprehensive and changing international, federal, state and municipal legislation, rules, regulations and agreements which impose the need to obtain and maintain licenses, as well as regulation and supervision by international organizations and Brazilian governmental agencies that are

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responsible for the implementation of environmental, health and safety laws and policies. Such laws and regulations, among other things, govern response to and liability for oil spills, discharges to air and water, and the handling and disposal of hazardous substances and wastes. In some cases, these laws and regulations require us to obtain governmental permits and authorizations before we may conduct activities.

Governmental agencies could take enforcement action against us for failure to comply with their regulations, or to obtain or maintain licenses. These actions could include, among other things, the imposition of administrative and criminal sanctions, including fines and revocation of licenses, or the suspension or termination of our operations, including, in certain instances, seizure or detention of our vessels. The sanctions depend on the seriousness of the infraction or on the extent of damage caused, and any mitigating or aggravating circumstances applicable to the violator. It is possible that enhanced environmental and health regulations will force us to allocate capital expenditures to compliance, and consequently, increase our level of investment or divert funds from existing planned investments, either of which could have a material adverse effect on our financial condition and results of operations.

There are various risks associated with greenhouse gases and climate change that could result in increased operating costs and reduced demand for the energy we produce.

Climate change continues to attract considerable attention in the United States, Brazil, and other foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases (“GHGs”) as well as to restrict or eliminate such future emissions. As a result, our operations are subject to a series of regulatory, litigation and financial risks associated with the transport of petroleum products and emission of GHGs.

In 2009, Brazil implemented the National Policy on Climate Change, which establishes a framework for reduction of GHGs. However, this does not include a mandatory emissions trading regime, carbon tax, or other such regulatory mechanism to enforce reductions of emissions across the country. Much of this reduction is expected to be achieved through reduced deforestation and increased supplies of renewable energy. It is not possible to know how quickly renewable energy technologies may advance, but the increased use of renewable energy for any reason could ultimately reduce future demand for hydrocarbons and energy produced from them. These developments could ultimately have a material adverse effect on our financial position, results of operations and cash flows. Additionally, various states and local governments have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding individually determined reduction goals every five years after 2020. As a party to the agreement, Brazil intends to reduce GHG emissions by 37% below 2005 levels by 2025.

There are also increasing risks of litigation related to climate change effects. In the United States, governments and third-parties have brought suit against some fossil fuel companies alleging, among other things, that such companies are liable for damages due to their production and marketing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Such cases could also adversely impact public perception and the demand for fossil fuels and petroleum products.

There are also increasing financial risks for fossil fuel producers as shareholders who are currently invested in fossil-fuel energy companies but are concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Our own operations could also face limitations on access to capital as a result of these trends, which could adversely affect our business and results of operations.

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The adoption and implementation of any Brazilian, international or foreign federal, state or local legislation or regulations imposing obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with our operations. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in legislative or regulatory policies that make hydrocarbon products more expensive to consume may reduce demand for the energy we provide. These developments could have a material adverse effect on our financial position, results of operations and cash flows. Additionally, litigation and financial risks may result in curtailed gas supply, incurred liability, or other adverse effects on our business, financial condition and results of operations.

Our operations could be limited or restricted in order to comply with protections for indigenous populations located in the areas in which we operate, and could also be adversely impacted by any changes in Brazilian law to comply with certain requirements embodied in international treaties and other laws related to indigenous communities.

Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. There are several indigenous communities that surround our operations in Brazil. We have entered into agreements with some of these communities that mainly provide for the use of their land for our operations, and negotiations with other such communities are ongoing. In the event that we are unable to reach an agreement with indigenous communities, that our relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to our operations, it could have a material adverse effect on our business and results of operations.

Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which is grounded on the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). ILO Convention 169 sets forth that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations such as are required for our operations, are consulted through appropriate procedures and through their representative institutions. ILO Convention 169 further states that the consultation must be undertaken aiming at achieving an agreement or consent to the proposed legislative or administrative measures.

Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for 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: the National Congress (in specific cases), the Federal Public Prosecutor's Office and the National Indian Foundation (Fundação Nacional do Índio or FUNAI) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities). If 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, we could face construction delays, increased costs, or otherwise experience adverse impacts on our business and results of operations.

Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact our 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

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their territory and the removal of the 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 our negotiations for outstanding development agreements with indigenous communities in the areas in which we operate. However, if the consultations with indigenous communities potentially impacted by our operations are found to be insufficient, we could experience a material adverse impact to our business and results of operations.

Changes in legislation and regulations, which occur frequently in developing countries like Brazil, could have a material adverse impact on our business, results of operations, financial condition, liquidity and prospects.

Our business is subject to governmental laws, rules, regulations and requires permits that impose various restrictions and obligations that may have material effects on our results of operations. In addition, each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the international, federal, state or local level, or by new or modified regulations that may be implemented under existing law. Emerging countries in particular are characterized by frequent legislative and regulatory change, creating uncertainty for businesses who operate in such jurisdictions. The nature and extent of any changes in these laws, rules, regulations and permits may be unpredictable 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 the storage, or regasification of LNG, or its transportation 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. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have an adverse effect on our business, the ability to expand our business, including into new markets, results of operations, financial condition, liquidity and prospects.

Our vessels operating in international waters, now or in the future, will be subject to various international and local laws and regulations relating to protection of the environment.

Our chartered vessels’ operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, and the handling and disposal of hazardous substances and wastes. 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 (“ECAs”) 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 Operation of Ships and for Pollution Prevention (the “ISM Code”), 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.

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, the IMO has promulgated regulations limiting the sulphur content of fuel oil for ships to 0.5 weight percent starting January 1, 2020. We contract with 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 Brazilian 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 waste handling

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and disposal, site remediation, and water and air quality, among others. Any operations in other jurisdictions may be subject to analogous laws. 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, administrative 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.

Compliance with safety and other vessel requirements imposed by classification societies may be very costly and may adversely affect our business.

The hull and machinery of every large, oceangoing commercial vessel must be classed by a classification society authorized by its country of registry. The classification society certifies that a vessel is safe and seaworthy in accordance with the applicable rules and regulations of the country of registry of the vessel and the Safety of Life at Sea Convention. All vessels in our current fleet are each certified by DNV GL.

As part of the certification process, a vessel must undergo annual surveys, intermediate surveys and special surveys. In lieu of a special survey, a vessel’s machinery may be on a continuous survey cycle, under which the machinery is surveyed periodically over a five-year period. Each of the vessels in our existing fleet is on a planned maintenance system approval, and as such the classification society attends on board once every year to verify that the maintenance of the equipment on board is done correctly. Each of the vessels in our existing fleet is required to be qualified within its respective classification society for dry-docking once every five years subject to an intermediate underwater survey done using an approved diving company in the presence of a surveyor from the classification society.

If any vessel does not maintain its class or fails any annual survey, intermediate survey or special survey, the vessel will be unable to trade between ports and will be unemployable. We would lose revenue while the vessel was off-hire and incur costs of compliance, which would negatively impact our results of operations.

Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operation of our facilities could impede operations and construction and could have a material adverse effect on us.

The design, construction and operation of energy-related infrastructure, including our existing and proposed facilities, the import and export of LNG and the transportation of natural gas, are highly regulated activities at the federal, state and local levels. Approvals of the Brazilian Ministry of Mines and Energy (“MME”) under Article 7 of the Law No. 9,074/1995, as well as several other material governmental and regulatory permits, approvals and authorizations, including under federal environmental laws and their state analogues, may be required in order to construct and operate a gas-powered thermoelectric plant. Permits, approvals and authorizations obtained from the MME, ANEEL, ANP, ANTAQ and other federal and state regulatory agencies also contain ongoing conditions, and additional requirements may be imposed. Certain federal permitting processes may trigger a requirement to undergo detailed and time-consuming assessments and technical studies for any actions that have the potential to significantly impact the environment. Compliance with such processes 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 any required analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. We may also be subject to analogous and additional requirements in other jurisdictions, including with respect to land use approvals needed to construct and operate our facilities.

We cannot control the outcome of any review and approval process, including whether or when any such permits, approvals 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, approvals and authorizations or the terms thereof. If we are unable to obtain and maintain such permits, approvals and authorizations on favorable terms, we may not be able to recover our investment in our projects. 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. There is no assurance that we will obtain and maintain these governmental permits, approvals and

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authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects. Moreover, these permits, approvals and authorizations could be subject to administrative and judicial challenges, which could delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty.

We are subject to numerous governmental laws and trade and economic sanctions laws and regulations. A failure by us to comply with such laws and regulations could subject us to liability and have a material adverse impact on our business, results of operations or financial condition.

We conduct business throughout the world and our business activities and services are subject to various applicable laws and regulations of the U.K. and other countries. Although we take precautions to comply with all such laws and regulations, violations of governmental control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal, administrative 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.

We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”) and the Bribery Act 2010 of the United Kingdom (“UK Bribery Act”), 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. We are also subject to Law No. 12.846/2013, a Brazilian statute (the “Clean Company Act”), which generally prohibits companies and their intermediaries from making improper payments to foreign or local officials whether or not such payments are for the purpose of obtaining or keeping business and/or other benefits. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, the UK Bribery Act and the Clean Company Act, 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, the UK Bribery Act and the Clean Company Act, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire. If we are not in compliance with anti-corruption laws and regulations, including the FCPA, the UK Bribery Act and the Clean Company Act, we may be subject to criminal, civil and administrative penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, as well as potential personnel change and disciplinary actions, which could have an adverse impact on our business, results of operations and financial condition.

In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries, such as customs agents. Violations of applicable trade and economic sanctions laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with economic sanctions, laws and regulations in the future. In such event of non-compliance, our business and results of operations could be adversely impacted.

Changing corporate laws and reporting requirements could have an adverse impact on our business.

Changing laws, regulations and standards could create greater reporting obligations and compliance requirements on companies such as ours. Whilst the regulatory environment continues to evolve, we have invested in, and intend to continue to invest in, reasonably necessary resources to comply with evolving standards and maintain high standards of corporate governance and public disclosure. Recent examples of increased regulation include the UK Modern Slavery Act 2015 and the GDPR. The GDPR, for instance, broadens the scope of personal privacy laws to protect the rights of European Union citizens and requires organizations to report on data breaches within 72 hours and be bound by more stringent rules for obtaining the consent of individuals on how their data can be used.

Non-compliance with such regulation could result in governmental or other regulatory claims or significant fines that could have an adverse effect on our business, financial condition, results of operations and cash flows.

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Risks Relating to the Jurisdictions in Which We Operate

We are currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil and the other jurisdictions in which we operate.

We currently conduct a meaningful portion of our business in Brazil. As a result, our current business, results of operations, financial condition and prospects are materially dependent upon economic, political and other conditions and developments in Brazil. For example, on July 8, 2019, Petróleo Brasileiro S.A. – Petrobras (“Petrobras”) the state-owned oil company in Brazil, entered into an agreement (Termo de Compromisso de Cessão de Prática) with Brazilian antitrust authorities (Conselho Administrativo de Defesa Econômica - CADE) pursuant to which it has agreed to divest its equity participation in the gas pipelines and state gas distribution companies in Brazil by December 31, 2021. Such divestment plan, intended to end Petrobras’s monopoly on the distribution of gas in Brazil, will increase competition and may affect our business.

We currently have interests and operations in Brazil and currently intend to expand into additional markets in Latin America, Southeast Asia, the Indian Subcontinent, West Africa and Europe, and such interests are subject to governmental regulation in each market. The governments in these markets differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. Weaknesses in legal systems and legislation in many of these countries create uncertainty for investments and business due to changing requirements that may be costly, incoherent and contradictory, limited budgets for judicial systems, questionable judicial interpretations and/or inadequate regulatory regimes. To the extent that our operations depend on governmental approval and regulatory decisions, the operations may be adversely affected by changes in the political structure or government representatives in each of the markets in which we operate. Recent political, security and economic changes have resulted in political and regulatory uncertainty in certain countries in which we operate or may pursue operations. Changes in legislative and regulatory provisions in these countries, which we may not be able to anticipate, could have a material adverse effect on our business, financial condition, results of operations and prospects.

Furthermore, government authorities have a high degree of discretion in many of the markets in which we currently operate, and have sometimes exercised their discretion in ways that may be perceived as selective or arbitrary, or in a manner that could be seen as being influenced by political or commercial considerations. Moreover, many of the governments in the countries in which we currently operate have the power in certain circumstances, by regulation or other government action, to interfere with the performance of contracts or to terminate them or declare them null and void. Governmental actions may include withdrawal of licenses, withholding of permits, criminal prosecutions and civil actions. In some countries, when the economic environment has deteriorated and in order to compensate for the resulting revenue shortages, authorities have imposed new regulations, in particular relating to tax and customs duties, sometimes unexpectedly. There is no guarantee that legislative authorities in the countries in which we currently operate will not pass new laws or regulations or amend existing laws and regulations in a manner that would significantly negatively impact our business model or may even render our business model no longer viable.

Some of these countries have experienced political, security and economic instability in the recent past and may experience instability in the future. Any slowdown or contraction affecting the local economy in a jurisdiction in which we operate could negatively affect the ability of our customers to purchase LNG, natural gas, steam or power from us or to fulfill their obligations under their contracts with us. If the economy in Brazil or other jurisdictions in which we operate worsens because of, for example:

•	lower economic activity;

•	an increase in oil, natural gas or petrochemical prices;

•	liquidity of domestic capital and lending markets;

•	devaluation of the applicable currency;

•	higher inflation; or

•	an increase in domestic interest rates,

then our business, results of operations, financial condition and prospects may also be significantly affected by actions taken by the government in the jurisdictions in which we operate.

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In particular, the Brazilian economy has been characterized by frequent and occasionally extensive intervention by the Brazilian government and unstable economic cycles. The Brazilian government has often changed monetary, taxation, credit, tariff and other policies to influence the course of Brazil’s economy. The Brazilian government’s actions to control inflation and implement other policies have at times involved wage and price controls, blocking access to bank accounts, imposing capital controls and limiting imports into Brazil. In addition, Brazilian markets and politics have been characterized by considerable instability in recent years due to uncertainties derived from the ongoing corruption investigations, the conviction of Former President Luiz Inácio Lula da Silva, the impeachment of Former President Dilma Rousseff and the election of Congressman Jair Bolsonaro. The spread of COVID-19 in Brazil has resulted in heightened uncertainty and political instability as government officials debate appropriate response measures. These uncertainties and any measures adopted by the new administration may increase market volatility and political instability.

Due to the locations in which we operate or plan to operate, a number of our current and potential future projects are subject to a number of uncertainties, including higher political and security risks than operations in other areas of the world.

We operate in, or are pursuing projects which could lead to future operations in, areas of the world where there are significant uncertainties, including those we have not yet considered and heightened political and security risks. We identify higher risk countries in which we operate through our experiences, the experiences of our partners and publicly available third party information such as Transparency International, the World Bank and TRACE International, and monitor the specific risks associated with countries in which we operate. Our operations may be subject to higher political and security risks than operations in other areas of the world. Any extreme levels of political instability resulting in changes of governments, internal conflict, unrest and violence could lead to economic disruptions and shutdowns in industrial activities.

In addition, we may maintain insurance coverage for only a portion of the risks incidental to doing business in higher risk countries. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. For example, any claims covered by insurance will be subject to deductibles, which may be significant. In the event that we incur business interruption losses with respect to one or more incidents, they could have a material adverse effect on our results of operations.

Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.

Our consolidated financial statements are presented in U.S. dollars. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars will impact our reported consolidated financial condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars.

A portion of our cash flows and expenses may in the future be incurred in currencies other than the U.S. dollar. Our material counterparties’ cash flows and expenses may be incurred in currencies other than the U.S. dollar. We cannot be sure 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. As a result, our expenses may, from time to time, increase relative to our revenues as a result of fluctuations in exchange rates, particularly between the U.S. dollar and the Brazilian real, which could affect the amount of net income that we report in future periods. Depreciation or volatility of any of these currencies against the U.S. dollar or other currencies could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us, which could also affect the amount of net income that we report in future periods.

Risks Inherent in an Investment in Us

Our Sponsors have the ability to direct the voting of a majority of our shares, and its interests may conflict with those of our other shareholders.

Upon completion of this offering, the Sponsors will initially own an aggregate of 100,000,000 common shares representing approximately 81.2% of our voting power (or approximately 79.0% if the underwriters’ option to purchase additional common shares is exercised in full). The Sponsors’ beneficial ownership of greater than 50% of our voting shares means the Sponsors will be able to control matters requiring shareholder approval, including the election of directors, changes to our organizational documents and significant corporate

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transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common shares will be able to affect the way we are managed or the direction of our business. The interests of the Sponsors 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 shareholders.

Furthermore, in connection with this offering, we will enter into a Shareholders’ Agreement with the Sponsors. The Shareholders’ Agreement will provide the Sponsors with the right to designate a certain number of nominees to our board of directors so long as the Sponsors and their respective affiliates collectively beneficially own at least 5% of the outstanding common shares. See “Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions—Shareholders’ Agreement.”

Given this concentrated ownership, the Sponsors would have to approve any potential acquisition of us. The existence of a significant shareholder 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 shareholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the Sponsors’ concentration of share ownership may adversely affect the trading price of our common shares to the extent investors perceive a disadvantage in owning shares of a company with a significant shareholder.

In addition, the Sponsors may have different tax positions from us that could influence their decisions regarding whether and when to support the disposition of assets and the incurrence or refinancing of new or existing indebtedness. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the Sponsors’ tax or other considerations, which may differ from our considerations or those of our other shareholders.

The Sponsors may compete with us.

The Sponsors are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, the Sponsors may compete with us for investment opportunities and may own an interest in entities that compete with us. Additionally, our governing documents will provide that if any of our officers or directors who are affiliates of the Sponsors or any of their respective affiliates acquire knowledge of a potential transaction that could be a corporate opportunity, they have no duty, to the fullest extent permitted by law, to offer such corporate opportunity to us, our common shareholders or our affiliates. This may create actual and potential conflicts of interest between us and the Sponsors and result in less than favorable treatment of us and our common shareholders.

Our officers may face conflicts in the allocation of their time to our business.

We do not currently have any of the executive officers who manage our business on our payroll, as we currently rely on third-party arrangements. Mr. Antonello, our Chief Executive Officer, is currently employed by Magni Partners (Bermuda) Limited (“Magni Bermuda”) and provides services to us pursuant to a secondment agreement we have entered into with Magni Bermuda. Mr. Maranhão, our Chief Financial Officer, is currently employed by Golar Management and provides services to us pursuant to a management and administrative services agreement that we have entered into with Golar Management. Our officers, who are employed by Magni Bermuda and Golar Management, are not required to work full-time on our affairs and also perform services for affiliates of their respective employers, which conduct substantial businesses and activities of their own in which we have no economic interest. However, because our Chief Executive Officer and Chief Financial Officer currently expend substantially all of their time on the business and affairs of Hygo, we are in the process of entering into direct employment arrangements with Messrs. Antonello and Maranhão to provide for full time dedication to their work for us as a result of their increasing responsibility and actual expenditure of time. Until those agreements are finalized, there could be competition for the time and effort of our officers. Further, as we expand our operations, we will require more of our management and will need not only to replace the current arrangement with full time commitments but also expand our team beyond those supplied by Magni Bermuda and Golar Management. If we are unable to maintain access to the time and effort of our officers or are otherwise unable to develop our management team it could have a material adverse effect on our business, results of operations and financial condition. Please read “Management.”

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Fees and cost reimbursements, which Golar Management will determine for services provided to us and certain of our subsidiaries, will be substantial and will be payable regardless of our profitability.

Pursuant to a management and administrative services agreement, Golar Management will provide us with significant management, administrative, financial and other support services. We will reimburse Golar Management for its reasonable costs and expenses incurred in connection with the provision of these services. In addition, we will pay Golar Management a management fee equal to 5% of its costs and expenses incurred in connection with providing services to us. We expect that we will pay Golar Management approximately $7 million in total under the management and administrative services agreement for the twelve months ending December 31, 2020.

For a description of the management and administrative services agreement, please read “Certain Relationships and Related Transactions.” The fees and expenses payable pursuant to the management and administrative services agreement will be payable without regard to our financial condition or results of operations.

Because we are a Bermuda exempted company, our shareholders may have less recourse against us or our directors than shareholders of a U.S. company have against the directors of that U.S. company.

Because we are a Bermuda exempted company, the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders in other jurisdictions, including with respect to, among other things, rights related to interested directors, amalgamations, mergers and acquisitions, takeovers, the exculpation and indemnification of directors and shareholder lawsuits.

Among these differences is a Bermuda law provision that permits a company to exempt a director from liability for any negligence, default or breach of a fiduciary duty except for liability resulting directly from that director’s fraud or dishonesty. Our bye-laws will provide that no director or officer shall be liable to us or our shareholders unless the director’s or officer’s liability results from that person’s fraud or dishonesty. Our bye-laws will also require us to indemnify a director or officer against any losses incurred by that director or officer resulting from their negligence or breach of duty, except where such losses are the result of fraud or dishonesty. Accordingly, we carry directors’ and officers’ insurance to protect against such a risk.

In addition, under Bermuda law, the directors of a Bermuda company owe their duties to that company and not to the shareholders. Bermuda law does not, generally, permit shareholders of a Bermuda company to bring an action for a wrongdoing against the company or its directors, but rather the company itself is generally the proper plaintiff in an action against the directors for a breach of their fiduciary duties. Moreover, class actions and derivative actions are generally not available to shareholders under Bermuda law. These provisions of Bermuda law and our bye-laws, as well as other provisions not discussed here, may differ from the law of jurisdictions with which shareholders may be more familiar and may substantially limit or prohibit a shareholder’s ability to bring suit against our directors or in the name of the company. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it.

It is also worth noting that under Bermuda law, our directors and officers are required to disclose to our board any material interests they have in any contract entered into by our company or any of its subsidiaries with third parties. Our directors and officers are also required to disclose their material interests in any corporation or other entity which is party to a material contract with our company or any of its subsidiaries. A director who has disclosed his or her interests in accordance with Bermuda law may participate in any meeting of our board, and may vote on the approval of a material contract, notwithstanding that he or she has a material interest.

Bermuda law differs from the laws in effect in the United States and may afford less protection to holders of our common shares.

We are incorporated under the laws of Bermuda. As a result, our corporate affairs are governed by the Companies Act, which differs in some material respects from laws typically applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, amalgamations, mergers and acquisitions, takeovers,

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shareholder lawsuits and indemnification of directors. Generally, the duties of directors and officers of a Bermuda company are owed to the company only. Shareholders of Bermuda companies may only take action against directors or officers of the company in limited circumstances. The circumstances in which derivative actions may be available under Bermuda law are substantially more proscribed and less clear than they would be to shareholders of U.S. corporations. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it.

When the affairs of a company are being conducted in a manner that is oppressive or prejudicial to the interests of some shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. In addition, the rights of holders of our common shares and the fiduciary responsibilities of our directors under Bermuda law are not as clearly established as under statutes or judicial precedent in existence in jurisdictions in the United States, particularly the State of Delaware. Therefore, holders of our common shares may have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction within the United States.

We have anti-takeover provisions in our bye-laws that may discourage a change of control.

Our bye-laws will contain provisions that could make it more difficult for a third-party to acquire us without the consent of our board of directors, including the ability of our board of directors to determine the powers, preferences and rights of preference shares and to cause us to issue the preference shares without shareholder approval.

These provisions could make it more difficult for a third-party to acquire us, even if the third-party’s offer may be considered beneficial by many shareholders. As a result, shareholders may be limited in their ability to obtain a premium for their common shares. See “Description of Share Capital” for a discussion of these provisions.

Because our offices and assets are outside the United States, our shareholders may not be able to bring a suit against us or enforce a judgment obtained against us in the United States.

We, and most of our subsidiaries, are incorporated in jurisdictions outside the U.S. and substantially all of our assets and those of our subsidiaries are located outside the U.S. In addition, most of our directors and officers are non-residents of the U.S., and all or a substantial portion of the assets of these non-residents are located outside the U.S. As a result, it may be difficult or impossible for U.S. investors to serve process within the U.S. upon us, our subsidiaries, or our directors and officers or to enforce a judgment against us for civil liabilities in U.S. courts. In addition, you should not assume that courts in the countries in which we or our subsidiaries are incorporated or where our or our subsidiaries’ assets are located would enforce judgments of U.S. courts obtained in actions against us or our subsidiaries based upon the civil liability provisions of applicable U.S. federal and state securities laws, or would enforce, in original actions, liabilities against us or our subsidiaries based on those laws.

Shareholders will experience immediate and substantial dilution of $14.25 per common share based on the midpoint of the price range set forth on the cover of this prospectus.

The initial public offering price of $19.50 per common share (the midpoint of the price range set forth on the cover of this prospectus) exceeds our pro forma as adjusted net tangible book value of $5.25 per common share. Based on the initial public offering price of $19.50 per common share (the midpoint of the price range set forth on the cover of this prospectus), shareholders will incur immediate and substantial dilution of $14.25 per common share in the pro forma as adjusted net tangible book value per share. Please read “Dilution.”

We do not intend to pay cash dividends on our common shares. Consequently, your only opportunity to achieve a return on your investment is if the price of our common shares appreciates.

We do not plan to declare cash dividends on our common shares in the foreseeable future. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common shares at a price greater than you paid for them. There is no guarantee that the price of our common shares that will prevail in the market will ever exceed the price that you pay in this offering.

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We may issue preferred shares, the terms of which could adversely affect the voting power or value of our common shares.

Our bye-laws will authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred shares having such designations, preferences, limitations and relative rights, including preferences over our common shares respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred shares could adversely impact the voting power or value of our common shares. For example, we might grant holders of preferred shares 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 shares could affect the residual value of the common shares.

The market price of our common shares could be adversely affected by sales of substantial amounts of our common shares in the public or private markets or the perception in the public markets that these sales may occur, including sales by the Sponsors or other large holders.

After this offering, we will have 123,100,000 common shares outstanding, assuming no exercise of the underwriters’ option to purchase additional common shares. The common shares sold in this offering will be freely tradable without restriction under the Securities Act except for any common shares that may be held or acquired by our directors, officers or affiliates, which will be restricted securities under the Securities Act. The common shares held by the Sponsors will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by the Sponsors or other large holders of a substantial number of our common shares in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common shares or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to the Sponsors. Please read “Shares Eligible for Future Sale.”

There is no existing market for our common shares and a trading market that will provide you with adequate liquidity may not develop. The price of our common shares may fluctuate significantly, and shareholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common shares. After this offering, there will be only 23,100,000 publicly traded common shares (assuming the underwriters’ option to purchase additional common shares is not exercised). We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Common shareholders may not be able to resell their common shares at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common shares and limit the number of investors who are able to buy the common shares.

The initial public offering price for our common shares will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the price of the common shares that will prevail in the trading market. The market price of our common shares may decline below the initial public offering price. The market price of our common shares may also be influenced by many factors, some of which are beyond our control, including:

•	our quarterly or annual earnings or those of other companies in our industry;

•	announcements by us or our competitors of significant contracts or acquisitions;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	general economic conditions;

•	the failure of securities analysts to cover our common shares after this offering or changes in financial estimates by analysts;

•	future sales of our common shares; and

•	the other factors described in these “Risk Factors.”

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We expect to be a “controlled company” within the meaning of NASDAQ rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Upon completion of this offering, the Sponsors will hold a majority of the voting power of our shares. As a result, we expect to be a controlled company within the meaning of 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. Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of NASDAQ. See “Management.”

As an exempted company incorporated under Bermuda law, we are permitted to adopt certain home country practices in relation to corporate governance matters that differ significantly from the NASDAQ listing standards; these practices may afford less protection to shareholders than they would enjoy if we complied fully with the NASDAQ listing standards.

As a Bermuda exempted company listed on the Nasdaq Global Select Market, we are subject to the Nasdaq Stock Market corporate governance listing standards. However, the Nasdaq Stock Market Rules permit a foreign private issuer like us to follow the corporate governance practices of its home country. Certain corporate governance practices in Bermuda, which is our home country, may differ significantly from the Nasdaq Stock Market corporate governance listing standards. We may rely on home country practice with respect to our corporate governance after we complete this offering. If we choose to follow home country practice in the future, our shareholders may be afforded less protection than they otherwise would enjoy under the Nasdaq Stock Market corporate governance listing standards applicable to U.S. domestic issuers.

As an exempted company incorporated under Bermuda law, our operations may be subject to economic substance requirements.

The Economic Substance Act 2018 and the Economic Substance Regulations 2018 of Bermuda (the “Economic Substance Act” and the “Economic Substance Regulations”, respectively) became operative on December 31, 2018. The Economic Substance Act applies to every registered entity in Bermuda that engages in a relevant activity and requires that every such entity shall maintain a substantial economic presence in Bermuda. A relevant activity for the purposes of the Economic Substance Act is banking business, insurance business, fund management business, financing business, leasing business, headquarters business, shipping business, distribution and service center business, intellectual property holding business and conducting business as a holding entity.

The Economic Substance Act provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (a) it is directed and managed in Bermuda, (b) its core income-generating activities (as may be prescribed) are undertaken in Bermuda with respect to the relevant activity, (c) it maintains adequate physical presence in Bermuda, (d) it has adequate full time employees in Bermuda with suitable qualifications and (e) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity.

A registered entity that carries on a relevant activity is obliged under the Economic Substance Act to file a declaration in the prescribed form (the “Declaration”) with the Registrar of Companies (the “Registrar”) on an annual basis.

If we fail to comply with our obligations under the Economic Substance Act or any similar law applicable to us in any other jurisdictions, we could be subject to financial penalties and spontaneous disclosure of

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information to foreign tax officials in related jurisdictions and may be struck from the register of companies in Bermuda or such other jurisdiction. Any of these actions could have a material adverse effect on our business, financial condition and results of operations.

We are a foreign private issuer within the meaning of the SEC rules, and as such we are exempt from certain provisions applicable to U.S. domestic public companies.

Because we qualify as a foreign private issuer under the Exchange Act, we are exempt from certain provisions of the securities rules and regulations in the United States that are applicable to U.S. domestic issuers, including:

•	the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q or current reports on Form 8-K;

•	the sections of the Exchange Act regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act;

•	the sections of the Exchange Act requiring insiders to file public reports of their stock ownership and trading activities and liability for insiders who profit from trades made in a short period of time; and

•	the selective disclosure rules by issuers of material nonpublic information under Regulation FD.

We will be required to file an annual report on Form 20-F within four months of the end of each fiscal year. In addition, we intend to publish our results on a quarterly basis as press releases, distributed pursuant to the rules and regulations of the Nasdaq Global Select Market. Press releases relating to financial results and material events will also be furnished to the SEC on Form 6-K. However, the information we are required to file with or furnish to the SEC will be less extensive and less timely compared to that required to be filed with the SEC by U.S. domestic issuers. As a result, you may not be afforded the same protections or information that would be made available to you were you investing in a U.S. domestic issuer.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosures regarding executive compensation required of larger public companies, or (iv) hold nonbinding advisory votes on executive compensation. We currently intend to take advantage of the exemptions described above. We have also elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(2) of the JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result, our consolidated financial statements may not be comparable to companies that comply with public company effective dates, and our shareholders and potential investors may have difficulty in analyzing our operating results if comparing us to such companies. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common shareholders held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common shares to be less attractive as a result, there may be a less active trading market for our common shares and our common share price may be more volatile.

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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 shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common shares.

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 our efforts to develop and maintain our internal controls will be successful, 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. In connection with our efforts to maintain effective internal controls, we will need to hire additional accounting personnel as well as to make additional investments in software and systems. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common shares.

We will incur increased costs as a result of being a public company.

We have no history operating as a publicly traded company. As a newly public company with shares listed on NASDAQ, we will need to comply with an extensive body of regulations that did not apply to us previously, including certain provisions of the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, regulations of the SEC and NASDAQ requirements. We expect these rules and regulations will increase our legal, accounting, compliance and other expenses that we did not incur prior to this offering and make some activities more time-consuming and costly. For example, as a result of becoming a public company, we intend to add independent directors and create additional board committees. We have entered into a management and administrative services agreement with Golar Management, an affiliate of Golar LNG, pursuant to which Golar Management provides us with certain back office and management services for the vessels in our fleet and charge us for the expenses incurred to provide these services. Golar Management will also continue to provide compliance services for the foreseeable future and any transition will take place over time. In addition, we may incur additional costs associated with our public company reporting requirements and maintaining directors’ and officers’ liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers. We estimate that we will incur approximately $3 million of incremental costs per year associated with being a publicly traded company; however, it is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate. We are currently evaluating and monitoring developments with respect to these rules, which may impose additional costs on us and 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 common shares or if our operating results do not meet their expectations, our share price could decline.

The trading market for our common shares 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.

Tax Risks

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.

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U.S. tax authorities could treat us as a “passive foreign investment company”, which could have adverse U.S. federal income tax consequences to U.S. shareholders.

A foreign corporation will be treated as a “passive foreign investment company” (a “PFIC”), for U.S. federal income tax purposes if, after applying certain look-through rules with respect to the income and assets of its subsidiaries, either (i) at least 75% of its gross income during the taxable year consists of “passive income” or (ii) the average percentage by value of the corporation’s assets during such taxable year that produce or are held for the production of “passive income” is at least 50%. For purposes of these tests, “passive income” includes dividends, interest, gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute “passive income.” U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC, and the gain, if any, they derive from the sale or other disposition of their shares in the PFIC.

Based on our current and expected future method of operation, and on the opinion of Vinson & Elkins L.L.P., our U.S. counsel, we expect that we will not be treated as a PFIC for the current or any subsequent year. We have represented to our U.S. counsel that more than 25% of our gross income for each year was or will be income that our U.S. counsel has opined, based on current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations promulgated thereunder (“Treasury Regulations”) and current administrative rulings and court decisions, should be non-passive income and that the average percentage by value of our assets for each year that produce or are held for the production of such non-passive income is at least 50%. Our U.S. counsel’s opinion is based on certain representations, valuations and projections regarding our income and assets and is conditioned on the accuracy of such representations, valuations and projections. While we believe such representations, valuations and projections to be accurate, no assurance can be given that they will be accurate in the future. In addition, although there is substantial legal authority supporting our position consisting of case law and U.S. Internal Revenue Service (“IRS”) pronouncements concerning the characterization of income derived from time charters and voyage charters as services income for other tax purposes, there is also case law which characterizes certain time charter income as rental income rather than services income for other tax purposes. If the reasoning of this case law were extended to the PFIC context, the gross income we derive or are deemed to derive from our time chartering activities might be treated as rental income, and we might be deemed a PFIC.

As described above, we indirectly own a 50% interest in CELSE, which recently completed construction of a gas-powered power plant, and expect to invest in additional power plants in the future. We believe the gross income we are deemed to derive pursuant to the applicable look-through rules from the generation and sale of power is active business income and does not constitute “passive income” under the PFIC provisions of the Code. Existing Treasury Regulations, however, have not been revised to address changes to the statutory provisions governing when gains from the sale of commodities are treated as giving rise to active business income. Further, the current PFIC statutory and regulatory provisions do not address how that active business income exception applies when the relevant commodities income and related activities arise in subsidiaries of the foreign corporation being tested for PFIC status. In light of that lack of guidance, there can be no assurance that the IRS or a court will agree with our position that CELSE’s income from power generation and sales qualifies for the active business income exception.

Because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because there is no controlling authority for determining whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for the current or any future taxable year. Furthermore, the PFIC rules may change, which could result in us being treated as a PFIC in the future as a result of such change in law. For example, Treasury Regulations that were recently proposed under the PFIC statutory provisions may affect the characterization of our income generated by the operation of our vessels through the Cool Pool. If such proposed Treasury Regulations are finalized, there is a risk that our Cool Pool income and assets that we currently treat as active could instead be treated as passive and we could therefore be classified as a PFIC. However, it is not currently known if, when, or the extent to which such proposed Treasury Regulations will be finalized.

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Under the PFIC rules, unless those shareholders make a certain U.S. federal income tax election (which election could itself have adverse consequences for such shareholders), such shareholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of our common shares, as if the excess distribution or gain had been recognized ratably over the shareholder’s holding period of our common shares.

We may have to pay tax on United States source income, which would reduce our earnings.

Under the Code, 50% of the gross shipping income of a vessel owning or chartering corporation that is attributable to transportation that begins or ends, but that does not both begin and end, in the U.S., is treated as U.S. source shipping income and may be subject to a 4% U.S. federal income tax without allowance for deduction (to the extent not considered to be “effectively connected” with the conduct of a U.S. trade or business as described below), unless that corporation qualifies for exemption from tax under Section 883 of the Code and the applicable Treasury Regulations promulgated thereunder. We expect that we will qualify for this statutory tax exemption beginning in the 2021 tax year. However, there are factual circumstances beyond our control that could cause us to lose the benefit of this tax exemption and thereby become subject to U.S. federal income tax on our U.S. source income. Therefore, we can give no assurances that this tax exemption will apply to us or to any of our subsidiaries.

To the extent the benefits of the Section 883 exemption are unavailable and our U.S. source shipping income or regasification and storage income is considered to be “effectively connected” with the conduct of a U.S. trade or business (as described below), any such “effectively connected” income, net of applicable deductions, would be subject to the U.S. federal corporate income tax, currently imposed at a rate of 21%. In addition, we may be subject to the 30% “branch profits” taxes on earnings effectively connected with the conduct of such trade or business, as determined after allowance for certain adjustments, and on certain interest paid or deemed paid attributable to the conduct of our U.S. trade or business. Our U.S. source shipping income would be considered “effectively connected” with the conduct of a U.S. trade or business only if:

•	we had, or were considered to have, a fixed place of business in the United States involved in the earning of our U.S. source shipping income; and

•	substantially all of our U.S. source shipping income was attributable to regularly scheduled transportation, such as the operation of a ship that followed a published schedule with repeated sailings at regular intervals between the same points for voyages that begin or end in the United States.

We believe that our vessel operations will not give rise to these conditions because we will not have, nor permit circumstances that would result in having, a fixed place of business in the United States or any vessel sailing to or from the United States on a regularly scheduled basis.

We do not expect our income we are deemed to earn from power generation activities to be considered “effectively connected” with the conduct of a U.S. trade or business, as we expect, based on our current and anticipated activities, all power generation activities will be conducted outside of the United States. See “Business—Taxation of Hygo—United States Taxation—Taxation of Operating Income” for a more detailed discussion.

Brazilian tax legislation is currently under discussion and tax reform may affect our revenues.

A bill to be voted on by the Brazilian congress would reinstate progressive taxation of dividends, while reducing progressively the taxation on corporate net income. If that bill is approved, it may affect our after-tax revenues.

Revenues derived from energy sales are subject to two monthly federal social contribution taxes that are levied on gross revenues: (i) the Contribuição para o Programa de Integração Social (the “PIS”), at a rate of 1.65%, and (ii) the Contribuição para o Financiamento da Seguridade Social (the “COFINS”), at a rate of 7.6%.

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These rates are applicable for entities subject to the non-cumulative regime, which allows the taxpayer to accrue PIS and COFINS credits with respect to eligible expenses and offset them against PIS and COFINS due on their revenue.

In addition, energy sales within a particular state are subject to the Imposto sobre Circulação de Mercadorias e Serviços (the “ICMS”), which is a state-specific value added tax. The applicable rate varies depending on the legislation of each state (usually ranging from 18% to 30%). In interstate sales, the outflow of energy is exempted from the ICMS (unless such energy is sold to non-taxpayers). Nonetheless, sellers of energy may be required to pay an amount equal to the amount of ICMS levied on the acquirer in the destination state under a substitute regime. Further discussion of rates under the PIS, COFINS, and ICMS can be found in “Taxation of Hygo—Brazilian Taxation.”

The Brazilian Federal Government recently proposed a bill that would replace the PIS and COFINS with a new tax, the Contribution on Goods and Services (“CBS”), levied at a rate of 12% on gross revenues with tax credit provisions like the PIS and COFINS.

However, there is also a constitutional amendment currently being discussed in the Brazilian congress that would abolish such taxes (including the CBS, if approved) and replace them with a single value-added tax on goods and services. This constitutional amendment or other tax legislation could affect our revenues.

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USE OF PROCEEDS

We expect to receive approximately $420.9 million of net proceeds from this offering, based upon the assumed initial public offering price of $19.50 per share (the midpoint of the price range set forth on the cover of this prospectus) and after deducting underwriting discounts and estimated offering expenses. If the underwriters exercise their option to purchase additional common shares in full, we expect the estimated net proceeds to be approximately $484.7 million. See “Underwriting.”

We intend to use the net proceeds to fund (i) $80.0 million of capital expenditures related to the Barcarena Terminal and acquiring all remaining outstanding equity interests in the Barcarena Terminal (which would give Hygo a 100% indirect equity interest in both CELBA and CELBA 2), (ii) $40.0 million of capital expenditures related to the Santa Catarina Terminal and (iii) $180.0 million to be paid to Stonepeak in redemption of the preference shares in the Recapitalization, which amount includes accrued and unpaid dividends of approximately $41.5 million. We intend to use the remaining net proceeds of $120.9 million for working capital and general corporate purposes. If the underwriters exercise their option to purchase additional common shares in full, the additional net proceeds will be approximately $63.8 million. The net proceeds from any exercise of such option will be used for general corporate purposes, including the development of future projects, such that a total of $184.7 million of the net proceeds of this offering will be used for working capital and general corporate purposes. For additional information on the Recapitalization and the terms of the preference shares, please see “Summary—Our History and Relationship with Our Sponsors” and “Description of Share Capital—Stonepeak Preference Shares.”

Pending any use, the net proceeds of this offering may be invested in short-term, interest-bearing investment-grade securities.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of June 30, 2020:

•	on an actual basis;

•

on a pro forma basis to give effect to (i) $180.0 million to be paid to Stonepeak for the redemption of the preference shares in the Recapitalization on mezzanine equity in connection with the consummation of this offering, which includes accrued and unpaid dividends. The $180.0 million to be paid to Stonepeak represents the contractual Required Return Amount for the preference shares, determined as $9.00 per share based on the redemption date, which includes the aggregate amount of approximately $41.5 million of accrued and unpaid dividends on such preference shares calculated up to the date of redemption; (ii) a subsequent 2.13-for-1 share split to be consummated after the effective date of the registration statement and prior to the consummation of the offering, which will further adjust the par value of our common shares from $1.00 to $0.46950154; (iii) the conversion of the convertible common shares into common shares upon consummation of this offering; and (iv) to reflect the settlement of the MIS which is accounted for as a capital contribution from Stonepeak, following the completion of the offering; and

•

on a pro forma as adjusted basis to give effect to the pro forma adjustments set forth above and the sale by us of common shares at an assumed initial public offering price of $19.50 per common share (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and estimated offering expenses, and the application of the proceeds from this offering, each as described under “Use of Proceeds.”

You should read this table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes contained elsewhere in this prospectus.

	As of June 30, 2020
	Actual	Pro Forma Shareholders’ equity (unaudited)⁽²⁾	Pro Forma As Adjusted⁽¹⁾
	(in thousands except share and per share data)
Cash and cash equivalents	$74,633	$—	$195,483
Total liabilities	555,575	—	516,913
Mezzanine equity
Preferred capital — 20,000,000 preferred shares, par value $5.00 per share, issued and outstanding, actual	100,000	—	—
Convertible share capital — 23,475,077 common shares, par value $1.00 per share, issued and outstanding, actual⁽³⁾	23,475	—	—
Shareholders’ equity
Share capital — 23,475,077 common shares, par value $1.00 per share, issued and outstanding, actual; 100,000,000 common shares, par value $0.46950154 per share, issued and outstanding, pro forma; 500,000,000 shares authorized, par value $0.46950154 per share, 123,100,000 outstanding, pro forma adjusted	23,475	46,950	57,795
Preferred capital — 100,000,000 preferred shares, par value $0.01 per share, authorized, none outstanding, pro forma and pro forma adjusted	—	—	—
Additional paid-in capital	527,324	584,696	994,701
Accumulated other comprehensive loss	(84,879)	(84,879)	(84,879)
Retained losses	(112,786)	(112,786)	(112,786)
Non-controlling interests	10,436	10,436	10,436
Total mezzanine and shareholders’ equity	487,045	444,417	865,267
Total liabilities, mezzanine and shareholders' equity	$1,042,620	$—	$1,382,180

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(1)

The pro forma as adjusted information discussed above is illustrative only. Our cash and cash equivalents, additional paid-in capital, total mezzanine and shareholders’ equity and total liabilities, mezzanine and shareholders’ equity following the completion of this offering are subject to adjustment based on the actual initial public offering price and other terms of this offering determined at pricing.

(2)

On a pro forma basis to give effect to (i) $180.0 million to be paid to Stonepeak for the redemption of the preference shares in the Recapitalization on mezzanine equity in connection with the consummation of this offering, which includes accrued and unpaid dividends. The $180.0 million to be paid to Stonepeak represents the contractual Required Return Amount for the preference shares, determined as $9.00 per share based on the redemption date, which includes the aggregate amount of approximately $41.5 million of accrued and unpaid dividends on such preference shares calculated up to the date of redemption; (ii) a subsequent 2.13-for-1 share split to be consummated after the effective date of the registration statement and prior to the consummation of the offering, which will further adjust the par value of our common shares from $1.00 to $0.46950154; (iii) the conversion of the convertible common shares into common shares; and (iv) to reflect the settlement of the MIS which is accounted for as a capital contribution from Stonepeak, following the completion of the offering.

(3)	Following the consummation of this offering, the common shares which comprise the convertible share capital will cease to be convertible into preference shares and will have the same rights and privileges as common shares offered hereby.

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DILUTION

Dilution is the amount by which the offering price per common share in this offering will exceed the pro forma net tangible book value per share after the offering. On a pro forma basis as of June 30, 2020, after giving effect to the offering of common shares, including the application of the net proceeds as described in “Use of Proceeds,” our net tangible book value was approximately $646.6 million, or $5.25 per common share. Purchasers of common shares in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common share for financial accounting purposes, as illustrated in the following table.

(1)	Determined by dividing the number of common shares (100,000,000 common shares) to be issued to our Sponsors into the pro forma net tangible book value of our assets and liabilities.

(2)	Determined by dividing the number of shares to be outstanding after this offering (123,100,000 common shares) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.

(3)

Assumes the underwriters’ option to purchase additional common shares from us is not exercised. If the underwriters’ option to purchase additional common shares from us is exercised in full, the immediate dilution in net tangible book value per common share to purchasers in this offering would be $13.89.

The following table summarizes, on an adjusted pro forma basis as of June 30, 2020, the total number of common shares owned by existing shareholders and to be owned by the new investors in this offering, the total consideration paid, and the average price per share paid by our existing shareholders and to be paid by the new investors in this offering, calculated before deducting of estimated discounts and commissions and offering expenses:

	Shares Acquired		Total Consideration		Average Price Per Share
	Number	%	Amount	%	Average Price Per Share
Existing shareholders⁽¹⁾⁽²⁾	100,000,000	81.2%	$46,950,154	9.4%	$0.47
Purchasers in this offering⁽²⁾	23,100,000	18.8%	450,450,000	90.6%	19.50
Total	123,100,000	100%	$497,400,154	100%

(1)	Following the completion of this offering and the Recapitalization, our Sponsors will own 100,000,000 common shares.

(2)	Assumes the underwriters’ option to purchase additional common shares from us is not exercised.

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common shares in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. 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.

Although we are incorporated in Bermuda, we are classified as a nonresident of Bermuda for exchange control purposes by the Bermuda Monetary Authority. Other than transferring Bermuda dollars out of Bermuda, there are no restrictions on our ability to transfer funds into or out of Bermuda to pay dividends to U.S. residents who are holders of our common shares or other non-resident holders of our common shares in currency other than Bermuda dollars.

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SELECTED HISTORICAL FINANCIAL DATA

The following table presents our selected historical financial data for the periods and as of the dates indicated. The selected historical financial data as of and for the years ended December 31, 2019 and 2018 was derived from the audited historical consolidated financial statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited, included elsewhere in this prospectus. The summary historical financial data as of June 30, 2020 and for the six months ended June 30, 2020 and 2019 was derived from the unaudited historical financial statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited, included elsewhere in this prospectus and which, in the opinion of management, contain all normal recurring adjustments necessary for a fair statement of the results for the unaudited interim periods and have been prepared on the same basis as the associated audited consolidated financial statements.

You should read the information set forth below together with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this prospectus. We expect our historical results of operations and cash flows, including our audited consolidated financial statements, to differ materially from our future operations and cash flows as our business and projects mature. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Historical and Anticipated Future Operating Results Will Differ Materially” for further information. Accordingly, our historical financial results are not necessarily indicative of results to be expected for any future periods.

	Six Months Ended June 30,		Year Ended December 31,
	2020	2019	2019	2018
	(in thousands except share and per share data)
Statements of Operations Data:
Operating revenues
Time charter revenues	$22,787	$14,425	$35,601	$47,968
Time charter revenues – collaborative arrangement	—	9,622	9,622	30,681
Management fees	—	—	—	83
Total operating revenues	22,787	24,047	45,223	78,732
Operating expenses
Vessel operating expenses	6,622	6,531	12,638	11,499
Voyage, charter-hire and commission expenses	770	2,882	5,912	3,160
Voyage, charter-hire and commission expenses – collaborative arrangement	—	9,825	9,825	39,836
Administrative expenses	11,849	7,285	16,126	17,652
Depreciation and amortization	5,640	5,579	11,212	11,180
Total operating expenses	24,881	32,102	55,713	83,327
Other operating income (loss)	3,714	—	1,100	—
Operating income (loss)	1,620	(8,055)	(9,390)	(4,595)
Other non-operating income (loss)
Loss on disposal of asset under development	(25,981)	—	—	—
Unrealized gain on derivative instrument	5,127	—	9,990	—
Other non-operating income	—	—	—	5,000
Net gain on loss of control of subsidiary	—	—	—	72
Total non-operating income (loss)	(20,854)	—	9,990	5,072

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	Six Months Ended June 30,		Year Ended December 31,
	2020	2019	2019	2018
	(in thousands except share and per share data)
Financial income (expense)
Interest income	10,839	489	795	1,336
Interest expense	(5,669)	—	(2)	(912)
Other financial items, net	2,011	(1,144)	(1,659)	(5,245)
Net financial income (expense)	7,181	(655)	(866)	(4,821)
Loss before equity in net losses of affiliates, income taxes and non-controlling interest	(12,053)	(8,710)	(266)	(4,344)
Income taxes	(2,522)	(33)	(4,152)	(110)
Equity in net loss of affiliates	(37,276)	(778)	(2,510)	(5,748)
Net loss	(51,851)	(9,521)	(6,928)	(10,202)
Net income attributable to non-controlling interest	(3,346)	(2,806)	(5,549)	(1,541)
Preferred dividends	(5,652)	(4,250)	(11,875)	(8,500)
Net loss attributable to common shareholders	$(60,849)	$(16,577)	$(24,352)	$(20,243)
Net loss per share – basic and diluted	$(1.30)	$(0.35)	$(0.52)	$(0.43)
Weighted average number of shares outstanding – basic and diluted	46,950,154	46,950,154	46,950,154	46,950,154

	As of June 30,	As of December 31,
	2020	2019	2018
	(in thousands)
Balance Sheet Data (at period end):
Vessels and equipment, net	$354,645	$360,143	$363,893
Total assets	1,042,620	1,154,792	1,034,129
Long-term debt	378,885	337,686	372,256
Total liabilities	555,575	570,551	434,561

	Six Months Ended June 30,		Year Ended December 31,
	2020	2019	2019	2018
	(in thousands)
Statements of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$11,724	$15,854	$13,755	$(12,947)
Investing activities	(18,109)	(13,466)	(71,447)	(310,794)
Financing activities	43,614	(10,721)	80,030	324,436

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read “Risk Factors” and “Forward-Looking Statements” elsewhere in this prospectus for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The following information should be read in conjunction with the audited consolidated financial statements and accompanying notes included elsewhere in this prospectus, as well as the information presented under “Selected Historical Financial Data.” The consolidated financial statements for Hygo Energy Transition Ltd., formerly known as Golar Power Limited, have been prepared in accordance with U.S. 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 “—Our Historical and Anticipated Future Operating Results Will Differ Materially” for further discussion.

Overview

Our Operating Segments

We operate our business in the following four reportable segments:

•	FSRUs and Terminals: FSRUs are vessels that are permanently moored offshore and used to store and regasify LNG. As of March 2020, we have one FSRU and terminal offshore Sergipe, Brazil, in service to CELSE pursuant to a 25-year charter.

•	Power: We have contracted with local partners to build cleaner and more economically advantageous natural gas-fired power generation assets backed by long-term PPAs in our core operating areas.

•

LNG Carriers: LNG carriers are vessels that transport LNG and are compatible with many LNG offloading and receiving terminals globally. We have two LNG carriers which are currently operating through the Cool Pool in the spot/short-term charter market. These vessels will continue to operate through the Cool Pool until their conversion into FSRUs.

•	Downstream Distribution: Our downstream distribution business is focused on the procurement of LNG or natural gas from our terminals and other sources to be able to deliver to our downstream customers under medium- to long-term contracts.

Our Historical and Anticipated Future Operating Results Will Differ Materially

We expect the historical results of operations and cash flows, discussed below, including our audited consolidated financial statements, to differ materially from our future operations and cash flows as our business and projects mature. In the paragraphs that follow, we discuss the primary ways in which we expect those results to differ.

Historic Revenues and Expenses

Our historical operating revenues and expenses have primarily consisted of time charter revenues and vessel expenses resulting from the operation of our vessels in the spot/short-term charter market. In addition, prior to March 2020, all of our projects were in various stages of development with none having yet commenced commercial

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operation or revenue generation. As a result, for periods prior to March 2020, our investments in affiliates and joint ventures, such as CELSEPAR, CELBA and CEBARRA, as reported in our consolidated financial statements consist primarily of pre-operating expenses and associated losses. Our results of operations for the six months ended June 30, 2020 include initial revenues from our FSRU offshore Sergipe, Brazil, which commenced operations in March 2020.

Future Revenues and Expenses

Going forward, we anticipate that our results will include increasing revenues resulting from the long-term charter of our vessels in support of our terminals and our downstream distribution business. Results from our FSRU and terminal operations will be reported in our FSRUs and Terminals reportable segment. While we intend to continue to deploy any of our LNG carriers not otherwise in the process of conversion or committed to one of our projects in the spot/short-term charter market, we expect any such revenue and expense resulting from such deployment to comprise an increasingly smaller portion of our overall results. Results associated with the charter of our LNG carriers will be reported in our LNG Carriers reportable segment.

In addition to revenues and expenses associated with our FSRU and wholly owned terminal operations, we also expect to benefit from our ownership interests in the Sergipe Power Plant, the Barcarena Power Plant and other similar future projects. These results will be reflected in our Power reportable segment. The Sergipe Power Plant commenced commercial operations in March 2020. Pursuant to the PPAs in place, CELSE receives (i) fixed revenue for the power plant’s availability, regardless of energy dispatch and (ii) variable revenue based on the amount of energy generated, due when there is energy dispatch. In addition, revenue may be generated as a result of additional sales of LNG and natural gas to various end-users pursuant to offtake agreements with the excess capacity of the Sergipe Terminal. Accordingly, in the second half of 2020, we expect to receive earnings from our indirect investment in CELSE as a result of the revenue and expenses resulting from its commercial operations. We expect that the Barcarena Terminal and our other projects currently in various stages of evaluation, development and construction will generate similar types of revenues and expenses upon commencement of commercial operations.

In addition to the increasing contribution of our FSRU charters and equity investments, our downstream distribution operations, including our strategic partnership with BR Distribuidora, is in the early stages of development but we expect it to have a material impact on our results of operations in future periods. These results will be reflected in our Downstream Distribution reportable segment. Our Downstream Distribution reportable segment will also include results from our gas marketing and trading activities.

Upon completion of this offering, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including costs associated with the employment of additional personnel, compliance under the Exchange Act, annual reports to common shareholders, registrar and transfer agent fees, national stock exchange fees, the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal controls and testing, audit fees, incremental director and officer liability insurance costs and director and officer compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

In addition, in connection with the vesting of the MIS as discussed elsewhere in this prospectus, and following the completion of the offering, we will recognize an one time share based compensation expense of $98.7 million with a credit in equal amount to additional paid-in capital reflecting the capital contribution from Stonepeak. Once each Allocation (as defined herein) vests and becomes payable upon the closing of this offering, no future awards will be granted nor will any additional amounts become payable under the MIS following the closing of this offering except that the MIS will remain in place until each Allocation that was outstanding prior to the closing of this offering is settled, at which point the MIS would be deemed terminated. The balance sheet adjustment is reflected in the pro forma information included in the financial statements found elsewhere in this prospectus. Both the share based compensation expense and the corresponding credit will be reflected in our financial statements for the period that includes the completion of this offering. Please see “Management—Compensation—Compensation of Management” for additional information regarding the MIS arrangement.

Impact of COVID-19

Market Conditions

The COVID-19 pandemic has spread quickly across the globe, and countries have mobilized to implement containment mechanisms and minimize impacts to their populations and economies. In an effort to contain

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COVID-19 or slow its spread, governments around the world have enacted various measures, including orders to close all businesses not deemed “essential,” isolate residents to their places of residence, and practice social distancing. While these restrictions have eased in some regions and countries, they remain in place in others and may be adopted in additional regions or countries. These restrictions and the global health crisis have negatively impacted business activity across the globe, including in Brazil. We have observed declining demand and lower prices for natural gas and LNG as Brazilian and global economic activity have decreased. Brazil’s economic outlook has been particularly impacted by COVID-19 and its related effects, including reduced activity with key trading partners, lower commodity prices, a contraction in domestic activity and higher unemployment rates.

Expected Impact on Our Operations

Due to concerns over health and safety, we have asked the majority of our non-essential workforce to work remotely until further notice. In addition, at our headquarters in London, we have put in place certain safety restrictions, such as limitations on the use of public transportation. As of July 31, 2020, working remotely has not significantly impacted our ability to maintain operations, including use of financial reporting systems, nor has it significantly impacted our internal control environment. We have not incurred, and in the future do not expect to incur, significant expenses related to business continuity as employees work from home.

Operations have not been disrupted at our Sergipe Terminal. We have continued to perform under our contracts, offtakers have continued to meet their payment obligations and liquidity has not been impacted due to the ongoing effects of COVID-19. We have, however, deferred certain capital expenditures and expect to see related delays in associated revenues from our downstream distribution business where we have experienced delays in the execution of contracts with potential offtakers. However, because of the contracted nature of our LNG terminals, we have not experienced, and do not expect to experience, material effects to that portion of our business. In addition, uncertain market conditions and changes in commodity prices may impact the cost benefits of LNG as compared to HFO, which may impact the ability of existing non-gas plants to switch to natural gas or the efficacy of doing so.

With respect to our projects under development, there is an increased risk that FID of our Barcarena and Santa Catarina terminals may be delayed due to severe restrictions on travel within Brazil and a country-wide delay on power auctions in Brazil due to lower than average demand for power in the region. Such travel restrictions have also prevented personnel from traveling between states, which has impacted the timing of inspections and permitting. In addition, the planned power auction related to the potential Santa Catarina Power Plant has been further postponed due to COVID-19.

Although we do not currently expect that COVID-19 will have a material long-term impact on our operating results, financial condition or our supply chain, we cannot predict whether or when economic activities will return to normalized levels.

We will continue to actively monitor the situation and may take further actions altering our business operations that we determine are in the best interests of our employees, customers, partners, suppliers, and stakeholders, or as required by federal, state, or local authorities. It is not clear what the potential effects any such alterations or modifications may have on our business, including the effects on our customers, employees, and prospects, or on our financial results. See “Risk Factors—Risks Related to Our Business—The scale and scope of the recent COVID-19 outbreak, the resulting pandemic, and the impact on the financial markets is unknown and could adversely affect our business, financial condition and results of operation at least for the near term.”

Primary Factors Expected to Impact Our Results of Operations

Brazilian Macroeconomic Environment

We will be affected by Brazilian macroeconomic conditions, including, among others, GDP growth, inflation and interest rates that affect the demand for LNG and natural gas and electricity in Brazil. The general performance of the Brazilian economy can adversely affect our financial condition and results of operations, as well as the overall demand for LNG and natural gas and electricity. In addition, the rate of adoption of LNG and natural gas as alternatives to traditional fossil fuels in Brazil will also significantly impact our future results of operations.

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Exchange Rate Variations

A substantial amount of our, including our joint ventures’, transactions, assets and liabilities are denominated in currencies other than U.S. dollars, such as Brazilian reais in respect of our subsidiaries and investments, which receive income and pay expenses in Brazilian reais. The fluctuation of the value of foreign currencies against other currencies, primarily the U.S. dollar, could adversely affect our, including our joint ventures’, financial condition and results of operations.

Interest Rates

We operate in a capital intensive industry and finance, and expect to continue to finance, a portion of our projects with borrowings from debt transactions and leasing arrangements with financial institutions. A significant portion of our long-term debt and capital lease obligations is, and will continue to be, subject to adverse movements in interest rates. Any such adverse changes in interest rates could increase our financing costs and have a material adverse effect on our results of operations and financial condition.

Natural Gas and LNG Prices

Our business is based on the price of natural gas and LNG. Natural gas and LNG prices have at various times been, and may become, volatile due to a number of factors beyond our control. Decreases in the prices at which we are able to sell LNG and natural gas, or increases in the prices we have to pay to purchase natural gas or LNG, could materially and adversely affect demand from our customers and/or our margins.

Financial Statement Presentation

Operating Revenues

Historically our operating revenues have primarily consisted of time charter revenues resulting from the operation of our vessels through the Cool Pool in the spot/short-term charter market, which was recorded in our LNG Carriers segment. We recognize revenues from such time charters over the term of the charter as the applicable vessel operates under the charter. We do not recognize revenue during days when the vessel is off-hire, unless the charter agreement makes a specific exception.

Revenues and expenses under the Cool Pool arrangement have historically been accounted for in accordance with the guidance for collaborative arrangements when two (or more) parties are active participants in the activity and exposed to significant risk and rewards dependent on the commercial success of the activity. On July 8, 2019, following the withdrawal of GasLog Ltd.’s vessels, we ceased applying the collaborative accounting guidance to the Cool Pool. This had no impact on how we account for revenues and expenses that were attributable to our own vessels, however, net revenue and expenses relating to the other pool participants is now presented on a net basis within “Voyage, charter-hire and commission expenses.”

We anticipate that time charter revenue will comprise a decreasing portion of our total revenue in the future as revenue from other sources, including FSRU charters and power, industrial and other downstream sales of LNG, increase and our existing LNG carriers are converted into FSRUs.

Operating Expenses

Vessel Expenses. Vessel operating expenses include direct vessel operating costs associated with operating a vessel, such as crew wages, which are the most significant component, vessel supplies, routine repairs, maintenance, lubricating oils, insurance and management fees for the provision of commercial and technical management services.

Voyage, Charter-Hire and Commission Expenses. Voyage, charter-hire and commission expenses, which are primarily fuel costs but which also include other costs such as port charges, are paid by our customers under our time charters. However, we may incur voyage related expenses during off-hire periods when positioning or repositioning vessels before or after the period of a time charter or before or after drydocking, which expenses will be payable by us. We also incur some voyage expenses, principally fuel costs, when our vessels are in periods of commercial waiting time. Following the withdrawal of GasLog Ltd.’s vessels from the Cool Pool, we account for voyage expenses under “Voyage, charter-hire and commission expenses.”

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Depreciation and Amortization. Depreciation and amortization expense, or the periodic cost charged to our income for the reduction in usefulness and long-term value of our assets, including our vessels and facilities, is impacted by the number of vessels we own or operate under long-term capital leases as well as the capital invested in our other assets over time. For our vessels, we depreciate their cost less their estimated residual value, and amortize the amount of our capital lease assets over their estimated economic useful lives, on a straight-line basis. We amortize our deferred drydocking costs over five years based on each vessel’s next anticipated drydocking.

Administrative Expenses. Administrative expenses are composed of general overhead, including personnel costs and fees incurred pursuant to the management services agreement with Golar Management, legal and professional fees, property costs, business development project costs and other general administration expenses.

Non-Operating Expenses

Interest Expense and Interest Income. Interest expense depends on our and our consolidated lessor variable interest entities’ (“VIEs”) overall level of borrowings, including costs associated with such borrowings. By virtue of the sale and leaseback transactions we have entered into with lessor VIEs, where we are deemed to be the primary beneficiary, we are required to consolidate these VIEs into our results. As of June 30, 2020, our VIEs include the Golar Penguin, the Golar Nanook and the Golar Celsius which have been financed through sale and leaseback transactions. Accordingly, although consolidated into our results, we have no control over the funding arrangements negotiated by these lessor VIE entities, including the interest rates to be applied. For additional detail refer to “—Non-Controlling Interests” below. During construction of an asset under development, interest expenses incurred are capitalized in the cost of the asset or vessel. In addition this treatment applies to certain of our equity method investments, meeting specific criterion, during the period prior to commencement of their planned principal operations.

Interest income will in part depend on prevailing interest rates and the level of our cash deposits and restricted cash deposits. On March 31, 2020, following commencement of operations at the Sergipe Power Plant, the Sergipe FSRU Charter commenced. All charter-hire revenue from the Sergipe FSRU Charter will be recognized as interest income.

Investments in Affiliates; Equity Method Accounting

Our assets include equity interests in non-consolidated affiliates, including CELSEPAR, CELBA, CEBARRA and São Marcos. The results of operations of these entities will be reflected in our Power reportable segment. Generally we have between 20% and 50% of the voting rights in these entities or may otherwise have significant influence, but over which we do not exercise primary control, or have the primary power to control the financial and operational policies. Investments in these entities are accounted for by the equity method of accounting. This also extends to entities in which we hold a majority ownership interest but do not control due to the participating rights of non-controlling interests. Under this method, we record an investment in the common stock (or “in-substance common stock”) of an affiliate at cost and adjust the carrying amount for our share of the earnings or losses of the affiliate subsequent to the date of the investment and report the recognized earnings or losses in income. Dividends received from an affiliate in connection with our ownership interest reduce the carrying amount of our investment. When our share of losses in an affiliate equals or exceeds our interest, we do not recognize further losses, unless we have incurred obligations or made payments on behalf of the affiliate. We recognize gains and losses in earnings for the issuance of shares by our affiliates, provided that the issuance of such shares qualifies as a sale of such shares.

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We have the following investments as of June 30, 2020 that are recorded using the equity method of accounting:

Investment in Affiliate	Ownership Interest	Operations/Assets	Other Owners
CELSEPAR⁽¹⁾	50%	Sergipe Terminal and Sergipe Power Plant	Ebrasil Energia Ltda.
CELBA	50%	Barcarena Power Plant	Evolution Power Partners S.A.
CELBA 2⁽²⁾	50.0%	Barcarena Power Purchase Agreements	CELBA, BEP and OAK
Golar Power Brasil 2 Participações S.A. (“GPB2”)	50%	CEBARRA	Evolution Power Partners S.A.
CEBARRA⁽³⁾	37.5%	Sergipe expansion rights	Ebrasil Energia Ltda.
São Marcos	50%	Future LNG Terminal in São Luis	Eneva S.A.

(1)	CELSEPAR owns 100% of CELSE which operates the Sergipe Terminal and the Sergipe Power Plant.

(2)

CELBA 2 was incorporated solely to comply with specific requirements of the related power auction in Brazil. As a condition to participation, the bidder is required to incorporate a consortium. Hygo currently indirectly owns a 50.0% interest in CELBA 2, and BEP, OAK and Evolution own an aggregate 50.0% interest therein.

(3)	GPB2 owns a 75% interest in CEBARRA. Ebrasil owns the remaining 25% interest.

For additional information about expected revenue generated by these non-consolidated affiliates, please read “—Our Historic and Anticipated Future Operating Results Will Differ Materially” and for a description of their assets and operations, please read “Business—Our Current and Anticipated LNG-to-Power Infrastructure Network,” “Business—Sergipe” with respect to CELSEPAR and “Business—Barcarena” with respect to CELBA.

Non-Controlling Interests

Non-controlling interests comprises equity interests in our VIEs. We were party to sale and leaseback arrangements for three vessels with these lessor VIEs during the six months ended June 30, 2020. While we do not hold any equity investments in these lessor VIEs, we are the primary beneficiary and accordingly, we are required to consolidate these VIEs into our consolidated financial results. Thus, the equity attributable to these financial institutions is included in our non-controlling interest. For additional details, see note 8 “Variable Interest Entities” to our unaudited consolidated financial statements included herein.

Results of Operations

Six months ended June 30, 2020 compared with six months ended June 30, 2019

Consolidated Results of Operations

	Six Months Ended June 30,
	2020	2019	Change	% Change
	(dollars in thousands)
Time charter revenues	$22,787	$14,425	$8,362	58%
Time charter revenues − collaborative arrangements	—	9,622	(9,622)	(100)%
Vessel operating expenses	6,622	6,531	91	1%
Voyage, charter-hire and commission expenses	770	2,882	(2,112)	73%
Voyage, charter-hire and commission expenses – collaborative arrangement	—	9,825	(9,825)	(100)%
Administrative expenses	11,849	7,285	4,564	63%
Depreciation and amortization	5,640	5,579	61	1%
Other operating income	3,714	—	3,714	NM*
Operating income (loss)	1,620	(8,055)	9,675	120%
Equity in net (loss) of affiliates	(37,276)	(778)	(36,498)	NM*

*	“NM” means “not meaningful.”

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Segment Results of Operations

	Six Months Ended June 30, 2020
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(dollars in thousands)
Total operating revenues⁽²⁾	$21,092	$1,696	$—	$—	$—	$22,787
Vessel operating expenses	(4,938)	(1,684)	—	—	—	(6,622)
Voyage, charter-hire and commission expenses⁽²⁾	(770)	—	—	—	—	(770)
Depreciation and amortization	(5,554)	—	—	(66)	(20)	(5,640)
Administrative expenses	(605)	(1,094)	(1,508)	(2,101)	(6,541)	(11,849)
Other operating income	3,714	—	—	—	—	3,714
Segment operating income/(loss)	12,939	(1,083)	(1,508)	(2,167)	(6,561)	1,620

Equity in net losses of affiliates	$—	$—	$(37,276)	$—	$—	$(37,276)

	Six Months Ended June 30, 2019
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(dollars in thousands)
Total operating revenues⁽²⁾	$24,047	$—	$—	$—	$—	$24,047
Vessel operating expenses	(6,531)	—	—	—	—	(6,531)
Voyage, charter-hire and commission expenses⁽²⁾	(12,707)	—	—	—	—	(12,707)
Depreciation and amortization	(5,564)	—	—	—	(15)	(5,579)
Administrative expenses	(484)	(1,361)	(815)	(1,158)	(3,467)	(7,285)
Segment operating income (loss)	(1,239)	(1,361)	(815)	(1,158)	(3,482)	(8,055)

Equity in net losses of affiliates	$—	$—	$(778)	$—	$—	$(778)

(1)	Relates to corporate overheads not allocated to a segment but included to reflect total depreciation and administrative expenses in the consolidated statement of income (loss).

(2)	Includes amounts from collaborative arrangement.

Total Operating Revenues and Voyage, Charter-Hire and Commission Expenses

Total operating revenues, including collaborative arrangement revenues, decreased by $1.3 million to $22.8 million for the six month period ended June 30, 2020 compared to $24.0 million for the same period in 2019. The decrease is due to the decline in revenues from our LNG carriers by $3.0 million. This was partially offset by the revenue from the Golar Nanook of $1.7 million in the six month period ended June 30, 2020 due to the commencement of its operating services agreement following the commencement of operations of the Sergipe Power Plant in March 2020.

Total voyage, charter-hire and commission expenses decreased by $11.9 million to $0.8 million for the six month period ended June 30, 2020 compared to $12.7 million for the same period in 2019.

The improvement in total operating revenues, net of voyage, charter-hire and commission expenses relating to our LNG carriers of $9.0 million in the six month period ended June 30, 2020 compared to the same period in 2019 is a result of higher utilization and higher charter-hire rates of the vessels in the Cool Pool, including our LNG carriers.

In July 2019, we ceased applying the collaborative accounting guidance to the Cool Pool, and net revenue and expenses relating to the other pool participant are now presented net within voyage, charter-hire and commission expenses as opposed to being presented gross within time charter revenues – collaborative arrangement and voyage, charter-hire and commission expenses – collaborative arrangement. Net revenue relating to the other pool participant presented on our consolidated statement of income (loss) under voyage, charter-hire and commission expenses for the six month period ended June 30, 2020 amounted to $3.1 million. For the six month period ended June 30, 2019, net expenses relating to the other pool participants amounted to $0.2 million which was presented as time charter revenues – collaborative arrangement of $9.6 million and voyage, charter-hire and commission expenses – collaborative arrangement of $9.8 million.

During the six month period ended June 30, 2020, we also recognized $3.7 million of other operating income relating to a successful insurance claim in relation to one of our LNG carriers.

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Vessel Operating Expenses

Vessel operating expenses relating to our LNG carriers decreased by $1.6 million to $4.9 million for the six month period ended June 30, 2020 compared to $6.5 million for the same period in 2019, principally due to the decrease in main engine overhaul costs of $1.2 million on our LNG carriers. This decrease was offset by vessel operating expenses of $1.7 million incurred by the FSRU, the Golar Nanook, following commencement of its sales-type finance lease in March 2020 compared to nil for the same period in 2019 as its costs were capitalized as an asset under development.

Administrative Expenses

Administrative expenses increased by $4.6 million to $11.8 million for the six month period ended June 30, 2020 compared to $7.3 million for the same period in 2019, principally due to a $3.1 million increase in other business and corporate administrative expenses. These administrative expenses incurred in the six month period ended June 30, 2020 were in relation to increased salary costs as well as lawyers' and other professional fees incurred in preparation for the planned initial public offering. In addition, administrative expenses increased in our other reportable segments as follows:

•	Downstream Distribution reportable segment – by $0.9 million to $2.1 million in the six months ended June 30, 2020 compared to $1.2 million in 2019 due to increased business activity in this segment;

•	Power reportable segment – by $0.7 million to $1.5 million in the six months ended June 30, 2020 compared to $0.8 million in 2019 mainly due to administrative expenses for Mercurio Comercializadora de Energia Ltda. (“Mercurio”), which was acquired in October 2019; and

•	LNG Carriers reportable segment – by $0.1 million to $0.6 million in the six months ended June 30, 2020 compared to $0.5 million in 2019.

Equity in Net Loss of Affiliates

Equity in net loss of affiliates increased by $36.5 million to $37.3 million for the six-month period ended June 30, 2020 compared to $0.8 million for the same period in 2019. Following the commencement of operations at the Sergipe Power Plant in March 2020, costs that were previously capitalized as part of the cost of the power plant have been expensed and include one-off start-up costs. The PPAs pursuant to which the Sergipe Power Plant will deliver power to 26 committed offtakers for a period of 25 years provide for guaranteed annual capacity payments of R$1.6 billion, adjusted annually for inflation, at an expected contracted EBITDA margin on gross revenue of 61% (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred).

Other Non-Operating Results

	Six Months Ended June 30,
	2020	2019	Change	% Change
	(dollars in thousands)
Total other non-operating income (loss)	$(20,854)	$—	$(20,854)	NM*
Interest income	10,839	489	10,350	NM*
Interest expense	(5,669)	—	(5,669)	NM*
Other financial items, net	2,011	(1,144)	3,155	NM*
Income taxes	(2,522)	(33)	(2,489)	NM*
Net (loss) attributable to non-controlling interests	$(3,346)	$(2,806)	$(540)	19%

*	“NM” means “not meaningful.”

Total non-operating income (loss): Total non-operating loss of $20.9 million for the six months ended June 30, 2020 was primarily due to the commencement of the Sergipe FSRU Charter, a sales-type lease, on March 31, 2020, which resulted in the de-recognition of the asset under development carrying value, the recognition of net investment in leased asset (consisting of the present value of the future lease receivables and unguaranteed residual value), and a loss on disposal of $26.0 million. This was partially offset by a gain on derivative instruments of $5.1 million for the six month period ended June 30, 2020, which related to gains on

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forward energy purchase contracts in connection with our contract with CELSE to fulfill CELSE’s supply obligations pursuant to the PPAs. There were no corresponding amounts for the same period in 2019 as these forward energy purchase contracts were entered into in the fourth quarter of 2019.

Interest income: Interest income increased by $10.3 million to $10.8 million for the six month period ended June 30, 2020 compared to $0.5 million for the same period in 2019. This was primarily due to $12.5 million interest income recognized in relation to the Sergipe FSRU Charter for the six month period ended June 30, 2020 following the commencement of the sales-type lease on March 31, 2020. This was partially offset by an allowance for current expected credit losses of $1.9 million relating to the Sergipe FSRU Charter. There was no such interest income or allowance for credit losses for the period ended June 30, 2019.

Interest expense: Interest expense of $5.7 million for the six month period ended June 30, 2020 was recognized in relation to the consolidated interest expense of our VIEs as well as the interest expense on our Brazilian reais denominated debenture. There was no such interest expense for the period ended June 30, 2019 as we recognized capitalized interest on our qualifying assets. Following the commencement of commercial operations of the Sergipe Power Plant and the Sergipe FSRU Charter in March 2020, such capitalized interest ceased.

Other financial items, net: Other financial items, net, changed by $3.2 million to a gain of $2.0 million for the six month period ended June 30, 2020 compared to a loss of $1.1 million for the same period in 2019. The change is primarily due to foreign exchange movements resulting from the strengthening of the U.S. dollar against the Brazilian reais.

Income taxes: Income taxes increased by $2.5 million to $2.5 million for the six month period ended June 30, 2020 compared to $33,000 for the same period in 2019. This was primarily due to income taxes with respect to gains on forward energy purchase contracts in Brazil.

Net loss attributable to non-controlling interests: Net loss attributable to non-controlling interests increased by $0.5 million to $3.3 million for the six months ended June 30, 2020 compared to $2.8 million for the same period in 2019. Net loss attributable to non-controlling interests pertains to equity interests in our lessor VIEs for the periods ended June 30, 2020 and 2019.

Year ended December 31, 2019 compared with year ended December 31, 2018

Consolidated Results of Operations

	Year Ended December 31,
	2019	2018	Change	% Change
	(dollars in thousands)
Total operating revenues	$45,223	$78,732	$(33,509)	43%
Vessel operating expenses	12,638	11,499	1,139	10%
Voyage, charter-hire and commission expenses	5,912	3,160	2,752	87%
Voyage, charter-hire and commission expenses – collaborative arrangement	9,825	39,836	(30,011)	75%
Administrative expenses	16,126	17,652	(1,526)	9%
Depreciation and amortization	11,212	11,180	32	—
Other operating income	1,100	—	1,100	NM*
Operating loss	(9,390)	(4,595)	(4,795)	104%
Equity in net (loss) of affiliates	(2,510)	(5,748)	3,238	56%

*	“NM” means “not meaningful.”

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Segment Results of Operations

	Year Ended December 31, 2019
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(dollars in thousands)
Total operating revenues	$45,223	$—	$—	$—	$—	$45,223
Total vessel operating expenses⁽²⁾	(28,375)	—	—	—	—	(28,375)
Depreciation	(11,168)	—	—	(10)	(34)	(11,212)
Administrative expenses	(869)	(3,053)	(1,730)	(2,671)	(7,803)	(16,126)
Segment operating income (loss)	4,811	(3,053)	(1,730)	(2,681)	(7,837)	(10,490)

Equity in net loss of affiliates	$—	$—	$(2,510)	$—	$—	$(2,510)

	Year Ended December 31, 2018
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(dollars in thousands)
Total operating revenues	$78,732	$—	$—	$—	$—	$78,732
Total vessel operating expenses⁽²⁾	(54,495)	—	—	—	—	(54,495)
Depreciation	(11,160)	—	—	—	(20)	(11,180)
Administrative expenses	(4,770)	(2,689)	(1,620)	(8)	(8,565)	(17,652)
Segment operating income (loss)	8,307	(2,689)	(1,620)	(8)	(8,585)	(4,595)

Equity in net loss of affiliates	$—	$—	$(5,748)	$—	$—	$(5,748)

(1)	Relates to corporate overheads not allocated to a segment but included to reflect total depreciation and administrative expenses in the consolidated statement of income (loss).

(2)	Total vessel operating expenses consists of the following line items in the Statement of Comprehensive Income (loss): Vessel operating expenses, Voyage, charter-hire and commission expenses and Voyage, charter-hire and commission expenses – collaborative arrangement.

Operating Revenue and Voyage, Charter-Hire and Commission Expenses

Total operating revenues, including collaborative arrangement revenues, decreased by $33.5 million to $45.2 million for the year ended December 31, 2019 compared to $78.7 million for the same period in 2018. The operating revenues during both periods were derived from our LNG Carriers reportable segment. During the year ended December 31, 2019, we also recognized $1.1 million of other operating income relating to a successful insurance claim.

Total voyage, charter-hire and commission expenses, including collaborative arrangement expenses, decreased by $27.3 million to $15.7 million for the year ended December 31, 2019 compared to $43.0 million for the same period in 2018.

Changes in Operating revenue and Voyage, charter-hire and commission expenses during the periods presented related principally to market rates for LNG carriers operating in the spot market. Voyage, charter-hire and commission expenses – collaborative arrangement, also relate to distributions to other participants in the Cool Pool.

Vessel Operating Expenses

Vessel operating expenses increased by $1.1 million to $12.6 million for the year ended December 31, 2019 compared to $11.5 million for the same period in 2018, principally due to the increase in repair and maintenance costs of one of our LNG carriers. All vessel operating expenses for both periods presented were derived from our LNG Carriers reportable segment.

Administrative Expenses

Administrative expenses decreased by $1.5 million to $16.1 million for the year ended December 31, 2019 compared to $17.7 million for the same period in 2018, principally due to a $3.9 million decrease in administrative expenses related to our LNG Carriers reportable segment. These administrative expenses incurred

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in the year ended December 31, 2018 were in relation to the conversion of one of our LNG carriers into an FSRU prior to making a FID on the conversion project. This decrease was partially offset by a $2.7 million increase in the year ended December 31, 2019 corporate costs and project development expenses related to Downstream Distribution reportable segment.

During the year ended December 31, 2019, we incurred administrative expenses of $3.1 million, $1.7 million, $0.8 million and $2.7 million related to our FSRUs and Terminals, Power, LNG Carriers and Downstream Distribution reportable segments, respectively. Other Business and Corporate accounted for the remaining $7.8 million in administrative expenses.

During the year ended December 31, 2018, we incurred administrative expenses of $2.7 million, $1.6 million, $4.8 million and $0.1 million related to our FSRUs and Terminals, Power, LNG Carriers and Downstream Distribution reportable segments, respectively. Other Business and Corporate accounted for the remaining $8.5 million in administrative expenses.

During the periods presented, we did not incur expenses other than administrative expenses in our FSRUs and Terminals, Power, LNG Carriers and Downstream Distribution reportable segments.

Equity in Net Loss of Affiliates

Equity in net loss of affiliates decreased by $3.2 million to $2.5 million for the year ended December 31, 2019 compared to $5.7 million for the same period in 2018, principally due to the increased net results in our investment in CELSEPAR.

Other Non-Operating Results

	Year Ended December 31
	2019	2018	Change	% Change
	(dollars in thousands)
Total other non-operating income	$9,990	$5,072	$4,918	97%
Interest income	795	1,336	(541)	40%
Interest expense	(2)	(912)	910	100%
Other financial items, net	(1,659)	(5,245)	3,586	68%
Income taxes	(4,152)	(110)	(4,042)	NM*
Net income attributable to non-controlling interests	$(5,549)	$(1,541)	$(4,008)	260%

*	“NM” means “not meaningful”.

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Total non-operating income: Total non-operating income increased by $4.9 million to $10.0 million for the year ended December 31, 2019, compared to $5.1 million for the same period in 2018 primarily due the recognition of a $10.0 million unrealized gain for the year ended December 31, 2019 on forward energy purchase contracts in connection with our contract with CELSE to sell a fixed quantity of power to CELSE prior to commencement of commercial operations at the Sergipe Power Plant to fulfill CELSE’s supply obligations pursuant to the PPAs. For the year ended December 31, 2018, we recognized one-time syndication fee assistance income of $5.0 million related to our assistance with the syndication of an unsecured loan to CELSE.

Interest income: Interest income decreased by $0.5 million to $0.8 million for the year ended December 31, 2019, compared to $1.3 million for the same period in 2018 due to decreased levels of cash deposits and restricted cash deposits throughout the period.

Interest expense: Interest expense decreased by $0.9 million to nil for the year ended December 31, 2019 compared to $0.9 million for the same period in 2018. This was primarily due an increase in the qualifying asset base for which we are able to recognize deemed interest.

Other financial items, net: Other financial items, net, includes the revaluation of deferred consideration payable to the project developer as part of the step acquisition of the investment in CELSEPAR in 2016 (inclusive of the unwinding discount) of $1.6 million and $3.3 million for the years ended December 31, 2019 and 2018, respectively, relating to our increased investment in CELSEPAR in July 2018. Other financial items, net, for the year ended December 31, 2019 also includes amounts incurred for foreign exchange gain and finance charges as well as the acceleration of the amortization of the counter-debt guarantee provided to Golar LNG as a result of the refinancing of Golar Penguin.

Income taxes: Income taxes increased by $4.1 million to $4.2 million for the year ended December 31, 2019 compared to $0.1 million for the same period in 2018. This was primarily due to the recognition of a deferred tax liability of $3.5 million with respect to unrealized gains on financial instruments in Brazil. For additional information, see “Business—Taxation of Hygo.”

Net income attributable to non-controlling interests: Net income attributable to non-controlling interests increased by $4.0 million to $5.5 million for the year ended December 31, 2019 compared to $1.5 million for the same period in 2018.

Liquidity and Capital Resources

We operate in a capital-intensive business and we expect to fund our operations and ongoing capital expenditure requirements through a combination of borrowings from, and leasing arrangements with, commercial banks and other financial institutions, cash generated from our operations, including distributions from our equity investees, and proceeds from debt and equity offerings, including this offering. We anticipate that CELSEPAR will begin making quarterly cash distributions once commercial operations commence in 2021, subject to limitations included in its debt agreements. Our cash requirements relate to funding our working capital, servicing our debt, funding the development of our projects, including those of our joint ventures.

Over the next twelve months, we expect to incur a total of approximately $70 million in capital expenditures, the majority of which will be deployed in connection with our Barcarena, Santa Catarina and Downstream Distribution projects and the conversion of one of our LNG carriers. For additional information regarding expected capital expenditures related to our projects, please see “Business—Terminals and Floating Storage and Regasification Units” and “Business—Our Current and Anticipated LNG-to-Power Infrastructure Network.” We believe that we will have sufficient current resources to meet our financial obligations over the next twelve months.

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Cash Flows

The following table summarizes the major components of our cash flows:

	Six Months Ended June 30,		Year Ended December 31,
	2020	2019	2019	2018
	(dollars in thousands)
Net cash provided by (used in):
Operating activities	$11,724	$15,854	$13,755	$(12,947)
Investing activities	(18,109)	(13,466)	(71,447)	(310,794)
Financing activities	43,614	(10,721)	80,030	324,436
Foreign exchange in cash	(2,355)	—	—	—
Net change in cash, cash equivalents and restricted cash	$34,874	$(8,333)	$22,338	$695
Cash, cash equivalents and restricted cash at beginning of period	72,851	50,513	50,513	49,818
Cash, cash equivalents and restricted cash at end of period	107,725	42,180	72,851	50,513

Net Cash Provided By/(Used In) Operating Activities

Our net cash provided by operating activities decreased by $4.2 million to $11.7 million for the six month period ended June 30, 2020 compared to $15.9 million for the six month period ended June 30, 2019. The decrease was mainly due to a net payment made to related parties in the six months ended June 30, 2020 of $0.2 million compared to a net receipt of $3.1 million in 2019. In addition, advance payments for certain items of equipment were made in the six month period ended June 30, 2020 as shown by the movement in prepaid expenses, accrued interest and other current assets of $0.7 million. Other movements are due to the general timing of working capital for the six month period ended June 30, 2020.

Our net cash provided by operating activities increased by $26.7 million to $13.8 million for the year ended December 31, 2019 compared to net cash used in operating activities of $12.9 million for the year ended December 31, 2018. The increase was primarily due to $9.5 million received from customers offset by lower contributions from our participation in the Cool Pool for the year ended December 31, 2019. The net change in deferred revenue of $37.6 million, trade receivables of $28.6 million and prepaid expenses of $1.3 million includes off-setting amounts relating to pre-commissioning revenue on Golar Nanook’s charter agreement with CELSE. Furthermore, the $10.4 million change in accrued expenses for the year ended December 31, 2019 is due to the timing of settlement and recognition of accruals during the year.

Net Cash (Used In) Investing Activities

Our net cash used in investing activities was $18.1 million in the six month period ended June 30, 2020 compared to $13.5 million in the period ended June 30, 2019. The increase in cash flow used in investing activities is mainly due to the payment of the deferred consideration on our investment in CELSEPAR of $11.5 million following the commencement of operations at the Sergipe Power Plant in March 2020. This was partially offset by the decrease in cash expenditures by $8.7 million in the six month period ended June 30, 2020 compared to the same period in 2019 relating to the construction of the Golar Nanook following the commencement of the Sergipe FSRU Charter in March 2020.

Our net cash flow used in investing activities was $71.4 million in the year ended December 31, 2019, which decreased from $310.8 million in the year ended December 31, 2018. The decrease in cash flow used in investing activities is due to significant cash expenditures incurred in 2018 related to the construction of the Golar Nanook as well as capital contributions to CELSEPAR for the construction of the Sergipe Terminal and Sergipe Power Plant.

Net Cash Provided By Financing Activities

Our net cash flow provided by financing activities of $43.6 million in the six month period ended June 30, 2020 was due to net proceeds from the refinancing of the Golar Celsius and the Golar Penguin of $117.1 million and $104.1 million, respectively, offset by repayment of debt obligations of $177.6 million. Net cash used in financing activities of $10.7 million in the six month period ended June 30, 2019 was due to repayment of debt obligations.

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Our net cash flow provided by financing activities was $80.0 million in the year ended December 31, 2019, which decreased from $324.4 million in the year ended December 31, 2018. The decrease in cash flow provided by financing activities is due to a decrease in proceeds from equity contributions from shareholders and a decrease in proceeds from debt, partially offset by an increase in repayments of debt.

Long-Term Debt

Hygo

ECA Facility. In connection with our formation, we assumed the credit facility related to the Golar Celsius and Golar Penguin (the “ECA Facility”). In December 2019, the ECA Facility was extinguished with respect to the Golar Penguin in connection with a sale and leaseback transaction. Please see “—Golar Penguin Leaseback and Credit Facility.” On March 3, 2020 the Golar Celsius was refinanced in a sale and leaseback transaction with Noble Celsius Shipping Limited (the “Celsius Leaseback”) and removed from the ECA Facility. Please see “—Golar Celsius Leaseback.” Following the Celsius Leaseback, we had no further obligations under the ECA Facility.

Golar Nanook Leaseback and Credit Facility. In September 2018, we completed the refinancing of the Golar Nanook and entered into a sale and leaseback transaction with Compass Shipping 23 Corporation Limited (the “Nanook Leaseback”). The Nanook Leaseback is guaranteed by Golar LNG and us, and is secured by: (i) the Golar Nanook; (ii) certain accounts; (iii) the assignment of certain warranties and insurance policies; (iv) the assignment of the 25-year charter to CELSE and related Operating & Services Agreement; and (v) shares in Golar FSRU 8 Corp., the charterer of the Golar Nanook under the Nanook Leaseback.

In September 2018, Compass Shipping 23 Corporation Limited, the owner of the Golar Nanook, entered into a twelve-year, $277 million credit facility (the “Nanook Facility”). Because we are the primary beneficiary of the Golar Nanook, we are required to consolidate the Nanook Facility in our financial results. The Nanook Facility bears interest at LIBOR plus a margin equal to 3.5% and is repayable in quarterly installments with a balloon payment on maturity. The Nanook Facility matures in September 2030.

Golar Penguin Leaseback and Credit Facility. In December 2019, we completed the refinancing of the Golar Penguin and entered into a sale and leaseback transaction with Oriental LNG 02 Limited (the “Penguin Leaseback”), which extinguished the ECA Facility with respect to the Golar Penguin. Payments are due quarterly in 24 installments of $1.89 million, with a balloon payment of approximately $68.0 million upon maturity. The Penguin Leaseback is guaranteed by Golar LNG and is secured by: (i) the Golar Penguin; (ii) restricted cash of $3.0 million; (iii) the assignment of insurance policies, earnings and requisition compensation; (iv) the assignment of any existing or future charters in excess of twelve months; and (v) the assignment of shares in Golar Hull M2023 Corp., the charterer of the Golar Penguin pursuant to the sale and leaseback transaction. The Penguin Leaseback also contains certain covenants that, among other things and subject to certain exceptions and qualifications, (i) require Golar LNG to maintain a Consolidated Net Worth (as defined therein) equal or greater to $450.0 million and maintain Current Assets equal to or greater than Current Liabilities and (ii) require the guarantor to maintain Free Liquid Assets (as defined therein) with aggregate value equal to or greater than $50.0 million. The Penguin Leaseback is cross-collateralized with a vessel under a sale and leaseback transaction between Golar LNG and Oriental LNG 01 Limited, whereby a default under one sale and leaseback transaction automatically results in a default under the other.

Also in December 2019, Oriental LNG 02 Limited, the owner of the Golar Penguin, entered into a short-term financing agreement for $113.4 million (the “Penguin Facility”). Although we have no control over the funding arrangements of Oriental LNG 02 Limited, we consider ourselves to be the primary beneficiary of the Golar Penguin and are therefore required to consolidate the Penguin Facility in our financial results. The loan facility bears interest at LIBOR plus a margin of 1.5%, has no repayment profile and is callable on demand.

Golar Celsius Leaseback and Credit Facility. On March 3, 2020, the Golar Celsius was refinanced in a sale and leaseback transaction with Noble Celsius Shipping Limited. The Celsius Leaseback is guaranteed by Golar LNG and us, and is secured by: (i) the Golar Celsius; (ii) the assignment of certain insurance policies; and (iii) the assignment of shares in Golar Hull M2026 Corp., the charterer under the Celsius Leaseback.

In March 2020, Noble Celsius Shipping Limited, the owner of the Golar Celsius, entered into a three-year loan facility for $118.2 million (the “Celsius Facility”). The Celsius Facility is denominated in U.S. dollars and bears interest at 4.64% and is repayable at the end of the three-year period. Although we have no control over

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the funding arrangements of Noble Celsius Shipping Limited, we consider ourselves to be the primary beneficiary of the Golar Celsius and are therefore required to consolidate the Celsius Facility in our financial results.

Debenture Loan. On September 10, 2019, our subsidiary, Golar Power Brasil Participações S.A. (“Golar Brazil”), issued debentures in the aggregate principal amount of R$300.0 million due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debentures”). The Debentures were issued in a public offering in Brazil with restricted efforts, exempted from registration before the Brazilian Securities and Exchange Commission (Comissão de Valores Mobiliários or “CVM”) pursuant to the Brazilian Law No. 6,385/1976, as amended, and to CVM Instruction No. 476/2009, as amended. The offering resulted in net proceeds to Golar Brazil, after deducting applicable discounts and commissions and offering expenses, of approximately R$295.0 million.

Interest is payable on the Debentures semi-annually on each September 13 and March 13, beginning on September 13, 2020. Principal due under the Debentures is amortized semi-annually on each September 13 and March 13, beginning September 13, 2020.

The Debentures are fully and unconditionally guaranteed by: (i) Brazilian law security interests over (A) 100% percent of the shares issued by Golar Brazil owned by our subsidiary, LNG Power Ltd. (“LNG Power”), (B) certain dividends and credit rights due to Golar Brazil in its capacity of shareholder of CELSEPAR and (C) a controlled account owned by Golar Brazil and any monies deposited therein; (ii) a first demand corporate guarantee under Bermuda law granted by the Company; (iii) a first demand corporate guarantee under U.K. law granted by LNG Power; and (iv) U.K. law security interests over controlled accounts owned by LNG Power and the Company.

At any time prior to September 13, 2024, Golar Brazil may redeem all, but not less than all, of the Debentures at a 0.1% premium, plus accrued and unpaid interest. Moreover, as long as in compliance with local capital markets regulation, Golar Brazil may also acquire the Debentures and such Debentures acquired by Golar Brazil may be cancelled, held in treasury or even traded in the market. When traded back in the market, such Debentures shall be entitled to the same interest payments due to the other Brazilian Debentures.

The indenture governing the Debentures contains covenants that, among other things and subject to certain exceptions and qualifications, (i) limit the ability of Golar Brazil, Golar Nanook UK Limited (“Golar Nanook UK”), us and LNG Power to pay certain dividends; (ii) limit the ability of Golar Brazil, us and LNG Power to incur certain debts or issue debt securities; (iii) limit the ability of Golar Brazil, Golar Nanook UK, us and LNG Power to grant certain liens or guarantees; (iv) limit the ability of Golar Nanook UK to make certain new investments; and (v) limit the ability of Golar Brazil to consolidate, merge, engage in a corporate restructuring or other change of control events.

Investments in Affiliates

To finance construction of the Sergipe Terminal and the Sergipe Power Plant, CELSE has incurred a significant amount of debt. In April 2018, CELSE signed financing agreements with amounts made available by banks and multilateral organizations throughout the years 2018 and 2019 (the “Celse Facility”). As of June 30, 2020, amounts outstanding and the effective interest rates under the Celse Facility were as set forth below. Principal and interest repayments are due each October and April, beginning October 2020. The Celse Facility matures in April 2032.

Credit facility	Total credit facility	Effective interest rate
IFC	R$803,995,600	9.79%
Inter-American Development Bank	R$664,000,000	9.69%
IDB Invest⁽¹⁾	$38,000,000	7.11%
IDB China Fund	$50,000,000	7.11%

(1)	Inter-American Investment Corporation is an international organization established by the Inter-American Investment Corporation Agreement between its member countries (“IDB Invest”).

Also in April 2018, CELSE issued debentures in the aggregate principal amount of R$3,370,000,000, due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”). The CELSE Debentures were purchased by Swiss Insured Brazil Power Finance S.à.r.l. (“Power Finance”) and secure the 9.85% Senior

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Secured Notes due 2032 that Power Finance issued on April 18, 2018 in reliance on exemption from registration provided by Rule 144A and in reliance on Regulation S. The CELSE Debentures have a unit nominal value of R$10,000 (the “Debenture Unit Nominal Value”).

Interest is payable on the CELSE Debentures semi-annually on each April 15 and October 15, beginning on October 15, 2018. The Debenture Unit Nominal Value of the CELSE Debentures is amortized and repaid in 24 consecutive semi-annual installments on each April 15 and October 15, commencing on October 15, 2020. If payment of any principal is not paid on the originally scheduled payment date, CELSE will be required to apply any funds available to the payment of such delinquent amounts on each subsequent payment date.

The CELSE Debentures are secured, on a pari passu basis with the other senior debt related to the Sergipe Power Plant, the 33 kilometer transmission line, dedicated gas pipeline and mooring system at the Sergipe Terminal (collectively, for purposes of this description of the CELSE Debentures, the “Project”) and subject to an Intercreditor Agreement among the senior lenders for the Project, by a first lien security interest in the (i) any and all shares issued by CELSE, including all earnings, benefits and rights attached thereto; (ii) all machinery, equipment and moveable assets of the Project; (iii) CELSE’s credit rights and receivables arising from and related to the PPAs and security related thereto; (iv) certain bank accounts, including certain offshore and Swiss accounts; (v) CELSE’s insurance policies; (vi) the Sergipe Power Plant; (vii) the real estate and related easements or rights of way associated with the transmission line and connection bay; (viii) the Sergipe FSRU Charter; (ix) the Operation & Services Agreement; (x) the EPC agreement with General Electric related to the Sergipe Power Plant; (xi) the Sergipe O&M Agreement; and (xii) the Sergipe Supply Agreement.

As of the date hereof, Brazilian law prohibits any prepayment (other than scheduled amortization payments) of the CELSE Debentures prior to maturity. To the extent Brazilian law permits a voluntary prepayment or redemption of the CELSE Debentures, a make-whole premium will apply, equal to the greater of (i) zero and (ii) (x) the present value of the remaining scheduled interest and principal payments, discounted at the then-prevailing Brazilian government local note (NTN-F) with a maturity that is closest to the remaining weighted average life of the CELSE Debentures minus (y) the aggregate principal amount of all CELSE Debentures so prepaid or redeemed (excluding any CELSE debentures held by CELSE and its affiliates). In connection with certain mandatory prepayment events, each holder of the CELSE Debentures has the irrevocable option to, following April 18, 2020, sell all or any portion of its CELSE Debentures to CELSE, at a price equal to the Debenture Unit Nominal Value plus any accrued and unpaid interest thereon.

The indenture governing the CELSE Debentures and the Common Terms Agreement, dated April 12, 2018, among CELSE and the senior lenders for the Project, contains covenants that, among other things and subject to certain exceptions and qualifications: (i) requires CELSE to maintain a Historical Debt Service Coverage Ratio (as defined in the Common Terms Agreement) for a twelve month period on or after March 31, 2021 of no less than 1.10 to 1.00; (ii) prohibit certain Restricted Payments (as defined in the Common Terms Agreement); (iii) limit the ability of CELSE from creating any liens or incurring additional indebtedness; (iv) prohibit certain fundamental changes; (v) limit the ability of CELSE to transfer or purchase assets; (vi) prohibit certain affiliate transactions; (vii) limit the ability of CELSE to make change orders or give other directions under the documents related to the construction and operation of the Project in certain circumstances; (viii) limit the ability of CELSE to enter into additional contracts; (ix) limit CELSE’s operating expenses and capital expenditures; and (x) prohibit CELSE from transferring, purchasing or otherwise acquiring any portion of the CELSE Debentures, other than pursuant to the exercise of the put option.

In connection with the financing of the Project, CELSEPAR entered into a Standby Guarantee and Credit Facility Agreement, dated April 12, 2018, with GE Capital EFS Financing, Inc. (“GE Capital”), as lender, and Ebrasil and Golar Power Brasil Participações S.A., each as sponsor (the “GE Credit Facility”). Pursuant to the GE Credit Facility, GE Capital agreed to provide $120.0 million in credit support in respect of CELSEPAR’s obligation to make certain contingent equity contributions to CELSE. Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate of LIBOR plus a margin of 11.4%. Amounts available to be borrowed under the GE Credit Facility bear a commitment fee of 2% per annum. If an event of default occurs and is continuing, the interest rate and commitment fee accruing will increase by 2%. Amounts are available to be borrowed under the GE Credit Facility until April 16, 2021. Amounts due under the GE Credit Facility are paid in installments pursuant to the terms of the GE Credit Facility. The GE Credit Facility matures on November 30, 2024. As of June 30, 2020, there was R$684.5 million outstanding under the GE Credit Facility.

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CELSEPAR’s current shareholders must control CELSEPAR at all times until the full repayment of the GE Credit Facility. In addition, all of CELSEPAR’s obligations under the GE Credit Facility are secured by (i) a share pledge over 51% of the shares of CELSEPAR, (ii) a first priority security interest over a debt service reserve account, which CELSEPAR is required to maintain with a balance sufficient to cover the immediately next scheduled payment of principal and interest due under the GE Credit Facility, a restricted payment account and an operating account from which CELSEPAR will be authorized to pay its administrative expenses and (iii) a fiduciary assignment over the amounts deposited in a project distribution account by the Project to CELSEPAR. The GE Credit Facility includes covenants and events of default that are customary for similar transactions.

Off-Balance Sheet Arrangements

As of June 30, 2020, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations as of June 30, 2020

	Total	Less than 1 year⁽¹⁾	Years 2 to 3	Years 4 to 5	More than 5 years
	(dollars in thousands)
Hygo long-term and short-term debt⁽²⁾	$54,869	$3,457	$20,850	$30,562	$—
VIE long-term and short-term debt⁽²⁾	439,504	104,126	—	118,200	217,178
Interest commitments on long-term and short-term debt⁽³⁾	113,774	7,927	30,182	19,390	56,275
Total	608,147	115,510	51,032	168,152	273,453

(1)	Refers to period of July 1, 2020 to December 31, 2020.

(2)

Hygo long-term and short-term debt is presented gross of deferred finance charges and excludes interest. Included in these amounts are balances relating to certain lessor entities (for which legal ownership resides with financial institutions) that we are required to consolidate into our financial statements as VIEs under U.S. GAAP. See note 8 “Variable Interest Entities and note 13 “Debt” of our unaudited consolidated financial statements included herein. The obligations in relation to the lessor VIE entities do not represent future cash outflows to us but rather to the VIE entities themselves.

(3)	Our interest commitment on our long-term and short-term debt is calculated based on assumed LIBOR rates of between 1.74% and 1.92% and takes into account our various margin rates associated with each financing arrangement.

Summary of Critical Accounting Estimates

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires that management make estimates and assumptions affecting the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a discussion of the accounting policies applied by us that are considered to involve a higher degree of judgment in their application. See note 2 “Accounting Policies” of our audited consolidated financial statements included herein.

Revenue Recognition and Related Expenses

Cool Pool

Pool revenues and expenses under the Cool Pool arrangement are accounted for in accordance with the guidance for collaborative arrangements when two (or more) parties are active participants in the activity and exposed to significant risk and rewards dependent on the commercial success of the activity. Active participation is deemed to be when there is participation on the Cool Pool steering committee.

When applying collaborative arrangements, we present our share of net income earned under the Cool Pool across a number of lines in the consolidated Income Statement. Net revenue and expenses incurred specifically to our vessels and for which we are deemed to be the principal, are presented gross on the face of the Income Statement in the line items “Time and voyage and charter revenues” and “Voyage, charter hire and commission expenses.” For pool net revenues generated by the other participants in the pooling arrangement, these are

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presented separately in revenue and expenses from collaborative arrangements. Each participants’ share of the net pool revenues is based on the number of days such vessels participated in the pool. Refer to note 7 “Revenue” of our audited consolidated financial statements for an analysis of the income statement effect for the pooling arrangement.

When no collaborative arrangement accounting is applied, we present our gross share of income earned and costs incurred under the Pool on the face of the Income Statement in the line items “Time and voyage and charter revenues” and “Voyage, charter hire and commission expenses” respectively. For pool net revenues and expenses generated by the other participants in the pooling arrangement, we analogize to the cost of obtaining a contract and expense these costs as incurred and present within the line item “Voyage, charter hire and commission expenses.”

Impairment of Long-Lived Assets

Vessels and Impairment

Description. We review vessels and equipment for impairment whenever events or circumstances indicate the carrying value of the vessel may not be fully recoverable. When such events or circumstances are present, we assess recoverability by comparing the vessel’s projected undiscounted net cash flows to its carrying value. If the total projected undiscounted net cash flows are lower than the vessel’s carrying value, we recognize an impairment loss measured as the excess of the carrying amount over the fair value of the vessel. As of December 31, 2019, for two of our vessels (refer to note 18 “Vessels and Equipment, net” of our audited consolidated financial statements included herein), the carrying value was higher than their estimated market values (based on third party ship broker valuations). As a result, we concluded that an impairment trigger existed and so performed a recoverability assessment for each of these vessels. However, no impairment loss was recognized as, for each of these vessels, the projected undiscounted net cash flows was significantly higher than the carrying value.

During the period ended June 30, 2020, as a result of COVID-19’s impact on our operations, we considered whether indicators of impairment existed that could indicate that the carrying amounts of the vessels may not be recoverable as of June 30, 2020 and concluded that no such events or changes in circumstances had occurred to warrant a change in the assumptions utilized in the December 31, 2019 impairment tests of our vessels. We will continue to monitor developments in the markets in which we operate for indications that the carrying values of our vessels are not recoverable.

Judgments and estimates. The cash flows on which our assessment of recoverability is based is highly dependent upon our forecasts, which are highly subjective and, although we believe the underlying assumptions supporting this assessment are reasonable and appropriate at the time they were made, it is therefore reasonably possible that a further decline in the economic environment could adversely impact our business prospects in the next year. This could represent a triggering event for a further impairment assessment.

Accordingly, the principal assumptions we have used in our recoverability assessment (i.e. projected undiscounted net cash flows basis) included, among others, charter rates, ship operating expenses, drydocking requirements and residual value. These assumptions are based on historical trends but adjusted for future expectations. Specifically, forecasted charter rates are based on information regarding current spot market charter rate (based on a third party valuation), option renewal rate with the existing counterparty or existing long-term charter rate, in addition to industry analyst and broker reports. Estimated outflows for operating expenses and drydockings are based on historical costs.

Effect if actual results differ from assumptions. Although we believe the underlying assumptions supporting the impairment assessment are reasonable, if charter rate trends and the length of the current market downturn vary significantly from our forecasts, management may be required to perform step two of the impairment analysis that could expose us to material impairment charges in the future. Our estimates of vessel market values may not be indicative of the current or future market value of our vessels or prices that we could achieve if we were to sell them and a material loss might be recognized upon the sale of our vessels.

Vessel Market Values

Description. Under “Vessels and impairment”, we discuss our policy for assessing impairment of the carrying values of our vessels. During the past few years, the market values of certain vessels in the worldwide fleet have experienced particular volatility, with substantial declines in many vessel classes. There is a future risk

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that the market value of certain of our vessels could decline below those vessels’ carrying value, even though we would not recognize an impairment for those vessels due to our belief that projected undiscounted net cash flows expected to be earned by such vessels over their operating lives would exceed such vessels’ carrying amounts.

Judgments and estimates. Our estimates of market value assume that our vessels are all in good and seaworthy condition without need for repair and, if inspected, would be certified in class without notations of any kind. Our estimates for our LNG carriers and FSRUs are based on approximate vessel market values that have been received from third party ship brokers, which are commonly used and accepted by our lenders for determining compliance with the relevant covenants in our credit facilities. Vessel values can be highly volatile, such that our estimates may not be indicative of the current or future market value of our vessels or prices that we could achieve if we were to sell. In addition, the determination of estimated market values may involve considerable judgment given the illiquidity of the second hand market for these types of vessels.

Effect if actual results differ from assumptions. As of June 30, 2020, while we intend to hold and operate our vessels, were we to hold them for sale, we have determined the fair market value of our vessels, with the exception of the two vessels, were greater than their carrying value. With respect to these two vessels, the carrying value of these vessels exceeded their aggregate market value. However, as discussed above, for each of these vessels, the carrying value was less than its projected undiscounted net cash flows, consequently, no impairment loss was recognized.

JOBS Act

In April 2012, the JOBS Act, was enacted. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards. Thus, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We intend to take advantage of the exemptions discussed above. Accordingly, the information contained herein may be different than the information you receive from other public companies.

Subject to certain conditions, as an emerging growth company, we intend to rely on certain of these exemptions, including without limitation, (1) providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act and (2) complying with any requirement that may be adopted by the PCAOB, regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements, known as the auditor discussion and analysis. We will remain an emerging growth company until the earlier of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.07 billion or more; (ii) the last day of the fiscal year following the fifth anniversary of the date of the completion of this offering; (iii) the date on which we have issued more than $1.00 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see note 3 “Recently Issued Accounting Standards” to our unaudited consolidated financial statements.

Quantitative and Qualitative Disclosures About Market Risk

In the normal course of business, we encounter 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 contracts with customers include pass-through mechanisms that allow us to pass a portion of the cost of natural gas onto our customers. Our exposure to market risk associated with LNG price changes may adversely impact our business. We do not currently have any derivative arrangements to protect against fluctuations in commodity prices, but to mitigate the effect of fluctuations in LNG prices on our operations, we may enter into various derivative instruments in the future.

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Interest Rate Risk

Debt that we incurred under our credit facilities bore interest at variable rates and exposed us to interest rate risk. Interest is calculated under the terms of each facility based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “—Liquidity and Capital Resources—Long-Term Debt.” Assuming no change in principal amount remains outstanding as of June 30, 2020, the impact on interest expense of a 1% increase or decrease in the interest rate would be approximately $2.7 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Foreign Currency Exchange Risk

A substantial amount of our transactions, assets and liabilities are denominated in currencies other than U.S. dollars, such as Brazilian reais in respect of our Brazilian subsidiaries and investments, which receives income and pays expenses in Brazilian reais. Based on our Brazilian reais revenues and expenses for the six months ended June 30, 2020, a 10% depreciation of the U.S. dollar against the Brazilian reais would decrease our revenue by $0.2 million and decrease our expenses by $2.5 million.

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INDUSTRY

The LNG and Natural Gas Industry

Natural gas is in abundant supply globally and is the fastest growing fossil fuel, representing 24% of global energy demand and 23% of electricity generation in 2019. Innovation in natural gas extraction has resulted in a dramatic decrease in natural gas prices with Henry Hub prices dropping from over $13.00 per MMBtu at the end of 2005 to $2.22 in December 2019 with an expectation that such prices will stabilize at these lower levels going forward. Currently, however, much of the world’s natural gas reserves are not directly connected by pipeline to electricity producers and other end users. An efficient way to facilitate the transportation of natural gas to its end users is by converting it to LNG, a process which involves treating natural gas to remove impurities and then chilling it to approximately negative 162 degrees Celsius, a process generally referred to as “liquefaction.” In LNG form, natural gas is typically transported in bulk by containers or tankers hauled by rail or truck or by marine vessels, such as LNG carriers. Once delivered to its end destination, LNG can be reconverted to natural gas through a process referred to as “regasification.” Natural gas is then carried by pipeline for distribution to power stations and other natural gas customers, including small scale distribution and industrial users.

The following diagram displays the flow of natural gas and LNG from production to consumption.

The LNG supply chain involves the following components:

Exploring and drilling: Natural gas is produced and transported via pipeline to natural gas liquefaction facilities located along the coast of the producing country. With the advent of floating liquefaction, gas can also be piped to offshore liquefaction facilities.

Production and liquefaction: Natural gas is cooled to a temperature of negative 162 degrees Celsius, transforming the gas into a liquid, which reduces its volume to approximately 1/600th of its gaseous state. The reduced volume facilitates economical storage and transportation by ship over long distances, enabling countries with limited natural gas reserves, and limited access to long-distance transmission pipelines or concerns over security of supply to meet their demand for natural gas.

Shipping: LNG is loaded onto specially designed, double-hulled LNG carriers and transported overseas from the liquefaction facility to the receiving terminal or ISO containers.

Regasification: At the receiving terminal (either onshore or aboard FSRUs), the LNG is returned to its gaseous state, or regasified. It may also be transferred to small scale LNG vessels that deliver LNG to users nearby.

Storage, distribution, marketing & power generation: Once regasified, the natural gas is stored in specially designed facilities or transported to power producers and natural gas consumers via pipelines.

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Globalization of Natural Gas is Transforming the Energy Landscape.

Natural gas is the cleanest burning fossil fuel – producing substantially lower carbon dioxide, nitrous oxides, sulphur oxides and particulate emissions relative to coal, heavy fuel oil, diesel, and other fossil fuels with tangible benefits for air quality and greenhouse emissions. According to the EIA, natural gas-fired power plants in the U.S. emit 56% less CO₂ per kWh compared to oil-fired plants and 58% less CO₂ per kWh compared to coal-fired plants. Furthermore, emissions in the form of NO_x from natural gas are reduced by 79% compared to oil and 80% compared to coal. For SO_x, the reductions are almost 100% as compared to both oil and coal. Since 2010, it is estimated that coal-to-gas switching has eliminated 500 million tonnes of CO₂ globally, equivalent to replacing 200 million electric cars running on zero-carbon electricity on the road over the same period. According to the International Energy Agency, industrial activity accounts for the largest use of global energy (~29%) followed by transportation (~29%), residential (~21%), commercial and public services (~8%) and agriculture (~2%).

Natural gas currently accounts for a smaller proportion of global energy use (24%) than other fossil fuels such as coal (27%) and fossil fuel liquids (34%) providing a significant upside opportunity for converting energy generation from other fossil fuels to natural gas. According to the U.S. Energy Information Administration (“EIA”)’s 2019 Energy Outlook, growth in global electricity generation will be led by renewables and natural gas. Gas-fired power generation is complementary to renewable sources of energy given the intermittent nature of solar, wind, and hydroelectric power generation. In fact, the EIA forecasts that global natural gas consumption will increase 40% by 2050. Conversely, coal-fired electricity generation is expected to decline from 35% of total consumption in 2018 to 22% by 2050.

The U.S., Russia, and the Middle East are the largest producers of natural gas, accounting for 27.3 trillion cubic feet (“Tcf”), 23.5 Tcf, and 21.9 Tcf of production, respectively, or approximately 56% of global production. The largest exporters of LNG by 2018 global exports were Qatar (24%), Australia (21%), Malaysia (8%), the U.S. (7%), Nigeria (6%) and Russia (6%). The world’s major sources of natural gas are often disconnected from major sources of energy demand, particularly demand from developing markets. This mismatch presents a logistical challenge as natural gas in its gaseous state can only be efficiently transported by pipeline. To match the global sources of natural gas supply and demand, natural gas can be converted into LNG. Natural gas is cooled to a temperature of negative 162 degrees Celsius, transforming the gas into a liquid, which reduces its volume to approximately 1/600th of its gaseous state. In LNG form, natural gas can be efficiently transported to sources of demand in tanks hauled by truck, rail, or marine vessel. Upon reaching a distribution hub, LNG is offloaded and returned to its gaseous state through a process known as “regasification”. Despite the costs associated with liquefaction, transportation and regasification, LNG provides end-users increased access to clean, efficient and low-cost energy.

LNG Supply and Demand Are Poised for Significant Global Growth

LNG trade has seen double-digit growth over the last three years, with LNG demand forecasted to grow at 4% annually from 2019 to 2040. By 2025, this equates to an addressable market with over 450 Mtpa (approximately 740 million gallons per day) of LNG demand according to the Shell 2020 LNG Outlook Report. The commissioning of record amounts of LNG liquefaction capacity in 2018 enabled LNG trading to grow by 10%, reaching 420 Bcm per year. Historically, LNG contracts have been indexed to Brent crude prices; however, the dramatic build out of LNG liquefaction capacity, increased market liquidity, and the rise of spot trading has changed this dynamic. LNG traded in the spot market has grown from ~13% in 2010 to ~28% in 2019. LNG has become an increasingly independent, globally traded, liquid commodity. Over the last 24 months, this dynamic has resulted in the convergence of Asian and European LNG prices with US Henry Hub natural gas prices and the divergence from indexation to Brent. In the near term, development of additional LNG liquefaction capacity is expected to keep pace with rising global demand to keep LNG prices relatively stable.

Stability and transparency in price, coupled with readily available cargos, has made LNG an attractive source of fuel for commercial, industrial and transportation of various sizes, including customers who require smaller cargos. The use of natural gas in transportation is expected to more than quadruple from 2018 to 2050 according to the EIA’s 2019 outlook. LNG’s use for maritime shipping is also poised for enormous growth given the International Maritime Organization’s stricter fuel standards (“IMO 2020”), with IHS Markit predicting LNG’s use as bunker fuel will increase from approximately 10 million metric tons (“MMt”) in 2020 to 70 MMt in 2050. Despite the clear opportunity for substantial demand pull, the initial capital investment required to build infrastructure capable of accessing LNG presents a challenge for small scale consumers, creating a clear need for

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LNG infrastructure that is able to deliver LNG for this emerging class of customers. FSRU projects provide an attractive option to meet this need while reducing environmental disruption and offering greater geographic flexibility than onshore regasification facilities. Often, these facilities can be deployed in half the time, at half the cost on a per unit basis, and can be moved if demand requirements change. Additionally, the redeployment benefit that underpins floating assets facilitates access to less expensive financing than fixed onshore facilities. The capacity of FSRUs is often greater than the anchor user for which it is deployed, allowing for incremental users to benefit from the existing infrastructure. In 2019, there were 13 countries that exclusively imported LNG through FSRU and FSUs, constituting 25 Mtpas or 7% of global LNG demand.

LNG Demand in Brazil

Historically, Brazil’s electricity generation has been dominated by hydro-electric plants, which, as of December 31, 2019 accounted for 64% of 171.8 GW of total installed capacity compared to 25% for thermoelectric facilities, 10% for renewables, and 1% for nuclear. In 2010, hydroelectricity accounted for approximately 80% of Brazil’s electricity generation; however, enhanced environmental regulatory requirements in Brazil have restricted additional expansion of hydroelectric capacity. Furthermore, hydroelectric facilities in Brazil are subject to substantial reductions in output during periods of drought, exemplified in nation-wide

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energy rationing in 2001 and regional disruptions in 2014. As a result of the limitations of hydroelectric capacity, Brazil’s government has recognized that expanding power needs will be satisfied by alternative sources of energy including thermal, wind and solar power generation. Brazil’s Energy Research Office, EPE, has created a ten year energy plan calling for 62 GW of installed capacity to be added through 2029, of which 27 GW is expected to be thermal, 4 GW hydroelectric and 30 GW from other renewables. Increased thermal power generation capacity, particularly clean natural gas generation, will be critical for Brazil to address the intermittent nature of hydro, wind and solar power. There are also compelling reasons for non-gas Brazilian thermal plants to switch to natural gas, including the substantial benefits of using an environmentally cleaner fuel source compared to HFO or ADO and cost benefits with LNG costs of $2.80 per MMBtu as compared to $11.20 for HFO as of March 2020. Moreover, Brazil has implemented PROCONVE P-8 emission standards to regulate gas and particulate emissions from on-road heavy-duty vehicles which will increase demand for LNG-fueled vehicles, driving greater demand for LNG. Brazil’s heavy duty truck fleet (over 3,500 kg) is comprised of over 2.8 million vehicles, over 650,000 tractor trailers and 600,000 buses; representing a large market for displacement of gasoline and diesel with clean LNG. Total fuel consumption by Brazil’s truck fleet is estimated to be 0.92 million barrels per day, equivalent to 42 million tonnes of LNG per day. There are 23 million vehicles powered by natural gas worldwide, according to the U.S. Department of Energy, and Brazil has a long history of adopting alternative fuel technologies for transportation.

(1)	2018 Statistical Yearbook of Electric Energy of Empresa de planejamento Energético (EPE).

(2)	Ten-year Energy Expansion Plan 2029 (PDE 2029), Empresa de planejamento Energético (EPE).

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Supply and Distribution Constraints Have Inhibited Natural Gas Consumption in Brazil and Globally

Despite the economic and environmental benefits of natural gas, it accounts for only 11% of Brazil’s total energy consumption as of 2017 primarily as a result of supply and distribution constraints. Many of Brazil’s cities lack access to natural gas pipelines, as Brazil has only approximately 12,000 km of gas pipelines compared to 30,000 km of gas pipelines in Argentina despite having a landmass three times larger. Most of Brazil’s existing gas infrastructure is located in the south and southeast regions while distribution across the rest of the country is limited. This lack of sufficient infrastructure restricts the availability of gas in major demand centers. In addition, local distribution companies have monopolies over gas distribution in their geographies and are regulated at the state level. As a result, small scale customers depend primarily on diesel, LPG and heavy fuel oils for energy. Domestic production accounts for approximately 70% of Brazil’s natural gas supply with the remainder coming from imports via pipeline and LNG. Brazil’s sole major import pipeline originates in Bolivia and operates under a long-term agreement with YPFB. The long-term supply contract underpinning this pipeline is constrained by available supply from Bolivia. The pipeline currently has no contracted volumes beyond 2022 with shortfall expected to be made up partly by LNG imports. Development of sufficient LNG infrastructure will offer an effective way to alleviate supply and distribution constraints and expand natural gas use in the power, industrial and transportation sectors in Brazil and elsewhere around the world.

Transparent and Stable Power Regulations in Brazil

The Brazilian power market offers utilities and Independent Power Producers an established and transparent regulatory and pricing regime that is regulated across the country, as opposed to the multi-regional regulatory authorities in the U.S. and other major power markets. The primary electric power regulator is ANEEL, which is responsible for regulating existing power producers as well as establishing auctions for new generation projects, typically held up to 6 years in advance of new generation delivery requirements. Auction winners execute a PPA contract, called CCEAR, with each distribution company. The CCEAR contains standard, non-negotiable terms and conditions which are established by ANEEL. Distributors grant financial guarantees to generators in order to secure payments. Brazil’s PPAs are typically 25 year contracts structured such that power plants receive fixed capacity payments and a variable unitary payment based on total power dispatched. Dispatch is determined by ONS, the national system operator, based on merit order where the system marginal cost is greater than the individual plants variable cost or as a result of shortages in certain power generation sources i.e. hydroelectric or renewable. Generators are compensated for availability to dispatch and are entitled to a variable compensation for actual delivery. Revenues are escalated by an inflation and a commodity price index.

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BUSINESS

Overview

Our business activities are conducted through four reportable segments: FSRUs and Terminals, Power, LNG Carriers and Downstream Distribution. Our reportable segments comprise the structure used to make key operating decisions and assess performance. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and note 6 “Segment Information” to our audited consolidated financial statements included herein.

Terminals and Floating Storage and Regasification Units

As of August 2020, we have an operating FSRU terminal, the Sergipe Terminal, in Sergipe, Brazil, two FSRU terminals in advanced stages of development in Pará, Brazil, the Barcarena Terminal, and Santa Catarina, Brazil, the Santa Catarina Terminal, and more than fifteen other terminals worldwide that are in various stages of evaluation or development. Our fleet consists of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which are expected to be converted into FSRUs. As of June 30, 2020, we have invested $30 million for the anticipated conversion of one of these vessels into an FSRU for deployment at the Barcarena Terminal once an FID has been made and we anticipate a total investment of $75 million to $85 million for the conversion. We expect to continue the conversion and deployment of FSRUs for utilization as LNG storage, transshipment and regasification terminals as our business continues to grow.

Our terminals position us to become a critical supply source to customers in developing markets around the world where there is significant need for cheaper, cleaner and more efficient fuel sources. We anticipate significant demand from end-users in the power, utility, industrial, commercial and transportation industries. Upon completion of the Barcarena and Santa Catarina Terminals, we expect to be capable of receiving an aggregate of 2,370,000 MMBtu/d with storage capacity of 500,000 cubic meters, giving us a critical mass of scale in our base infrastructure investment and creating significant barriers to entry in our areas of operation.

Power Generation

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America, not including (i) the Sergipe Power Plant, a 1.5 GW thermal power station supplied by the Sergipe Terminal, which reached COD in March 2020, and (ii) the Barcarena Power Plant, a 605 MW thermal power station supplied by the Barcarena Terminal, which is expected to commence operations in 2025. Please see “—Our Current and Anticipated LNG-to-Power Infrastructure Network—Other Projects—Project Pipeline” for additional information.

Downstream Distribution

Our Current and Anticipated LNG-to-Power Infrastructure Network

Sergipe

Terminal. Our Sergipe Terminal located near Aracaju, the state capital of Sergipe, on the northeast coast of Brazil, commenced commercial operations in March 2020 and is a key component in Brazil’s first private-sector LNG-to-power project. The Sergipe Terminal is operated by CELSE, an entity wholly owned by CELSEPAR, a 50/50 joint venture between us and Ebrasil, an affiliate of Eletricidade do Brasil S.A., one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. Because CELSEPAR is indirectly jointly owned and operated with Ebrasil, it is treated as an equity method investment in our consolidated financial statements. The terminal’s assets consist of (i) our FSRU, the Golar Nanook, which is under a 25-year bareboat charter with CELSE, (ii) specialized mooring infrastructure and (iii) a dedicated 8 kilometer pipeline which connects to the adjacent Sergipe Power Plant. The Golar Nanook is financed through a twelve year sale-leaseback transaction with the right and obligation to repurchase the vessel at the end of the lease period. The balance of the infrastructure as well as our interest in the Sergipe Power Plant is owned through our joint venture, CELSEPAR.

Pursuant to the Sergipe FSRU Charter, the Golar Nanook generates approximately $44 million per year in bareboat charter earnings, indexed to the CPI, with operating expenditures passed through to CELSE. Pursuant to the terms of the Sergipe FSRU Charter, we expect total revenues less estimated operating costs, without adjusting for inflation, of $1.1 billion over the 25-year term. The charter terminates on December 31, 2044. In addition to the charter, we expect to generate incremental revenue in the Sergipe Terminal from downstream customers. The Sergipe Terminal is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. We expect the terminal to utilize approximately 230,000 MMBtu/d (30% of the terminal’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant at full dispatch. Subject to obtaining required consents, we expect to utilize the terminal’s remaining 560,000 MMBtu/d of capacity to provide natural gas to additional customers, including industrial, commercial, transportation and other end-users via truck loading facilities. See “—Detailed Description of our Operating and Advanced Stage Terminals—Sergipe—Description of Contractual Arrangements Related to Sergipe—Sergipe FSRU Charter.” We also intend to construct 30 kilometers of additional pipeline connecting the Sergipe Terminal to the regional natural gas distribution network and other downstream customers. As of the commencement of operations in March 2020, capital expenditures related to the Sergipe Terminal totaled approximately $280 million. While we do not anticipate any additional capital expenditures to complete the Sergipe Terminal, we expect CELSE to invest $20 million to $30 million to complete interconnections to the regional natural gas distribution network. CELSE has also entered into the Sergipe Supply Agreement, a long-term, 25-year supply agreement for LNG for the Sergipe Terminal with Ocean LNG, an affiliate of Qatar Petroleum. For the period from April 1, 2020 through June 30, 2020, net revenues generated from the Sergipe Terminal were $13.0 million.

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compared to diesel powered plants of similar capacity. The power plant was constructed pursuant to a lump sum turn-key EPC agreement with General Electric. CELSE also entered into an operation and maintenance agreement with General Electric pursuant to which General Electric will maintain and operate the Sergipe Power Plant. At full dispatch, the Sergipe Power Plant can supply up to 15% of total current power demand in northeast Brazil, a region with a population of more than 57 million people.

Following its bid award in a government power auction in April 2015, CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant will deliver power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years. These PPAs provide for guaranteed annual capacity payments of R$1.6 billion at an expected contracted EBITDA margin on gross revenue of 61% (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred). The fixed capacity payments are adjusted annually for the IPCA, the Brazilian inflation-targeting system, which has historically offset changes in the exchange rate between the U.S. dollar and the Brazilian real. Annual revenues less operating costs are expected to be R$1.1 billion. Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$41.0 billion. We also expect to generate incremental variable revenue during periods we elect to dispatch and sell power from the facility. Based on the terms of our PPAs, for the period from its commencement on April 1, 2020 through July 31, 2020, the Sergipe Terminal generated approximately R$527.9 million in fixed payments and R$83.5 million in variable payments.

From February 2010 through February 2020, the average spot price for electricity in the region where the Sergipe Power Plant is located was R$247 per MWh, with the lowest price recorded being R$12 per MWh and the highest price recorded price being R$823 per MWh. Assuming the sale of merchant power generated from LNG purchased at a price of $7 per MMBtu delivered at power plant, the average marginal cost of production over the same period would have been R$151 per MWh for the Sergipe Power Plant.

Future Expansion. We also own 37.5% of CEBARRA, our joint venture with Ebrasil, which owns expansion rights with respect to the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for up to 3.2 GW of power generation, including the capacity of the Sergipe Power Plant. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. Our ownership in CEBARRA is also accounted for under the equity method.

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Barcarena

Terminal. Upon the commencement of operations expected in the second half of 2021, the Barcarena Terminal will provide a strategic entry point for LNG to the north and northeast regions of Brazil, with a combined population of approximately 75 million that currently lacks the infrastructure necessary to support the region’s gas needs, and will be used as a hub for the distribution of LNG and natural gas for electricity generation, commercial and industrial customers, transportation and bunkering. We anticipate that the Barcarena Terminal will be anchored by several large-scale industrial and power customer contracts, including a contract with CELBA, a 50/50 joint venture between us and Evolution. The Barcarena Terminal will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. We will be the sole owner and operator of the FSRU and will control the balance of the terminal infrastructure through our ownership in CELBA. We expect to incur approximately R$200 million to R$250 million in capital expenditures to construct and initiate operations at the Barcarena Terminal, exclusive of the approximately $75 million to $85 million of capital expenditures required to convert one of our vessels to an FSRU. Contracts will be structured for either regasification of LNG or for the storage of LNG with take-or-pay obligations. In July 2020, we entered into a memorandum of understanding with Norsk Hydro to supply LNG to its Alunorte refinery, which will be the first operational customer for the Barcarena Terminal. We are in what we believe to be the final stages of negotiations with Norsk Hydro for approximately 80,000 MMBtu per day of regasification capacity at an average net tariff to Hygo of approximately $1.30/MMBtu and approximately 45,000 MMBtu per day of storage capacity at an average net tariff of approximately $0.50/MMBtu. Assuming FID on the power plant, CELBA will pay an amount of approximately $10 million annually for their required capacity of the power plant. The fixed capacity payments will be adjusted annually to offset changes in the exchange rate between the U.S. dollar and the Brazilian real. We expect to incur capital expenditures of approximately $13 million per year in connection with the operation of the Barcarena Terminal.

Power Generation. In October 2019, CELBA 2 was awarded multiple 25-year PPAs to support the construction of the Barcarena Power Plant, a 605 MW combined cycle thermal power plant to be located in the Brazilian city of Barcarena, State of Pará. The power plant will utilize LNG sourced and processed at the Barcarena Terminal for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019. We anticipate that the Barcarena Power Plant will commence operations in 2025, and we expect total capital expenditures by CELBA of approximately R$2.0 billion in order to complete construction. The PPAs provide for combined revenue from fixed capacity and dispatch charges of R$861 million per year. The fixed capacity charge is annually adjusted for the IPCA, which has historically offset changes in the exchange rate between the U.S. dollar and Brazilian real. The fixed dispatch charge is based on fuel-pass through with a margin. We expect our operations to generate approximately 27% contracted EBITDA margin on gross revenue (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred). Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$21.5 billion.

Santa Catarina

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LNG to the Santa Catarina Power Plant, a 600 MW regional power plant, for which we have an option to purchase up to 100% of the equity interest. We intend to participate in the next planned power auction related to the potential Santa Catarina Power Plant (which has been delayed due to COVID-19). The construction of the Santa Catarina Power Plant is contingent upon winning this power auction and, should we win that auction, we would expect to commence operation of the Santa Catarina Terminal in 2022. We expect to incur approximately $50 million to $75 million in capital expenditures for terminal construction and pipeline interconnection in Garuva, exclusive of the approximately $75 million to $85 million of capital expenditures required to convert one of our vessels to an FSRU. While the Santa Catarina Terminal currently has no firm capacity contracts, we believe there is significant demand from multiple potential end-users, including power generation, industrial, commercial, transportation and residential customers, including the potential adjacent Santa Catarina Power Plant.

Suape

Terminal. In March 2020, we signed a Protocol of Intentions with the government of the State of Pernambuco, Brazil to develop an LNG import terminal in the Port of Suape, the Suape Terminal, located in the northeast region of Brazil, which has a population of approximately 57 million. We intend to install an LNG carrier with storage capacity of a minimum 125,000 cubic meters to act as an FSU. The Suape Terminal will connect to onshore truck loading facilities to facilitate loading of LNG ISO containers for distribution to industrial, commercial and residential offtakers for regions that are underserved or not served by traditional pipeline networks. We have also secured contracts with Copergás to facilitate the distribution of LNG or natural gas to such offtakers. The terminal will also act as a transshipment location to break bulk for downstream distribution. We expect to take FID on the Suape Terminal in the third quarter of 2020. We estimate initial volumes for onshore distribution to be equivalent to approximately 22,000 MMBtu/d with commencement of operations in the first half of 2021. Final development of the project remains subject to regulatory approvals and finalization of commercial agreements. We expect to incur approximately $10 million to $15 million in capital expenditures required to construct and initiate operations at the Suape Terminal. Subject to securing contracts from offtakers requiring regasification services, we may consider replacing the FSU with an FSRU. In addition, a local distribution company is considering constructing a natural gas pipeline to connect the Suape Terminal to the local distribution network. In its initial phase, we estimate regasification volumes related to the pipeline of up to 500,000 cubic meters/d with regasification operations expected to begin in the second half of 2022.

Other Projects

São Marcos, Brazil. We have partnered with Eneva S.A. to form São Marcos, a 50/50 joint venture developing the São Marcos Terminal, an integrated LNG-to-power terminal in São Luis, State of Maranhão, Brazil, and a power plant with 3.2 GW of installed capacity. We have applied for preliminary permits and environmental licenses and we anticipate that the São Marcos Terminal would supply natural gas to the power plant, which would be developed if awarded a PPA.

Ivory Coast, Africa. In 2017, we were awarded a 20-year charter of an FSRU off Abidjan, Ivory Coast. The charter will commence upon FID and is expected to generate average annual bareboat earnings of approximately $30.0 million. Golar LNG currently owns a 6% equity interest in the Ivory Coast LNG terminal consortium, which is in the process of being transferred to us. Our local partners in this project include major integrated independent and state-owned energy companies.

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Region	Annual Regas Capacity (TBtu)	Expected Anchor Customer	Size of Power Plant (MW)	Expected Anchor Customer Regas Capacity Utilization	Estimated Startup	Estimated Total Capex Required ($MM)
Awaiting FID
West Africa	149	Power Plant	150 - 500	10%	2021-2022	250
Feasibility / FEED Study
Latin America		TBD	TBD		2022-2023	TBD
Latin America		TBD	TBD		2022-2023	TBD
Latin America	186	Pipeline / Power Plant	TBD		2021-2022	310
West Africa	186	Power Plant	1,000 - 2,000	41%	2023+	325
West Africa	47	Power Plant	150 - 500	33%	2021-2022	165
Southeast Asia	186	Power Plant	3,000+	41%	2022	310
South Asia	47	Power Plant	150 - 500	33%	2022	185
Early Stage Development
Latin America	186	Pipeline / Power Plant	TBD		2022	310
Latin America	186	TBD	TBD		2023+	250
Southern Africa	186	Power Plant	1,000 - 2,000	55%	2022	310
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	125
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	125
Southeast Asia	186	Power Plant	150 - 500	14%	2023+	250
Southeast Asia	279	Power Plant	3,000+	92%	2023+	300
South Asia	186	Pipeline / Power Plant	TBD		2022	250
Europe	186	Industrial / Power Plant	TBD		2023	250

In addition, we are currently in discussions to acquire interests in long-term PPAs related to a brownfield opportunity in the State of Bahia, Brazil.

Downstream Distribution

We expect to capitalize on our strategic locations and LNG processing capacity by establishing a broader network of LNG distribution channels to penetrate additional downstream demand. To that end, we are in the process of establishing eight LNG and natural gas distribution hubs across Brazil from which we expect to pursue downstream customers. These eight hubs consist of our Sergipe, Barcarena, Santa Catarina and Suape Terminals as well as small scale receiving terminals in São Paulo, Rio de Janeiro, Itaqui and Pecem. In addition, we have entered into a strategic partnership with BR Distribuidora, Brazil’s leading fuel distribution company, as discussed in more detail below.

In order to facilitate our distribution of LNG through our eight hubs, we have entered into a bareboat charter agreement for one 7,500 cubic meter, small-scale LNG carrier from Avenir LNG Limited. The Avenir vessel is expected to be deployed in Brazil for three years with an option to extend. We anticipate that the vessel will be delivered to us from the shipyard in the first half of 2021.

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Partnership with BR Distribuidora

During the first quarter of 2020, we entered into a strategic partnership with BR Distribuidora, Brazil’s leading fuel distribution company, to serve as its exclusive provider of LNG for use in Brazil’s transportation and industrial sectors. Using BR Distribuidora’s 94 distribution centers and 7,600+ fuel stations across Brazil, we expect to leverage our existing infrastructure and LNG supply chain expertise to increase the accessibility of LNG to downstream end-users using a combination of marine and onshore solutions. According to ANP, diesel consumption in Brazil stood at 56 million cubic meters (equivalent to approximately 37 million tonnes of LNG) in 2018 with total consumption of diesel, gasoline, LPG, jet fuel, fuel oil and ethanol amounting to 136 million cubic meters (equivalent to approximately 80 million tonnes of LNG). BR Distribuidora reported a total sales volume of 42 million cubic meters in 2018 – making it the largest distributor of fuels in the Brazilian market. In connection with this partnership, we have executed letters of intent with three potential downstream customers with total demand of approximately 4,200 MMBtu/d. Once our downstream logistics systems commence operations we expect to enter into supply contracts in order to secure LNG volumes sufficient to meet our contractual delivery obligations. BR Distribuidora, as a major transportation end-user itself, also intends to replace its hired fleet of approximately 5,000 diesel trucks with LNG-powered vehicles at a stated goal of 20% annually, for which we will serve as the exclusive LNG supplier.

The average national retail price for diesel in Brazil at the end of 2019 was R$3.751 per liter – equivalent to approximately $27 per MMBtu. Based on our current value chain, we expect to be able to deliver LNG to be used as fuel for trucks at a price between $15 and $18 per MMBtu at the pump, which contributes to a reduction in overall fuel cost for trucks operated on LNG by 22% to 35%, based on observed fuel consumption for both LNG- and diesel-powered vehicles. Actual reduction in total fuel cost will depend on load carried, road surface, geography, driver pattern and several other variables.

Other Downstream Customers in Brazil

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The map below illustrates the location of our combined downstream distribution hubs in Brazil.

Other Downstream Opportunities Globally

Beyond Brazil, we have identified key markets and countries of focus where distribution of LNG can be facilitated from the use of terminal infrastructure we are currently developing through our project pipeline. A bespoke study of thirteen focus countries performed by Rystad Energy on the potential for diesel-to-LNG conversion of trucks indicates Mexico, South Africa, Thailand and Colombia, among others, as markets where our approach currently being implemented in Brazil could be replicated. These markets have large fleets of HCV and high diesel prices that, when combined, form a strong value proposition for LNG as an alternative fuel. Based on total diesel demand from commercial vehicles and buses in the thirteen focus countries, Rystad Energy estimates diesel consumption in such countries of more than 2.6 million barrels per day with prices ranging from $15 per MMBtu to more than $30 per MMBtu as of February 2020.

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In addition to our owned assets, our relationship with one of our shareholders, Golar LNG, provides us with the opportunity to access capacity on their existing fleet of strategically located FSRUs under contract, which would enable break bulk operations to facilitate distribution of LNG worldwide and expand our geographical footprint. Additionally, we may charter or acquire FSRUs from relevant subsidiaries or affiliates of Golar LNG upon expiry of the current contracts to further develop our business.

Gas Marketing and Trading

LNG Technology and Other Initiatives

As part of our efforts to reduce emissions, we have entered into an agreement with Galileo, whereby Galileo will deliver two LNG production clusters for the production of Bio-LNG. This technology captures methane produced from the decomposition of organic waste, including from landfills and the residual fibers from crushing sugar cane for sugar production. The clusters will be installed in the State of Bahia and the State of São Paulo, and can produce up to 45 tons of Bio-LNG per day, in aggregate. We expect to commence operations using Galileo’s technology by the end of 2020. Our goal is to have 20% of our natural gas portfolio come from biomethane production.

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turbines installed at the Sergipe Power Plant can use hydrogen as a fuel source after certain upgrades. We are also considering adding hydrogen production facilities to our existing sites to leverage locally available renewable energy sources to produce energy with a reduced carbon footprint.

Natural Gas Market and Market Access

Approximately 850 million people still do not have access to electricity, according to the International Energy Agency 2019 World Energy Outlook. Globally, many developing countries lack access to affordable fuel in order to generate electricity and large parts South America, Africa and Asia consume less than 3,000 MWh of electricity per capita because of high costs and lack of infrastructure. According to Bloomberg NEF, 63 out of 107 reported non-OECD countries have a cost of commercial electricity in excess of $100 per MWh. We believe we are well-positioned to bring low-cost and clean LNG to these countries to fuel further development.

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Large-scale power plants utilizing natural gas as fuel with high efficiency have the ability to produce electricity at marginal costs (defined as variable cost and cost of fuel excluding local taxes) as low as $47 per MWh when cost of gas is $7 per MMBtu delivered at power plant. Comparing the marginal cost of electricity production to a selection of countries from Bloomberg NEF’s Climatescope study that are currently importing or considering importing LNG shows the impact LNG-fired electricity generation could have on reducing electricity prices.

Economic development, increasing populations and rising standards of living will increase demand for homes, businesses and transportation, and the associated necessary energy use. According to Exxon Mobil’s 2019 Outlook on Energy, global electricity demand is expected to rise 60% by 2040. To satisfy these power needs with gas-fired power would require approximately 310 TBtu of LNG per day (based upon an estimated conversion of 2,500 gallons per day of LNG for every MW of power capacity). We believe that many countries around the world – keenly focused on both cost and environmental concerns – will increasingly look to natural gas to displace more environmentally damaging fuels such as HFO, ADO and coal, particularly because natural gas can be significantly less expensive than these higher polluting fuels.

In Brazil, electricity generation has been historically dominated by hydroelectric power, which as of April 2020 accounted for 64% of Brazil’s 171.8 GW of total installed capacity compared to 25% for thermoelectric facilities, 11% for renewables and 1% for nuclear. In 2010, hydroelectricity accounted for approximately 80% of Brazil’s electricity generation; however, environmental regulatory hurdles in Brazil have restricted further expansion of hydroelectric capacity. In addition, hydroelectric facilities in Brazil are subject to substantial reductions in output during periods of drought, resulting in nation-wide energy rationing in 2001 and regional disruptions in 2014. As a result of the limitations of hydroelectric capacity, Brazil’s expanding power needs will be satisfied by alternative sources of energy including thermal, wind and solar power generation. The ten-year energy plan of the Brazilian Energy Research Company, EPE, calls for 60 GW of installed capacity to be added through 2029, of which 20 GW will be thermal, 5 GW hydro, 1 GW nuclear and 33 GW other renewables. Increased thermal power generation capacity, particularly cleaner natural gas generation, will be critical for Brazil to address the intermittent nature of hydroelectric, wind and solar power. There are also compelling reasons for existing non-gas Brazilian plants burning HFO or ADO as fuel to switch to natural gas, including the substantial benefits of using an environmentally cleaner fuel source compared to HFO or ADO, coupled with the cost benefits of LNG ($2.80 per MMBtu versus $11.20 for HFO as of March 2020). Moreover, Brazil has implemented PROCONVE P-8 emission standards to regulate gas and particulate emissions from on-road heavy-duty vehicles increasing the value proposition for LNG-fueled vehicles and driving greater demand for LNG.

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Brazil has only approximately 12,000 km of gas pipelines compared to 30,000 km of gas pipelines in Argentina despite having a landmass three times larger and population more than four times larger than that of Argentina. Most of Brazil’s existing gas infrastructure is located in the south and southeast regions while distribution across the rest of the country is limited. This lack of sufficient infrastructure restricts availability of gas in major demand centers. In addition, local distribution companies have monopolies over gas distribution in their districts which are regulated at the state level. As a result, small scale customers depend primarily on diesel, LPG and HFO for energy. Domestic production accounts for approximately 70% of Brazil’s natural gas supply, with the remainder coming from imported gas via pipelines and LNG. The only major gas import pipeline originates in Bolivia and sources supply from YPFB. The long-term supply contract underpinning this pipeline is constrained by available supply from Bolivia. The pipeline has no contracted volumes beyond 2022 with shortfalls expected to be made up partly by LNG imports. Development of sufficient LNG infrastructure will offer an effective way to address supply and distribution constraints and expand natural gas use in the power, industrial, and transportation sectors in Brazil and elsewhere around the world.

We plan to capitalize on this growing supply-demand gap and create new markets for natural gas by developing downstream distribution networks, particularly in areas with significant demand. We design our downstream distribution networks to center around FSRU terminal “hubs,” and we target areas that have historically been underserved by regional pipelines, increasing access to natural gas and LNG via transportation by truck and barge.

LNG Supply

Competitive Strengths

We believe we are well-positioned to execute our business strategies and deliver on our long-term growth objectives based on our competitive strengths:

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LNG-powered vehicles, we expect it will replace its hired fleet of diesel trucks at its stated goal of 20% annually, for which we will serve as the exclusive LNG supplier. We have also established discrete, project-specific partnerships with experienced developers in our power generation projects, such as Ebrasil, one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. Together with our partners, we intend to develop natural gas-fired power plants and offer less expensive and cleaner energy to Brazil’s power grid, including the Sergipe Power Plant. The strength of these partnerships is further enhanced by our Sponsor, Golar LNG, a leading independent maritime LNG asset owner and operator by fleet count, with 27 vessels totaling an aggregate 2,108,687 Dwt and 4,005,000 cubic meters, providing us deep maritime expertise and enhancing our integrated service offering.

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Well-positioned in Brazil, a market we believe is poised for substantial near- and long-term growth in natural gas consumption. We believe Hygo is well-positioned to capitalize on growth in Brazil’s energy demand which is driven by attractive, underserved and diverse end-markets. Demand for electricity in Brazil is forecasted to grow 30% over the next decade. BP’s 2019 Energy Outlook forecasts Brazil’s natural gas consumption to increase 114% (3.4% per annum) from 2017 to 2040 compared to an increase of only 0.4% per annum for coal and 1.4% per annum for oil. We believe our existing and planned LNG infrastructure positions us well to capitalize on a significant oil-to-gas switching opportunity as diesel, HFO and LPG are phased out in favor of cleaner natural gas. Additionally, we believe there is a large addressable market to convert over-the-road transportation assets, such as trucks and buses, to LNG, an opportunity for which we are uniquely positioned. We have established a strategic partnership with BR Distribuidora, which we believe enhances our commercial reach, expands our gas distribution channels and will help accelerate the conversion from traditional fossil fuels to LNG.

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development. We are proactive in educating communities and businesses in the regions in which we operate regarding the economic and environmental benefits, as compared to other fossil fuels, of the long-term adoption of LNG and natural gas as cleaner and more efficient fuels.

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Business Strategies

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Our History and Relationship with Our Sponsors

We were formed in May 2016 by Golar LNG. In June 2016, Stonepeak acquired a 50% common equity interest in us from Golar LNG and 20,000,000 preference shares from us. We will use the net proceeds from this offering to fund capital expenditures for the growth of our business as well as to redeem all of the preference shares held by Stonepeak. Following the completion of this offering, our Sponsors will retain a significant interest in us through their ownership of 100,000,000 common shares, representing approximately 81.2% of the voting power (or approximately 79.0% if the underwriters’ option to purchase additional common shares is exercised in full).

Prior to consummation of this offering, the entity that holds Stonepeak’s investment in Hygo (Stonepeak Infrastructure Fund II Cayman (G) Ltd.) will merge with and into Hygo, with Hygo surviving the merger. Following consummation of this offering, Stonepeak’s investment in Hygo will be held through Stonepeak Golar Power Holdings (Cayman) LP. In connection with the Recapitalization, the preference shares of Hygo held by Stonepeak will be redeemed in exchange for the right to receive an amount of cash equal to the redemption price of such preference shares, with such cash to be paid with a portion of the proceeds of this offering. For additional information regarding the preference shares and the terms thereof, please see “Description of Share Capital—Stonepeak Preference Shares.”

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Simplified Organizational and Ownership Structure After this Offering

(1)	BR Distribuidora has an option to acquire 50% of this entity, which expires six months after certain conditions precedent have been met. See “—BR Distribuidora Partnership.”

(2)

Our History and Development

We were incorporated on May 19, 2016 by Golar LNG, pursuant to the Companies Act, as an exempted company and registered in the Bermuda register of companies with the name “Golar Power Limited.” In June 2016, Stonepeak acquired a 50% common share interest in us from Golar LNG and 20,000,000 preference shares from us. On August 13, 2020, we registered in the Bermuda register of companies our change of name from “Golar Power Limited” to “Hygo Energy Transition Ltd.” Our principal executive offices are located at 2^nd Floor, S.E. Pearman Building, 9 Par-la-Ville Road, Hamilton HM 11, Bermuda and our telephone number is +1 (441) 295-4705.

We have appointed Puglisi & Associates, whose address is 850 Liberty Avenue, Suite 204, Newark Delaware 19711, as our agent upon whom process may be served in any action brought against us under the laws of the United States. Please see “Service of Process and Enforcement of Civil Liabilities” for more information.

The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov. Our internet address is www.hygoenergy.com. The information contained on our website is not incorporated by reference and does not form part of this Prospectus.

Since our inception, we have made a number of investments, acquisitions and dispositions:

•

In connection with our formation in May 2016, Golar LNG contributed its interests in certain of its wholly owned subsidiaries that own the Golar Penguin, the Golar Celsius and the Golar Nanook as well as its initial 25% investment in CELSE. In exchange for the contributed assets, Golar LNG received 46,950,154 common shares in us.

•	In October 2016, we acquired an additional 25% interest in CELSE for $45.9 million.

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•	In November 2016, we and our subsidiary, GPB2, entered into an agreement with Ebrasil to establish CEBARRA and acquired an aggregate of 7,500 common shares at a subscription price of R$1.00 per share, representing a 75% interest in CEBARRA.

•	In September 2017, we entered into an agreement with Evolution to establish CELBA and we acquired 5,000 common shares at a subscription price of R$1.00 per share, representing a 50% interest in CELBA.

•	In July 2018, we sold 750 common shares in GPB2 at a subscription price of R$1.00 per share, representing a 50% interest in GPB2, to Evolution. Following such sale, we owned a 50% interest in GPB2 and a 37.5% indirect interest in CEBARRA.

•	In March 2019, we entered into an agreement with Eneva S.A. to establish São Marcos and we acquired 3,000,500 shares at a subscription price of R$1.00 per share, representing a 50% interest in São Marcos.

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In January 2020, our subsidiary, Golar Brazil, established CELBA 2, with CELBA, BEP and OAK Through Golar Brasil and our proportionate ownership in CELBA, we own 50.0% of CELBA 2. CELBA 2 was incorporated solely to comply with specific requirements of the related power auction in Brazil, and therefore is expected to be party to the Barcarena PPAs.

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In February 2020, we entered into a strategic partnership with BR Distribuidora. In connection with this partnership, our subsidiary, Golar Brazil, formed Golar Power Distribuidora de Gás Natural Ltda. (“Golar Distribuidora”). BR Distribuidora has an option to purchase 50% of Golar Distribuidora within six months. For more information, see “—BR Distribuidora Partnership.”

Our ownership interests in our various joint ventures and investments is as follows:

Investment/Joint Venture	Ownership Interest	Operations/Assets	Other Owners
CELSEPAR	50%	Sergipe Power Plant and Terminal	Ebrasil Energia Ltda.
CELBA	50%	Barcarena Power Plant	Evolution Power Partners S.A.
CELBA 2⁽¹⁾	50.0%	Barcarena power purchase agreements	CELBA, BEP and OAK
CEBARRA⁽²⁾	37.5%	Sergipe expansion rights	Ebrasil Energia Ltda., Evolution Power Partners S.A.
São Marcos	50%	Future LNG Terminal in São Luis	Eneva S.A.

(1)

(2)	We hold our investment in CEBARRA through GPB2, a 50/50 joint venture between us and Evolution.

Our Vessels

As of December 31, 2019, our current fleet comprises two LNG carriers undergoing or being contemplated for conversions and one FSRU. The following table lists our current fleet of LNG carriers and FSRU as of December 31, 2019:

Golar Nanook

2018

170,000

Marshall

Islands

FSRU

CELSE

2045

Golar Celsius

2013

160,000

Marshall

Islands

LNGC

(TFDE)

Cool Pool

n/a

Golar Penguin

2014

160,000

Marshall

Islands

LNGC

(TFDE)

Cool Pool

n/a

FSRUs. FSRUs represent a flexible, proven, expedient and cost effective means for countries and regions to import LNG by offering a unique solution for LNG terminals. Because they are moored offshore, FSRU facilities are significantly less likely than onshore facilities to be significantly delayed or blocked by local communities hesitant to permit land-based LNG processing facilities. This is especially true for facilities intended to serve

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highly populated areas where there is high demand for natural gas. Planning, siting, permitting and constructing a traditional, land-based LNG terminal typically takes several years. In comparison, FSRU projects typically take less than 24 months to execute and have been implemented in as little as six months. In addition, FSRUs are considerably less capital intensive than land-based LNG terminals. Converting an LNG carrier for regasification or storage creates a self-contained LNG terminal that can reduce overall costs substantially.

The Cool Pool. We currently participate in an LNG carrier pooling arrangement, which we refer to as the Cool Pool, the manager of which markets the participating vessels in the LNG shipping spot market. The vessel owner continues to be fully responsible for the manning and technical management of their respective vessels. The Cool Pool allows pool participants to optimize the utilization of their vessels through improved scheduling ability, cost efficiencies and common marketing. The objective of the Cool Pool is to serve the transportation requirements of the LNG shipping market by providing customers with reliable, flexible and innovative solutions to meet increasingly complex shipping requirements. As of June 30, 2020, Golar Celsius and Golar Penguin operated in the Cool Pool under index-linked contracts with charterers. We expect that each of these LNG carriers will continue participate in the Cool Pool until an FID is reached on their conversions to FSRUs.

Detailed Description of our Operating and Advanced Stage Terminals

Sergipe

The Sergipe Project includes both the Sergipe Power Plant and the Sergipe Terminal and includes five major interconnected components: the Golar Nanook FSRU, a mooring system, an offshore/onshore gas pipeline, the Sergipe Power Plant and the related transmission line.

Sergipe Terminal

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Chartered FSRU: Golar Nanook, a recently converted FSRU, moored 6.5 kilometers offshore with a storage capacity of 170,000 cubic meters and an LNG regasification capacity of up to 21,000,000 cubic meters per day at maximum capacity. The Golar Nanook is operated by Hygo and is currently in service to CELSE pursuant to a 25-year charter, which entitles CELSE to 100% of the capacity of the Golar Nanook. The FSRU is able to store and regasify LNG in order to provide fuel to the Sergipe Power Plant as well as other end users. LNG carrier ships will moor adjacent to Golar Nanook to deliver and offload LNG cargo.

•	Gas Pipeline: A 16” to 18” subsea and underground gas pipeline running 6.5 kilometers offshore and 1.5 km onshore to connect the regasified LNG (RLNG) from the offshore terminal to the Sergipe Power Plant gas terminal point.

•

Mooring System: The subsea soft yoke mooring system allows vessels to weathervane 360 degrees from their mooring point to accommodate ocean currents and winds, and is designed so the Golar Nanook may function at capacity for the duration of its expected use. Yoke mooring systems have a long track record for use offshore in the oil and gas industry. The mooring point for the Golar Nanook is 6.5 kilometers offshore from the power plant’s location, at a depth of 20 meters.

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Sergipe Power Plant

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Power Plant: A combined cycle power plant utilizing General Electric’s advanced gas turbine technology, the 7HA.02. The 7HA.02 is the largest operational gas turbine in the 60 Hz market offered by any original equipment manufacturer. The 7HA.02 is an upgrade of a prior model, the 7HA.01, with approximately 30% increased generating capacity, totaling 382 MW for a single gas turbine.

•

Transmission Line: A 33-kilometer 500 kV double circuit transmission line and air-insulated bay expansion of an existing substation in the State of Sergipe that can receive up to 3 GW of electricity. This transmission line will connect to a new continuous transmission line that is currently under construction. Once the continuous transmission line is complete, the transmission line at Sergipe will be contributed to the concessionaire which operates the continuous transmission line.

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Within Brazil’s power generation system, the Sergipe Power Plant will be a “reserve plant.” The National Electricity System Operator (Operador Nacional do Sistema Elétrico), or “ONS,” dispatches generation and transmission resources on a price merit order of least-cost basis according to its computational models. Its models are calibrated to minimize operating costs while considering the supply variability of energy inputs. Only after hydropower generation is maximized does the ONS look to wind power generation, followed by solar power and, finally, thermal power, only when needed to fill any energy demand gap unmet by the first three energy sources. Under this hierarchical power generation system, contracts for thermal power generation are structured as “availability” contracts, designed to compensate the availability of thermal power generation, as opposed to its actual dispatch.

Availability contracts, such as CELSE’s PPAs, provide for annual fixed payments in exchange for which CELSE ensures the availability of its Power Plant as a reserve plant to generate thermal power, according to the physical capacity of the Power Plant. If dispatched upon ONS’s order, CELSE’s revenues under the PPAs would include, in addition to the fixed charge, the variable costs associated with energy production. In addition, the Sergipe Supply Agreement and the PPAs are structured in a way that ensures LNG supply availability in the case of a request of dispatch while not requiring CELSE to maintain levels of LNG inventory and storage that are or may not be necessary for energy generation under the PPAs.

We have the ability to expand the Sergipe Power Plant with a second power plant, the rights for which are owned by CEBARRA. This expansion would not affect the Sergipe Power Plant’s revenue generation, but may reduce overall maintenance and other costs as a result of certain economies of scale. Any expansion of the Sergipe Power Plant will be subject to prior approval by the CELSE’s lenders.

LNG Supply

LNG for the Sergipe Power Plant is supplied by Ocean LNG Limited under an agreement providing for a contract price calculated on a monthly basis as a factor of (i) the amount of LNG delivered; and (ii) quoted crude oil prices. CELSE has designed an inventory management system that seeks to match supply to forecasted dispatch as closely as possible.

Description of Contractual Arrangements Related to Sergipe

We have provided below a description of certain agreements related to the Sergipe Terminal and the Sergipe Power Plant. This summary does not purport to be complete and is subject to, and is qualified in its entirety by reference to, the provisions of the actual agreements filed as exhibits hereto.

Sergipe PPA Agreements. In April 2015, Genpower Participações S.A. (“Genpower”) and GPE Sergipe Empreendimentos SPE Ltda. (“GPE SPE”) executed 26 long-term PPAs following a bid award in a government power auction. In March 2018, Genpower and GPE SPE assigned CELSE the long-term PPAs with 26 concessionaires across Brazil for the availability and production of electricity to be generated by the project. The PPAs provide for the

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commencement of supply of energy on January 1, 2020, with 25-year terms. CELSE’s revenues for the sale of energy under the PPAs include (i) a fixed Brazilian real denominated revenue component (indexed for inflation) for the availability of the Power Plant, and (ii) a variable revenue component based on the MWh amount of energy generated, if any. Each purchaser under the PPAs has executed a Security Agreement, providing for the encumbrance of part of each purchaser’s revenues to ensure the satisfaction of its payment obligations under its PPAs.

Sergipe FSRU Charter. CELSE has entered into an FSRU Charter Agreement with Golar Nanook UK, a wholly owned subsidiary of Hygo, for chartering of the Golar Nanook. CELSE has leased the FSRU on bareboat charter from Golar Nanook UK for a period of 25 years (the “Agreement Period”). Pursuant to the Sergipe FSRU Charter, CELSE is responsible for generally managing the Sergipe Terminal, including all safety, security and environmental aspects. During the Agreement Period, CELSE pays to the Golar Nanook UK a daily rate set, which shall be readjusted annually by the consumer price index (as published by the U.S. Bureau of Labor Statistics). If the Sergipe PPAs are terminated, CELSE may terminate the FSRU Charter Agreement, provided that CELSE shall have (i) given the Golar Nanook UK at least one month notice of termination and (ii) solely in the event such termination has resulted from CELSE’s fault, paid an early termination payment in an amount equivalent to one year of Rates to be calculated proportionately to the remaining balance of the contractual term. In addition, CELSE has the right to utilize 100% of the capacity at our Sergipe Terminal pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Terminal, we will need the consent of CELSE and the senior lenders under CELSE’s financing arrangements. While we expect to come to an agreement that will enable us to utilize this excess capacity, it has not yet been negotiated.

Sergipe O&M Agreement. On December 22, 2016, CELSE entered into the O&M Agreement with affiliates of General Electric, the “Plant Operators,” regarding the operation and maintenance services for the Sergipe Power Plant. The scope of the work contracted with the Plant Operators comprises, among others, pre-mobilization and mobilization services, outage maintenance planning, planned and unplanned maintenance, administrative and operation services and demobilization.

The Sergipe LNG Supply Agreement. On November 10, 2016, CELSE and Ocean LNG entered into the Sergipe Supply Agreement for the supply of LNG to the Sergipe Terminal. The contract price under the Sergipe Supply Agreement is calculated on a monthly basis as a factor of (i) the amount of LNG delivered; and (ii) quoted crude oil prices. Unless terminated as permitted under the agreement’s terms, the contract will not expire before 2036, which term could be extended to 2044, subject to certain conditions. For each contract year during the term of the Sergipe Supply Agreement, Ocean LNG must sell and deliver to CELSE a specified base annual contract quantity, calculated as the product of (i) a gross heating value of 68,400,000 million British thermal units, or MMBtu, and (ii) the number of days in the contract year, divided by the number of days in the relevant calendar year. The Sergipe Supply Agreement provides for adjustments to the base annual contract quantity, depending on, among other variables, accumulated amounts and the Sergipe Power Plant’s downtime.

If CELSE takes less than the full number of scheduled cargoes per year under the Sergipe Supply Agreement, CELSE will be required to pay Ocean LNG a cancellation fee per cargo according to a formula based on the number of the cargoes not taken, subject to a cap of $110 million for every five-year period, or an aggregate of $550 million over the 25-year term. If Ocean LNG fails deliver a contracted cargo of LNG, Ocean LNG will be required to pay CELSE up to 50% of the cost of the undelivered cargo. The amount of CELSE's take-or-pay obligations under the Sergipe Supply Agreement is offset by the fixed capacity charges under the PPAs related to the Sergipe Power Plant.

The Sergipe Supply Agreement is structured to meet the LNG supply demands of the Sergipe Power Plant. All of the Sergipe Terminal’s storage capacity and approximately 40% of its regasification capacity is allocated to the Sergipe Power Plant. Therefore, if CELSE took 100% of the LNG cargos available to it under the Sergipe Supply Agreement, the LNG delivered pursuant to the Sergipe Supply Agreement would represent 40% of the regasification capacity and 100% of the storage capacity of the Sergipe Terminal. We anticipate that the LNG needed to supply future additional off takers from the Sergipe Terminal will be sourced from the spot market or pursuant to other long-term supply agreements, depending on the nature of the end user.

Barcarena

Upon commencement of operations expected in the second half of 2021, the Barcarena Project will include both the Barcarena Power Plant and the Barcarena Terminal. We anticipate that it will include five major interconnected components: an FSRU, a mooring system, an offshore/onshore gas pipeline, the Barcarena Power Plant and the related transmission line.

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Barcarena Terminal

FSRU: Depending on the requirements of our offtakers, we will deploy one of our converted LNG carriers or the Golar Tundra, an FSRU currently owned by Golar LNG, to service the Barcarena Terminal. If we deploy a converted LNG carrier, we will convert either the Golar Celsius or the Golar Penguin, which are identically designed, into an FSRU that will be capable of processing up to 790,000 MMBtu/d and storing 160,000 cubic meters of LNG. We expect total capital expenditures of approximately $85 million in order to complete the conversion of one of these vessels, of which $30 million has been paid to date. If we need additional storage capacity, we intend to deploy the Golar Tundra. The Golar Tundra is capable of processing up to 790,000 MMBtu/d and storing 170,000 cubic meters of LNG. We have no agreement with Golar LNG to acquire the Golar Tundra and, accordingly, the terms of acquiring the Golar Tundra have not been determined. We are currently considering a number of alternatives, including purchasing the Golar Tundra from Golar LNG, swapping the Golar Penguin or Golar Celsius for the Golar Tundra or chartering the Golar Tundra for a period of time. There can be no assurance that we are able to reach an agreement with Golar LNG for the acquisition or charter of the Golar Tundra on favorable terms or at all.

The FSRU will be located at a fixed jetty structure approximately 1,000 meters from shore. We expect the FSRU will be in service to CELBA pursuant to a 25-year terminal user agreement allowing it to provide regasification services to other industrial users under similar terminal user agreements for a period up to 25 years. The FSRU will be able to store and regasify LNG in order to provide fuel to the Barcarena Power Plant as well as other end users. LNG carrier ships will dock next to the FSRU to deliver and offload LNG cargo.

Gas Pipeline: We expect to install a 20” gas pipeline running 0.5 kilometers offshore on a fixed steel structure and 2.8 kilometers onshore to connect the regasified LNG (RLNG) from the FSRU to the delivery point distributing gas to the Barcarena Power Plant and other industrial users.

Mooring System: We expect to construct a new fixed jetty extending from an existing jetty. The jetty will allow the FSRU to remain in a fixed direction and will be designed so that our FSRU may function at capacity for the duration of its expected use. Golar LNG has experience with similar mooring structures at other FSRU installations. The mooring point for the FSRU is 1.2 kilometers offshore and at a depth of approximately 15 meters.

Barcarena Power Plant

Power Plant and Transmission Line: A 605 MW combined cycle power plant utilizing modern H-Class gas turbines and associated transmission line. Power generated at the Barcarena Power Plant will be distributed to the national electricity grid through the existing Vila do Conde Substation. We anticipate that the Barcarena Power Plant will commence operations in 2025.

Transmission Line: A 5-kilometer double circuit 5230 kV double circuit transmission line and air-insulated bay expansion of an existing substation in the State of Pará.

Like the Sergipe Power Plant, the Barcarena Power Plant will serve as a “reserve plant” and its PPA is an availability contract including a guaranteed 50% dispatch that provides for annual fixed payments in exchange for which CELBA will ensure the availability of its Power Plant to deliver electricity in certain periods of the year as well as a reserve plant to generate thermal power, according to the physical capacity of the Power Plant. If dispatched upon ONS’s order, CELBA 2’s revenues under the PPAs would include, in addition to the fixed charge, the variable costs associated with energy production.

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LNG Supply

We expect to enter into an LNG supply agreement for the Barcarena Power Plant which will provide for a contract price calculated on a monthly basis as a factor of (i) the amount of LNG delivered; and (ii) quoted crude oil prices.

Description of the Barcarena PPA Agreements

CELBA 2 has been awarded long-term PPAs with nine concessionaires across Brazil for the availability and production of electricity to be generated by the project. The PPAs, which are currently being finalized, will provide for the commencement of supply of energy on January 1, 2025. CELBA 2’s revenues for the sale of energy under the PPAs will be comprised of (i) a fixed Brazilian real denominated revenue component (indexed for inflation) for the availability of the Power Plant, and (ii) a variable revenue component based on the MWh amount of energy generated, if any. The Barcarena PPAs are expected to generate fixed annual revenues of R$861 million.

Santa Catarina

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install an FSRU with a processing capacity of 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. The Santa Catarina Terminal is being designed to connect to existing onshore pipeline systems via a 31 kilometer, 20” pipeline to an interconnection point in Garuva, which supplies regional distribution companies.

Upon commencement of operations expected in 2022, the Santa Catarina Terminal will include an FSRU, a mooring system and an offshore/onshore gas pipeline. While the Santa Catarina Terminal currently has no firm capacity contracts, we believe there is significant demand from multiple potential end-users, including power generation, industrial, commercial, transportation and residential customers, including the potential adjacent Santa Catarina Power Plant.

•

Chartered FSRU: We intend to install an FSRU that will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The FSRU will be located at a fixed jetty structure approximately 300 meters from shore. The FSRU will be able to store and regasify LNG in order to provide fuel to end users. LNG carrier ships will dock next to the FSRU to deliver and offload LNG cargo.

•	Gas Pipeline: We expect to install a 20” gas pipeline running approximately 2 kilometers subsea and 33 kilometers onshore to a connection point in the vicinity of Garuva to transfer the regasified LNG (RLNG) from the offshore terminal onshore to the power plant and industrial users.

•

Mooring System: We expect to construct a new fixed dolphin-based mooring system. The mooring system allows the FSRU to remain in a fixed direction and will be designed so that our FSRU may function at capacity for the duration of its expected use. Golar LNG has experience with similar mooring structures at other FSRU installations. The mooring point for the FSRU is approximately 300 meters offshore and at a depth of approximately 15 meters.

Norte Catarinense power plant

•

The Santa Catarina Terminal is expected to supply LNG to the Norte Catarinense power plant, a 600 MW regional power plant (the “Santa Catarina Power Plant”), for which we have an option to purchase up to 100% equity interest, that is under consideration for construction. We intend to participate in the next planned power auction (which has been delayed due to COVID-19).

BR Distribuidora Partnership

In February 2020, we entered into the Partnership Agreement with BR Distribuidora for the distribution of our LNG products in Brazil. The partnership intends to introduce LNG as an alternative to the fuels currently available to Brazil’s transportation, industrial, thermoelectric generation, commercial and residential sectors by leveraging our extensive LNG infrastructure and BR Distribuidora’s market-leading brand and national network of 7,600 fuel stations and 94 bases of supply, operation and distribution.

The Partnership Agreement, formed between our subsidiaries, Golar Brazil and Golar Distribuidora, and BR Distribuidora (collectively, the “Partnership”), contemplates the development of a commercial partnership by means of implementing the Partnership’s business plan, the details of which will be developed by the Partnership’s working group in conjunction with a business consulting firm. In connection with the Partnership Agreement, the parties also executed a Purchase Option, which grants BR Distribuidora the right and option to, within six months of the formation of the working group or 10 business days following antitrust approval, whichever is later, purchase from Golar Brazil a 50 percent interest in Golar Distribuidora.

The Partnership Agreement sets forth the following objectives or “priorities”: (1) the introduction of LNG as a diesel substitute for the trucking industry, (2) LNG demand generation via “virtual pipelines,” (3) demand conversion from LPG and diesel to LNG and (4) demand conversion from fuel oil to LNG.

To realize these objectives, Golar Distribuidora agrees to: (i) contribute its existing contracts, resources and small-scale LNG “know how”; (ii) contract a business consulting firm in conjunction with BR Distribuidora; (iii) nominate working group candidates; (iv) consult with BR Distribuidora on accelerating BR Distribuidora’s trucking fleet transition to LNG; (v) receive up to four BR Distribuidora employees at Golar Distribuidora’s offices; (vi) grant the Purchase Option to BR Distribuidora; (vii) reform Golar Distribuidora as a sociedade anónima from its current form as a limitada if the Purchase Option is exercised; (viii) permit BR Distribuidora

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reasonable access to its employees and documents for diligence purposes related to the Purchase Option and permit BR Distribuidora to perform a financial audit on Golar Distribuidora and its parent Golar Power SSLNG Participações Ltda.; (ix) grant exclusive gas station supply rights to BR Distribuidora, the terms of which rights vary depending on whether BR Distribuidora exercises the Purchase Option; (x) if BR Distribuidora exercise its Purchase Option, authorize amendments to Golar Distribuidora’s organizational documents to reflect such exercise; and (xi) make an annual allocation for 50% of the investments necessary for the JV.

BR Distribuidora, in turn, agrees to: (i) grant Golar Distribuidora exclusive LNG supply rights to BR Distribuidora; (ii) make available its Filling, Operations and Distribution Bases for the use of the Partnership; (iii) make available other infrastructure, such as industrial support stations, for the use of the Partnership; (iv) invest in new industrial support stations to offer LNG as a fuel to clients; (v) present to the Partnership business opportunities related to the Partnership’s business; (vi) seek to refresh its trucking fleet with vehicles that use LNG; (vii) provide the necessary resources for the pursuit of the Partnership’s objectives; (viii) promote on a national level an LNG marketing program; (ix) make an annual allocation for 50% of the investments necessary for the JV; (x) provide technical consulting services; and (xi) nominate working group candidates.

Environmental and Community Impact

While LNG and natural gas is more environmentally friendly than many traditional distillate fuels and coal, we recognize that our business has an impact on the environment and the communities in which we and our affiliates operate. According to the EIA, power plants operated on natural gas in the United States emit 56% less CO₂ per kWh generated compared to oil and 58% less compared to coal. We believe that natural gas remains the most cost-effective complement for intermittent renewable energy, such as hydroelectricity, aiding the growth of these technologies around the world. Natural gas produces significantly lower toxins and particulate matter relative to other fossil fuels. As the cleanest burning fossil fuel, natural gas produces substantially lower carbon dioxide, nitrous oxides, sulphur oxides and particulate emissions relative to coal, heavy fuel oil, diesel, and other fossil fuels with tangible benefits for air quality and greenhouse emissions. For NOx, the reduction in emissions from natural gas are 79% and 80%, respectively, and for SOx, the reductions are close to 100%. Since 2010, it is estimated that coal-to-gas switching has eliminated 500 million tonnes of CO₂ globally, equivalent to replacing 200 million electric cars running on zero-carbon electricity on the road over the same period. We estimate a potential for replacing approximately 1.8 million tons of LNG equivalents per annum of LPG, diesel, fuel oil and coal with just the capacity of the Barcarena Terminal, creating the foundation for a broader transition away from the carbon-intensive energy sources in the region.

We continue to work on reducing the environmental impacts of our terminals and power projects. In particular, CELSE has committed to implementing 55 environmental projects, of which 49 have been implemented and 6 are currently under implementation to minimize the impacts of the construction of the Sergipe Power Plant and Sergipe Terminal. These projects include monitoring air emissions, hydrodynamic monitoring of local water sources, wildlife rescue and flora conservation. A program for monitoring noise and vibration has been in place since commencement of construction.

Hygo also looks to invest in communities where its projects are located. LNG infrastructure and distribution capabilities in remote and otherwise energy-isolated geographies benefit local communities by providing access to affordable and clean energy and can provide a significant boost to economic development, including the addition of stable, well paid jobs and the increase in municipal tax revenues that directly benefit local economies. Through our joint ventures, we participate in a number of community initiatives, including partnerships with local schools, libraries and marine foundations. We intend to continue to collaborate with local partners to help improve the quality of life and increase opportunities for members of the communities in which we operate. For example, the Sergipe Power Plant and Sergipe Terminal have created many jobs and increased municipal revenues. The hiring of local labor and investment in infrastructure and culture are among the highlights of CELSE’s community and social engagement. CELSE has 70 direct employees and construction of the Sergipe Power Plant and Sergipe Terminal involved more than 3,000 workers, 65% of which were hired residing in the State of Sergipe. In addition, Sergipe’s Program for Complementary Public Health widely provides free health benefits to the workers and communities directly involved in the project. CELSE has also invested more than R$20 million in work to recover Aracaju’s cultural heritage, as well as improvements in infrastructure,

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urbanization and education in the city of Barra dos Coqueiros. The initiatives at our Sergipe Terminal are indicative of those that we anticipate pursuing at our other terminals and projects. We are also committed to partnering with companies with strong track records, and who are aligned with our ESG goals, including CELSE, CELBA and BR Distribuidora.

Government Regulation

General

Our LNG infrastructure is and our operations are subject to extensive regulation under Brazilian 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.

LNG facilities are also subject to regulation by several entities, including MME, ANP and the Brazilian Institute of the Environment and Renewable Natural Resources. These regulations address LNG facility siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. There is an ongoing trend for increased regulation of facilities involved in the handling and use of natural gas, and any such regulation may become more stringent in future. Facilities are also required to obtain permits, the issuance of which is subject to a complex administrative process, which could result in delays, perhaps substantial in length, to the construction of our facilities; additionally, agencies may condition, revoke, suspend or modify the permits they issue.

Indigenous Rights

Our facilities and operations are surrounded by several indigenous and tribal communities, which are subject to certain protections under international and national law. For more information, see “Risk Factors—Risks Related to Applicable Laws and Regulations—Our operations could be limited or restricted in order to comply with protections for indigenous populations located in the areas in which we operate, and could also be adversely impacted by any changes in Brazilian law to comply with certain requirements embodied in international treaties and other laws related to indigenous communities.”

Natural Gas Market in Brazil

In March 2009, the Brazilian Congress enacted Law No. 11,909, or the Gas Law, which regulates activities in the gas industry, including transportation, processing, storage, liquefaction, regasification and commercialization.

The Gas Law created a concession regime for the construction and operation of new pipelines to transport natural gas of general interest, but maintained an authorization regime for pipelines subject to international agreements.

According to the Gas Law, after a certain exclusivity period, operators (transportadores) are required to grant access to transport pipelines and maritime terminals to third parties in order to maximize utilization of capacity. Pursuant to the Gas Law, LNG terminals are not subject to open access.

The Gas Law authorized the ANP to issue authorizations for the development of liquefaction and regasification of natural gas related activities. All services provided and/or facilities currently owned and/or operated by our subsidiaries in Brazil are subject to an authorization regime, which is subject to specific regulations issued by the agency.

Pursuant to such rules, in order to build and operate LNG facilities, our subsidiaries must obtain construction and operation authorizations.

There is no specific regulation on the prices and terms of services in the LNG sector. Prices are freely negotiated by the parties involved.

Although prices are freely negotiated between the parties, the seller must obtain an authorization from the ANP to perform trade activities and the respective contracts must be registered therewith. There are specific ANP regulations regarding price transparency obligations.

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The Gas Law also authorized certain consumers, who can purchase natural gas on the open market or obtain their own supplies of natural gas, to construct facilities and pipelines for their own use in the event local gas distributors, controlled by a state-owned monopoly, do not meet their distribution needs. These consumers are required to delegate the operation and maintenance of the facilities and pipelines to local gas distributors, but they are not required to sign gas supply agreements with the local gas distributors.

There are ongoing discussions in the Brazilian Congress which may result in a new regulatory framework for the gas industry known as “New Gas Law”, aimed at fostering the natural gas industry in Brazil and focusing on the Brazilian midstream gas market, particularly in relation to transportation and access to the infrastructure used for flowing, processing, liquefaction and regasification.

The New Gas Law is currently under review by the Brazilian Chamber of Deputies. Some of the measures proposed to foster the natural gas market under discussion are:

(i)	Expansion of the authorization regime to all new transportation facilities in order to reduce bureaucracy to develop new projects (the current framework allows the authorization regime only for international pipelines);

(ii)	Inclusion of rules regarding third-parties access to essential gas facilities, such as gas pipelines, Natural Gas Processing Units, and the LNG terminals, always on a non-discriminatory and transparent basis; and

(iii)

De-verticalization between transportation companies in relation to other activities in the chain, including exploration, development, production, import, shipping and/or sales of natural gas.After the approval of the New Gas Law bill by the Chamber of Deputies, it will be sent to the Senate. If and when the New Gas Law bill is approved, it may impose changes requiring us to conduct our business, mainly related to LNG terminals, in a manner substantially different from our current operations, which may adversely affect our operations, financial results and our capacity to fulfill our contractual obligations.

After the approval of the New Gas Law bill by the Chamber of Deputies, it will be sent to the Senate. If and when the New Gas Law bill is approved, it may impose changes requiring us to conduct our business, mainly related to LNG terminals, in a manner substantially different from our current operations, which may adversely affect our operations, financial results and our capacity to fulfill our contractual obligations.

Energy Auction and PPAs

Auctions are the primary mechanism to contract energy in Brazil. It is through auctions that power distribution concessionaires connected to the SIN ensure the necessary supply of energy to Brazil’s Regulated Market (Ambiente de Contratação Regulada), or the Regulated Market. Because the entire necessary supply of energy must be contracted, the spot market serves to settle positive or negative differences between a power plant’s physical production, as determined by the EPE, and its contracted energy.

Procurement of new generation projects is carried out regularly at predetermined intervals, through public auctions each year. Electricity subject of each auction is delivered one, three or five years subsequent to the date of the auction, known respectively as A-1, A-3, A-4, A-5 or A-6 auctions. Auction participants are required to provide five-year capacity forecasts, among other requirements. As a result of its successful bids in 2015 and 2019, CELSE and CELBA 2 executed PPAs with 26 and 9 energy distribution companies, respectively. In respect of each of the PPAs, each purchaser thereunder has executed a Security Agreement (Contrato de Constituição de Garantias), or CCG, setting forth the arrangements for the payment of amounts owed to the seller pursuant to the relevant PPA, and providing for the encumbrance of part of each purchaser’s revenues to ensure the satisfaction of its payment obligations under its PPAs.

Regulatory Authorities in the Brazilian Power Market

Ministry of Mines and Energy

The MME is the Brazilian Government’s primary regulator of the power industry acting as the granting authority on behalf of the Brazilian government, and empowered with policy-making, regulatory and supervising capacities. MME’s activities also include drafting guidelines governing the granting of concessions and the issuance of directives governing the bidding process for the trading of energy within the Regulated Market and concessions related to public assets and public services.

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ANEEL

The Brazilian power industry is regulated by ANEEL, an independent regulatory agency. ANEEL’s primary responsibility is to regulate and supervise the power industry in line with the policy dictated by the MME and to respond to matters which are delegated to it by the Brazilian government and by the MME. ANEEL’s current responsibilities include, among others: (i) administration of concessions for electricity generation, transmission and distribution activities, including the approval of electricity tariffs; (ii) enacting regulations for the electricity industry; (iii) implementing and regulating the exploitation of energy sources; (iv) promoting the public bidding process for new concessions and new energy auctions; (v) settling administrative disputes among sector agents; and (vi) defining the criteria and methodology for the determination of sector tariffs.

National Energy Policy Council

CNPE was created to advise the Brazilian president with respect to the development and creation of national energy policy. The CNPE is presided over by the MME, and the majority of its members are ministers of the Brazilian government. The CNPE was created to optimize the use of Brazil’s energy resources, to assure the supply of electricity to the country and to periodically review the use of regular and alternative energy to determine whether the nation is properly using a variety of energy sources and is not heavily dependent on a particular source.

National Electricity System Operator

The ONS is a private, non-profit entity comprised of concessionaires, other legal entities holding permissions or authorizations in the electrical energy market, and consumers connected to Interconnected Power System. The primary role of the ONS is to coordinate and control the generation and transmission operations in the Interconnected Power System, subject to ANEEL’s regulation and supervision. The objectives and principal responsibilities of the ONS include: operational planning for the generation industry, organizing the use of the domestic Interconnected Power System and international interconnections, guaranteeing that all parties in the industry have access to the transmission network in a non-discriminatory manner, assisting in the expansion of the energy system, proposing plans to MME for extensions of the Basic Network (which proposals must be taken into account in planning expansion of the transmission system) and submitting rules for the operation of the transmission system for ANEEL’s approval. Certain generators must declare their availability to ONS, which then attempts to establish an optimal electricity dispatch program.

Energy Trading Chamber

CCEE succeeded the MAE, the market in which all large electricity generation companies, energy traders and importers and exporters of electricity had participated and on which the spot price of electricity was determined. CCEE assumed all of the assets and operations of the MAE (which had previously been regulated by ANEEL). CCEE’s members include generation, distribution and trading companies, as well as Free Consumers.

The CCEE is responsible, among other things, for: (i) registering all the energy purchased through CCEARs, and the agreements resulting from market adjustments and the volume of electricity contracted in the Free Market, see “—Electric Generation in Brazil—Environments for the Trading of Electric Energy—Free Market;” and (ii) accounting and clearing of short-term transactions. It also assists ANEEL to conduct public auction on the Regulated Market; see “—Electric Generation in Brazil—Environments for the Trading of Electric Energy—Regulated Market”. Recently, CCEE has become responsible for managing certain funds related to the industry.

Energy Research Company

EPE is a state-owned company which is responsible for conducting strategic research on the energy industry, including with respect to electrical energy, oil, gas, coal and renewable energy sources. The research carried out by EPE is subsidized by the MME as part of its policymaking role in the energy industry.

Furthermore, EPE is the entity in charge of the technical qualification of the projects participating in the bids promoted by ANEEL for sale of energy.

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Energy Industry Monitoring Committee

The Energy Industry Monitoring Committee (Comitê de Monitoramento do Setor Elétrico) acts under the direction of the MME and is responsible for monitoring the supply conditions of the system and for proposing preventive action (including demand-related action and contracting for a supply-side reserve) to restore service conditions where applicable.

Electric Generation in Brazil

Companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must apply to the Brazilian Ministry of Mines and Energy, or MME, or to the Brazilian Electricity Regulatory Agency, or ANEEL, as representatives of the Brazilian government, for a concession, permission or authorization. Concessions and permissions are granted through more complex proceedings or through public tender, whilst authorizations are granted through simple administrative proceedings or through public auctions for power purchase and sale.

Concessions grant rights to generate, transmit or distribute electricity in the relevant concession area for a specified period (as opposed to permissions and authorizations, which may be revoked at any time at the discretion of the MME, in consultation with ANEEL). This period is usually 35 years for new generation concessions, and 30 years for new transmission or distribution concessions. An existing concession may be renewed at the granting authority’s discretion and subject to compliance by the concessionaire with certain requirements.

Authorizations are unilateral and discretionary acts carried out by the granting authority. Unlike concessions, authorizations generally do not require public tender. As an exception to the general rule, authorizations may also be granted to potential power producers after specific auction processes for the purchase of power conducted by ANEEL.

While the assets in connection with transmission and distribution concessions and hydroelectric generation projects (both under concessions or authorizations) revert back to the granting authority (or are transferred to new concessionaires) at the end of the concessions, the assets of thermoelectric, wind and solar power generation projects do not revert to the granting authority upon termination of authorizations. The investors remain liable for such assets, including any applicable decommissioning and removal obligations.

In the power generation sector, Independent Power Producers and self-generators typically hold an authorization as opposed to a concession. Independent Power Producers and self-generators do not receive public service concessions or permits to render public services. Rather, they are granted authorizations or specific concessions to explore water or other resources that merely allow them to freely produce, use or sell electric energy. Each authorization granted to an Independent Power Producer or self-generator sets forth the rights and duties of the authorized company. Authorized companies have the right to ask ANEEL issue public utility dedications in order to allow them to carry out expropriations and create rights of way for transmission lines, and, to their benefit, are subject to ANEEL and prior approval or post facto supervision in the event of a change in their controlling interests, depending on the project’s characteristics. Authorizations have a term of up to 35 years and can be renewed at the discretion of the granting authority.

An Independent Power Producer may sell part or all of its output to customers on its own account and at its own risk. A self-generator may, upon specific authorization by ANEEL, sell or trade any excess energy it is unable to consume. Independent Power Producers and self-generators are not granted monopoly rights and are not subject to price controls, except in specific cases. Independent Power Producers compete with public utilities and among themselves for large customers, pools of customers of distribution companies or any customers not served by a public utility. In addition, Independent Power Producers and self-generators may enter into freely-negotiated PPAs with other power generators and power commercialization companies in the Free Market. Independent Power Producers, self-generators and concessionaire companies are subject to a series of penalties for the failure to comply with provisions of the authorizations. The following penalties may be applied: (i) warning notices; (ii) fines per breach of up to 2.0% of the annual revenues generated by the relevant authorization, or, if the relevant authorization is non-operational, up to 2.0% of the estimated value of the energy that would have been produced for the twelve months prior to the infraction notice related to the breach;

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(iii) injunctions related to construction activities; (iv) restrictions on the operation of existing facilities and equipment; (v) temporary suspension from participating in new tenders, which may also be extended to controlling shareholders of the entity subject to the penalty; (vi) intervention; or (vii) termination of the authorization.

Research and Development Duties

Companies holding concessions, permission and authorizations for distribution, generation and transmission of electricity, which includes our power generation projects, must annually invest a minimum of 1% of their net operational revenue in research and development projects and funds. Small hydroelectric, wind, solar and biomass generation projects are not subject to this requirement.

The New Regulatory Framework

Since 1995, the Brazilian government has taken a number of measures to reform the Brazilian electric energy sector. These culminated on March 15, 2004, with the enactment of the New Regulatory Framework, which further restructured the power industry with the ultimate goal of providing consumers with a secure electricity supply at an adequate tariff.

The New Regulatory Framework introduced material changes to the regulation of the power industry, with the intention to (i) provide incentives to private and public entities to build and maintain generation capacity and (ii) assure the supply of electricity within Brazil at adequate tariffs through competitive public electricity auction processes. The key features of the New Regulatory Framework include:

•

Creation of two “environments” for the trading of electricity, including: (i) the Regulated Market, a more stable market in terms of supply of electricity; and (ii) a market specifically addressed to certain participants (i.e., Free Consumers and commercialization companies), called the Free Market, that permits a certain degree of competition.

•	Restrictions on certain activities of Distributors, so as to require them to focus on their core business of distribution, to promote more efficient and reliable services to Captive Consumers.

•

The prohibition of Distributors to carry out power commercialization under a freedom of contract regimen. Under the New Regulatory Framework, save for some very specific exceptions, Distributors may only purchase power to be supplied to their Final Customers in energy auctions of the Regulated Market.

•	Maintenance of contracts entered into prior to the New Regulatory Framework, in order to provide regulatory stability for transactions carried out before its enactment.

The New Regulatory Framework excludes Eletrobras and its subsidiaries from the National Privatization Program, a program originally created by the Brazilian government in 1990 to promote the process of privatization of state-owned companies.

Regulations under the New Regulatory Framework include, among other items, rules relating to auction procedures, the form of PPAs and the method of passing costs through to Final Consumers. Under these regulations, all parties that purchase electricity must contract all of their electricity demand under the guidelines of the New Regulatory Framework. Parties that sell electricity must have “ballast” for their sales (i.e., the amount of energy sold in the CCEE must be previously purchased under PPAs and/or generated by the seller’s own power plants). Agents that do not comply with such requirements are subject to penalties imposed by ANEEL and CCEE.

Beginning in 2005, all electricity generation, distribution and transmission companies, Independent Power Producers and Free and Special Consumers are required to annually notify the MME of their estimated electricity demand or estimated electricity generation for each of the subsequent five years. Each distribution company is required to notify the MME of the amounts of electricity that it intends to contract in the auction process. Based on this information, the MME must establish the total amount of energy to be contracted in the Regulated Market during such period and the list of generation projects that will be allowed to participate in the auctions.

Environments for the Trading of Electric Energy

Under the New Regulatory Framework, electricity purchase and sale transactions are carried out in two different segments: (i) the Regulated Market, which contemplates the purchase by distribution companies through

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public auctions of all electricity necessary to supply their consumers, and (ii) the Free Market, which contemplates the purchase of electricity by non-regulated entities (such as Free Consumers and energy traders).

Regulated Market. In the Regulated Market, distribution companies purchase their expected electricity requirements for their Captive Consumers from generators through public auctions. The auctions are administered by MME and ANEEL, either directly or indirectly through the CCEE.

Pursuant to Decree No. 9,143/2017, electricity auctions for new generation projects are held as A-“n” auctions, where “n” represents the number of years before the initial delivery date and currently ranges from three to seven (referred to as “A-3”, “A-4”, “A-5”, “A-6” and “A-7” auctions). Electricity auctions for existing power generation facilities take place (i) from one to five years before the initial delivery date (referred to as “A-1”, “A-2”, “A-3”, “A-4” and “A-5” auctions) or (ii) approximately four months before the initial delivery date (referred to as “market adjustments”). Traditionally, “A-4” and “A-6” auctions have been launched for new generation projects and “A-1” and “A-2” auctions have been launched for existing generation facilities.

The public auctions are prepared by ANEEL in compliance with guidelines established by the MME, including the requirement to use the lowest bid as the criteria to determine the winner of the auction.

Each generation company that participates in the auction must execute a contract for purchase and sale of electricity with each distribution company in proportion to the distribution companies’ respective estimated demand for electricity. The CCEARs for “A-6,” “A-5,” “A-4” and “A-3” auctions have a term of between 15 and 30 years, the CCEARs for alternative energy sources have a term between 10 and 30 years, and the CCEARs for existing power generation facilities have a term between one and 15 years. The only exception to these rules relates to the market adjustment auction, in which the generation and the distribution companies will enter into two-year bilateral agreements that must be registered with ANEEL and CCEE.

Auctions in the Regulated Market, subject to the conditions set forth in the respective requests for proposals, may originate two types of CCEARs: (i) energy agreements (contratos de quantidade de energia); and (ii) availability agreements (contratos de disponibilidade de energia), typically adopted for thermoelectric projects.

Under an energy agreement, a generator commits to supply a certain amount of electricity and assumes the risk that the electricity supply could be adversely affected by hydrological conditions and low reservoir levels, among other conditions, that could interrupt the supply of electricity, in which case the generator will be required to purchase the electricity elsewhere in order to comply with its supply commitments. Under a capacity agreement, a generator commits to make a specified amount of capacity available to the Regulated Market and to perform under any generation dispatches from ONS. In this case, the generator is entitled to a fixed revenue amount in order to repay the investments for the construction of the power plant and to a variable revenue amount in the case of a generation dispatch.

The New Regulatory Framework provides that all electricity generation, distribution and trading companies, Independent Power Producers and Free Consumers must inform the MME their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years. To encourage power distribution companies to make accurate estimates and to enter into PPAs accordingly, pass-through tariffs, as mentioned above, are permitted provided that the purchased power stays within 105.0% of the distribution company’s actual power demand. Surpluses and shortages of power distribution companies concerning power acquisitions in the Regulated Market may be offset against each other by means of an offsetting mechanism managed by CCEE and the sale of distribution companies’ energy surplus. Pursuant to the New Regulatory Framework, electricity distribution entities are entitled to pass on to their customers the costs related to electricity purchased through public auctions as well as any taxes and industry charges related to public bids, subject to certain limitations related to the inability of distribution companies to accurately forecast demand.

Free Market. The Free Market covers transactions between generation concessionaires, Independent Power Producers, self-generators, energy traders, importers of electric energy, Free Consumers and Special Consumers. The Free Market can also include existing bilateral contracts between generators and distributors entered into prior to 2003 until they expire. Generators generally sell their generation simultaneously, sharing the total amount of energy between the Regulated and Free Markets. It is possible to sell energy separately in one or more markets.

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Free Consumers are certain qualified consumers that may opt to purchase power directly from any participant in the Free Market and not from the local Distributor. On December 28, 2018, the MME issued Ordinance No. 514/2018, which lowers the requirements for being a Free Consumer of conventional energy, by dropping the minimum contracted energy demand from 3.0 MW to 2.5 MW, effective as of July 1, 2019, and from 2.5 MW to 2.0 MW, effective as of January 1, 2020. Prior to Ordinance No. 514/2018, Free Consumers with contracted energy demands between 0.5 MW and 3.0 MW could only purchase power from special sources (small hydro, solar, wind and biomass sources).

On December 12, 2019, the MME issued Ordinance No. 465/2019, which amends Ordinance No. 514/2018 and lowers the requirements for being a Free Consumer of conventional energy, by dropping the minimum contracted energy demand from 2.0 MW to 1.5 MW, effective as of January 1, 2021, from 1.5 MW to 1.0 MW, effective as of January 1, 2022, and from 1.0 MW to 0.5 MW, effective as of January 1, 2023.

Brazilian Port Regulatory Framework

The Brazilian port regulatory environment has undergone several significant changes in recent years. Until mid-2012, legislation for the port sector was based on Law 8.630/1993 (the “Port Modernization Law”). This law contributed significantly to the increase of port operational efficiency and the private sector’s participation in port operations, at the same time it guaranteed the right of the private sector to build, reform, and explore port facilities, subject to (i) a lease agreement (Contrato de Arrendamento) entered with the Federal Government itself or the State controlled companies in charge to the port operations, subject to a mandatory bidding procedure, when the port terminal was located within the organized port area; or (ii) an authorization from the competent authority, with respect to private terminals outside the organized port area or even within the organized port area to the extent that the interested party held legal rights to use the relevant land.

On December 6, 2012, the Brazilian Federal Government enacted Provisional Measure (Medida Provisória) No. 595/2012 (the “Provisional Ports Legislation”), which repealed the Port Modernization Law and established new legislation for the sector The Provisional Ports Legislation was converted into Federal Law No. 12,815/2013 in June 2013 (“Ports Law”) and was succeeded by regulations established under Decree No. 8,033 (passed in June 2013) (“Ports Decree”), further amended by Decree No. 9,048/2017, which introduced important changes to the regime applicable to both public and private port terminals, with the purpose of increasing legal stability and expanding investments. The Ports Law and Ports Decree are referred to as the “Ports Regulatory Framework.”

The Ports Law provides for a specific legal framework that is applicable to all ports in Brazil, as well as other port terminals and facilities used by the industry (including those currently managed by the private sector).

Under the current Ports Regulatory Framework, the rules applicable to public and private terminals can be summarized as the following:

•	the expansion, modernization and optimization of the infrastructure and superstructure contained within the statutory ports and their facilities;

•	guarantees regarding the accessibility and transparency of the tariffs and prices practiced in the sector, the quality of the service provided and the effectiveness of users’ rights;

•	fostering the modernization and increased efficiency of port management within statutory ports and their facilities, enhancing the quality of the port and its manpower and the efficiency of the services offered;

•	enhanced security for shipping access to the port; and

•	increased competition, with incentives for the participation of the private sector and assurances regarding full access to statutory ports, facilities and port activities.

Public ports may be developed and operated pursuant to concessions, by means of which the management of a public port, in whole or in part, may be delegated to a private party in lieu of state-owned port authorities, subject to prior public bidding procedures. In the broadest scope of concessions, the private party then becomes, for a pre-determined term, responsible for managing the whole area and infrastructure of the organized port, including the entire facility built to serve the navigation needs, the boarding and arrival of passengers as well as the handling and storage of cargo.

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Public-use terminals located within the area of organized ports are usually developed and operated pursuant to lease agreements (arrendamento), by means of which a private party, upon prior public bidding procedure, becomes entitled to manage and exploit the relevant port facilities for a pre-defined term. The lease agreements are subject to a typical concession regime, where, at the end of its tenor, the assets revert back to the Federal Government or to the port authority to which the Federal Union had delegated the management and exploitation of the organized port.

The concession of an organized port and the lease of port facilities located within the area of an organized port are subject to a public law regime, meaning that the private party must comply with all service standards required on the bidding procedure, including the tariffs charges that have been agreed with the Federal Government, subject only to the adjustments authorized in the agreements and/or the remedies under the economic equilibrium theory. In the case of lease agreements, the lease holders shall pay a rental fee for the use of any other public facilities located within the organized ports.

In contrast, private-use terminals (“TUPs”), depend typically on the initiative of private sector entrepreneurs and are developed and operated pursuant to grants of authorization by the Federal Government in the form of adhesion agreements (contratos de adesão), awarded by means of public bidding processes led by ANTAQ.

In addition to the public and private-use terminal’s regime, ANTAQ’s Resolution No. 13/2016 regulates the registration regime applicable to waterway transport facilities not subject to the TUP authorization regime, such as the FSRU.

The Brazilian Oil and Gas Regulatory Framework

The Brazilian Federal Law No. 2,004/1953 established the federal government’s monopoly over all activities relating to the research, exploration, production, refining and transportation of oil and its sub products. On November 9, 1995, the Brazilian Congress approved the reform of the oil and gas regulatory system by enacting the ninth Constitutional Amendment to allow the federal government to contract private or state-owned companies to carry out oil and gas upstream and downstream activities in Brazil, eliminating Petrobras’ monopoly on the exploration and production of domestic hydrocarbon reserves.

The regulatory framework was defined by the 1997 Oil and Gas Law (Law No. 9,478/1997), which established a concession regime and created the ANP, responsible for the regulation of the oil and gas industry in Brazil. ANP’s responsibilities includes the granting of oil and gas exploration concessions, by means of a competitive bidding process, as well as of authorizations for the import and export of LNG and the transportation and distribution of natural gas activities.

Environmental Regulation

Our infrastructure and operations are subject to various international treaties and conventions and to the extent applicable, federal, state and local laws, rules and regulations of the counties in which we operate relating to the protection of the environment, natural resources and human health. These environmental 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. Local laws and regulations might require us to obtain governmental permits and authorizations before we may conduct certain activities. Failure to comply with these laws or to obtain the necessary business and technical licenses could result in sanctions including suspension and/or freezing of the business and responsibility for all damages arising from any violation. Governments may also periodically revise their environmental laws and regulations or adopt new ones, and the effects of new or revised laws and regulations on our operations cannot be predicted. These laws and regulations may also lead to substantial penalties for noncompliance and substantial liabilities for incidents and environmental damages 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, administrative and criminal fines and penalties for non-compliance. Such fines and penalties are independent and may be imposed on a cumulative basis depending on the violation. Furthermore, Brazilian environmental law provides joint, several and strict (objetiva) civil liability. Given the broad definition of civil liability, an enabler of or contributor to environmental damages, regardless of fault, negligence or willful misconduct, will be held liable for the recovery of the damages.

Although we have systems designed to achieve compliance with applicable environmental laws and regulations and believe we have all permits, licenses and certificates required for our vessels, future

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non-compliance or failure to maintain necessary permits or approvals could require us to incur substantial costs or temporarily suspend the operation of one or more of our vessels. There can be no assurance that additional significant costs and liabilities will not be incurred to comply with such current and future laws and regulations, or that such laws and regulations will not have a material effect on our operations. International environmental treaties and conventions, Brazilian and U.S. environmental laws and regulations that apply to the operation of our vessels are described below. Other countries in which we operate or in which our vessels are registered have or may in the future have laws and regulations that are similar in nature to the U.S. laws referenced below.

Air and Climate

Our infrastructure is subject to international, federal, state and local laws, rules and regulations limiting the release of emissions to the air. We may be required to incur certain capital expenditures over the next several years for equipment to control air emissions as a condition to maintaining or obtaining permits and approvals. Alternatively, we may be required to restrict or limit the amount of LNG we consume in order to obtain or maintain a permit. We do not believe, however, that our operations, or the construction and operations of our gas-fired thermoelectric plant, will be materially and adversely affected by any such requirements.

In 2009, Brazil implemented the National Policy on Climate Change, which establishes a framework for reduction of GHGs. However, this does not include a mandatory emissions trading regime, carbon tax, or other such regulatory mechanism to enforce reductions of emissions across the country. Much of this reduction is expected to be achieved through reduced deforestation and increased supplies of renewable energy. It is not possible to know how quickly renewable energy technologies may advance, but the increased use of renewable energy for any reason could ultimately reduce future demand for hydrocarbons. These developments could ultimately have a material adverse effect on our financial position, results of operations and cash flows. Additionally, various states and local governments have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding individually determined reduction goals every five years after 2020. As a party to the agreement, Brazil intends to reduce GHG emissions by 37% below 2005 levels by 2025.

Coastal Zone

LNG infrastructure may be subject to the review and requirements of Brazil’s Integration Coastal Zone Management program (“ICZM”) when facilities are located within the coastal zone. The ICZM is administered jointly by federal, state, and local authorities. This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the National Coastal Management Plan (Federal Law 7661/1988) and any applicable state or local analogs, which may require further permitting or other authorization for projects such as ours to proceed.

Water

Our LNG infrastructure is also subject to the federal National Water Resources Policy (Federal Law 9433/1997) (“NWRP”) and analogous state and local laws. The NWRP imposes strict controls both on the capture of water for use and on the discharge of pollutants into the waters of Brazil, including discharges of wastewater and storm water runoff and fill/discharges into waters of Brazil. Permits must be obtained prior to capturing water for use or discharging pollutants into state and federal waters and before constructing infrastructure that requires the dredging and filling of waters of Brazil. The NWRP is administered by various federal executive authorities and by the states via the applicable state agency.

Enviormental Licensing

We are required to comply with numerous other federal, state and local environmental, health and safety laws and regulations in addition to those previously discussed. Moreover, our current operations and future projects may be subject to additional federal permits, orders, approvals and consultations required by other federal agencies under these and other statutes, such as Federal Law 6933/1981. In addition, federal permitting processes may trigger a requirement to undergo detailed and time-consuming assessments and technical studies for any actions that have the potential to significantly impact the environment. Such permitting can also impose

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or otherwise result in significant costs with respect to construction or operation of our facilities. State permitting regimes may require similar consultations with applicable state-level agencies and/or the preparation of a similar assessment of environmental impacts pursuant to state law.

Other local laws and regulations, including local zoning laws and fire protection codes, may also affect where and how we operate.

International Maritime Regulations of LNG Vessels

The IMO provides international regulations governing shipping and international maritime trade. Among other requirements, Chapter IX of SOLAS, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system and the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies. Our ship manager holds a document of compliance under the ISM Code for operation of Gas Carriers.

Vessels that transport gas, including LNG carriers and FSRUs, are also subject to the International Gas Carrier Code (“IGC”) which 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. Each of our vessels is in compliance with the IGC Code and each of our new buildings/conversion contracts requires that the vessel receive certification that it is in compliance with applicable regulations before it is delivered.

The IMO also promulgates ongoing amendments to SOLAS which provides rules for the construction of and equipment required for commercial vessels and includes regulations for safe operation. It requires the provision of lifeboats and other life-saving appliances, requires the use of the Global Maritime Distress and Safety System which is an international radio equipment and watch keeping standard, afloat and at shore stations, and relates to the International Convention on the Standards of Training and Certification of Watchkeeping Officers (“STCW”) also promulgated by the IMO. The SOLAS and other IMO regulations concerning safety, including those relating to treaties on training of shipboard personnel, lifesaving appliances, radio equipment and the global maritime distress and safety system, are applicable to our operations. Flag states that have ratified the SOLAS and STCW generally employ the classification societies, which have incorporated the SOLAS and STCW requirements into their class rules, to undertake surveys to confirm compliance.

In the wake of increased worldwide security concerns, the IMO amended SOLAS and added the International Ship and Port Facility Security Code (“ISPS Code”), which came into effect on July 1, 2004, to detect security threats and take preventive measures against security incidents affecting vessels or port facilities. Golar Management has developed security plans and appointed and trained ship and office security officers. In addition, all of our vessels have been certified to meet the ISPS Code and the security requirements of the SOLAS and the Maritime Transportation Security Act (“MTSA”). Future security measures could have a significant financial impact on us. Golar Management has developed security plans, appointed and trained ship and office security officers and all of our vessels have been certified to meet the ISPS Code and the security requirements of the SOLAS and the MTSA.

The IMO continues to review and introduce new regulations. 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. Non-compliance with the IGC Code or other applicable IMO regulations may subject a shipowner or a bareboat charterer to increased liability or penalties, may lead to decreases in available insurance coverage for affected vessels and may result in the denial of access to, or detention in, some ports.

Safety Management System Requirements

Under the ISM Code, our operations are also subject to environmental standards and 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 safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies. We rely upon the safety management system that we and our technical management team have developed for compliance with the ISM Code. The failure of a vessel owner or bareboat charterer to comply with the ISM Code may subject such party to increased liability, may decrease available insurance coverage for the affected vessels and may result in a denial of access to, or detention in, certain ports.

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The ISM Code requires that vessel operators obtain a safety management certificate for each vessel they operate. This certificate evidences compliance by a vessel’s management with the ISM Code requirements for a safety management system. No vessel can obtain a safety management certificate unless its manager has been awarded a document of compliance, issued by each flag state, under the ISM Code. We have obtained applicable documents of compliance for our offices and safety management certificates for all of our vessels for which the certificates are required by the IMO. The document of compliance and safety management certificate are renewed as required.

Amendments to SOLAS Chapter VII apply to vessels transporting dangerous goods and require those vessels be in compliance with the International Maritime Dangerous Goods Code (“IMDG Code”). Effective January 1, 2018, the IMDG Code includes (1) updates to the provisions for radioactive material, reflecting the latest provisions from the International Atomic Energy Agency, (2) new marking, packing and classification requirements for dangerous goods, and (3) new mandatory training requirements.

The IMO’s Maritime Safety Committee and MEPC, respectively, each adopted relevant parts of the International Code for Ships Operating in Polar Water (the “Polar Code”). The Polar Code, which entered into force on January 1, 2017, covers design, construction, equipment, operational, training, search and rescue as well as environmental protection matters relevant to ships operating in the waters surrounding the two poles. It also includes mandatory measures regarding safety and pollution prevention as well as recommendatory provisions. The Polar Code applies to new ships constructed after January 1, 2017, and after January 1, 2018, ships constructed before January 1, 2017 are required to meet the relevant requirements by the earlier of their first intermediate or renewal survey.

Furthermore, recent action by the IMO’s Maritime Safety Committee and United States agencies indicate that cybersecurity regulations for the maritime industry are likely to be further developed in the near future in an attempt to combat cybersecurity threats. For example, cyber-risk management systems must be incorporated by ship-owners and managers by 2021. This might cause companies to create additional procedures for monitoring cybersecurity, which could require additional expenses and/or capital expenditures. The impact of such regulations is hard to predict at this time.

Competition

The markets in which we operate can be highly competitive. We currently conduct the substantial majority of our operations in Brazil but intend to target additional markets around the world, such as the Indian Subcontinent, the Caribbean, West Africa, South East Asia and Europe, and our competitors include other global integrated LNG companies and individual regional power providers. Specifically, our primary competitors with respect to our terminal and gas distribution operations include New Fortress Energy LLC and Royal Dutch Shell PLC. In Brazil, our primary competitors with respect to power generation include ENEVA, ENGIE and Gás Natural Açu - GNA.

We believe the principal competitive factors in the markets in which we operate are technical expertise, capabilities location, price and scale. Additionally, power generation projects are awarded on a bid basis through power auctions organized by government agencies in Brazil, which tends to create a highly competitive environment. Once we are awarded a bid and enter into long-term PPAs, other distributors cannot distribute energy in our concession area. As such, customers located in the respective region can only acquire energy from us, with the exception of consumers who become Free Consumers, who can acquire energy directly in the Free Market. When these agreements expire, the energy generated by the power plant may be traded through auctions organized by ANEEL or sold in the Free Market.

Customers

Historically, our revenue was solely derived from the operation of our two LNG carriers in the Cool Pool. Following the completion of our power plants and terminals, we expect that our customers will primarily include the counterparties to our PPAs, as well as our downstream distribution customers.

Seasonality

The advent of FSRUs has opened up new markets and uses for LNG, spreading consumption more evenly over the year. There is a higher seasonal demand during the summer months due to energy requirements for air

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conditioning in some markets or reduced availability of hydroelectric power in others, particularly Brazil, and a pronounced higher seasonal demand during the winter months for heating in other markets. In Brazil, seasonal variations in dispatch amounts and any performance adjustments at the power plants owned by certain of our subsidiaries will be borne by us.

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, general liability, and the portion of workers’ compensation not covered under a governmental program and are in the process of obtaining environmental liability insurance.

Additionally, in Brazil, we have developed an insurance management plan to determine the insurance coverage we will need to contract and the risks we will need to cover. In order to develop its insurance management plan, we have mapped the risks that we can transfer to an insurer, along with the probability of those risks manifesting. Our finance teams are responsible for maintaining and updating this risk map periodically and monitoring the insurance coverage contracted and the risks covered by each insurance policy.

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 or our subsidiaries. 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.

Our Employees

We currently have 63 employees in Brazil. We also rely on the executive officers and other key employees of Golar Management who perform services for us pursuant to the management and administrative services agreement. Golar Management also provides commercial and technical management services to our fleet and will provide administrative services to us pursuant to the management and administrative services agreement. Please read “Management—Executive Officers.”

Taxation of Hygo

United States Taxation

Treated as a Corporation

We are treated as a foreign corporation for U.S. federal income tax purposes. As such, we will be subject to U.S. federal income tax on our income to the extent it is from U.S. sources or is otherwise effectively connected with the conduct of a trade or business in the Unites States, as discussed below.

Taxation of Operating Income

We expect that we will not be subject to a material amount of U.S. taxation on our income. We expect that substantially all of our gross income will be attributable to the (i) generation and sale of power and (ii) transportation, regasification, and storage of LNG. Gross income we earn from the regasification and storage of LNG and the generation and sale of power outside of the United States generally will not be subject to U.S. federal income tax, and gross income we generate from such activities in the United States generally will be subject to U.S. federal income tax. We expect all of our generation and sale of power and regasification and storage of LNG will take place outside of the United States and, accordingly, will not be subject to U.S. taxation.

Gross income that is attributable to transportation that either begins or ends, but that does not both begin and end, in the United States will be considered to be 50% derived from sources within the United States (“U.S. Source International Transportation Income”) and may be subject to U.S. federal income tax as described below. Gross income attributable to transportation that both begins and ends in the United States (“Domestic Transportation Income”) will be considered to be 100% derived from sources within the United States and generally will be subject to U.S. federal income tax. Gross income attributable to transportation exclusively

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between non-U.S. destinations will be considered to be 100% derived from sources outside the United States and generally will not be subject to U.S. federal income tax. We are not permitted by law to engage in transportation that gives rise to Domestic Transportation Income, and we do not anticipate providing any regasification or storage services in the United States. However, certain of our activities give rise to U.S. Source International Transportation Income, which could be subject to U.S. federal income taxation unless the exemption from U.S. taxation under Section 883 of the Code (the “Section 883 Exemption”) applies.

We expect that, based on our ownership structure after the consummation of this offering and our current and expected future operations, the Section 883 Exemption will apply beginning in the 2021 tax year, and we do not expect to be subject to U.S. federal income tax on our U.S. Source International Transportation Income. This expectation is based upon factual matters that are subject to change and, in some cases, are not within our control. Our board of directors could determine that it is in our best interests to take an action that would result in our not being able to qualify for the Section 883 Exemption in the future.

If the Section 883 Exemption is not applicable for any year, we would be subject to a 4.0% U.S. federal income tax on our gross U.S. Source International Transportation Income, without benefit of deductions, if such income is not effectively connected with a U.S. trade or business, as described below. Based on our current and anticipated future operations, we do not expect any such tax would be material in amount. However, there is no assurance that we would not in the future increase our LNG transportation activities, which might result in an increase to our U.S. Source International Transportation Income and in the amount of such tax if the Section 883 Exemption were not applicable.

Further, if we earn U.S. Source International Transportation Income and the Section 883 Exemption does not apply, our U.S. Source International Transportation Income may be treated as “effectively connected” with the conduct of a trade or business in the United States (or “Effectively Connected Income”) if:

•	we have, or are considered to have, a fixed place of business in the United States involved in the earning of such income; and

•

substantially all (at least 90%) of our U.S. Source International Transportation Income is, (i) other than with respect to leasing income, attributable to regularly scheduled transportation, such as the operation of a vessel that follows a published schedule with repeated sailings at regular intervals between the same points that begin or end in the United States and, (ii) with respect to leasing income, attributable to a fixed place of business in the United States.

For these purposes, leasing income is treated as attributable to a fixed place of business where such place of business is a material factor in the realization of such income and such income is realized in the ordinary course of business carried on through such fixed place of business. In addition, if we earn income from regasification or storage of LNG within the territorial seas of the United States, such income would be treated as Effectively Connected Income.

Any income we earn that is treated as Effectively Connected Income would be subject to U.S. federal corporate income tax, currently imposed at 21% rate. In addition, a 30% branch profits tax imposed under Section 884 of the Code also would apply to such income, and a branch interest tax could be imposed on certain interest paid or deemed paid by us.

Based on our current operations, none of our income is attributable to regularly scheduled transportation, and none of our regasification, storage, or power generation activities occur within the territorial seas of the United States. As a result, we do not anticipate that any of our U.S. Source International Transportation Income, income earned from regasification or storage activities, or income earned from power generation will be treated as Effectively Connected Income. However, there is no assurance that in the future we will not earn income pursuant to regularly scheduled transportation or vessel leasing attributable to a fixed place of business in the United States or earn income from regasification or storage activities within the territorial seas of the United States, which would result in such income being treated as Effectively Connected Income.

Non-U.S. Taxation

The Company, while incorporated and resident in Bermuda, is an exempted company and, therefore, not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. We have received from the Minister of Finance under The Exempted Undertaking Tax

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Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, any such tax shall not be applicable to us or to any of our operations or to our shares, debentures or other obligations, until March 31, 2035, except insofar as such tax applies to persons in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda. The assurance does not exempt us from paying import duty on goods imported into Bermuda. In addition, all entities employing individuals in Bermuda are required to pay payroll tax and there are other sundry amounts payable, directly or indirectly, to the Bermuda government. We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.

Further, certain of our subsidiaries are subject to taxation in the jurisdictions in which they are organized, conduct business, or own assets. In particular, as discussed below, our subsidiaries engaged in LNG storage, LNG regasification, and power generation activities in Brazil will be subject to tax in Brazil on their net income from such activities. We intend that our business and the business of our subsidiaries will be conducted and operated in a manner designed to minimize the tax imposed on us and our subsidiaries. However, we cannot assure this result as we may enter into new business transactions in these or other jurisdictions and the tax law in such jurisdictions may change, either of which could affect our tax liability.

Brazilian Taxation

Brazilian corporations are subject to two annual corporate income taxes, which are levied on total net income, as adjusted according to applicable tax law: (i) Corporate Income Tax, at approximately a 25% rate, and (ii) Social Contribution on Net Profit, at a 9% rate (and thus an aggregate tax rate of approximately 34%). Dividends distributed to a shareholder are fully exempted from tax, irrespective of the jurisdiction in which the shareholder is domiciled. A bill to be voted on by the Brazilian congress would reinstate progressive taxation of dividends, while reducing progressively the taxation of corporate net income. If that bill is approved, it may affect our after-tax revenues.

Revenues derived from energy sales are subject to two monthly federal social contributions, that are levied on gross revenues: (i) PIS, at a rate of 1.65%, and (ii) COFINS, at a rate of 7.6%. These rates are applicable for entities subject to the non-cumulative regime, which allows the taxpayer to accrue PIS and COFINS credits with respect to eligible expenses and offset them against the PIS and COFINS due on their revenue.

In addition, energy sales within a particular state are subject to the ICMS, which is a state-specific value added tax. The applicable rate varies depending on the legislation of each state (usually ranging from 18% to 30%). In interstate sales, the outflow of energy is exempted from ICMS. Nonetheless, sellers of energy may be required to pay the ICMS levied on the acquirer in the destination state under a substitute regime. Domestic acquisitions of inputs are subject to the PIS and COFINS, which may be recoverable taxes. The ICMS is also levied on local acquisitions within the same state, generating credit input to the acquirer, except to Final Consumers.

•

The applicable PIS and COFINS rates depend on the regime adopted by the seller. If the seller is subject to the non-cumulative regime, a 1.65% PIS rate and a 7.6% COFINS rate apply. If the seller is subject to the cumulative regime, a 0.65% PIS rate and a 3% COFINS rate apply. If the acquiring entity is subject to the non-cumulative regime, it is allowed to accrue a 1.65% PIS credit and a 7.6% COFINS credit with respect to the acquisition expense incurred, regardless of the regime adopted by the seller.

•

ICMS rates depend on the applicable state’s legislation and the products involved. Usually intrastate transactions are subject to rates that range between 17% and 19% (for energy, the applicable rates range from 18% to 30%), while interstate transactions are subject to 4%, 7%, or 12% rates, depending on the origin and destination of the applicable products.

Acquisitions of manufactured inputs from the manufacturer are also subject to the Tax on Industrialized Products (“IPI”) at rates that vary depending on the product acquired. Energy sales are exempted from the IPI.

Brazil generally heavily taxes the import of certain inputs (i.e., Import Tax, PIS, COFINS, IPI and ICMS). However, the import of LNG benefits from a 0% Import Tax rate, as well as 0% PIS and COFINS rates. In addition, the import of LNG is not taxed under the IPI. The ICMS, however, is due on the import of LNG and should be paid to the state of the importing establishment at the rate imposed by that state. The ICMS tax rates

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on imports vary by state. In Sergipe, for example, the rate is 18%. The payment of the ICMS on the import becomes a credit to the importer, to be offset against the ICMS due in subsequent transactions. Some states provide for a deferment of the ICMS due on the importation of LNG, allowing the importer to pay such tax together with the ICMS due on the subsequent transaction.

Subsequent sales of LNG, within the same state or to other states, are subject to the PIS, COFINS, and ICMS, which can be offset with credit inputs accrued on acquisitions. As a rule, such taxes should be recoverable by the acquirer, except to Final Consumers.

Equipment rental is subject only to the PIS and COFINS, while services are subject to the PIS, COFINS, and the Imposto sobre Serviços (the “ISS”), a municipal service tax. Note that where services are rendered to customers domiciled in different cities, a conflict may arise in determining which city is entitled to levy this tax, in which case there is a risk that the ISS would be charged by both the municipality where our FSRU terminal is located and the municipality where the customer is domiciled. Additionally, there is uncertainty as to whether the ISS or ICMS would apply to regasification services being rendered to third parties.

Whenever there is a simultaneous execution of a vessel charter and a contract to provide services, as is the case with the Golar Nanook, the withholding income tax rate is reduced to 0% on the charter portion that represents up to 60% of the total value of the contracts. If the value of the charter contract exceeds this limit, such excess will be subject to withholding income tax at the rate of 15%. If the charter revenues are remitted to a country with favorable taxation or where the charterer is the beneficiary of a privileged tax regime, the rate of income tax withheld at source will be 25%.

The provision of services in Brazil is subject to the ISS, the rate of which may vary from 2 to 5%.

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MANAGEMENT

Management of Hygo Energy Transition Ltd.

Our bye-laws to be adopted in connection with the completion of this offering will provide our board of directors the authority to oversee and direct our operations, management and policies on an exclusive basis. Our executive officers, who are employed by Golar Management, will manage our day-to-day activities consistent with the policies and procedures adopted by our board of directors. All of our executive officers and directors also are affiliates of Golar LNG.

Upon consummation of this offering our bye-laws will provide that our board of directors shall consist of not less than two directors as the board of directors may from time to time determine. Our board of directors will initially consist of six directors. Further, upon the consummation of this offering, we will enter into a Shareholders’ Agreement with our Sponsors. Among other things, the Shareholders' Agreement is expected to provide our Sponsors with the right to designate a certain number of nominees to our board of directors for so long as each Sponsor beneficially owns at least 5% of our outstanding common shares. See “Certain Relationships and Related Transactions—Shareholders' Agreement.”

Our bye-laws will not provide for cumulative voting in the election of directors, which means that the holders of a majority of our issued and outstanding voting shares can elect all of the directors standing for election, and the holders of the remaining shares will not be able to elect any directors. Our Sponsors’ aggregate beneficial ownership of greater than 50% of our voting shares means together our Sponsors will be able to control matters requiring shareholder approval, which includes the election of directors.

In evaluating director candidates, our board of directors will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Employees of Golar Management, including those employees who will act as our executive officers, provide services to us and our subsidiaries pursuant to the management and administrative services agreement and will continue to provide services to us and our subsidiaries after the closing of this offering under the management and administrative services agreement. Please read “Certain Relationships and Related Transactions—Other Transactions with Related Persons—Management and Administrative Services Agreement.”

Directors

The following table shows information about each of our directors upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. The business address for these individuals is 2^nd Floor, S.E. Pearman Building, 9 Par-la-Ville Road, Hamilton HM 11, Bermuda.

Name	Age	Position
Tor Olav Trøim	57	Director
Luke Taylor	42	Director
Jeffry Myers	62	Director
Georgina Sousa	69	Director and Corporate Secretary
Kate Blankenship	55	Director Nominee
Paul Hanrahan	62	Director Nominee

Tor Olav Trøim has served as a director of the Company since May 2016. Mr. Trøim also serves as the Chairman of the Board of Golar LNG, a position he has held since September 2017, and as Chairman of the Board of Golar LNG Partners LP, an affiliate of Golar LNG (“Golar Partners”), a position he has held since January 2009. Mr. Trøim previously served as a director and vice-president of Golar LNG from its incorporation in May 2001 until October 2009, after which time he served as a director and Chairman of Golar LNG’s listed subsidiary, Golar LNG Energy Limited. Mr. Trøim graduated with a M.Sc Naval Architect from the University of Trondheim, Norway in 1985. He was formerly an Equity Portfolio Manager with Storebrand ASA (1987-1990), and Chief Executive Officer for the Norwegian Oil Company DNO AS (1992-1995). Mr. Trøim was a director of Seatankers Management in Cyprus from 1995 until September 2014. Mr. Trøim also served as a director and

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Chairman of ITCL, a director of Seadrill Limited (“Seadrill”), Golden Ocean Group Limited, Golden State Petro (IOM I-A) Plc, Archer Limited, Golar Partners, Seadrill Partners LLC (“Seadrill Partners”) and as an alternate director of Frontline Ltd. (“Frontline”) until September 2014. He currently holds controlling interests in Magni Bermuda and Magni Partners UK. He also serves as a director in Stolt-Nielsen Limited, Borr Drilling Limited (“Borr Drilling”) (NYSE: BORR) and Valerenga Football Club.

Luke Taylor has served as a director since May 2016. Mr. Taylor is a Senior Managing Director with Stonepeak, a position he has held since 2013 and is a member of the Stonepeak Executive Committee. Prior to joining Stonepeak, Mr. Taylor was a senior executive at Macquarie Capital, previously holding various positions from 2001 to 2011 across Auckland, London and New York offices. He currently serves on the board of directors of Lineage Logistics, Ironclad Energy Partners, Trac Intermodal and Sanchez Midstream Partners. Mr. Taylor holds a Bachelor of Commerce and a Master of Business with distinction from the University of Otago in New Zealand.

Jeffry Myers has served as a director since August 2020. Mr. Myers previously served as a director from June 2016 until February 2018. Mr. Myers is a Senior Operating Partner with Stonepeak, a position he has held since 2011. Prior to joining Stonepeak, Mr. Myers was a co-founder, Chairman of the Board, President and Chief Executive Officer of Pristine Power from its founding in 2002 through public offering in 2008 and to its sale in 2010. Mr. Myers has been involved as a developer and executive in the development and management of over 5 GW of independent power projects and a number of major pipeline projects. He currently serves on the board of directors of Ironclad Energy Partners, Kelvin Storage, Transition Energy, and Kalina Power (ASX: KPO). Mr. Myers holds an Honours degree in Business Administration from Western University and a Master of Business Administration from the University of Windsor.

Georgina Sousa has served as a director since August 2020 and as company secretary since October 2019. She is currently a director and secretary of Golar LNG, a director, secretary and resident representative of Golar LNG Partners LP and a director and secretary of each of 2020 Bulkers Ltd. and Borr Drilling (NYSE: BORR). Ms. Sousa was employed by Frontline as Head of Corporate Administration from February 2007 until December 2018 and joined Golar Management Bermuda Limited in January 2019. She previously served as a director of Frontline from April 2013 until December 2018, as a director of Ship Finance International Limited from May 2015 until September 2016, as a director of North Atlantic Drilling Ltd. from September 2013 until June 2018, as a director of Sevan Drilling Limited from August 2016 until June 2018, as a director of Northern Drilling Ltd. from March 2017 until December 2018 and as a director of FLEX LNG LTD. from June 2017 until December 2018. Ms. Sousa also served as a director of Seadrill from November 2015 until July 2018 and as a director of Knightsbridge Shipping Limited (the predecessor of Golden Ocean Group Limited) from 2005 until 2015. Ms. Sousa served as Secretary for all of the above mentioned companies at various times during the period between 2005 and 2018. She served as secretary of Archer Limited from 2011 until December 2018 and as secretary of Seadrill Partners from 2012 until 2017. Until January 2007, she was Vice President-Corporate Services of Consolidated Services Limited, which she joined in 1993 as Manager of Corporate Administration.

Kate Blankenship will become a member of our board of directors in connection with our listing on NASDAQ. Mrs. Blankenship has served as a director on the board of directors of Borr Drilling (NYSE: BORR) and as the Chair of its Audit Committee since February 26, 2019. Mrs. Blankenship joined Frontline in 1994 and served as its Chief Accounting Officer and Company Secretary until October 2005. Among other positions, she has served on the board of numerous companies, including as director and audit committee Chairperson of North Atlantic Drilling Ltd. from 2011 to 2018, Archer Limited from 2007 to 2018, Golden Ocean Group Limited from 2004 to 2018, Frontline from August 2003 to 2018, Avance Gas Holding Limited from 2013 to 2018, Ship Finance International Limited from October 2003 to 2018, Golar LNG from 2003 to 2015, Golar LNG Partners LP from 2007 to 2015, Seadrill from 2005 to 2018 and Seadrill Partners from 2012 to 2018. Mrs. Blankenship is a member of the Institute of Chartered Accountants in England and Wales and graduated from the University of Birmingham with a Bachelor of Commerce in 1986.

Paul Hanrahan will become a member of our board of directors in connection with our listing on NASDAQ. Mr. Hanrahan served as the Chief Executive Officer of Globeleq Advisors Limited, a leading independent power producer operating and developing power projects in Africa, from September 18, 2017, to December 31, 2019, when he assumed a board position as a nonexecutive director. Prior thereto, Mr. Hanrahan served as the Chief Executive Officer of American Capital Energy & Infrastructure Management, LLC, an investment company formed to raise, invest and manage funds in the energy and infrastructure industries, from

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September 2012 to December 16, 2016. He left American Capital Energy & Infrastructure Management, LLC after all its assets were sold as part of its acquisition by Ares Capital Corporation of American Capital, Ltd., a sponsor investor in American Capital Energy & Infrastructure Management, LLC. Mr. Hanrahan served as the President and Chief Executive Officer of The AES Corporation, one of the world’s leading independent power producers, from June 2002 to September 2011. He was Executive Vice President and Chief Operating Officer of The AES Corporation and President and Chief Executive Officer of AES China Generating Co., Ltd., a public company formerly listed on NASDAQ, from 1993 to June 2002. Mr. Hanrahan served as a director of The AES Corporation from June 2002 to September 2011. He also previously served on the boards of other major publicly listed utilities in Brazil, Chile and Venezuela. In 2009 Mr. Hanrahan was appointed by the White House to serve on the U.S.-India CEO forum. Mr. Hanrahan is a director of AquaVenture Holdings Limited, a global provider of water services. He is also a director of BMR Energy, a renewable energy company, and Ingredion Incorporated, a global food and industrial ingredient company. He served as a director of Arch Coal, Inc., a global coal producer and marketer, from June 2012 to October 2016. He previously served as a director of Azura Power Holdings, Ltd, an electric power generation company in Nigeria, and GreatPoint Energy, Inc., a producer of clean, low-cost natural gas from coal, petroleum coke and biomass. Mr. Hanrahan holds a Bachelor of Science degree in mechanical engineering from the U.S. Naval Academy and a Master of Business Administration degree from Harvard Business School.

Executive Officers

We do not currently employ any of the executive officers who manage our business. Mr. Antonello, our Chief Executive Officer, is employed by Magni Bermuda and provides services to us pursuant to a secondment agreement we have entered into with Magni Bermuda. Mr. Maranhão, our Chief Financial Officer, is employed by Golar Management and provides services to us pursuant to a management and administrative services agreement that we have entered into with Golar Management. Pursuant to this management and administrative services agreement, Golar Management will also provide to us other management, administrative, financial and support services and we will reimburse Golar Management for its reasonable costs and expenses incurred in connection with providing such services. In addition, we will pay Golar Management a management fee equal to 5% of certain of its costs and expenses incurred in connection with providing these services to us. For more information, please read “Certain Relationships and Related Transactions—Other Transactions with Related Persons—Management and Administrative Services Agreement.”

Our officers and the other individuals providing services to us or our subsidiaries may face a conflict regarding the allocation of their time between our business and the other business interests of their employers. The amount of time our officers will allocate between our business and the business of their employers will vary from time to time depending on various circumstances and needs of the businesses, such as the level of strategic activities of the businesses. Our officers intend to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

The following table shows information for each of the persons who will perform executive officer services for us upon the consummation of this offering. The business address for these individuals is 2^nd Floor, S.E. Pearman Building, 9 Par-la-Ville Road, Hamilton HM 11, Bermuda.

Name	Age	Position
Eduardo Antonello	44	Chief Executive Officer
Eduardo Maranhão	36	Chief Financial Officer

Eduardo Antonello has served as our Chief Executive Officer since May 2016. Mr. Antonello is an employee of Magni Bermuda and provides services to us pursuant to a secondment agreement by and between us and Magni Bermuda. Prior to becoming our Chief Executive Officer, Mr. Antonello served as an employee of Magni Partners Limited (“Magni Partners”), a consulting firm that provides certain services to us, from April 2015 to May 2016. Before that, he served as a Senior Vice President of Seadrill from September 2008 to February 2015, where he was responsible for establishing the company’s Brazilian operations, and as a Geomarket Manager for Schlumberger from September 2000 to September 2008. Mr. Antonello is also currently a partner in Magni Partners. Mr. Antonello holds a Bachelor of Mechanical Engineering from Universidade Mackenzie in São Paulo, Brazil.

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Eduardo Maranhão has served as our Chief Financial Officer since April 2018. Mr. Maranhão is an employee of Golar Management and provides services to us pursuant to a management and administrative services agreement by and between us and Golar Management. Prior to joining us, Mr. Maranhão served as the Chief Executive Officer of CELSE from May 2016 to April 2018. Before CELSE, he served as a partner of Lakeshore Partners, an independent financial advisory firm based in São Paulo, Brazil, from November 2011 to March 2015 and as a Senior Associate at Banco Santander focusing on the power and oil and gas sectors from October 2010 to November 2011. Mr. Maranhão also currently serves on the board of directors of CELSE, a position he has held since May 2018, and as a partner in Magni Partners, a position he has held since March 2015. Mr. Maranhão holds a Bachelor of Business Administration from Universidade de Pernambuco in Brazil and has completed a Management Acceleration Programme from INSEAD in France.

Corporate Governance

Because we qualify as a foreign private issuer under SEC rules, we are permitted to follow the corporate governance practices of Bermuda (the jurisdiction in which we are organized) in lieu of certain NASDAQ corporate governance requirements that would otherwise be applicable to us. For example, under Bermuda law, we are not required to, and we do not intend to, have a board of directors comprised of a majority of directors meeting the independence standards described in the NASDAQ rules.

In the event we no longer qualify as a foreign private issuer, we intend to rely on the “controlled company” exemption under the NASDAQ corporate governance standards. Because our Sponsors will initially hold approximately 81.2% of the voting power of our shares following the completion of this offering (or approximately 79.0% if the underwriters exercise their option to purchase additional common shares in full), we expect to be a controlled company as of the completion of the offering under the NASDAQ corporate governance standards. 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. As a controlled company, we will remain subject to the rules of the Sarbanes-Oxley Act and NASDAQ that require us to have an audit committee composed entirely of independent directors.

If at any time we cease to be a foreign private issuer or a controlled company, we will take all action necessary to comply with the NASDAQ corporate governance standards, including by appointing a majority of independent directors to our board of directors, subject to a permitted “phase-in” period.

Director Independence

Because we qualify as a foreign private issuer under SEC rules, we are permitted to follow the corporate governance practices of Bermuda (the jurisdiction in which we are organized) in lieu of certain NASDAQ corporate governance requirements that would otherwise be applicable to us. Under Bermuda law, we are not required to have a board of directors comprised of a majority of directors meeting the independence standards described in NASDAQ rules.

Committees of the Board of Directors

Audit Committee

The NASDAQ requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members all of whom are required to meet the independence and experience standards established by NASDAQ and the Exchange Act. Because, as of the closing of this offering, we will be a foreign private issuer under SEC rules, we are exempt from certain rules of NASDAQ and are permitted to follow home country practice in lieu of certain NASDAQ corporate governance standards. Consistent with our status as a foreign private issuer and the jurisdiction of our incorporation (Bermuda), our audit committee will consist of two members, Mrs. Blankenship and Mr. Hanrahan, each of whom will be independent under NASDAQ corporate governance standards and the Exchange Act relating to audit committees. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. Both Mrs. Blankenship and Mr. Hanrahan will satisfy the definition of “audit committee financial expert.” We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NASDAQ standards.

The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and company policies and controls. The audit committee

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will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management.

Compensation Committee

Because, as of the closing of this offering, we will be a foreign private issuer under SEC rules and “controlled company” within the meaning of the NASDAQ corporate governance standards, we will not be required to, and do not currently expect to, have a compensation committee as of the closing of this offering. If and when we are no longer a foreign private issuer under SEC rules or a “controlled company” within the meaning of NASDAQ corporate governance standards, we will be required to establish a compensation committee. We anticipate that such a compensation committee would consist of three directors who will be “independent” under the rules of the SEC and NASDAQ. This committee would establish salaries, incentives and other forms of compensation for officers and other employees. Any compensation committee would also administer our incentive compensation and benefit plans. Upon formation of a compensation committee, we would expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NASDAQ or market standards.

Nominating Committee

Because we intend to list our common shares on NASDAQ, we will not be required to have a nominating committee as of the closing of this offering; however, we have chosen to establish a Nominating Committee of our Board. The primary responsibility of this committee is to select and recommend to the board, director and committee member candidates. We will not be subject to NASDAQ’s requirements relating to independent director oversight of director nominations because, as of the closing of this offering, we will be a foreign private issuer under SEC rules and a “controlled company” within the meaning of the NASDAQ corporate governance standards. If and when we are no longer a foreign private issuer or a “controlled company” within the meaning of NASDAQ corporate governance standards, we will be subject to NASDAQ’s requirements related to independent oversight of director nominations.

Compensation

Compensation of Management

We do not directly employ any of the executive officers who manage our business. Mr. Antonello, our Chief Executive Officer, is employed and compensated by Magni Bermuda and provides services to us pursuant to a secondment agreement that we have entered into with Magni Bermuda. Mr. Maranhão, our Chief Financial Officer, is employed and compensated by Golar Management and provides services to us pursuant to a management and administrative services agreement that we have entered into with Golar Management. For the year ended December 31, 2019, we incurred charges from Magni Partners and Magni Bermuda of $1.4 million for services provided by Magni Partners and Magni Bermuda to us, which includes services performed by Mr. Antonello pursuant to the secondment agreement as well as other management and administrative services provided to us by Magni Partners and Magni Bermuda. For the year ended December 31, 2019, we incurred charges from Golar Management of $5.9 million for services provided under the management and administrative services agreement, which includes services performed by Mr. Maranhão as well as other management and administrative services provided to us by Golar Management. For the year ended December 31, 2019, we did not set aside or accrue any amounts to provide pension, retirement or similar benefits to our executive officers as such executive officers were compensated by Magni Bermuda or Golar Management, as applicable.

Please read “Certain Relationships and Related Transactions—Other Transactions with Related Persons—Management and Administrative Services Agreement” and “Certain Relationships and Related Transactions—Other Transactions with Related Persons—Magni Partners” for additional information.

Certain of our employees and directors, including Messrs. Antonello, Maranhão and Trøim (through Magni Partners), participate in a management incentive scheme (the “MIS”), which entitles them to receive a certain percentage (an “Allocation”) of the total amount payable under the MIS, which is approximately $98,700,000

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(the “MIS Pool”) based on the mid-point of the price range on the cover of this prospectus following the closing of this offering. Each Allocation will vest in full and will no longer be subject to forfeiture upon the closing of this offering. The Allocation for each of Messrs. Antonello, Maranhão and Trøim is as follows: Mr. Antonello is eligible to receive 25% of the MIS Pool, Mr. Maranhão is eligible to receive 19.75% of the MIS Pool and Mr. Trøim (through Magni Partners) is eligible to receive 22.25% of the MIS Pool. Based on the mid-point of the price range on the cover of this prospectus, upon settlement of the MIS Pool, it is currently anticipated that, in respect of their respective Allocations, Mr. Antonello will receive approximately $6.0 million in cash and 957,808 common shares, Mr. Maranhão will receive approximately $3.0 million in cash and 845,899 common shares and Mr. Trøim (through Magni Partners) will receive 1,126,296 common shares. Each Allocation will be settled as soon as practicable following the closing of this offering unless the parties otherwise agree to defer settlement in a manner that does not result in adverse tax consequences. Once each Allocation vests and becomes payable upon the closing of this offering, no future awards will be granted nor will any additional amounts become payable under the MIS following the closing of this offering except that the MIS will remain in place until each Allocation that was outstanding prior to the closing of this offering is settled, at which point the MIS would be deemed terminated. The entire cost of the MIS will be funded by Stonepeak upon settlement which will be recorded as a capital contribution by the Company. The Company will not incur any cash outflow upon settlement. For further information regarding the MIS, see Note 26 to the audited consolidated financial statements included elsewhere in this prospectus.

Compensation of Directors

We believe that attracting and retaining qualified non-management directors will be critical to the future value growth and governance of our company. Accordingly, in connection with this offering, we expect to implement a non-management director compensation program, but the terms of such program have not yet been finalized.

Directors who serve as our executive officers or as officers of Golar LNG will not receive any additional compensation for their service as directors but may receive certain director fees in lieu of other compensation paid by Golar LNG.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common shares that will be issued and outstanding upon the consummation of this offering, and assuming the underwriters do not exercise their option to purchase additional common shares and held by:

•	beneficial owners of 5% or more of any class of our shares;

•	each director and executive officer; and

•	all of our directors, director nominees and executive officers as a group.

Unless otherwise noted, the address for each beneficial owner listed below is c/o Golar Management Limited, 6th Floor, The Zig Zag, 70 Victoria Street, London SW1E 6SQ, United Kingdom.

Name of Beneficial Owner	Common Shares Beneficially Owned Prior to the Offering		Common Shares Beneficially Owned After the Offering
Name of Beneficial Owner	Number⁽¹⁾	Percent⁽²⁾	Number	Percent
Golar LNG Ltd.⁽³⁾	23,475,077	50%	50,000,000	40.6%
Stonepeak Golar Power Holdings (Cayman) LP⁽⁴⁾⁽⁵⁾	23,475,077	50%	50,000,000	40.6%

Directors, Director Nominees and Executive Officers
Eduardo Antonello⁽⁵⁾	—	—%	—	—%
Eduardo Maranhão⁽⁵⁾	—	—%	—	—%
Tor Olav Trøim⁽⁵⁾	—	—%	—	—%
Luke Taylor	—	—%	—	—%
Jeffry Myers	—	—%	—	—%
Georgina Sousa	—	—%	—	—%
Kate Blankenship	—	—%	—	—%
Paul Hanrahan	—	—%	—	—%
All executive officers and directors as a group (8 persons)	—	—%	—	—%

(1)	Beneficial ownership of common shares in this column does not give effect to a 2.13-for-1 share split to be effective prior to the consummation of this offering.

(2)

Based upon an aggregate of 46,950,154 shares outstanding as of September 16, 2020. For each shareholder, in accordance with Rule 13d-3 promulgated under the Exchange Act, this percentage is determined by assuming the named shareholder exercises all options and other instruments pursuant to which the shareholder has the right to acquire shares of our common shares within 60 days of September 16, 2020, but that no other person exercises any options or other purchase rights (except with respect to the calculation of the beneficial ownership of all directors and executive officers as a group, for which the percentage assumes that all directors and executive officers exercise all such options or other purchase rights).

(3)	Golar LNG (Nasdaq: GLNG) is managed by its board of directors. In August 2019, Golar LNG entered into a $150 million term loan facility with a total term of fifteen months. The term loan facility is secured by a pledge against its shares in Hygo.

(4)

Prior to consummation of this offering, the entity that holds Stonepeak’s investment in Hygo (Stonepeak Infrastructure Fund II Cayman (G) Ltd.) will merge with and into Hygo, with Hygo surviving the merger. Following consummation of this offering, Stonepeak’s investment in Hygo will be held through Stonepeak Golar Power Holdings (Cayman) LP. See “Business—Our History and Relationship with Our Sponsors.” Stonepeak Infrastructure Fund II Cayman (G) Ltd. is wholly owned by Stonepeak Golar Power Holdings (Cayman) LP. The general partner of Stonepeak Golar Power Holding (Cayman) LP is Stonepeak Infrastructure Fund II Cayman LP. The general partner of Stonepeak Infrastructure Fund II Cayman LP is Stonepeak Infrastructure Fund II Cayman Ltd., whose managing shareholders are, collectively, Michael Dorrell and Trent Vichie. The principal business address of the entities and individuals identified herein is c/o Stonepeak Infrastructure Partners, 55 Hudson Yards, 550 W. 34th St., 48th Floor, New York, NY 10001.

(5)

Certain of our employees and directors, including Messrs. Antonello, Maranhão and Trøim (through Magni Partners), participate in the MIS, which entitles them to a certain percentage of the MIS Pool. Stonepeak is responsible for making all payments relating to the MIS Pool. Based on the mid-point of the price range on the cover of this prospectus, upon settlement of the MIS Pool, it is currently anticipated that Mr. Antonello will receive approximately $6.0 million in cash and 957,808 common shares, Mr. Maranhão will receive approximately $3.0 million in cash and 845,899 common shares and Mr. Trøim (through Magni Partners) will receive 1,126,296 common shares. Stonepeak is responsible for making all payments relating to the MIS Pool. See “Management—Compensation—Compensation of Management.”

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Agreements with Affiliates in Connection with the Transactions

In connection with this offering, we will enter into certain agreements with our Sponsors, as described in more detail below.

Shareholders’ Agreement

In connection with this offering, we expect to enter into a Shareholders’ Agreement with Golar LNG and Stonepeak. This agreement will grant each of our Sponsors the right to nominate to our board of directors two directors so long as such Sponsor and its affiliates and certain of their transferees own at least 10% of our outstanding common shares and at least one director so long as the applicable Sponsor and its affiliates and certain of their transferees own at least 5% of our outstanding common shares. As long as our Sponsors collectively own 50% of our voting share capital, each Sponsor will agree to vote the other’s nominees. To the extent the size of the board of directors exceeds nine directors, the number of directors each Sponsor shall be entitled to nominate shall increase by one. Pursuant to the Shareholders' Agreement, the size of the board of directors shall not exceed 15 directors. As long as a Sponsor has the right to designate at least one director to the board of directors, such Sponsor will have the right to designate one member to each committee of the board of directors, subject to applicable law and independence requirements, and each Sponsor shall be represented on any committee in the same proportion as it is represented on the board of directors unless otherwise agreed by the Sponsors. In addition, in the event a vacancy on the board of directors is created by the death, disability, retirement or resignation of a Sponsor director designee, such Sponsor, its affiliates and certain transferees who designated such director shall, to the fullest extent permitted by law, have the right to have the vacancy filled by a new Sponsor director-designee. The Shareholders' Agreement also provides the Sponsors with customary board observer and information rights.

In the Shareholders’ Agreement, we will grant our Sponsors the right to cause us, at our expense, to file registration statements under the Securities Act covering resales of our common shares held by our Sponsors. Under the Shareholders’ Agreement, all holders of registrable securities party thereto will also be provided with customary “piggyback” registration rights following an initial public offering, with certain exceptions. These shares will represent approximately 81.2% of our outstanding common shares after this offering, or approximately 79.0% if the underwriters exercise in full their option to purchase additional common shares. We will also agree not to grant any other person registration rights that have priority over the registration rights granted by the Shareholders’ Agreement without the prior written consent of each of our Sponsors. In addition, in connection with the offering of equity securities by the Company to either of the Sponsors, the Company is required to offer to such other Sponsor equity securities on the same terms and on a pro rata basis in the same proportion as the Sponsors' beneficial ownership immediately prior to the time of such offering. The Shareholders’ Agreement will also require us to indemnify certain of our shareholders and their affiliates in connection with any registrations of our securities.

Other Transactions with Related Persons

Management and Administrative Services Agreement

In connection with this offering, we expect to amend and restate our existing management and administrative services agreement with Golar Management, an affiliate of Golar LNG, pursuant to which Golar Management provides us with certain management and administrative services. In consideration of such services, we will pay to Golar Management an uncapped amount equal to the costs incurred to provide such services plus a 5% management fee. For the six months ended June 30, 2020 and the years ended December 31, 2019 and 2018, we incurred charges from Golar Management of $2.7 million, $5.9 million and $6.2 million, respectively, for services provided under the management and administrative services agreement. Either party may terminate the agreement by providing six month’s written notice.

Under the management and administrative services agreement, Golar Management will provide administrative and executive functions for our benefit. Golar Management will be responsible for our day-to-day management subject to the direction of our executive officers and board of directors.

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The administrative services provided by Golar Management will include:

•

bookkeeping, audit and accounting services: assistance with the maintenance of our corporate books and records, assistance with the preparation of our tax returns and arranging for the provision of audit and accounting services, as well as the preparation of financial statements of the Company in accordance with applicable securities laws and regulations;

•	legal and insurance services: arranging for the provision of periodic and annual reports and legal, insurance and other professional services;

•

banking and financial services: providing cash management including assistance with preparation of budgets, overseeing banking services and bank accounts, arranging for the collection and deposit of funds, settling debts, disputes and inter-company accounts and negotiating loan and credit terms with lenders and providing all administrative services required for subsequent debt and equity financings;

•	internal guidelines and policies: developing and implementing internal guidelines related to safety, environmental protection and ethical conduct;

•	advisory services: assistance in complying with United States and other relevant securities laws and the rules and regulations of the Nasdaq Global Select Market; and

•	client and investor relations: arranging for the provision of advisory, clerical and investor relations services to assist and support us in our communications with our shareholders.

At the beginning of each quarter, we will reimburse Golar Management in advance for its reasonable costs and expenses expected to be incurred in connection with the provision of these services. In addition, we will pay Golar Management a management fee equal to 25% of certain of its costs and expenses expected to be incurred in connection with providing services to us for the quarter. Amounts payable under the management and administrative services agreement in advance must be paid at the beginning of each quarter. Following the finalization of Golar Management's annual accounts, Golar Management will calculate the difference between the expected costs and expenses paid in advance and the actual costs and expenses owed under the management and administrative services agreement. Such amounts payable pursuant to the calculated difference must be paid within 15 days after Golar Management submits to us a calculation of the difference between such costs and expenses. We expect that we will pay Golar Management approximately $7 million in total under the management and administrative services agreement for the twelve months ending December 31, 2020.

Under the management and administrative services agreement, we will indemnify Golar Management, its subcontractors, and any of its or their employees against all actions which may be brought against them under the management and administrative services agreement and against and in respect of all losses they may suffer or incur arising in connection with the provision of services under such agreement; provided, however that such indemnity excludes any or all losses which may arise from or be caused by gross negligence or willful misconduct, by Golar Management, its subcontractors, or any of its or their employees. The aggregate liability of Golar Management in any calendar year shall not exceed the fee payable in such calendar year.

Cooperation Agreement

In August 2020, we entered into a cooperation agreement with Golar Partners to develop LNG terminals using Golar Partners’ existing vessel portfolio. We intend to utilize Golar Partners’ vessels for terminal developments where such assets are technically suitable. The terms and structure of the commercial cooperation agreement will be subject to negotiation between the parties if a suitable opportunity is identified on a project by project basis.

Ship Management Fees

Golar LNG and certain of its affiliates charge us ship management fees for the provision of technical and commercial management of our vessels. Each of our vessels is subject to management agreements pursuant to which certain commercial and technical services are provided by Golar Management. We may terminate these agreements by providing 30 days’ written notice. During the six months ended June 30, 2020 and the years ended December 31, 2019 and 2018, ship management fees totaled $0.8 million, $1.2 million and $1.4 million, respectively.

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Operation Services Agreement

We provide technical and operational services related to the Golar Nanook pursuant to an Operation Services Agreement with CELSE. During the six months ended June 30, 2020 and the years ended December 31, 2019, total compensation for services provided under the Operation Services Agreement was $5.3 million and $5.0 million, respectively. There was no compensation during 2018.

Debt Guarantees

We entered into agreements to compensate Golar LNG in relation to certain debt guarantees. These guarantees were issued by Golar LNG to third party banks in connection with secured debt facilities related to the Golar Celsius and the Golar Penguin. Golar LNG also provided a guarantee to cover the remaining payments due to the shipyard for the Golar Nanook. This compensation amounted to $0.6 million, $0.7 million and $0.7 million for the six months ended June 30, 2020 and the years ended December 31, 2019 and 2018, respectively.

Magni Partners

Tor Olav Trøim, one of our directors, is the founder of, and a partner in, Magni Partners Limited, a privately held UK company, as well as Magni Partners (Bermuda) Ltd., a Bermudan domiciled company. In his role, Mr. Trøim is the ultimate beneficial owner of Magni Partners and Magni Bermuda. Eduardo Antonello, our Chief Executive Officer, and Eduardo Maranhão, our Chief Financial Officer, are also partners in Magni Partners Limited. Pursuant to management agreements between us, Magni Partners and Magni Bermuda, we are charged for salary and consulting expenses for all individuals working for Magni Partners and Magni Bermuda and dedicated to us, including our Chief Executive Officer and Chief Financial Officer. During the six months ended June 30, 2020 and the years ended December 31, 2019 and 2018, we were charged $1.4 million, $1.4 million and $0.9 million, respectively.

Currently, Mr. Antonello, our Chief Executive Officer, provides services to us pursuant to a secondment and consultancy agreement (a “Secondment Agreement”), dated April 4, 2017, by and among Magni Bermuda and us. The terms of the Secondment Agreement state that Mr. Antonello is seconded to us for the purpose of acting as our Chief Executive Officer on a part-time basis, representing approximately 50% of a full working year for an individual. However, Mr. Antonello currently expends substantially all of his business time as our Chief Executive Officer, and we are in the process of terminating the Secondment Agreement and replacing it with an agreement directly with Mr. Antonello pursuant to which he will be compensated for his service as our Chief Executive Officer on a full time basis, to align his compensation and duties with his actual dedication over the past year.

Under the terms of the current agreement, we pay an annual secondment fee related to Mr. Antonello’s secondment, and Mr. Antonello is eligible for an annual performance-based cash bonus, which would be awarded at the discretion of our board of directors. Also pursuant to the current arrangement, Magni Bermuda provides certain consulting services, including strategic planning, financing and evaluating potential projects, for a monthly fee plus reimbursement of reasonable expenses incurred. Magni Bermuda is eligible, at the discretion of our board of directors, for a bonus payment with respect to specific projects to which Magni Bermuda has contributed.

We may terminate the Secondment Agreement without notice and without liability for further payment under certain circumstances, including if Magni Bermuda or Mr. Antonello: (i) commits any gross misconduct affecting our business; (ii) commits any serious or repeated breach of the Secondment Agreement or refuses or neglects to comply with any reasonable and lawful direction of our board of directors; (iii) is convicted of any criminal offense; (iv) is, in our reasonable opinion, negligent or incompetent in the performance of its or his obligations under the Secondment Agreement; (v) is declared bankrupt or makes any arrangement with or for the benefit of its or his creditors; (vi) is incapacitated from providing the services under the Secondment Agreement for an aggregate period of 25 days in any 52 week consecutive period; (vii) commits any fraud or dishonesty or acts in any manner which, in our opinion, is likely to bring us into disrepute or is materially adverse to our interests; (viii) commits any offense under any applicable anti-bribery legislation; and (ix) if Mr. Antonello is no longer available to Magni Bermuda. We expect to terminate the agreement upon the mutual consent of the parties.

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Joint Venture Shareholders’ Agreements

CELSEPAR

General

The Shareholders’ Agreement of CELSEPAR, dated March 16, 2018 (the “CELSEPAR Agreement”), governs the rights of its members, Ebrasil and Golar Brazil, which is a wholly-owned subsidiary of Hygo. Ebrasil and Golar Brazil each hold a 50.0% membership interest in CELSEPAR.

Governance

CELSEPAR is managed by its board of directors and an executive board. The board of directors consists of four members, elected by each of the shareholders for a term of three years. Two members are appointed by Ebrasil and two members are appointed by Golar Brazil. If a shareholder’s ownership interest is less than 38% but greater than 19%, such shareholder will have the right to appoint only one director. If a shareholder owns less than 19%, then such shareholder is not entitled to designate anyone to the board of directors. Golar Brazil appointed the current chairman of the board, and his term expires in 2022.

The board of directors is responsible for the following matters, among others:

•	approval or amendment of CELSEPAR’s business plan;

•	execution of financial operations of any nature, in an amount exceeding R$800,000;

•

execution, termination or amendment of (i) a definitive lump sum turn key EPC or long term gas or LNG supply agreements by CELSE and bridge loan with the project financiers; or (ii) any contract between CELSEPAR and any shareholder, as well as the assumption or waiver of any obligations to CELSEPAR in such instruments;

•	approval of any share capital increase within the limit of the authorized capital;

•	approval of any investment, acquisition or expense equal to or greater than R$5,000,000;

•	sale, lease, assignment, transfer or any other form of disposition of rights of CELSEPAR, in an amount equal to or greater than R$800,000; and

•	any settlement of legal proceedings in an amount exceeding R$100,000.

The matters listed above must be approved by the majority of the members of the Board of Directors, so long as each shareholder holds at least 21% of the shares (some matters requiring 38%) with voting rights, provided that it includes the affirmative vote of at least 1 member appointed by each shareholder. All other resolutions of the board shall be approved by the affirmative vote of the absolute majority of the members of the board.

Certain other matters are reserved for a vote by the shareholders at a general meeting, including:

•	amendment of CELSEPAR's bylaws solely if it entails (i) amendment of the corporate purpose or (ii) alteration of the powers of the General Meeting and the Board of Directors or its composition;

•	authorization for the creation and issuance of any security that assures its holders rights over CELSEPAR's profits, subscription bonuses, convertible debentures or any other convertible security;

•	increase of CELSEPAR’s capital stock outside the authorized capital;

•	reduction of CELSEPAR's share capital;

•	redemption, cancellation, amortization or repurchase of shares issued by CELSEPAR;

•	distribution of dividends or interest on equity other than as provided in the CELSEPAR Agreement;

•	setting the overall compensation of CELSEPAR’s managers at values above market standards;

•	merger, absorption (including absorption of shares) or spin-off of CELSEPAR;

•	adoption, establishment, amendment or termination of any plan, program, contract or benefit agreement for employees or managers of CELSEPAR;

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•	registration as a publicly held company or cancellation of such registration;

•	transformation of CELSEPAR into any other corporate type;

•	authorization to file for bankruptcy or to request judicial reorganization or to propose out-of-court reorganization;

•	dissolution, liquidation, extinction, or termination of the state of liquidation of CELSEPAR; and

•	guide CELSEPAR's vote in the general meetings of its controlled companies.

Resolutions regarding the matters listed in bullets 1, 2, 3, 5, 8, 11 and 12 require the approval of shareholders holding 79% of the shares with voting rights. Resolutions regarding the matters listed in bullets 7 and 10 above require the approval of shareholders holding 62% of the shares with voting rights. All other matters shall be approved by the affirmative vote of an absolute majority.

Distributions

CELSEPAR shall distribute to its shareholders, at least quarterly, the total net income available, provided that the legal requirements, covenants of any financial agreements entered into by CELSEPAR are met and that such distribution does not jeopardize CELSEPAR’s operations.

Capital Calls to Members

The shareholders are obligated to contribute, in proportion to their ownership interests, up to 25% of the resources necessary for the Sergipe Power Plant.

Transfer Restrictions

Shareholders may not sell, transfer or otherwise dispose of all or part of their shares to third parties without first offering them to another shareholder. Such other shareholder shall have a right of first refusal to purchase the shares or a tag along right, where such other shareholder has the right to require that its shares be included in the sale. Such tag along right is subject to a proportionate reduction if more than one shareholder exercises the tag along right.

CELBA

General

The Shareholders’ Agreement of CELBA, dated July 19, 2018 (the “CELBA Agreement”), governs the rights of its members, Evolution and Golar Power Latam Participações e Comércio Ltda., which is a wholly-owned subsidiary of Hygo Energy Transition Ltd. (“Golar Latam”). Evolution and Golar Latam each hold a 50.0% membership interest in CELBA. We intend to use a portion of the net proceeds of this offering to purchase the remaining 50.0% membership interest in CELBA from Evolution.

Governance

CELBA is managed by its board of directors, which consists of two members, elected by each of the shareholders for a term of two years. One member is appointed by Evolution and the other is appointed by Golar Latam.

The board of directors is responsible for the administration of CELBA and all of the acts necessary for the operation CELBA, subject to the limitations set forth in the CELBA Agreement and CELBA’s Bylaws.

Approval by the holders of 100% of CELBA’s outstanding shares is required for the board of directors to act on certain matters, including:

•	authorize the opening of branches, deposits, offices or other establishments domestically or internationally;

•	choose and dismiss the independent auditors;

•	acquire, dispose of or encumber non-current assets;

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•	authorize encumbrances of Company property or the issuance of guarantees or obligations in an amount greater than R$1,000,000;

•	assume any obligation or release third parties from any obligation of an amount greater than R$1,000,000;

•	incur debt by financing, loan or other indebtedness in any amount;

•	declare bankruptcy;

•	set or adjust executive compensation in any way, including stock option grants;

•	approve the adoption, approval or modification of the budget or strategic plan;

•	dispose of assets in an amount greater than R$1,000,000;

•	define or alter the conditions and characteristics of CELBA’s energy generation projects;

•	authorize the grant of guarantees, sureties or other warranties related to the obligations of third parties;

•	settle any private or governmental dispute;

•	approve capital raises for CELBA or any subsidiary;

•	undertake a merger, incorporation or dissolution of CELBA;

•	redemption, cancellation or buybacks of shares or other securities issued by CELBA;

•	transactions with related parties;

•	alteration of the Bylaws that (i) modifies the powers of the Shareholders acting together or the Board, (ii) reduces the minimum required dividend or creates statutory reserves for CELBA’s profits and/or (iii) changes CELBA’s corporate purpose;

•	winding up or liquidation of CELBA;

•	acquisition by CELBA of ownership in other persons; and

•	creation of instruments to regulate the stockholder relations of CELBA with any third parties, including shareholder agreements or stockholder agreements.

In the event that shareholders do not obtain the votes necessary to approve any of the above matters (an “Impasse”), the shareholders shall submit such Impasse for negotiation by their respective Chief Executive Officers, who must make a good faith attempt to reach an agreement within twenty business days from the date the matter was submitted for their consideration. If such officers are unable to reach an agreement, the matter will be resubmitted to the shareholders and an independent nationally-recognized mediator, whose opinion shall represent a recommendation to the shareholders and shall not be binding. If the shareholders fail to reach an agreement following the mediator’s recommendation, they may submit the matter to arbitration.

Distributions

CELBA shall distribute to its shareholders 25% of its net income as the minimum required dividend. Shareholders may, upon the vote of the shareholder, declare dividends or interest on CELBA’s profits.

Transfer Restrictions

Shareholders may not sell, transfer or otherwise dispose of all or part of their shares to third parties without first offering them to another shareholder. Such other shareholder shall the right of first refusal to purchase the shares or a tag along right. The right of first refusal and tag along right are not applicable in the case of a transfer of shares held by any shareholders to its affiliates, except if such affiliate has its control shared between the shareholder and third parties.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that our board of directors will adopt a written policy that outlines procedures for approving certain transactions with related persons, and that any such transactions will be reviewed and approved or ratified

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by a majority of our disinterested and independent directors pursuant to the procedures outlined in any such policy. In determining whether to approve or ratify a transaction with a related person, we expect that the independent and disinterested directors will consider a variety of factors they deem relevant. For purposes of the policy, “related person” means:

•	any director, director nominee or executive officer;

•	any immediate family member of a director, director nominee or executive officer;

•	a 10% beneficial owner of our voting securities or any immediate family member of such owner;

•	enterprises in which a substantial interest in the voting power is owned, directly or indirectly by a person described in any of immediately preceding three bullet points or over which such a person is able to exercise significant influence; and

•	enterprises that directly or indirectly control or are controlled by, or under common control, with us.

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DESCRIPTION OF SHARE CAPITAL

The following description of our share capital summarizes certain provisions of our memorandum of association and our bye-laws that will become effective as of the closing of this offering. Such summaries do not purport to be complete and are subject to, and are qualified in their entirety by reference to, all of the provisions of our memorandum of association, a copy of which has been filed as an exhibit, and Bye-laws, a copy of which will be filed as an exhibit to the registration statement of which this prospectus forms a part. Prospective investors are urged to read the exhibits for a complete understanding of our memorandum of association and bye-laws.

We are an exempted company limited by shares incorporated in Bermuda and our corporate affairs are governed by our memorandum of association and bye-laws, the Companies Act and the common law of Bermuda.

Following this offering, our authorized share capital will consist of 500,000,000 common shares of par value of $0.4695 each and 100,000,000 preferred shares of par value $0.01 each. All of our issued and outstanding common shares are fully paid. Immediately upon the completion of this Offering, there will be 123,100,000 common shares outstanding, assuming the underwriters do not exercise the option to purchase additional common shares. There will be no preferred shares outstanding upon the completion of this Offering.

Subject to any special rights conferred on the holders of any share or class of shares, any share may be issued with or have attached thereto, such preferential, deferred, qualified or other special rights, privileges or conditions whether in regard to dividend, voting, return of capital or otherwise.

Purpose

We were incorporated by registration under the Companies Act. The purposes and powers of the Company are set forth in our memorandum of association. Our business objects are unrestricted and we have all the powers of a natural person.

Common Shares Ownership

Our memorandum of association and bye-laws will not impose any limitations on the ownership rights of our shareholders. There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote our common shares.

Preference Shares

The Board is authorized to provide for the issuance of preference shares in one or more classes or series, and to fix, for each such class or series, the number of shares which shall constitute such class or series, full, limited or no voting power, designations, preferences, special rights, qualifications, limitations and restrictions thereof, as shall be stated and expressed in the resolution or resolutions adopted by the Board. The Board shall have the authority to provide that any such class or series may be: (a) subject to redemption at the option of the Company or the holders, or both; (b) entitled to receive dividends at such rates, on such conditions, and at such times, and payable in preference to, or in such relation to, the dividends payable on any other class or classes or any other series; (c) entitled to such rights upon the dissolution of, or upon any distribution of the assets of, the Company; or (d) convertible into, or exchangeable for, any other class or classes of shares, or of any other series of the same or any other class or classes of shares, of the Company at such price or prices or at such rates of exchange and with such adjustments.

Dividends

Holders of our common shares are entitled to receive ratably all dividends, if any, declared by our board of directors, out of funds legally available for dividends. As a Bermuda exempted company limited by shares, we are subject to Bermuda law relating to the payment of dividends. We may not pay any dividends if, at the time the dividend is declared or at the time the dividend is paid, there are reasonable grounds for believing that, after giving effect to that payment:

•	we will not be able to pay our liabilities as they fall due; or

•	the realizable value of our assets is less than our liabilities.

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In addition, since we are a holding company with no material assets, and conduct our operations through subsidiaries, our ability to pay any dividends to shareholders will depend on our subsidiaries’ distributing to us their earnings and cash flow. Some of our loan agreements currently limit or prohibit our subsidiaries’ ability to make distributions to us and our ability to make distributions to our shareholders.

In addition, we may not pay distributions to our shareholders out of our contributed surplus account, as such funds are reserved to our Sponsors in connection with their capital contributions to the Company and the reduction in the par value of our common shares that was effective prior to this offering.

Voting Rights

Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Unless a different majority is required by law or by our bye-laws, resolutions to be approved by holders of common shares require approval by a simple majority of votes cast at a meeting at which a quorum is present.

Majority shareholders do not generally owe any duties to other shareholders to refrain from exercising all of the votes attached to their shares. There are no deadlines in the Companies Act relating to the time when votes must be exercised. However, our bye-laws will provide that where a shareholder or a person representing a shareholder as a proxy wishes to attend and vote at a meeting of our shareholders, such shareholder or person must give us not less than 48 hours’ notice in writing of their intention to attend and vote.

The key powers of our shareholders include the power to alter the terms of our memorandum of association and to approve and thereby make effective any alterations to our bye-laws made by the directors. Dissenting shareholders holding 20% of our issued share capital may apply to the court to annul or vary an alteration to our memorandum of association. A majority vote against an alteration to our bye-laws made by the directors will prevent the alteration from becoming effective. Other key powers are to approve the alteration of our capital, including a reduction in share capital, to approve the removal of a director, to resolve that we will be wound up or discontinued from Bermuda to another jurisdiction or to enter into an amalgamation, merger or winding up. Under the Companies Act, all of the foregoing corporate actions require approval by an ordinary resolution (a simple majority of votes cast), unless our bye-laws provide otherwise, which our bye-laws will. Our bye-laws will provide that the board of directors may, with the sanction of a resolution passed by a simple majority of votes cast at a general meeting with the necessary quorum for such meeting of two persons at least holding or representing a majority of our issued common shares (or the class of securities, where applicable) provided, that so long as any of the Sponsors hold at least 5% of the outstanding shares with the right to vote attached thereto, a quorum must include a Shareholder representative of such Sponsor, amalgamate or merge us with another company. In addition, our bye-laws will permit us to reduce our issued share capital with the authority of an ordinary resolution of the shareholders. Not less than seven days’ prior written notice of any resolution to reduce our issued share capital and a copy of such resolution shall be circulated to all shareholders who would be entitled to vote on the resolution at a general meeting at which the resolution could have been considered.

The Companies Act provides that a company shall not be bound to take notice of any trust or other interest in its shares. There is a presumption that all the rights attaching to shares are held by, and are exercisable by, the registered holder, by virtue of being registered as a member of the company. Our relationship is with the registered holder of our shares. If the registered holder of the shares holds the shares for someone else (the beneficial owner), then the beneficial owner is entitled to the shares and may give instructions to the registered holder on how to vote the shares. The Companies Act provides that the registered holder may appoint more than one proxy to attend a shareholder meeting, and consequently where rights to shares are held in a chain the registered holder may appoint the beneficial owner as the registered holder’s proxy.

Meetings of Shareholders

The Companies Act provides that a company must have a general meeting of its shareholders in each calendar year unless that requirement is waived by resolution of the shareholders. Under our bye-laws, annual meetings of shareholders will be held at a time and place selected by our board of directors each calendar year. Special meetings may be called at any time at the discretion of the board of directors provided, however, that prior to the Trigger Date (as defined herein), special meetings shall be convened by the board of directors at the request of the holders of record of a majority of the outstanding shares with the right to vote attached thereto.

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Annual shareholder meetings and special meetings must be called by not less than seven days’ prior written notice specifying the place, day and time of the meeting. Under Bermuda law, accidental failure to give notice will not invalidate proceedings at a meeting. Our board of directors may set a record date at any time before or after any date on which such notice is dispatched.

The quorum at any annual or special meeting is equal to at least two shareholders, present in person or by proxy, and entitled to vote (whatever the number of shares held by them), holding aggregate shares carrying 33.33% of the voting rights entitled to be exercised at such meeting. In addition, so long as any of the Sponsors hold at least 5% of the Company's outstanding shares with the right to vote attached thereto, a quorum at any general meeting shall require a Shareholder representative of such Sponsor.

The Companies Act provides shareholders holding 10% of a company’s voting shares the ability to request that the board of directors shall convene a meeting of shareholders to consider any business which the shareholders wish to be discussed by the shareholders including (as noted below) the removal of any director. However, the shareholders are not permitted to pass any resolutions relating to the management of our business affairs unless there is a pre-existing provision in the company’s bye-laws which confers such rights on the shareholders.

In addition, certain voting rights in our Bye-laws are modified during such times that the Sponsors and their respective affiliates individually or collectively beneficially own more than 50% of the Company's outstanding shares with the right to vote attached thereto (such date that the Sponsors no longer collectively own more than 50% of the Company's outstanding shares, the “Trigger Date”).

Under the Companies Act, unless the Company’s bye-laws provide otherwise, any action required to or that may be taken at an annual or general meeting can be taken without a meeting if a written consent to such action is signed by the necessary majority of the shareholders entitled to vote with respect thereto. Our Bye-Laws provide that action by written consent is only permissible prior to the Trigger Date.

Our bye-laws will provide that, prior to the Trigger Date, and except in the case of the removal of auditors and directors, anything which may be done by resolution may, without an annual or special general meeting and without any previous notice being required, be done by resolution in writing, signed by a simple majority of all the shareholders or their proxies (or such greater majority required by the Companies Act).

Election, Removal and Remuneration of Directors

In addition to the applicable provisions of the Companies Act, the general provisions set forth below regarding the election, removal and remuneration of directors are subject to the terms and provisions of the Shareholders' Agreement. For additional information, please see “Certain Relationships and Related Transactions.”

The Companies Act provides that the directors shall be elected or appointed by the shareholders. A director may be elected by a simple majority vote of shareholders. A person or group of persons holding more than 50% of the voting shares of the company will be able to elect all of the directors, and to prevent the election of any person whom such shareholders do not wish to be elected. There are no provisions for cumulative voting in the Companies Act or the bye-laws. Further, our bye-laws will not contain any super-majority voting requirements relating to the appointment or election of directors.

There are procedures for the removal of one or more of the directors by the shareholders before the expiration of his term of office. Shareholders holding 10% or more of our voting shares may require the board of directors to convene a shareholder meeting to consider a resolution for the removal of a director. At least 14 days’ written notice of a resolution to remove a director must be given to the director affected, and that director must be permitted to speak at the shareholder meeting at which the resolution for his removal is considered by the shareholders. Certain advance notice procedures must also be complied with in order to nominate a director by parties other than the Sponsors. Any vacancy created by such a removal may be filled at the meeting by the election of another person by the shareholders or in the absence of such election, by the board of directors.

The Companies Act stipulates that an undischarged bankruptcy of a director (in any country) shall prohibit that director from acting as a director, directly or indirectly, and taking part in or being concerned with the management of a company, except with leave of the court. Our bye-laws will be more restrictive in that it stipulates that the office of a director shall be vacated upon the happening of any of the following events:

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•	If he resigns his office by notice in writing delivered to the registered office or tendered at a meeting of the board of directors;

•	If he becomes of unsound mind or a patient for any purpose of any statute or applicable law relating to mental health and the board of directors resolves that his office is vacated;

•	If he becomes bankrupt or compounds with his creditors;

•	If he is prohibited by law from being a director; or

•	If he ceases to be a director by virtue of the Companies Act or is removed from office pursuant to the company’s bye-laws.

Under our bye-laws, the minimum number of directors comprising the board of directors at any time shall be two. The board of directors currently consists of four directors. The minimum and maximum number of directors comprising the board of directors from time to time shall be determined by way of an ordinary resolution of our shareholders. The shareholders may, at the annual general meeting by ordinary resolution, determine that one or more vacancies in the board of directors be deemed casual vacancies. Our directors are not required to retire because of their age, and the directors are not required to be holders of our common shares. The board of directors, so long as a quorum remains in office, shall have the power to fill such casual vacancies. Each director will hold office until the next annual general meeting or until his successor is appointed or elected. There is no requirement for our directors to hold our shares to qualify for appointment.

Director Transactions

Our bye-laws will not prohibit a director from being a party to, or otherwise having an interest in, any transaction or arrangement with our Company or in which our Company is otherwise interested. Our bye-laws will provide that a director who has an interest in any transaction or arrangement with us and who has complied with the provisions of the Companies Act and with our bye-laws with regard to disclosure of such interest shall be taken into account in ascertaining whether a quorum is present, and will be entitled to vote in respect of any transaction or arrangement in which he is so interested.

Our bye-laws will provide our board of directors the authority to exercise all of our powers to borrow money and to mortgage or charge all or any part of our property and assets as collateral security for any debt, liability or obligation. However, under the Companies Act, companies may not lend money to a director or to a person connected to a director who is deemed by the Companies Act to be a director (a “Connected Person”), or enter into any guarantee or provide any security in relation to any loan made to a director or a Connected Person without the prior approval of the shareholders of the company holding in aggregate 90% of the total voting rights in the company.

Our-bye laws will provide that no director, alternate director, officer, person or member of a committee, if any, resident representative, or his heirs, executors or administrators, which we refer to collectively as an indemnitee, is liable for the acts, receipts, neglects or defaults of any other such person or any person involved in our formation, or for any loss or expense incurred by us through the insufficiency or deficiency of title to any property acquired by us, or for the insufficiency of deficiency of any security in or upon which any of our monies shall be invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious act of any person with whom any monies, securities or effects shall be deposited, or for any loss occasioned by any error of judgment, omission, default or oversight on his part, or for any other loss, damage or other misfortune whatever which shall happen in relation to the execution of his duties, or supposed duties, to us or otherwise in relation thereto. Each indemnitee will be indemnified and held harmless out of our funds to the fullest extent permitted by Bermuda law against all liabilities, loss, damage or expense (including but not limited to liabilities under contract, tort and statute or any applicable foreign law or regulation and all reasonable legal and other costs and expenses properly payable) incurred or suffered by him as such director, alternate director, officer, person or committee member or resident representative (or in his reasonable belief that he is acting as any of the above). In addition, each indemnitee shall be indemnified against all liabilities incurred in defending any proceedings, whether civil or criminal, in which judgment is given in such indemnitee’s favor, or in which he is acquitted. We will be authorized to purchase insurance to cover any liability indemnitees may incur under the indemnification provisions of our bye-laws. Each shareholder will agree pursuant to our bye-laws to waive to the

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fullest extent permitted by Bermuda law any claim or right of action he might have whether individually or derivatively in the name of the company against each indemnitee in respect of any action taken by such indemnitee or the failure by such indemnitee to take any action in the performance of his duties to us.

In addition, in connection with this offering, we will enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in our Bye-laws. The indemnification agreements require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, which may be incurred by them in their capacity as such.

The proposed form of underwriting agreement to be filed as Exhibit 1.1 to this registration statement will also provide for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Liquidation

In the event of our liquidation, dissolution or winding up, the holders of common shares are entitled to share in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.

Redemption, Repurchase and Surrender of Shares

Subject to certain balance sheet restrictions, the Companies Act permits a company to purchase its own shares if it is able to do so without becoming cash flow insolvent as a result. The restrictions are that the par value of the share must be charged against the company’s issued share capital account or a company fund which is available for dividend or distribution or be paid for out of the proceeds of a fresh issue of shares. Any premium paid on the repurchase of shares must be charged to the company’s current share premium account or charged to a company fund which is available for dividend or distribution. The Companies Act does not impose any requirement that the directors shall make a general offer to all shareholders to purchase their shares pro rata to their respective shareholdings. Our bye-laws will not contain any specific rules regarding the procedures to be followed by us when purchasing our common shares, and consequently the primary source of our obligations to shareholders when we tender for our common shares will be the rules of the listing exchanges on which our common shares are listed.

Issuance of Additional Shares

Our bye-laws will confer on the directors the right to issue any number of unissued shares forming part of our authorized share capital without any requirement for shareholder approval.

The Companies Act does, and our bye-laws will, not confer any pre-emptive, redemption, conversion or sinking fund rights attached to our common shares. Our bye-laws will specifically provide that the issuance of more shares ranking pari passu with the shares in issue shall not constitute a variation of class rights, unless the rights attached to shares in issue state that the issuance of further shares shall constitute a variation of class rights.

Pursuant to Bermuda law and our bye-laws, our board of directors may establish by resolution one or more series of preference shares in such number and with such designations, dividend rates, relative voting rights, conversion or exchange rights, redemption rights, liquidation rights and other relative participation, optional or other special rights, qualifications, limitations or restrictions as may be fixed by the board without any further shareholder approval. Such rights, preferences, powers and limitations could have the effect of discouraging an attempt to obtain control of the Company.

Inspection of Books and Records

The Companies Act provides that a shareholder is entitled to inspect the register of shareholders and the register of directors and officers of the company. A shareholder is also entitled to inspect the minutes of the meetings of the shareholders of the company, and the annual financial statements of the company. Our bye-laws will not provide shareholders with any additional rights to information, and our bye-laws will not confer any general or specific rights on shareholders to inspect our books and records.

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Anti-Takeover Provisions

Our bye-laws will provide that the board of directors may, with the sanction of a resolution passed by a simple majority of votes cast at a general meeting with the necessary quorum for such meeting of two persons at least holding or representing by proxy a majority of our issued common shares (or the class of securities, where applicable) provided, that so long as any of the Sponsors hold at least 5% of the outstanding shares with the right to vote attached thereto, a quorum must include a Shareholder representative of such Sponsor, amalgamate or merge us with another company. In addition, we may reduce our issued share capital selectively with the authority of a resolution of the shareholders.

Certain Bermuda Company Considerations

Our corporate affairs are governed by our memorandum of association and bye-laws as described above, the Companies Act and the common law of Bermuda. You should be aware that the Companies Act differs in certain material respects from the laws generally applicable to U.S. companies incorporated in the State of Delaware. Accordingly, you may have more difficulty protecting your interests under Bermuda law in the face of actions by management, directors or controlling shareholders than would shareholders of a corporation incorporated in a United States jurisdiction, such as the State of Delaware. The following table provides a comparison between the statutory provisions of the Companies Act and the Delaware General Corporation Law relating to shareholders’ rights.

BERMUDA			DELAWARE

Shareholder Meetings and Voting Rights

Shareholder meetings may be held at such times and places as designated in the bye-laws.			Shareholder meetings may be held at such times and places as designated in the certificate of incorporation or the bye-laws, or if not so designated, as determined by the board of directors.

Special meetings of the shareholders may be called by the board of directors at any time. A special shareholder meeting may be called at the request of shareholders holding at least 10% of paid-up share capital carrying the right to vote at general meetings.			Special meetings of the shareholders may be called by the board of directors or by such person or persons as may be authorized by the certificate of incorporation or by the bye-laws.

A minimum of seven days’ notice of an annual meeting or special meeting must be given to each shareholder. Accidental failure to give notice will not invalidate proceedings at a meeting.			Written notice shall be given not less than 10 nor more than 60 days before the meeting. Whenever shareholders are required to take any action at a meeting, a written notice of the meeting shall be given which shall state the place, if any, date and hour of the meeting, and the means of remote communication, if any.

Shareholder meetings may be held in or outside of Bermuda.			Shareholder meetings may be held within or without the State of Delaware.

Shareholders may take action by written consent if such consent is signed by a simple majority of the shareholders who would be entitled to attend a meeting and vote on the action.			Any action required to be taken by a meeting of shareholders may be taken without a meeting if a consent for such action is in writing and is signed by shareholders having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.

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BERMUDA			DELAWARE

Transactions with Significant Shareholders

A company may enter into certain business transactions with its significant shareholders, including asset sales, in which a significant shareholder receives, or could receive, a financial benefit that is greater than that received, or to be received, by other shareholders with prior approval from our board of directors but without obtaining prior approval from our shareholders.			Subject to certain exceptions and conditions, a corporation may not enter into a business combination with an interested shareholder for a period of three years from the time the person became an interested shareholder without prior approval from shareholders holding at least 66 2/3% of the corporation’s outstanding voting stock which is not owned by such interested shareholder.

Dissenters’ Rights of Appraisal

In the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation or merger and is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares.			Appraisal rights shall be available for the shares of any class or series of stock of a corporation in a merger or consolidation, subject to limited exceptions, such as a merger or consolidation of corporations listed on a national securities exchange in which listed stock is the offered consideration.

Shareholders’ Suits

Class actions and derivative actions are generally not available to shareholders under the laws of Bermuda. However, the Bermuda courts ordinarily would be expected to follow English case law precedent, which would permit a shareholder to commence an action in our name to remedy a wrong done to us where the act complained of is alleged to be beyond our corporate power or is illegal or would result in the violation of a company’s memorandum of association or bye-laws. Furthermore, consideration would be given by the court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of shareholders than actually approved it.			Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In any derivative suit instituted by a shareholder or a corporation, it shall be averred in the complaint that the plaintiff was a shareholder of the corporation at the time of the transaction of which he complains or that such shareholder’s stock thereafter developed upon such shareholder by operation of law.

Indemnification of Directors and Officers

A company’s bye-laws may contain provisions excluding personal liability of a director, alternate director, officer, member of a committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators to the company for any loss arising or liability attaching to him by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which the officer or person may be guilty. Companies also have the power, generally, to			A corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if (i) such director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and (ii) with respect to any criminal action or proceeding, such director or officer had

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BERMUDA			DELAWARE
indemnify directors, alternate directors and officers of a company and any member of a committee authorized under the company’s bye-laws, resident representatives or their respective heirs, executors or administrators if any such person was or is a party or threatened to be made a party to a threatened, pending or completed action, suit or proceeding by reason of the fact that he or she is or was a director, alternate director or officer of the company or member of a committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators or was serving in a similar capacity for another entity at the company’s request.			no reasonable cause to believe his conduct was unlawful.

Directors

The board of directors must consist of at least one member, although the minimum number of directors may be set higher.			The board of directors must consist of at least one member.

The maximum number of directors may be set by the shareholders at a general meeting or in accordance with the bye-laws. The maximum number of directors is usually fixed by the shareholders at the annual general meeting and may be fixed at a special general meeting. Only the shareholders may increase or decrease the number of directors’ seats last approved by the shareholders. If the maximum number of directors fixed by the shareholders has not been elected by the shareholders, the shareholders may authorize the board of directors to fill any vacancies.			Number of board members shall be fixed by, or in a manner provided by, the bye-laws, unless the certificate of incorporation fixes the number of directors, in which case a change in the number shall be made only by amendment of the certificate of incorporation.

Duties of Directors

Members of a board of directors owe a fiduciary duty to the company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly.			The business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a fiduciary duty of care to protect the interests of the corporation and a fiduciary duty of loyalty to act in the best interests of its shareholders.

History of Securities Issuances

In connection with our formation in June 2016, Golar LNG contributed its interests in its subsidiaries that owned the Golar Penguin, the Golar Celsius and the Golar Nanook as well as its initial 25% interest in CELSE in exchange for 46,950,154 common shares. There has been no other share issuances paid for with assets other than cash within the past five years and we have not issued any additional shares in the past three years. Accordingly, there was no change from number of shares outstanding on January 1, 2019 to the number of shares outstanding on December 31, 2019.

Stonepeak Preference Shares

In July 2016, we issued 20 million preference shares to Stonepeak for net proceeds of $95.7 million. The preference shares have no voting rights but have priority with respect to distributions, with a fixed cumulative preference dividend of 8.5%, payable semi-annually. We have the right to redeem the preference shares prior to

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an initial public offering at any time for a fixed return to Stonepeak, as defined in our bye-laws. If we fail to complete an initial public offering by July 2021, the preference dividend increases to 11.5% and Stonepeak has the option to require us to redeem the shares upon six months’ notice for the same fixed return. While by their terms the preference shares convert to common shares upon the completion of an initial public offering, we will use a portion of the proceeds of this offering to redeem the preference shares in the Recapitalization and there will be no preference shares outstanding following the consummation of this offering. See “Use of Proceeds.” In June 2016, we also issued 23,475,077 common shares to Stonepeak, which are convertible into preference shares under certain circumstances. Upon the completion of this offering, the conversion right of the common shares held by Stonepeak will terminate, such that none of the common shares will have such conversion right. For a more complete description of the preference shares, please see Note 25 to the audited consolidated financial statements included elsewhere in this prospectus.

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SHARES ELIGIBLE FOR FUTURE SALE

Immediately prior to this offering, there was no public market for our common shares. Future sales of substantial amounts of common shares in the market, or the perception that such sales may occur, could adversely affect the market price of our common shares.

Upon the closing of this offering, we will have outstanding an aggregate of 123,100,000 common shares, reflecting the issuance of 23,100,000 common shares offering by us in this offering, assuming no exercise of the underwriters’ option to purchase additional common shares. Our common shares sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common shares held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•	1% of the total number of the securities outstanding; or

•	the average weekly reported trading volume of our common shares for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common shares for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common shares under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted shares for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common shares without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our bye-laws will confer on the directors the right to dispose of any unissued shares forming part of our authorized share capital without any requirement for shareholder approval, subject to the requirements of NASDAQ. Any issuance of additional common shares or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the market price of, common shares then outstanding. Please read “Description of Share Capital—Issuance of Additional Shares.”

Under the Shareholders’ Agreement that we expect to enter into, our Sponsors and their respective affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any shares that they hold. Subject to the terms and conditions of the Shareholders’ Agreement, these registration rights allow our Sponsors and their respective affiliates or their assignees holding any shares to require registration of any of these shares and to include any of these shares in a registration by us of other shares, including shares offered by us or by any shareholder. In connection with any registration of this kind, we will indemnify each shareholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our Sponsors and their respective affiliates may sell their shares in private transactions at any time, subject to compliance with applicable laws.

Our executive officers and directors and our Sponsors will agree not to sell any common shares they beneficially own for a period of 180 days from the date of the underwriting agreement to be entered into in connection with this offering. Please read “Underwriting” for a description of these lock-up provisions.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a discussion of the material U.S. federal income tax considerations applicable to the purchase, ownership, and disposition of our common shares, and, unless otherwise noted in the following discussion and subject to the limitations, qualifications, and assumptions described herein and in the opinion filed as Exhibit 8.1 to this Registration Statement, of which this prospectus forms a part, constitutes the opinion of Vinson & Elkins L.L.P., our U.S. counsel, insofar as it contains legal conclusions with respect to matters of U.S. federal income tax law. The opinion of our counsel is dependent on the accuracy of factual representations made by us to them, including descriptions of our operations contained herein. Statements contained herein that “we believe,” “we expect,” or similar phrases are not legal conclusions or opinions of counsel. This discussion is based upon provisions of the Code as in effect on the date of this prospectus, existing final and temporary Treasury Regulations, and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. The following discussion is for general information purposes only and does not purport to be a comprehensive description of all of the U.S. federal income tax considerations applicable to us.

The following discussion applies only to beneficial owners of our common shares that hold such shares as “capital assets” within the meaning of Section 1221 of the Code (generally property held for investment purposes). We have not sought any ruling from the IRS with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This discussion does not address all aspects of U.S. federal income taxation that may be relevant to holders in light of their personal circumstances. In addition, this summary does not address impact of the the Medicare surtax on certain net investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws, or any tax treaties. This discussion also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

•	banks, insurance companies, or other financial institutions;

•	tax-exempt or governmental organizations;

•	retirement plans or individual retirement accounts;

•	persons who own (actually or constructively) 10.0% or more of the voting power or value of our equity;

•	dealers in securities or foreign currencies;

•	persons whose functional currency is not the U.S. dollar;

•	traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

•	partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

•	certain former citizens or long-term residents of the United States; and

•	persons that hold our common shares as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction, or other integrated investment or risk reduction transaction.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common shares, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, the activities of the partnership, and certain determinations made at the partner level.

PROSPECTIVE INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP, AND DISPOSITION OF OUR COMMON SHARES ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

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U.S. Federal Income Taxation of United States Holders

As used herein, the term “United States Holder” means a beneficial owner of common shares that is

•	an individual who is a citizen or resident of the United States;

•	a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof, or the District of Columbia;

•	an estate the income of which is subject to U.S. federal income tax regardless of its source; or

•

a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code) who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable Treasury Regulations to be treated as a United States person.

Distributions with Respect to Common Shares

As described in the section entitled “Dividend Policy,” we do not expect to pay any distributions on our common shares in the foreseeable future. However, in the event we do make distributions of cash or other property on our common shares, subject to the discussion of PFICs below, any distributions made by us with respect to our common shares to a United States Holder will generally constitute dividends, which may be taxable as ordinary income or “qualified dividend income,” as described in more detail below, to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of our current and accumulated earnings and profits will be treated first as a nontaxable return of capital to the extent of the United States Holder’s tax basis in its common shares on a dollar for dollar basis and thereafter as capital gain from the sale or exchange of such common shares. Because we are not a United States corporation, United States Holders that are corporations will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common shares will generally be treated as passive category income or, in the case of certain types of United States Holders, general category income, for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes. Dividends paid on our common shares to a United States Holder who is an individual, trust, or estate (a “United States Individual Holder”) generally will be treated as “qualified dividend income” that is taxable to such United States Individual Holders at preferential tax rates provided that (1) the common shares are readily tradable on an established securities market in the United States (such as the Nasdaq Stock Market); (2) we are not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (see the discussion below under “—PFIC Status and Material U.S. Federal Tax Consequences”); and (3) the United States Individual Holder owns the common shares for more than 60 days in the 121-day period beginning 60 days before the date on which the common shares become ex-dividend. Special rules may apply to any “extraordinary dividend.” Generally, an extraordinary dividend is a dividend in an amount which is equal to or in excess of ten percent of a shareholder’s adjusted basis (or fair market value in certain circumstances) in a common share paid by us. In addition, extraordinary dividends include dividends received within a one-year period that, in the aggregate, are equal to or in excess of 20% of a shareholder’s adjusted basis (or fair market value in certain circumstances). If we pay an “extraordinary dividend” on our common shares that is treated as “qualified dividend income,” then any loss derived by a United States Individual Holder from the sale or exchange of such common shares will be treated as long-term capital loss to the extent of such dividend. There is no assurance that any dividends paid on our common shares will be eligible for these preferential rates in the hands of a United States Individual Holder. Any dividends paid by us which are not eligible for these preferential rates will be taxed to a United States Individual Holder at the standard ordinary income rates.

Sale, Exchange, or other Disposition of Common Shares

Subject to the discussion of PFIC status below, a United States Holder generally will recognize taxable gain or loss upon a sale, exchange, or other disposition of our common shares in an amount equal to the difference between the amount realized by the United States Holder from such sale, exchange, or other disposition and the United States Holder’s tax basis in such shares. Such gain or loss will be treated as long-term capital gain or loss

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if the United States Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Such capital gain or loss will generally be treated as U.S. source income or loss, as applicable, for United States foreign tax credit purposes. A United States Holder’s ability to deduct capital losses is subject to certain limitations.

PFIC Status and Material U.S. Federal Tax Consequences

Adverse U.S. federal income tax rules apply to a United States Holder that holds shares in a foreign corporation classified as a PFIC for U.S. federal income tax purposes. In general, we will be treated as a PFIC with respect to a United States Holder in any taxable year in which, after applying certain look-through rules, either:

•	at least 75% of our gross income for such taxable year consists of passive income (e.g., dividends, interest, capital gains, and rents derived other than in the active conduct of a rental business); or

•	the average percentage by value of our assets during such taxable year that produce or are held for the production of passive income is at least 50%.

For purposes of determining whether we are a PFIC, we will be treated as earning and owning our proportionate share of the income and assets, respectively, of any of our subsidiary corporations in which we own at least 25% of the value of the subsidiary’s stock. Income earned, or deemed earned, by us in connection with the performance of services will not constitute passive income. By contrast, rental or lease income will generally constitute “passive income.” We may hold, directly or indirectly, interests in other entities that are PFICs (“Subsidiary PFICs”). If we are a PFIC, each United States Holder will be treated as owning its pro-rata share by value of the stock of any such Subsidiary PFICs.

Based on our current and expected future method of operation and an opinion of counsel, we do not believe that we will be a PFIC with respect to the current or any subsequent taxable year. Our U.S. counsel, Vinson & Elkins L.L.P., is of the opinion that (1) the income we earn from our present time chartering activity and assets engaged in generating such income should not be treated as passive income or assets, respectively, and (2) the income we earn and expect to earn from power generation activities and assets engaged in generating such income should not be treated as passive income or assets, respectively. In addition, we have represented to our U.S. counsel that we expect that more than 25% of our gross income for the current and any subsequent taxable year arose or will arise from such income or other income our U.S. counsel has opined does not constitute passive income, and the average percentage by value of our assets for each such year that produce or are held for the production of such non-passive income is more than 50%. Assuming the accuracy of representations we have made to our U.S. counsel for purposes of its opinion, our U.S. counsel is of the opinion that, assuming the composition of our income and assets is consistent with these expectations for our current and future years, we should not be a PFIC for the current or any subsequent taxable year. This opinion is based on representations, valuations and projections provided to our counsel by us regarding our assets, income, and charters, and its validity is conditioned on the accuracy of such representations, valuations and projections. While we believe these representations, valuations, and projections to be accurate, no assurance can be given that they will continue to be accurate at any time in the future.

Our counsel has indicated to us that the conclusions described above are not free from doubt. While there is legal authority supporting our conclusions, including IRS pronouncements concerning the characterization of income derived from time charters as services income, the United States Court of Appeals for the Fifth Circuit (or the Fifth Circuit) held in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. 2009), that income derived from certain marine time charter agreements should be treated as rental income rather than services income for purposes of a “foreign sales corporation” provision of the Code. In that case, the Fifth Circuit did not address the definition of passive income or the PFIC rules; however, the reasoning of the case could have implications as to how the income from a time charter would be classified under such rules. If the reasoning of this case were extended to the PFIC context, the gross income we derive or are deemed to derive from our time chartering activities may be treated as rental income, in which case we might be treated as a PFIC. The IRS has announced its non-acquiescence with the court’s holding in the Tidewater case and, at the same time, announced the position of the IRS that the marine time charter agreements at issue in that case should be treated as service contracts. We are not seeking a ruling from the IRS on the treatment of income generated from our time chartering operations. Thus, it is possible that the IRS or a court could disagree with our position.

As described above, we indirectly own a 50% interest in CELSE, which recently completed construction of a gas-powered power plant. Our U.S. counsel has opined that the gross income we are deemed to derive pursuant

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to the applicable look-through rules from the generation and sale of power by CELSE pursuant to its PPAs should be treated as active business income and should not constitute passive income under the PFIC provisions of the Code. Existing Treasury Regulations, however, have not been revised to address changes to the statutory provisions governing when gains from the sale of commodities are treated as giving rise to active business income. Further, the current PFIC statutory and regulatory provisions do not address how that active business income exception applies when the relevant commodities income and related activities arise in subsidiaries of the foreign corporation being tested for PFIC status. In light of that lack of guidance, there can be no assurance that the IRS or a court will agree with our position that CELSE’s income from power generation and sales qualifies for the active business income exception.

If we were a PFIC for any taxable year, our U.S. shareholders would face adverse U.S. tax consequences and certain information reporting requirements regardless of whether we remain a PFIC in subsequent years. In addition, although we intend to conduct our affairs in a manner to avoid being classified as a PFIC, we cannot assure you that the nature of our assets, income, and operations will not change, or that we can avoid being treated as a PFIC for any taxable year.

As discussed more fully below, if we were to be treated as a PFIC for any taxable year in which a United States Holder holds our common shares (and regardless of whether we remain a PFIC for subsequent taxable years), a United States Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund,” which we refer to as a “QEF election.” As an alternative to making a QEF election, a United States Holder should be able to make a “mark-to-market” election with respect to our common shares, as discussed below. If we are a PFIC, a United States Holder will be subject to the PFIC rules described herein with respect to any of our subsidiaries that are PFICs. However, the mark-to-market election discussed below will likely not be available with respect to shares of such PFIC subsidiaries. In addition, if a United States Holder owns our common shares during any taxable year that we are a PFIC, such holder must file an annual report with the IRS.

Taxation of United States Holders Making a Timely QEF Election

If a United States Holder makes a timely QEF election with respect to our common shares, which United States Holder we refer to as an “Electing Holder,” for U.S. federal income tax purposes, each year the Electing Holder must report its pro-rata share of our ordinary earnings and our net capital gain, if any, for our taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether or not distributions were received from us by the Electing Holder. Generally, a QEF election should be made on or before the due date for filing the electing United States Holder’s U.S. federal income tax return for the first taxable year in which our common shares are held by such United States Holder and we are classified as a PFIC. The Electing Holder’s adjusted tax basis in the common shares would be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed would result in a corresponding reduction in the adjusted tax basis in the common shares and would not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange, or other disposition of our common shares. A United States Holder would make a QEF election with respect to any year that our company and any Subsidiary PFICs are treated as PFICs by filing one copy of IRS Form 8621 with its U.S. federal income tax return and a second copy in accordance with the instructions to such form. If we were to become aware that we were a PFIC for any taxable year, we would notify all United States Holders of such treatment and would provide all necessary information to any United States Holder who requests such information in order to make the QEF election described above with respect to our common shares and the stock of any Subsidiary PFIC.

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Taxation of United States Holders Making a “Mark-to-Market” Election

Alternatively, if we were treated as a PFIC for any taxable year and, as we anticipate, our common shares are treated as “marketable stock,” a United States Holder of our common shares would be allowed to make a “mark-to-market” election with respect to our common shares, provided the United States Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the United States Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the common shares at the end of the taxable year over such holder’s adjusted tax basis in the common shares. The United States Holder also would be permitted an ordinary loss in respect of the excess, if any, of the United States Holder’s adjusted tax basis in the common shares over its fair market value at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A United States Holder’s tax basis in its common shares would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange, or other disposition of our common shares would be treated as ordinary income, and any loss realized on the sale, exchange, or other disposition of the common shares would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included by the United States Holder. A mark-to-market election under the PFIC rules with respect to our common shares would not apply to a Subsidiary PFIC, and a United States Holder would not be able to make such a mark-to-market election in respect of its indirect ownership interest in that Subsidiary PFIC. Consequently, United States Holders of our common shares could be subject to the PFIC rules with respect to income of the Subsidiary PFIC, the value of which already had been taken into account indirectly via mark-to-market adjustments.

Taxation of United States Holders Not Making a Timely QEF or Mark- to-Market Election

Finally, if we were treated as a PFIC for any taxable year, a United States Holder who does not make either a QEF election or a “mark-to-market” election for that year, whom we refer to as a “Non-Electing Holder,” would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common shares in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period for the common shares) and (2) any gain realized on the sale, exchange, or other disposition of our common shares. Under these special rules:

•	the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for the common shares;

•	the amount allocated to the current taxable year or to any portion of the United States Holder’s holding period prior to the first taxable year for which we were a PFIC would be taxed as ordinary income; and

•

the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

If we were treated as a PFIC for any taxable year, a United States Holder that owns our shares would be required to file an annual information return with the IRS reflecting such ownership, regardless of whether a QEF election or a mark-to-market election had been made.

If a United States Holder held our common shares during a period when we were treated as a PFIC but the United States Holder did not have a QEF election in effect with respect to us, then in the event that we did not qualify as a PFIC for a subsequent taxable year, the United States Holder could elect to cease to be subject to the rules described above with respect to those shares by making a “deemed sale” or, in certain circumstances, a “deemed dividend” election, with respect to our common shares. If the United States Holder makes a deemed sale election, the United States Holder will be treated, for purposes of applying the rules described in the preceding paragraph, as having disposed of its shares of our common shares for their fair market value on the last day of the last taxable year for which we qualified as a PFIC (the “termination date”). The United States Holder would increase its basis in such common shares by the amount of the gain on the deemed sale described in the preceding sentence and the amount of gain would be taxed as an excess distribution. Following a deemed sale election, the United States Holder would not be treated, for purposes of the PFIC rules, as having owned the common shares during a period prior to the termination date when we qualified as a PFIC and would not be treated as owning PFIC stock thereafter unless we later qualified as a PFIC. The holding period for such stock would begin the day after the termination date for purposes of the PFIC rules.

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U.S. Federal Income Taxation of Non-U.S. Holders

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common shares that is not a United States Holder.

Distributions

As described in the section entitled “Dividend Policy,” we do not expect to pay any distributions on our common shares in the foreseeable future. However, in the event we do make distributions of cash or other property on our common shares, such distributions will not be subject to U.S. federal income tax or withholding tax if the non-U.S. holder is not engaged in a U.S. trade or business. If the non-U.S. holder is engaged in a U.S. trade or business, distributions paid to the non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States Holders. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

Gain on Disposition of Common Shares

Subject to the discussion below under “—Backup Withholding and Information Reporting,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our common shares if the non-U.S. holder is not engaged in a trade or business. Any non-U.S. holder that is engaged in a U.S. trade or business will be subject to U.S. tax in the same manner as a United States Holder if the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States)

If the non-U.S. holder is a corporation for U.S. federal income tax purposes, then the after-tax amount of such gain may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty). Even if not engaged in a U.S. trade or business, individual non-U.S. holders may be subject to tax on gain from the disposition of our common shares if the non-U.S. holder is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common shares.

Backup Withholding and Information Reporting

In general, payments to a non-corporate United States Holder of distributions or proceeds of a disposition of common shares will be subject to information reporting. These payments to a non-corporate United States Holder also may be subject to backup withholding if the non-corporate United States Holder:

•	fails to provide an accurate taxpayer identification number;

•	is notified by the IRS that it has failed to report all interest or corporate distributions required to be reported on its U.S. federal income tax returns; or

•	in certain circumstances, fails to comply with applicable certification requirements.

Non-U.S. holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on IRS Form W-8BEN, W-8BEN-E, W-8ECI, W-8EXP, or W-8IMY, as applicable.

Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

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In addition, individual citizens or residents of the United States holding certain “foreign financial assets” (which generally includes shares and other securities issued by a foreign person unless held in account maintained by a financial institution) that exceed certain thresholds (the lowest being foreign financial assets with a value in excess of (i) $50,000 on the last day of the taxable year or (ii) $75,000 at any time during the taxable year) are required to report information relating to such assets. Significant penalties may apply for failure to satisfy the reporting obligations described above. United States Holders should consult their tax advisors regarding their reporting obligations, if any, under this legislation as a result of their purchase, ownership or disposition of our common shares.

INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON SHARES SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL, OR NON-U.S. TAX LAWS AND TAX TREATIES.

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BERMUDA TAXATION

There is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax or estate duty or inheritance tax payable by nonresidents of Bermuda in respect of capital gains realized on a disposition of our common shares or in respect of distributions they receive from us with respect to our common shares. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common shares. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967. The assurance does not exempt us from paying import duty on goods imported into Bermuda. In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.

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UNDERWRITING

Under the terms and subject to the conditions in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. LLC and Goldman Sachs & Co. LLC are acting as representatives, have severally agreed to purchase, and we have agreed to sell to them, severally, the number of shares indicated below:

Name			Number of Shares
Morgan Stanley & Co. LLC
Goldman Sachs & Co. LLC
Citigroup Global Markets Inc.
Barclays Capital Inc.
Banco BTG Pactual S.A. – Cayman Branch
BofA Securities, Inc.
BTIG, LLC
Credit Suisse Securities (USA) LLC
Itaú BBA USA Securities, Inc.
UBS Securities LLC
XP Investments US, LLC
Arctic Securities AS
DNB Markets Inc.
Fearnley Securities, Inc.
Total:			23,100,000

The underwriters and the representatives are collectively referred to as the “underwriters” and the “representatives,” respectively. The underwriters are offering the common shares subject to their acceptance of such common shares from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the common shares offered pursuant to this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the common shares offered pursuant to this prospectus if any such common shares are taken. However, the underwriters are not required to take or pay for the shares covered by the underwriters’ option to purchase additional shares described below.

The underwriters initially propose to offer part of common shares directly to the public at the offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $ per share under the public offering price. After the initial offering of the common shares, the offering price and other selling terms may from time to time be varied by the representatives. The offering of the common shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 3,465,000 additional common shares at the public offering price listed on the cover page of this prospectus, less underwriting discounts and commissions. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase about the same percentage of the additional common shares as the number listed next to the underwriter’s name in the preceding table bears to the total number of common shares listed next to the names of all underwriters in the preceding table.

The following table shows the per share and total public offering price, underwriting discounts and commissions, and proceeds before expenses payable to us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 3,465,000 common shares.

	Per Common Share	Total
	Per Common Share	No Exercise	Full Exercise
Public offering price	$	$	$
Underwriting discounts and commissions to be paid by us:	$	$	$
Proceeds, before expenses, to us	$	$	$

The estimated offering expenses payable by us, exclusive of the underwriting discounts and commissions, are approximately $4.6 million. We have agreed to reimburse the underwriters for expenses relating to clearance of this offering with the Financial Industry Regulatory Authority up to $30,000.

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The underwriters have informed us that they do not intend sales to discretionary accounts to exceed 5% of the total number of common shares offered by them.

We have applied to list our common shares on the NASDAQ Global Select Market under the symbol “HYGO.”

We and all of our directors and officers and the holders of all of our outstanding equity securities and options for such equity securities, including the Sponsors, have agreed that, without the prior written consent of Morgan Stanley & Co. LLC and Goldman Sachs & Co. LLC, on behalf of the underwriters, we and they will not, during the period ending 180 days after the date of this prospectus (the “restricted period”):

•

offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any common shares or any securities convertible into or exercisable or exchangeable for common shares;

•	file any registration statement with the SEC relating to the offering of any common shares or any securities convertible into or exercisable or exchangeable for common shares; or

•	enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of common shares,

whether any such transaction described above is to be settled by delivery of common shares or such other securities, in cash or otherwise. In addition, we and each such person agrees that, without the prior written consent of Morgan Stanley & Co. LLC and Goldman Sachs & Co. LLC, on behalf of the underwriters, we or such other person will not, during the restricted period, make any demand for, or exercise any right with respect to, the registration of any common shares or any security convertible into or exercisable or exchangeable for common shares.

The restrictions described in the immediately preceding paragraph to do not apply to:

•	the sale of common shares to the underwriters; or

•	the issuance by the Company of common shares upon the exercise of an option or a warrant or the conversion of a security outstanding on the date of this prospectus of which the underwriters have been advised in writing;

•

transactions by any person other than us relating to common shares or other securities acquired in open market transactions after the completion of the offering of the common shares; provided that no filing under Section 16(a) of the Exchange Act, is required or voluntarily made in connection with subsequent sales of the common shares or other securities acquired in such open market transactions; or

•

the establishment of a trading plan pursuant to Rule 10b5-1 under the Exchange Act for the transfer of common shares, provided that (i) such plan does not provide for the transfer of common shares during the restricted period and (ii) to the extent a public announcement or filing under the Exchange Act, if any, is required or voluntarily made regarding the establishment of such plan, such announcement or filing shall include a statement to the effect that no transfer of common shares may be made under such plan during the restricted period.

Morgan Stanley & Co. LLC and Goldman Sachs & Co. LLC, in their sole discretion, may release the common shares and other securities subject to the lock-up agreements described above in whole or in part at any time.

In order to facilitate the offering of the common shares, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common shares. Specifically, the underwriters may sell more common shares than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common shares available for purchase by the underwriters under the option. The underwriters can close out a covered short sale by exercising the option or purchasing common shares in the open market. In determining the source of common shares to close out a covered short sale, the underwriters will consider, among other things, the open market price of common shares compared to the price available under the option. The underwriters may also sell common shares in excess of the option, creating a naked short position. The underwriters must close out any naked short position by purchasing common shares in the open market. A naked short position is more likely to

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be created if the underwriters are concerned that there may be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in this offering. As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common shares in the open market to stabilize the price of the common shares. These activities may raise or maintain the market price of the common shares above independent market levels or prevent or retard a decline in the market price of the common shares. The underwriters are not required to engage in these activities and may end any of these activities at any time.

We and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act.

A prospectus in electronic format may be made available on websites maintained by one or more underwriters. The representatives may agree to allocate a number of common shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to underwriters that may make Internet distributions on the same basis as other allocations.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for us, for which they received or will receive customary fees and expenses.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

Banco BTG Pactual S.A. – Cayman Branch and Arctic Securities AS are not broker-dealers registered with the SEC, and therefore may not make sales of any securities in the United States or to U.S. persons except in compliance with applicable U.S. laws and regulations. To the extent that Banco BTG Pactual S.A. – Cayman Branch or Arctic Securities AS intend to effect sales of common shares in the United States, they will do so only through one or more U.S. registered broker-dealers, including their respective affiliates, BTG Pactual US Capital, LLC and Arctic Securities LLC, to the extent permitted by Rule 15a-16 of the Exchange Act.

Pricing of the Offering

Prior to this offering, there has been no public market for our common shares. The initial public offering price was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our future prospects and those of our industry in general, our sales, earnings and certain other financial and operating information in recent periods, and the price-earnings ratios, price-sales ratios, market prices of securities, and certain financial and operating information of companies engaged in activities similar to ours.

Selling Restrictions

European Economic Area and United Kingdom

In relation to each Member State of the European Economic Area and the United Kingdom (each a “Relevant State”), no common shares have been offered or will be offered pursuant to the offering to the public in that Relevant State prior to the publication of a prospectus in relation to the common shares that has been approved by the competent authority in that Relevant State or, where appropriate, approved in another Relevant State and notified to the competent authority in that Relevant State, all in accordance with the Prospectus Regulation), except that offers of common shares may be made to the public in that Relevant State at any time under the following exemptions under the Prospectus Regulation:

(a)	to any legal entity which is a qualified investor as defined under the Prospectus Regulation;

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(b)	to fewer than 150 natural or legal persons (other than qualified investors as defined under the Prospectus Regulation), subject to obtaining the prior consent of the global coordinator for any such offer; or

(c)	in any other circumstances falling within Article 1(4) of the Prospectus Regulation.

provided that no such offer of common shares shall require the Company or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Regulation or supplement a prospectus pursuant to Article 23 of the Prospectus Regulation.

For the purposes of this provision, the expression an “offer to the public” in relation to any common shares in any Relevant State means the communication in any form and by any means of sufficient information on the terms of the offer and any common shares to be offered so as to enable an investor to decide to purchase or subscribe for any common shares, and the expression “Prospectus Regulation” means Regulation (EU) 2017/1129.

The above selling restriction is in addition to any other selling restrictions set out below.

United Kingdom

In addition, in the United Kingdom, this document is being distributed only to, and is directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This document must not be acted on or relied on in the United Kingdom by persons who are not relevant persons. In the United Kingdom, any investment or investment activity to which this document relates is only available to, and will be engaged in with, relevant persons.

Canada

The securities may be sold in Canada only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions, and Ongoing Registrant Obligations. Any resale of the securities must be made in accordance with an exemption form, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies (Winding Up and Miscellaneous Provisions) Ordinance (Cap. 32 of the Laws of Hong Kong) (“Companies (Winding Up and Miscellaneous Provisions) Ordinance”) or which do not constitute an invitation to the public within the meaning of the Securities and Futures Ordinance (Cap. 571 of the Laws of Hong Kong) (“Securities and Futures Ordinance”), or (ii) to “professional investors” as defined in the Securities and Futures Ordinance and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies (Winding Up and Miscellaneous Provisions) Ordinance, and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the

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purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” in Hong Kong as defined in the Securities and Futures Ordinance and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor (as defined under Section 4A of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”)) under Section 274 of the SFA, (ii) to a relevant person (as defined in Section 275(2) of the SFA) pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor, the securities (as defined in Section 239(1) of the SFA) of that corporation shall not be transferable for 6 months after that corporation has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer in that corporation’s securities pursuant to Section 275(1A) of the SFA, (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore (“Regulation 32”).

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole purpose is to hold investments and each beneficiary of the trust is an accredited investor, the beneficiaries' rights and interest (howsoever described) in that trust shall not be transferable for 6 months after that trust has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer that is made on terms that such rights or interest are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction (whether such amount is to be paid for in cash or by exchange of securities or other assets), (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Act of Japan (Act No. 25 of 1948, as amended), or the FIEA. The securities may not be offered or sold, directly or indirectly, in Japan or to or for the benefit of any resident of Japan (including any person resident in Japan or any corporation or other entity organized under the laws of Japan) or to others for reoffering or resale, directly or indirectly, in Japan or to or for the benefit of any resident of Japan, except pursuant to an exemption from the registration requirements of the FIEA and otherwise in compliance with any relevant laws and regulations of Japan.

Argentina

The common shares are not authorized for public offering in Argentina by the Comisión Nacional de Valores pursuant to Argentine Public Offering Law No. 17,811, as amended, and they shall not be sold publicly. Therefore, any transaction carried out in Argentina must be made privately.

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Brazil

The offer and sale of our common shares has not been, and will not be, registered (or exempted from registration) with the Brazilian Securities Commission (Comissão de Valores Mobiliários—CVM) and, therefore, will not be carried out by any means that would constitute a public offering in Brazil under Law No. 6,385, of December 7, 1976, as amended, under CVM Rule No. 400, of December 29, 2003, as amended, or under CVM Rule No. 476, of January 16, 2009, as amended. Any representation to the contrary is untruthful and unlawful. As a consequence, our common shares cannot be offered in Brazil.

Chile

The offer of the common shares is subject to CMF Rule 336. The common shares being offered will not be registered under the Chilean Securities Market Law in the Securities Registry (Registro de Valores) or in the Foreign Securities Registry (Registro de Valores Extranjeros) of the CMF and, therefore, the common shares are not subject to the supervision of the CMF. As unregistered securities, we are not required to disclose public information about the common shares in Chile. Accordingly, the common shares cannot and will not be publicly offered to persons in Chile unless they are registered in the corresponding securities registry. The common shares may only be offered in Chile in circumstances that do not constitute a public offering under Chilean law or in compliance with CMF Rule 336. Pursuant to CMF Rule 336, the common shares may be privately offered in Chile to certain “qualified investors” identified as such therein (which in turn are further described in Rule No. 216, dated June 12, 2008 and in Rule No. 410, dated July 27, 2016, both issued by the CMF).

LA OFERTA DE LAS ACCIONES COMUNES CLASE A SE ACOGE A LA NORMA DE CARÁCTER GENERAL N°336 DE LA CMF. LAS ACCIONES COMUNES CLASE A QUE SE OFRECEN NO ESTÁN INSCRITOS BAJO LA LEY DE MERCADO DE VALORES EN EL REGISTRO DE VALORES O EN EL REGISTRO DE VALORES EXTRANJEROS QUE LLEVA LA CMF, POR LO QUE TALES VALORES NO ESTÁN SUJETOS A LA FISCALIZACIÓN DE ÉSTA. POR TRATARSE DE VALORES NO INSCRITOS, NO EXISTE OBLIGACIÓN POR PARTE DEL EMISOR DE ENTREGAR EN CHILE INFORMACIÓN PÚBLICA RESPECTO DE ESTOS VALORES. LAS ACCIONES COMUNES CLASE A NO PODRÁN SER OBJETO DE OFERTA PÚBLICA EN CHILE MIENTRAS NO SEAN INSCRITOS EN EL REGISTRO DE VALORES CORRESPONDIENTE. LAS ACCIONES COMUNES CLASE A SOLO PODRÁN SER OFRECIDOS EN CHILE EN CIRCUNSTANCIAS QUE NO CONSTITUYAN UNA OFERTA PÚBLICA O CUMPLIENDO CON LO DISPUESTO EN LA NORMA DE CARÁCTER GENERAL N°336 DE LA CMF. EN CONFORMIDAD CON LO DISPUESTO POR LA NORMA DE CARÁCTER GENERAL N°336, LAS ACCIONES COMUNES CLASE A PODRÁN SER OFRECIDOS PRIVADAMENTE A CIERTOS “INVERSIONISTAS CALIFICADOS,” IDENTIFICADOS COMO TAL EN DICHA NORMA (Y QUE A SU VEZ ESTÁN DESCRITOS EN LA NORMA DE CARÁCTER GENERAL N°216 DE LA CMF DE FECHA 12 DE JUNIO DE 2008 Y EN LA NORMA DE CARÁCTER GENERAL N°410 DE LA CMF DE FECHA 27 DE JULIO DE 2016).

Colombia

The common shares have not been and will not be registered on the Colombian National Registry of Securities and Issuers or in the Colombian Stock Exchange. Therefore, the common shares may not be publicly offered in Colombia. This material is for your sole and exclusive use as a determined entity, including any of your shareholders, administrators or employees, as applicable. You acknowledge the Colombian laws and regulations (specifically foreign exchange and tax regulations) applicable to any transaction or investment consummated pursuant hereto and represent that you are the sole liable party for full compliance with any such laws and regulations.

Peru

The common shares and this prospectus have not been registered in Peru under the Decreto Supremo N° 093-2002-EF: Texto Único Ordenado de la Ley del Mercado de Valores (the “Peruvian Securities Law”) or before the Superintendencia del Mercado de Valores and cannot be offered or sold in Peru except in a private offering under the meaning of the Peruvian Securities Laws. The Peruvian Securities Law provides that an offering directed exclusively to “institutional investors” (as defined in the Institutional Investors Market Regulations) qualifies as a private offering. The common shares acquired by institutional investors in Peru cannot be transferred to a third party, unless such transfer is made to another institutional investor or the common shares have been previously registered with the Registro Público del Mercado de Valores.

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LEGAL MATTERS

The validity of the common shares offered by this prospectus and certain other legal matters with respect to the laws of Bermuda will be passed upon for us by MJM Limited, our counsel as to Bermuda law. Certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Vinson & Elkins L.L.P. may rely on the opinions of MJM Limited for all matters of Bermuda law. Certain legal matters in connection with our common shares offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited, at December 31, 2019 and 2018, and for each of the two years in the period ended December 31, 2019, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing. The consolidated financial statements of CELSEPAR - Centrais Elétricas de Sergipe Participações S.A. as of December 31, 2019 and 2018, and for each of the years in the two-year period ended December 31, 2019, have been included herein and in the registration statement in reliance upon the report of KPMG Auditores Independentes, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES

We are a Bermuda exempted company. As a result, the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors referred to in this prospectus are not residents of the United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws.

We have appointed Puglisi & Associates as our agent upon whom process may be served in any action brought against us under the laws of the United States. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.

EXPENSES OF THE OFFERING

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NASDAQ listing fee, the amounts set forth below are estimates.

SEC registration fee			$72,411
FINRA filing fee			84,180
Printing and engraving expenses			100,000
Fees and expenses of legal counsel			3,000,000
Accounting fees and expenses			1,000,000
Transfer agent and registrar fees			5,000
NASDAQ listing fee			295,000
Miscellaneous			43,409
Total			$4,600,000

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form F-1 regarding our common shares. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common shares offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules can be downloaded from the SEC’s website at www.sec.gov.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www.hygoenergy.com and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

As a foreign private issuer, we are exempt under the Exchange Act from, among other things, the rules prescribing the furnishing and content of proxy statements, and our executive officers, directors and controlling shareholder are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we will not be required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act.

We will send the transfer agent a copy of all notices of shareholders’ meetings and other reports, communications and information that are made generally available to shareholders. The transfer agent has agreed to mail to all shareholders a notice containing the information (or a summary of the information) contained in any notice of a meeting of our shareholders received by the transfer agent and will make available to all shareholders such notices and all such other reports and communications received by the transfer agent.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

			Page
Consolidated Financial Statements of Hygo Energy Transition Ltd., formerly known as Golar Power Limited

Report of Independent Registered Public Accounting Firm			F-2
Consolidated Statement of Income (Loss) for the years ended December 31, 2019 and 2018			F-3
Consolidated Statement of Comprehensive Loss for the years ended December 31, 2019			F-4
Consolidated Balance Sheet as at December 31, 2019 and 2018			F-5
Consolidated Statement of Changes in Equity for the years ended December 31, 2019 and 2018			F-6
Consolidated Statement of Cash Flows for the years ended December 31, 2019 and 2018			F-7
Notes to Consolidated Financial Statements			F-9

Unaudited Condensed Consolidated Financial Statements of Hygo Energy Transition Ltd.,

formerly known as Golar Power Limited

Unaudited Consolidated Statements of Loss for the six months ended June 30, 2020 and 2019			F-41
Unaudited Consolidated Statements of Comprehensive Income for the six months ended June 30, 2020 and 2019			F-42
Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019			F-43
Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2020 and 2019			F-44
Unaudited Consolidated Statements of Changes in Equity for the six months ended June 30, 2020 and 2019			F-46
Notes to the Unaudited Condensed Consolidated Financial Statements			F-47

Consolidated Financial Statements of

CELSEPAR – Centrais Elétricas de Sergipe Participações S.A.

Report of Independent Registered Public Accounting Firm			F-62
Consolidated Statements of Financial Position as of December 31, 2019 and 2018			F-63
Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2019 and 2018			F-64
Consolidated Statement of Changes in Equity for the years ended December 31, 2019 and 2018			F-65
Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018			F-66
Notes to the Consolidated Financial Statements			F-67

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Hygo Energy Transition Ltd. (formerly known as Golar Power Limited)

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Hygo Energy Transition Ltd. (formerly known as Golar Power Limited) and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of income (loss), consolidated statements of comprehensive loss, consolidated statements of changes in equity and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (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, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

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 Public Company Accounting Oversight Board (United States) (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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2016.

London, United Kingdom

April 29, 2020

except for Note 2 - “Mezzanine equity”, as to which the date is July 21, 2020 and except for the reduction in par value described in Note 25, as to which the date is September 16, 2020

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Hygo Energy Transition Ltd.

Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018

	Notes	2019	2018
	(in thousands of $)
Time charter revenues	7	35,601	47,968
Time charter revenues - collaborative arrangement	7	9,622	30,681
Management fees	14	—	83
Total operating revenues		45,223	78,732

Vessel operating expenses		12,638	11,499
Voyage, charter-hire and commission expenses	7	5,912	3,160
Voyage, charter-hire and commission expenses - collaborative arrangement	7	9,825	39,836
Administrative expenses⁽¹⁾		16,126	17,652
Depreciation and amortization	18	11,212	11,180
Total operating expenses		55,713	83,327
Other operating income	8	1,100	—
Operating loss		(9,390)	(4,595)

Other non-operating income
Unrealized gain on derivative instrument	5	9,990	—
Other non-operating income	8	—	5,000
Net gain on loss of control of subsidiary	16	—	72
Total other non-operating income		9,990	5,072

Financial income (expense)
Interest income		795	1,336
Interest expense		(2)	(912)
Other financial items, net	9	(1,659)	(5,245)
Net financial income (expense)		(866)	(4,821)

Losses before equity in net losses of affiliates, income taxes and non-controlling interest		(266)	(4,344)
Income taxes	10	(4,152)	(110)
Equity in net loss of affiliates	16	(2,510)	(5,748)
Net loss		(6,928)	(10,202)
Net income attributable to non-controlling interest		(5,549)	(1,541)
Preferred dividends	25	(11,875)	(8,500)
Net loss attributable to common stockholders		(24,352)	(20,243)

Loss per share attributable to common stockholders:
Basic and diluted loss per share	11	$(0.52)	$(0.43)

(1)	This includes amounts arising from transactions with related parties (see note 14)

The accompanying notes are an integral part of these consolidated financial statements.

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Hygo Energy Transition Ltd.

Consolidated Statements of Comprehensive Loss for the years ended December 31, 2019 and 2018

	2019	2018
	(in thousands of $)
COMPREHENSIVE LOSS
Net loss	(6,928)	(10,202)
Other comprehensive loss:
Foreign exchange loss on currency translation⁽¹⁾	(6,524)	(32,383)
Comprehensive loss	(13,452)	(42,585)

Comprehensive loss attributable to:
Stockholders of Hygo Energy Transition Ltd.	(19,001)	(44,126)
Non-controlling interests	5,549	1,541
Comprehensive loss	(13,452)	(42,585)

(1)	No tax impact for the years ended December 31, 2019 and 2018.

The accompanying notes are an integral part of these consolidated financial statements.

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Hygo Energy Transition Ltd.

Consolidated Balance Sheets as at December 31, 2019 and 2018

	Notes	2019 Pro Forma Stockholder’s equity (unaudited)⁽²⁾	2019	2018
	(in thousands of $)
ASSETS
Current assets
Cash and cash equivalents		—	49,949	25,808
Restricted cash and short-term deposits	12	—	22,861	24,662
Trade accounts receivable⁽¹⁾	13	—	30,479	10,202
Amounts due from related parties	14	—	9,335	9,394
Derivative asset	5	—	10,200	—
Other current assets	15	—	3,582	8,963
Total current assets		—	126,406	79,029
Non-current assets
Restricted cash	12	—	41	43
Investments in affiliates	16	—	311,105	265,072
Assets under development	17	—	327,754	302,410
Vessels and equipment, net	18	—	360,143	363,893
Other non-current assets	20	—	29,343	23,682
Total assets		—	1,154,792	1,034,129

LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt and short-term debt	21	—	127,056	21,120
Trade accounts payable⁽¹⁾		—	2,583	2,252
Accrued expenses	22	—	46,053	25,934
Other current liabilities⁽¹⁾	23	—	54,324	524
Amount due to related parties	14	—	2,184	1,929
Total current liabilities		—	232,200	51,759
Non-current liabilities
Long-term debt	21	—	337,686	372,256
Other non-current liabilities	24	—	665	10,546
Total liabilities		—	570,551	434,561

Mezzanine equity	25
Preferred capital 20,000,000 preferred shares of $5.00 each issued and outstanding		—	100,000	100,000
Convertible share capital 23,475,077 common shares of $1.00 each issued and outstanding		—	23,475	23,475
Total mezzanine equity		—	123,475	123,475

Stockholder’s equity	25
Share capital 23,475,077 common shares of $1.00 each issued and outstanding and 100,000,000 common shares of $0.47 each issued and outstanding pro forma (unaudited)		46,950	23,475	23,475
Additional paid-in capital		579,042	527,324	517,324
Accumulated other comprehensive loss		(45,186)	(45,186)	(38,662)
Retained losses		(51,937)	(51,937)	(27,585)
Non-controlling interest		7,090	7,090	1,541
Total stockholder’s equity		535,959	460,766	476,093
Total liabilities, mezzanine equity and stockholder’s equity		—	1,154,792	1,034,129

(1)	These include amounts arising from transactions with related parties (see note 14).

(2)

The unaudited pro forma Stockholder's equity as at December 31, 2019 gives effect to (i) $180.0 million to be paid to Stonepeak for the redemption of the preference shares in the Recapitalization on mezzanine equity in connection with the consummation of this offering, which includes accrued and unpaid dividends. The $180.0 million to be paid to Stonepeak represents the contractual Required Return Amount for the preference shares, determined as $9.00 per share based on the redemption date, which includes the aggregate amount of approximately $41.5 million of accrued and unpaid dividends on such preference shares calculated up to the date of redemption; (ii) a subsequent 2.13-for-1 share split to be consummated after the effective date of the registration statement and prior to the consummation of the offering, which will further adjust the par value of the common shares from $1.00 to $0.46950154; and (iii) to reflect the settlement of the MIS which is accounted for as a capital contribution from Stonepeak, following the completion of the offering.

The accompanying notes are an integral part of these consolidated financial statements.

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Hygo Energy Transition Ltd.

Consolidated Statements of Changes in Equity for the years ended December 31, 2019 and 2018

	Notes	Preference Shares (Mezzanine)	Convertible Common Share Capital (Mezzanine)	Common Share Capital	Additional Paid-in Capital	Accumulated Other Comprehensive Loss	Retained losses	Non- controlling Interest	Total Stockholder’s Equity
	(in thousands of $)
Balance at December 31, 2017		100,000	23,475	23,475	407,324	(6,279)	(7,342)	—	417,178
Net (loss) / income		—	—	—	—	—	(11,743)	1,541	(10,202)
Dividends⁽¹⁾	25	—	—	—	—	—	(8,500)	—	(8,500)
Capital contributions	25	—	—	—	110,000	—	—	—	110,000
Foreign currency translation adjustments		—	—	—	—	(32,383)	—	—	(32,383)
Balance at December 31, 2018		100,000	23,475	23,475	517,324	(38,662)	(27,585)	1,541	476,093
Net (loss) / income		—	—	—	—	—	(12,477)	5,549	(6,928)
Dividends⁽¹⁾	25	—	—	—	—	—	(11,875)	—	(11,875)
Capital contributions	25	—	—	—	10,000	—	—	—	10,000
Foreign currency translation adjustments		—	—	—	—	(6,524)	—	—	(6,524)
Balance at December 31, 2019		100,000	23,475	23,475	527,324	(45,186)	(51,937)	7,090	460,766

(1)	This relates to accrued dividends to Preference Shareholders (see note 25).

The accompanying notes are an integral part of these consolidated financial statements.

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Hygo Energy Transition Ltd.

Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018

	Notes	2019	2018
	(in thousands of $)
Operating activities
Net loss		(6,928)	(10,202)
Adjustments to reconcile net loss to net cash provided by / (used in) operating activities:
Equity in net losses of affiliates	16	2,510	5,748
Net foreign exchange gain		(1,844)	(2,047)
Depreciation and amortization	18	11,212	11,180
Amortization of deferred charges		1,336	(1,651)
Drydock expenditure		(1,314)	—
Change in fair value of derivative instrument	5	(9,990)	—
Change in fair value of investment, net of unwind of discount	9	1,553	3,346
Recognition of guarantee net of amortization		(1,122)	(697)
Write off of loan receivable		—	1,617
Change in assets and liabilities:
Deferred revenue	23	38,730	—
Trade accounts receivable		(20,277)	(7,142)
Inventories		1,909	(1,893)
Prepaid expenses, accrued income and other assets		3,471	(6,007)
Other non-current assets		(673)	(1,682)
Amounts due from / (to) related companies		312	(4,725)
Trade accounts payable		331	(398)
Accrued expenses		(10,384)	1,678
Other current and non-current liabilities⁽¹⁾		4,923	(72)
Net cash provided by / (used in) operating activities		13,755	(12,947)

Investing activities
Additions to investments in affiliates	16	(48,652)	(106,516)
Additions to vessels and equipment	18	(3,389)	(4,394)
Additions to assets under development		(19,406)	(199,884)
Net cash used in investing activities		(71,447)	(310,794)

Financing activities
Proceeds from equity contributions from shareholders	25	10,000	110,000
Proceeds from short-term and long-term debt (including related parties)		194,834	235,878
Repayments of short-term and long-term debt (including related parties)		(122,325)	(21,442)
Financing fees		(2,479)	—
Net cash provided by financing activities		80,030	324,436
Net increase in cash, cash equivalents and restricted cash		22,338	695
Cash, cash equivalents and restricted cash at beginning of period		50,513	49,818
Cash, cash equivalents and restricted cash at end of period		72,851	50,513

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid, net of capitalized interest		—	—
Income taxes paid		756	110

(1)	For the year ended December 31, 2019, $3.5 million relates to the deferred tax liability (see note 10).

The accompanying notes are an integral part of these consolidated financial statements.

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Supplemental note to the consolidated statements of cash flows

The following table identifies the balance sheet line-items included in cash, cash equivalents and restricted cash presented in the consolidated statements of cash flows:

The accompanying notes are an integral part of these consolidated financial statements.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements

GENERAL

Hygo Energy Transition Ltd., formerly known as Golar Power Limited (the “Company” or “Hygo”) was incorporated in Hamilton, Bermuda on May 19, 2016. The Company is a 50/50 joint venture partnership between Golar LNG Limited (“Golar LNG”), an owner and operator of marine based liquified natural gas (“LNG”) midstream infrastructure and who is active in liquefaction, transportation and regasification of natural gas and Stonepeak Infrastructure Fund II Cayman (G) Ltd (“Stonepeak”), a private equity firm. Hygo’s purpose is to develop projects that encourage the use of natural gas as a more sustainable source of fossil energy generation, replacing oil-derived liquid fuels. This objective is achieved through owning and operating natural gas storage transportation vessels and regasification units and their associated energy infrastructure. As part of this strategy, Hygo may construct or acquire the necessary infrastructure.

The Company, through its equity method investment in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), has constructed and is operating, a combined cycle power plant in Brazil with investment partner Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A. Located near Aracaju, the state capital of Sergipe, the 1.5GW power station is the largest thermal power station in South America and supplements hydropower during dry seasons and help to meet the growing demand for electricity in the region. The power project has commenced commercial operations and is scheduled to deliver power to 26 committed off-takers for 25 years from Q1 2020, in accordance with Power Purchase Agreement (“PPA”) contracts awarded by the Brazilian Government in 2015.

The Company, through its investment in equity method investee project company Centrais Elétricas Barcarena S.A. (“CELBA”), additionally plans to construct and operate a 605MW combined cycle power plant in the city of Barcarena in the State of Pará, Brazil. The power plant will utilise imported LNG for the generation of electricity which will be distributed to the Brazilian national electricity grid through the existing Vila do Conde Substation located nearby. The power project is scheduled to deliver power to 9 committed off-takers for 25 years from 2025 in accordance with the PPA contracts awarded by the Brazilian Government in October 2019.

As of December 31, 2019, the Hygo fleet consists of two LNG carriers, Golar Celsius and Golar Penguin and one Floating Storage Regasification Unit (“FSRU”) asset under development, Golar Nanook. In 2018 and 2019, the Golar Nanook and Golar Penguin entered into sale and lease back transactions with a subsidiary of China Construction Bank Financial Leasing Corporation Limited (“CCBFL”) and a subsidiary of COSCO Shipping Leasing Company Limited (“COSCO”), respectively. The Golar Nanook is located offshore Sergipe, Brazil to supply LNG to the Sergipe power station and in the second quarter of 2019 commenced its charter with Centrais Elétricas de Sergipe S.A. (“CELSE”) for a period of 25 years. Golar Celsius and Golar Penguin are currently operating in the spot market as part of the Cool Pool.

The Company is also pursuing multiple gas to power opportunities that have been identified elsewhere across Latin America, the Indian Subcontinent, the Caribbean, West Africa, South East Asia and Europe.

As used herein and unless otherwise required by the context, the terms “Hygo”, the “Company”, “we”, “our” refer to Hygo or any one or more of its consolidated subsidiaries, or to all such entities.

2.	BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of accounting and presentation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements, unless otherwise noted.

Use of estimates

The preparation of financial statements in accordance with US GAAP and in the application of our accounting policies below requires management to make estimates and assumptions affecting the reported

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The areas requiring the most significant judgement are the recoverability of asset carrying values.

In assessing the recoverability of our vessels’ carrying amounts, we make assumptions regarding estimated future cash flows and estimates in respect of residual or scrap value. Significant assumptions used include, among others, charter rates, ship operating expenses, utilization, drydocking requirements and residual value.

Principles of consolidation

The Consolidated Financial Statements of Hygo Energy Transition Ltd. include the results of other entities in which we have a controlling financial interest. All material intercompany balances and transactions have been eliminated.

Voting interest entities are entities that have sufficient equity and provide the equity investors with voting rights that enable them to make significant decisions relating to the entity’s operations. For these types of entities, the determination on whether we have a controlling financial interest is primarily based on the amount of voting equity interests held.

Variable interest entities (“VIEs”) are entities that by design, either (1) lack sufficient equity to allow the Company to finance its activities without additional subordinated financial support from other parties, or (2) have equity investors that do not have the ability to make significant decisions relating to the entity’s operations through voting rights, or do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of the entity. The primary beneficiary of a VIE (i.e. the party with the controlling financial interest) 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.

The most common type of VIE for Hygo Energy Transition Ltd. is the Sale and Leaseback financings for LNG carriers and FSRU. As part of these financings, Hygo Energy Transition Ltd. sells the asset to a single asset entity of the lending bank and then leases the asset back. While we do not hold an equity investment in these entities, we have determined that these entities are a VIE and that we have a variable interest in them due to the guarantees and fixed price repurchase options that absorb the losses of the VIE that could potentially be significant to the entity. We have concluded that we have the power to direct the economic activities that most impact the economic performance as we control the significant decisions relating to the assets and we have the obligation to absorb losses or the right to receive the residual returns from the leased asset.

The accompanying consolidated financial statements include the financial statements of the entities listed in note 4 and note 5.

Business combinations

When the assets acquired, and liabilities assumed constitute a business then the acquisition is a business combination. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not considered a business. An input and a substantive process together must significantly contribute to the creation of the output to constitute a business.

Business combinations of subsidiaries are accounted for under the acquisition method. On acquisition, the identifiable assets, liabilities and contingent liabilities of a subsidiary are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair values of the identifiable net assets acquired is recognized as goodwill. Any deficiency of the cost of acquisition below the fair values of the identifiable net assets acquired (i.e. bargain purchase) is credited to the consolidated statement of income (loss) in the period of acquisition. The consideration transferred for an acquisition is measured at fair value of the consideration given. Acquisition related costs are expensed as incurred. The results of subsidiary undertakings are included from the date of acquisition.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

If the assets acquired are not a business, goodwill is not recognized in an asset acquisition. 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.

Investments in affiliates

Many of our development projects are carried out through specific entities jointly owned and managed with other third parties. Where these entities are set up for the purpose of sharing the risks and rewards of developing an asset and each party has the ability to participate equally and directly in the overall management of the Company plus the operation of the entity is for the mutual benefit of the members then we class these investments as Joint Ventures.

The results, assets and liabilities of joint ventures are incorporated into the Financial Statements using the equity method of accounting. Income / (losses) from equity method investments represents our proportionate share of net income / (losses) generated by the equity method investees. When our share of losses in an affiliate equals or exceeds its interest, we do not recognize further losses, unless the Company has incurred obligations or made payments on behalf of the affiliate. Intra entity profits are eliminated until realized by the investee, this includes unrealized gains and losses on physical power purchase contracts between Hygo and its equity accounted investments. Equity method investments are assessed for impairment whenever there are changes in the facts and circumstances which indicate a loss in value has occurred.

Reporting currency

In individual subsidiaries and joint ventures, transactions in foreign currencies are initially recorded in the functional currency of those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the Balance Sheet date. Any resulting exchange gain / (loss) is included in the Income Statement. Non-monetary assets and liabilities are not retranslated after recognition.

The consolidated financial statements are reported in U.S. dollars. The assets and liabilities of non-US dollar functional currency subsidiaries or joint ventures are translated into US dollars at the spot exchange rate on the Balance Sheet date. The statements of Consolidated Statement of Income (Loss) and the Consolidated Statements of Cash Flows of non-US dollar subsidiaries and joint ventures are translated into US dollars using the average rates of exchange for the period. Exchange adjustments arising from translating non-US dollar subsidiaries and joint ventures into US dollars are recorded in equity and reported in the Consolidated Statements of Comprehensive Loss and the Consolidated Statements of Changes in Equity.

Fair value measurements

We measure assets and liabilities requiring fair value presentation or disclosure using an exit price (i.e. the price that would be received to sell an asset or paid to transfer a liability) and disclose these amounts according to the source of the inputs into the valuation exercise under the following hierarchy:

Level 1: Quoted prices in an active market for identical assets and liabilities

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data

Level 3: Unobservable inputs that are significant to the fair value of the assets and liabilities.

We consider all our cash and cash equivalent balances as being highly liquid with original maturities of three months or less to be equivalent to cash.

Lessor accounting

Contracts relating to our LNG carriers and FSRU take on the form of leases as they convey the right to obtain substantially all of the economic benefits from the use of the asset and they allow the customer to direct the use of that asset.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

At inception, we make an assessment on whether the contract is an operating lease or a finance lease. An agreement will be a finance lease if any of the following conditions are met:

•	ownership of the asset is transferred at the end of the lease term;

•	the contract contains an option to purchase the asset which is reasonably certain to be exercised;

•	the lease term is for a major part of the remaining useful life of the contract, although contracts entered into the last 25% of the asset’s useful life are not subject to this criterion;

•	the discounted value of the fixed payments under the lease represent substantially all of the fair value of the asset; or

•	the asset is heavily customized such that it could not be used for another charter at the end of the term.

Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, lease accounting will not commence until the asset has successfully passed the acceptance test. We assess a lease under the modification guidance 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.

Costs directly associated with the execution of the lease or costs incurred after lease inception (the execution of the contract) but prior to the commencement of the lease that directly relate to preparing the asset for the contract (for example bunker costs), are capitalized and amortized to the consolidated statement of income over the lease term. We also defer upfront revenue payments (for example positioning fees) to the consolidated balance sheet and amortize to the consolidated statement of income over the lease term.

Fixed revenue from operating leases is accounted for on a straight-line basis over the life of the lease; while variable revenue is accounted for as incurred in the relevant period. Fixed revenue includes fixed payments and variable payments based on a rate or index. For our operating leases, we have elected the practical expedient to combine our service revenue and operating lease income as both the timing and the pattern of transfer of the components are the same. The predominant assessment is lease revenue.

Collaborative arrangements

Our LNG carriers participate in an LNG carrier pool arrangement with Golar LNG Limited, Gaslog Limited (up to July 2019) and Dynagas Ltd (up to June 2018), referred to as the Cool Pool. The Cool Pool allows the Pool Participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as agent, for the marketing and chartering of the participating vessels and paying other voyage costs such as port call expenses and brokers’ commissions in relation to employment contracts, but each of the Pool Participants continues to be fully responsible for the financing, insurance, manning and technical management of their respective vessels.

Up until July 2019, the Cool Pool arrangement was accounted for in accordance with the guidance on collaborative arrangements as through the Cool Pool steering committee the members actively participated in managing the pool and were exposed to the significant risks and rewards of the commercial success of the pool. The guidance on collaborative arrangements requires a company to assess whether they are the agent or principal in the arrangement and to account for the underlying transactions based on that determination.

We concluded that we were the principal for the Hygo vessels operating in the Cool Pool and presented the income and expenses relating to our vessels gross on the face of the Income Statement in the line items “Time charter revenues” and “Voyage, charter-hire and commission expenses.” For Cool Pool net revenues generated

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

by the other participants in the pooling arrangement, these were presented separately in revenue and expenses from collaborative arrangements. Each participants’ share of the net Cool Pool revenues is based on the number of days such vessels participated in the pool.

Upon exit of Gaslog from the Cool Pool in July 2019, we ceased applying collaborative arrangement accounting. This has had no impact for the accounting treatment relating to our own vessels, however, for Cool Pool net revenues and expenses generated by the other participants we analogise to the cost of obtaining a contract and present the net balance within the line item “Voyage, charter hire and commission expenses.”

Segment reporting

A segment is a distinguishable component of the business that is engaged in business activities from which we earn revenues and incur expenses whose operating results are regularly reviewed by the chief operating decision maker, and which are subject to risks and rewards that are different from those of other segments. We have identified four reportable industry segments: LNG carriers, FSRU and terminals, power and downstream distribution.

Restricted cash and short-term deposits

We also present short-term deposits and cash balances relating to our consolidated VIEs within restricted cash as we do not have the ability to use that cash freely for company purposes.

Inventories

Inventories, which are comprised principally of fuel, lubricating oils and ship spares, are stated at the lower of cost or net realizable value. Cost is determined on a first-in, first-out basis and inventories are included in “Other current assets” in the consolidated balance sheets.

Assets under development

An asset is classified as asset under development when there is a firm commitment from us to proceed with the construction of the asset and the likelihood of conversion is virtually certain to occur. Vessels that are under development are stated at cost. All pre-delivery costs incurred during the construction of the vessels, including purchase installments, interest, supervision and technical costs, are capitalized. Capitalization ceases and depreciation commences when the vessel is available for its intended use.

Vessels and equipment

Vessels and equipment are stated at cost less accumulated depreciation. The cost of vessels and equipment less the estimated residual value is depreciated on a straight-line basis over the assets’ remaining useful economic lives. Management estimates the residual values of our vessels based on a scrap value determined by broker valuations. Residual values are periodically reviewed and revised to recognize changes in conditions, new regulations or other reasons.

Refurbishment costs incurred during the period are capitalized as part of vessels and equipment and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs are costs that appreciably increase the capacity, or improve the efficiency or safety of vessels and equipment. Expenditures of a routine repairs and maintenance nature that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred.

Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years. We have adopted the “built-in overhaul” method of accounting. The built-in overhaul method is based on the segregation of vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals to reflect the

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

different useful lives of the components of the assets. The estimated cost of the drydocking component is amortized until the date of the first drydocking following acquisition, upon which the cost is capitalized and the process is repeated. Any historical drydocking expenditure which has not been fully depreciated at the point of drydocking is immediately written off in the Consolidated Statement of Income (Loss). When a vessel is disposed, any unamortized drydocking expenditure is charged against income in the period of disposal.

Useful lives applied in depreciation are as follows:

Vessels			40 years
Drydocking expenditure			5 years
ISO containers and associated equipment			10 years
Office equipment			5 - 10 years

Impairment of long-lived assets

We continually monitor events and changes in circumstances that could indicate carrying amounts of long-term assets may not be recoverable. In assessing the recoverability of our vessels’ carrying amounts, we make assumptions regarding estimated future cash flows and estimates in respect of residual or scrap value. When such events or changes in circumstances are present, we assess the recoverability of long-term assets by determining whether the carrying value of such assets will be recovered through undiscounted expected future cash flows. If the total of the future cash flows is less than the carrying amount of those assets, we recognize an impairment loss based on the excess of the carrying amount over the lower of the fair market value of the assets, less cost to sell, and the net present value (“NPV”) of estimated future undiscounted cash flows from the employment of the asset (“Value in use”).

Interest costs capitalized

Interest is capitalized on all qualifying assets that require a period of time to get them ready for their intended use. Qualifying assets consist of vessels under construction. In addition, certain equity method investments may be considered qualifying assets prior to commencement of their planned principal operation. The interest capitalized is calculated using the rate of interest on the loan to fund the expenditure or our weighted average cost of borrowings where appropriate, from commencement of the asset development until substantially all the activities necessary to prepare the assets for its intended use are complete.

If our financing plans associate a specific borrowing with a qualifying asset, we use the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset provided that does not exceed the amount of that borrowing. We do not capitalize amounts beyond the actual interest expense incurred in the period.

Deferred financing charges

Costs associated with long-term financing, including debt arrangement fees are deferred and amortized over the term of the relevant loan, using the effective interest method. Amortisation of debt issuance costs are included in interest expense. These costs are presented as a deduction from the corresponding liability, consistent with debt discounts.

Derivatives

All derivative instruments are initially recorded at fair value as either assets or liabilities in the accompanying consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. Where the fair value of a derivative instrument is a net liability, the derivative instrument is classified in “Other current liabilities” in the consolidated balance sheets. Where the fair value of a derivative instrument is a net asset, the derivative instrument is classified in “Derivative asset” in the consolidated balance sheets. The changes in fair value of derivative financial instruments are accounted in “Unrealized gain on derivative instrument” in the consolidated statements of income (loss). We do not apply hedge accounting.

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Notes to Consolidated Financial Statements(Continued)

The fair value of the derivative instrument was determined using a forward curve. Significant inputs used in the valuation of the derivative instrument include management’s estimate of forward energy prices.

Provisions

In the ordinary course of business, we are subject to various claims, law suits and complaints. Management, in consultation with internal and external advisers, will provide for a contingent loss in the consolidated financial statements if the contingency had occurred at the date of the financial statements and the likelihood of loss was probable and the amount can be reasonably estimated. If we determine that the reasonable estimate of the loss is a range and there is no best estimate within the range, we will provide the lower amount within the range.

Guarantees

Guarantees issued by us, excluding those that are guaranteeing our own performance, are recognized at fair value at the time that the guarantees are issued and reported in “Other current liabilities.” and “Other non-current liabilities”. A liability for the fair value of the obligation undertaken in issuing the guarantee is recognized. If it becomes probable that we will have to perform under a guarantee, we will recognize an additional liability if the amount of the loss can be reasonably estimated. The recognition of fair value is not required for certain guarantees where they are a guarantee over our own performance (such as the parent’s guarantee of a subsidiary’s debt to a third party).

Earnings per share

Basic earnings per share (“EPS”) is computed based on the income available to common stockholders and the weighted average number of shares outstanding for basic EPS. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments. Such potentially dilutive common shares are excluded when the effect would be to increase earnings per share or reduce a loss per share.

Income taxes

The guidance on “Income Taxes” prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Penalties and interest related to uncertain tax positions are recognized in “Income taxes” in the consolidated statements of income (loss).

Deferred taxes

Deferred tax assets and liabilities are recognized principally for the expected tax consequences of temporary differences between the tax bases of assets and liabilities and their reported amounts. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Realization of the deferred income tax asset is dependent on generating sufficient taxable income in future years.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on the tax rates and tax laws that have been enacted at the balance sheet date. Income tax relating to items recognized directly in the statement of comprehensive income is recognized in the statement of changes in equity and not in the consolidated statements of income (loss).

Related Parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or can significantly influence the management or operating policies. Parties are also related if they are subject to common control or significant influence.

Share options

We recognize compensation expense for a share-based award over an employee’s requisite service period based on the award’s grant date fair value, subject to adjustment. Our share-based awards are settled in cash and are accounted for as liability-based awards. As such liabilities are required to be measured at fair value at each reporting date until the date of settlement. Where an Initial Public Offering (IPO) is a vesting event we do not recognize any value until the event has occurred.

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Notes to Consolidated Financial Statements(Continued)

Mezzanine equity

Where ordinary shares or preference shares are determined to be conditionally redeemable upon the occurrence of certain events that are not solely within the control of the issuer, and upon such event, the shares would become redeemable at the option of the holders, they are classified as ‘mezzanine equity’ (temporary equity). The purpose of this classification is to convey that such a security may not be permanently part of equity and could result in a demand for cash, securities or other assets of the entity in the future.

3.	RECENTLY ISSUED ACCOUNTING STANDARDS

Adoption of new accounting standards

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02 Leases (Topic 842) along with subsequent amendments ASU 2019-20 Leases (Topic 842): Narrow scope improvements for lessors in December 2018 and ASU 2019-01 Leases (Topic 842): Codification improvements in March 2019. Topic 842 modifies the definition of a lease, requires reassessment of the lease term upon the occurrence of certain triggers and introduces new disclosures. Lessors are required to classify leases as sales-type, direct financing or operating, with classification affecting the pattern of income recognition and provides guidance for sale and leaseback transactions. Topic 842 requires a lessee to recognize leases on its balance sheet by recording a lease liability (representing the obligation to make future lease payments) and a right of use asset (representing the right to use the asset for the lease term). Leases for lessees will be classified as either financing or operating with classification affecting the pattern of expense recognition in the income statement.

We adopted this Topic 842 on January 1, 2019 under a modified retrospective transition approach. The impact of this amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings as of January 1, 2019.

In July 2018, the FASB issued ASU 2018-09 Codification improvements. The amendments in this ASU cover a wide range of topics covering primarily minor corrections, clarifications and codification improvements. We adopted the codification improvements that were not effective on issuance on January 1, 2019 under the specified transition approach connected with each of the codification improvements. The impact of this amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings as of January 1, 2019.

Accounting pronouncements that have been issued but not adopted

In June 2016, the FASB issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments, including ASU 2018-19, ASU 2019-04 & ASU 2019-11 Codification Improvements to Topic 326 “Financial Instruments-Credit Losses”. Topic 326 replaces the incurred loss impairment methodology, with a requirement to recognize lifetime expected credit losses (measured over the contractual life of the instrument) immediately based on information about past events, current conditions and forecasts of future economic conditions. This will reflect the net amount expected to be collected from the financial asset and is referred to as the current expected credit loss “CECL” methodology. The guidance applies to financial assets measured at amortized cost as well as off-balance sheet credit exposures not accounted for as insurance, for example financial guarantees. Topic 326 also makes changes to the accounting for available-for-sale debt securities and purchased credit deteriorated financial assets, however, no such financial assets existed on date of adoption or in the reporting periods covered by these consolidated financial statements.

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Notes to Consolidated Financial Statements(Continued)

Topic 326 will become effective for us on January 1, 2020 and we will apply the modified retrospective transition approach. At inception the standard is not anticipated to have any material impact as:

•	Cash and cash equivalents (including restricted cash and short-term deposits) either are payable on demand, have short-term maturities (highly liquid) or held with financial institutions with investment grade credit rating that overall results in limited credit risk exposure

•

Trade receivables and related party transactions are mainly short-term and mostly have historic low write-offs. In addition there is no significant past due amounts indicating delinquency of payments, which together with the mostly short-term maturities result in forward looking factors being insignificant and limited credit risk exposure impact based on current and past conditions

•	Off balance sheet guarantees only pertain to financial guarantees where collateral from return of the vessel on default will cover the guarantee amount in each remaining year covered by the guarantee.

The following table provides a brief description of other recent accounting standards that have been issued but not yet adopted:

Standard	Description	Date of Adoption	Expected Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.	Removes some disclosure requirements relating to transfers between Level 1 and Level 2 of the FV hierarchy. Introduces new disclosure requirements for Level 3 measurements.	January 1, 2020	No material impact on our disclosure requirements as we have no Level 3 measurements.

ASU 2018-17 Consolidation (Topic 810) - Targeted Improvements to Related Party Guidance for Variable Interest Entities	For the purposes of determining whether a decision making fee is a variable interest, a company is now required to consider indirect interests held through related parties under common control on a proportionate basis as opposed to as a direct investment in the entity.	January 1, 2020	No impact on consolidation assessments

ASU 2019-12 Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes.	The amendment removes certain exceptions previously available and provides some additional calculation rules to help simplify the accounting for income taxes.	January 1, 2021	Under evaluation

ASU 2020-03 Financial Instruments (Topic 825) - Codification Improvements	The amendment proposes seven clarifications to improve the understandability of existing guidance, including that fees between debtor and creditor and third-party costs directly related to exchanges or modifications of debt instruments include line-of-credit or revolving debt arrangements.	January 1, 2020	No impact

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Notes to Consolidated Financial Statements(Continued)

Standard			Description			Date of Adoption			Expected Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2020-04 Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting			The amendments provide temporary optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The applicable expedients for us are in relation to modifications of contracts within the scope of Topics 310, Receivables, 470, Debt, and Topic 842, Leases. This optional guidance may be applied prospectively from any date beginning March 12, 2020 and cannot be applied to modifications that occur after December 31, 2022.			Under evaluation			Under evaluation

4.	SUBSIDIARIES

The following table lists our significant subsidiaries and their purpose as at December 31, 2019. Unless otherwise indicated, we own a 100% controlling interest in each of the following subsidiaries.

Name	Jurisdiction of Incorporation	Purpose
LNG Power Limited	United Kingdom	Holding company⁽¹⁾
Golar Power Penguin Corp.	Marshall Islands	Holding company to vessel owning company of Golar Penguin⁽²⁾
Golar Hull 2026 Corp.	Marshall Islands	Owns Golar Celsius
Golar FSRU 8 Corp.	Marshall Islands	Leases and operates Golar Nanook⁽²⁾

(1)	LNG Power Limited is the holding company of various of our wholly owned Brazilian domiciled subsidiaries, one of which is Golar Power Brasil Participações S.A. (“Golar Brasil”) , which holds our investment in equity method investee project companies CELSEPAR and CELBA (see note 16).

(2)

The above table excludes mention of the lessor variable entities (“lessor VIEs”) whereby we have leased vessels under finance leases. The lessor VIEs are wholly owned, newly formed special purpose vehicles (“SPVs”) of financial institutions. While we do not hold any equity investments in these SPVs, we have concluded that we are the primary beneficiary of the lessor VIEs and accordingly have consolidated these entities into our financial results. Refer to note 5 for additional detail.

5.	VARIABLE INTEREST ENTITIES (“VIEs”)

5.1	Lessor VIEs

As of December 31, 2019, we leased two vessels (December 31, 2018: one vessel) from VIEs as part of sale and leaseback arrangements with subsidiaries of CCBFL and COSCO.

CCBFL Lessor VIE

In September 2018, we sold the Golar Nanook to a CCBFL entity and subsequently leased back the vessel on a bareboat charter for a term of twelve years. We have options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third year anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve year lease period.

Oriental Shipping Company Lessor VIE

In December 2019, we sold the Golar Penguin to Oriental Fleet LNG 02 Limited and subsequently leased back the vessel on a bareboat charter for a term of six years. We have options to repurchase the vessel

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Notes to Consolidated Financial Statements(Continued)

throughout the charter term at fixed pre-determined amounts, commencing from the first year anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six year lease period.

While we do not hold an equity investment in the above SPVs, we have determined that we have a variable interest in these SPVs and that the lessor entities, that own the vessels, are VIEs. Based on our evaluation of the agreements, we have concluded that we are the primary beneficiary of these VIEs and, accordingly, these VIEs are consolidated into our financial results. We did not record any gains or losses from the sale of these vessels as they continued to be reported as vessels at their original costs in our consolidated financial statements at the time of each transaction. Similarly, the effect of the bareboat charter arrangements are eliminated upon consolidation of the SPV. The equity attributable to CCBFL and COSCO in their respective VIEs are included in non-controlling interests in our consolidated financial statements. As of December 31, 2019 the Golar Nanook is reported under “Assets under development” and the Golar Penguin is reported under “Vessel and equipment, net” in our consolidated balance sheet.

The following table gives a summary of the sale and leaseback arrangements, including repurchase options and obligations as of December 31, 2019:

Golar Nanook

September 2018

277.0

247.7

September 2021

94.2

September 2030

Golar Penguin

December 2019

162.0

105.8

December 2020

69.9

December 2025

A summary of our payment obligations (excluding repurchase options and repurchase obligations) under the bareboat charter with the lessor VIEs as of December 31, 2019, are shown below:

	2020	2021	2022	2023	2024	2025+
	(in $ thousands)
Golar Nanook	24,610	23,878	23,181	22,484	21,816	111,781
Golar Penguin	13,621	13,200	12,778	12,369	11,935	8,688

The assets and liabilities of the lessor VIEs that most significantly impacts our consolidated balance sheet as of December 31, 2019 and 2018 are as follows:

	Golar Nanook	Golar Penguin	2019 Total	2018 Total
	(in $ thousands)
Assets
Restricted cash	6,132	4,940	11,072	—
Other current assets	—	—	—	6,166
Liabilities
Long-term interest bearing debt - current portion⁽¹⁾	—	113,400	113,400	—
Long-term interest bearing debt - non-current portion	217,178	—	217,178	235,878

(1)	The long-term interest bearing debt associated with the Penguin lessor VIE is classified as short-term as it has no repayment profile and is repayable on demand by the lender.

The most significant impact of the lessor VIEs operations on our consolidated statement of operations is interest expense of $8.4 million and $2.2 million for the years ended December 31, 2019 and 2018, respectively. The most significant impact of the lessor VIEs cash flows on our consolidated statements of cash flows is net cash received in financing activities of $113.4 million and $235.4 million for the years ended December 31, 2019 and 2018, respectively.

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Notes to Consolidated Financial Statements(Continued)

5.2	Mercurio VIE

On October 9, 2019, the Company acquired 100% of the equity interest in Mercurio Comercializadora de Energia Ltda. (“Mercurio”), a variable interest entity, for purchase consideration of $0.5 million. The entity was purchased in order for Hygo to fulfill its obligation to purchase replacement power in the market for the Sergipe Project in January and February 2020. We have determined that the entity is a VIE as although we own 100% of the equity, some of the profits related to the trades not executed on behalf of Hygo. However, we have determined that we have control over the most significant activities and the greatest exposure to variability in residual returns and expected losses of the entity. Accordingly, we have consolidated Mercurio as we are the primary beneficiary of the VIE.

The assets and liabilities of Mercurio that most significantly impacts our consolidated balance sheet as of December 31, 2019 and our consolidated statement of income (loss) for the year ended December 31, 2019 are as follows:

			2019 Total
			(in $ thousands)
Assets
Derivative asset			10,200
Liabilities
Deferred tax liability			(3,468)
Other non-operating income
Unrealized gain on derivative instrument			9,990
Tax expense
Tax expense			(3,396)

Pursuant to the terms of the CELSE power auction, CELSE was obliged to deliver 867 MW to the grid effective January 1, 2020 otherwise it would have to pay liquidated damages. Under local regulations, if CELSE was unable to meet its contractual obligations it could provide replacement power by purchasing power from third parties and delivering it to the grid. In order to avoid CELSE incurring liquidated damages, the joint venture partners entered into a contract with CELSE on June 30, 2019 to deliver power to the grid until the power station was successfully commissioned. The contract meets the definition of a derivative and for the year ended December 31, 2019, the Company recognised an unrealized gain on the forward energy purchase contracts of $10.0 million and an associated tax expense of $3.4 million. As such, as at December 31, 2019, a derivative asset of $10.2 million and associated deferred tax liability of $3.5 million were recognised (see note 10).

6.	SEGMENT INFORMATION

We provide integrated downstream LNG solutions to underserved markets by delivering less expensive, more environmentally sustainable energy alternatives to customers around the world. Our reportable segments consist of the primary services that each provides. Although our segments are generally influenced by the same economic factors, each represents a distinct product in the LNG downstream industry. Segment results are evaluated based on net income. The accounting principles for the segments are the same as for our consolidated financial statements. Indirect general and administrative expenses are allocated to each segment based on estimated use.

The split of the organization of the business into four reportable segments is based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure. As of December 31, 2019, we operate in the following four reportable segments:

•

LNG Carriers – LNG carriers are vessels that transport LNG and are compatible with many LNG offloading and receiving terminals globally. We have two LNG carriers which are currently operating through the Cool Pool in the spot/short-term charter market. These vessels will continue to operate through the Cool Pool until their conversion to FSRUs.

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Notes to Consolidated Financial Statements(Continued)

•	FSRU and Terminals – FSRUs are vessels that are permanently moored offshore and used to store and regasify LNG. We have one FSRU and terminal offshore Sergipe, Brazil, which is in service to CELSE pursuant to a 25-year charter.

•	Power – We have contracted with local partners to build cleaner and economically advantageous natural gas-fired power generation assets backed by long-term power purchase agreements in our core operating areas.

•	Downstream Distribution - Our downstream distribution business is focused on the procurement of LNG or natural gas from our terminals and other sources to be able to deliver to our downstream customers under medium to long-term contracts.

	Year Ended December 31, 2019
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(in thousands of $)
Statement of Operations:
Total operating revenues	45,223	—	—	—	—	45,223
Total vessel operating expenses⁽²⁾	(28,375)	—	—	—	—	(28,375)
Depreciation	(11,168)	—	—	(10)	(34)	(11,212)
Administrative expenses	(869)	(3,053)	(1,730)	(2,671)	(7,803)	(16,126)
Segment operating income (loss)	4,811	(3,053)	(1,730)	(2,681)	(7,837)	(10,490)
Equity in net loss affiliates	—	—	(2,510)	—	—	(2,510)

	Year Ended December 31, 2018
	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(in thousands of $)
Statement of Operations:
Total operating revenues	78,732	—	—	—	—	78,732
Total vessel operating expenses⁽²⁾	(54,495)	—	—	—	—	(54,495)
Depreciation	(11,160)	—	—	—	(20)	(11,180)
Administrative expenses	(4,770)	(2,689)	(1,620)	(8)	(8,565)	(17,652)
Segment operating income (loss)	8,307	(2,689)	(1,620)	(8)	(8,585)	(4,595)
Equity in net loss affiliates	—	—	(5,748)	—	—	(5,748)

(1)	Relates to corporate overheads not allocated to a segment but included to reflect total depreciation and administrative expenses in the consolidated statement of income (loss).

(2)	Total vessel operating expenses consists of the following line items in the Statement of Comprehensive Income (loss): Vessel operating expenses, Voyage, charter-hire and commission expenses and Voyage, charter-hire and commission expenses – collaborative arrangement.

Year Ended December 31, 2019

	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(in thousands of $)
Balance Sheet:
Total assets	410,930	369,902	332,363	1,662	39,935	1,154,792
Investments in affiliates	—	—	311,105	—	—	311,105
Assets under development	—	327,754	—	—	—	327,754
Vessels and equipment, net	358,489	3	—	1,489	162	360,143
Other assets	52,441	42,145	21,258	173	39,773	155,790

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Notes to Consolidated Financial Statements(Continued)

Year Ended December 31, 2018

	LNG Carriers	FSRU and Terminals	Power	Downstream Distribution	Other Business and Corporate⁽¹⁾	Total
	(in thousands of $)
Balance Sheet:
Total assets	428,004	310,914	274,318	5	20,888	1,034,129
Investments in affiliates	—	—	265,072	—	—	265,072
Assets under development	—	302,410	—	—	—	302,410
Vessels and equipment, net	363,769	—	—	—	124	363,893
Other assets	64,235	8,504	9,246	5	20,764	102,754

(1)	Relates to assets not allocated to a segment but included to reflect the total assets in the consolidated balance sheet.

Geographic Data

During the year ended December 31, 2019 and 2018, our vessels operated solely within the Cool Pool. In time and voyage charters for LNG carriers, the charterer, not us, controls the routes of our vessels. These routes can be worldwide as determined by the charterers. Accordingly, our management, including the chief operating decision maker, do not evaluate our performance either according to customer or geographical region.

REVENUE

The table below summarizes our net earnings (impacting each line item in our consolidated statement of income (loss)) generated from our participation in the Cool Pool:

	2019	2018
	(in thousands of $)
Time charter revenues	35,601	47,968
Time charter revenues - collaborative arrangement	9,622	30,681
Voyage, charter-hire and commission expenses	(5,912)	(3,160)
Voyage, charter-hire and commission expenses - collaborative arrangement	(9,825)	(39,836)
Net income from the Cool Pool	29,486	35,653

On July 8, 2019, following the withdrawal of GasLog Ltd.’s vessels we ceased applying the collaborative accounting guidance to the Cool Pool. This had no impact on how we account for revenues and expenses that were attributable to our own vessels, however, net revenue and expenses relating to the other pool participants are now presented net within “Voyage, charter-hire and commission expenses” as opposed to being presented gross within “Time charter revenues - collaborative arrangement” and “Voyage, charter-hire and commission expenses - collaborative arrangement” under the previously adopted collaborative arrangement accounting principles.

Trade accounts receivable includes amounts due from the Cool Pool, amounting to $1.3 million as of December 31, 2019 (December 31, 2018: $10.2 million) as well as deferred revenue of $1.2 million as at December 31, 2019 (December 31, 2018: nil).

8.	OTHER OPERATING AND NON-OPERATING INCOME

For the year ended December 31, 2019, Other operating income consisted of $1.1 million of proceeds relating to a successful insurance claim.

For the year ended December 31, 2018, Other non-operating income of $5.0 million related to consideration paid by certain legal entities of Goldman Sachs (“GS”) to Hygo for Hygo’s assistance to GS in the syndication of an unsecured loan to CELSE and the right (but not the obligation) until December 12, 2018 for GS to act as a sole leading book running underwriter and/or sole initial purchaser in the case of any issuance of debt or equity

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Notes to Consolidated Financial Statements(Continued)

securities offering and as exclusive structuring advisor and sole arranger in the case of any bank loan for the construction and/or maintenance of an infrastructure or energy and power project in Brazil. As of December 31, 2018, all performance obligations relating to this agreement with GS were satisfied and the consideration associated with the agreement was recognized.

9.	OTHER FINANCIAL ITEMS, NET

	2019	2018
	(in thousands of $)
Deferred consideration⁽ⁱ⁾	1,553	3,346
Foreign exchange gain / (loss) and finance charges	680	(207)
Debt forgiveness⁽ⁱⁱ⁾	—	2,087
Amortization of debt guarantee⁽ⁱⁱⁱ⁾	(574)	19
	1,659	5,245

(i)	Deferred consideration relates to the revaluation of the consideration payable to the project developer as part of the step-acquisition on the investment in CELSEPAR in 2016. The impact is inclusive of the unwinding of the discount with the total paid in Q1 2020.

(ii)

As a result of the need to terminate a Memorandum of Understanding between the Company and Genpower, on July 19, 2018 the Company entered into a debt forgiveness agreement and accordingly the loan receivable associated with the initial agreement between the Company and Genpower dated September 2015, was written off in 2018.

(iii)

In December 2019, the Company completed the refinancing of the Golar Penguin. This accelerated the amortization of the cost of the counter guarantee provided to Golar LNG that had been recognised at fair value upon formation of Hygo ($0.6 million).

10.	INCOME TAXES

The components of income tax expense are as follows:

	2019	2018
	(in thousands of $)
Current tax expense:
Brazil	515	110
Other	241	—
Total current tax expense	756	110
Deferred tax expense	3,396	—
Total tax expense	4,152	110

The income taxes for the years ended December 31, 2019 and 2018 differed from the amount computed by applying the Bermuda statutory income tax rate of 0% as follows:

	2019	2018
	(in thousands of $)
Effect of taxable income in various countries	756	110
Effect of movement in deferred tax balance	3,396	—
Total tax expense	4,152	110

Bermuda

The Minister of Finance in Bermuda has granted the Company a tax exempt status until March 31, 2035, under which no income taxes or other taxes (other than duty on goods imported into Bermuda and payroll tax in respect of any Bermuda-resident employees) are payable by the Company in Bermuda. If the Minister of Finance in Bermuda does not grant a new exemption or extension of the current tax exemption, and if the Bermudian Parliament passes legislation imposing taxes on exempted companies, the Company may be subject to taxation in Bermuda after March 31, 2035.

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Notes to Consolidated Financial Statements(Continued)

Brazil

The current tax expense of $515 thousand (2018: $0.1 million) relates to taxation levied on our Brazilian subsidiaries.

As of December 31, 2019, the Company recognised a deferred tax liability of $3.5 million with respect to unrealized gains on financial instruments in Brazil. This item represents the only temporary difference on the Company’s Consolidated Balance Sheet as at December 31, 2019.

Other jurisdictions

The current tax expenses of $241 thousand related to United States taxation levied on our two LNG carrier vessel owning entities on income earned for transportation that began in the United States. No tax has been levied on income derived from our subsidiaries registered in the Marshall Islands. There are no potential deferred tax liabilities arising on undistributed earnings within the Group as there are no current distributable reserves in the Group.

11.	LOSS PER SHARE

Basic loss per share (“EPS”) is calculated with reference to the weighted average number of common shares outstanding during the year.

The unaudited pro forma basic and diluted loss per share for the year ended December 31, 2019 gives effect to the redemption of the preference shares as well as a 2.13-for-1 share split, to be effected after the effective date of the registration statement and prior to the consummation of this offering.

The components of the numerator for the calculation of basic and diluted EPS are as follows:

	2019 Pro forma (unaudited)	2019	2018
	(in thousands of $)
Numerator — net loss available to common stockholders	(24,352)	(24,352)	(20,243)
Pro forma effect of redemption of preferred shares	11,875	—	—
Numerator — net loss available to common stockholders	(12,477)	(24,352)	(20,243)

The components of the denominator for the calculation of the basic and diluted EPS are as follows:

	2019 Pro forma (unaudited)	2019	2018
	(in thousands of $, except per share data)
Basic and diluted loss per share:
Weighted average number of common shares outstanding⁽¹⁾	100,000,000	46,950,154	46,950,154

(1)	Includes the common shares included in the mezzanine classification

Loss per share are as follows:

	2019 Pro forma (unaudited)	2019	2018
	(in thousands of $, except per share data))
Basic and diluted ($)	(0.12)	(0.52)	(0.43)

The effects of the convertible ordinary and preference shares have been excluded from the calculation of diluted EPS for each of the years ended December 31, 2019 and 2018 as these are contingent on the Initial Public Offering (“IPO”) event and therefore the effects were anti-dilutive.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

12.	RESTRICTED CASH AND SHORT-TERM DEPOSITS

Our restricted cash and short-term deposits balances are as follows:

	Notes	2019	2018
	(in thousands of $)
Restricted cash and short-term deposits held by lessor VIEs⁽ⁱ⁾	5	11,072	—
Restricted cash relating to the Golar Penguin and Golar Celsius⁽ⁱⁱ⁾		6,039	22,412
Restricted cash relating to LC⁽ⁱⁱⁱ⁾		5,750	—
Restricted cash relating to bid bonds^(iv)		—	2,250
Restricted cash relating to Brazil office lease		41	43
Total restricted cash		22,902	24,705
Less: Amounts included in current restricted cash		22,861	24,662
Non-current restricted cash		41	43

(i)	These are amounts held by our lessor VIE entities that we are required to consolidate under U.S. GAAP into our financial statements as VIEs (see note 5).

(ii)

Restricted cash relating to the Golar Penguin and Golar Celsius refers to cash deposits required in connection with the financial covenant compliance related to the financing of these vessels. As at December 31, 2019 the restricted cash balance solely relates to the Golar Celsius due to the re-financing of the Golar Penguin (see note 21).

(iii)

This amount relates to an irrevocable stand-by letter of credit (“LC”) required in connection with the financing of the CELSE project.

(iv)	These amounts relate to commercial bid bonds in the amounts of $1.5 million and $0.8 million which expired in February 2019 and May 2019, respectively.

Restricted cash does not include $3.9 million and $0.9 million which is the minimum cash position that we are required to maintain as part of the financial covenants for our sale and leaseback financing. These are included in “cash and cash equivalents” in the Consolidated Balance Sheet as at December 31, 2019 and 2018 respectively.

13.	TRADE ACCOUNTS RECEIVABLE

As of December 31, 2019 and 2018, there was no provision for doubtful accounts.

14.	RELATED PARTY TRANSACTIONS

a) Transactions with CELSE:

Income (expenses): The transactions with CELSE for the years ended December 31, 2019 and 2018 consisted of the following:

Receivables (payables): The balances with CELSE as of December 31, 2019 and 2018 consisted of the following:

	2019	2018
	(in thousands of $)
Deferred revenue⁽ⁱⁱ⁾	(37,568)	—
Trade receivable⁽ⁱⁱ⁾	28,601	—
Total	(8,967)	—

(i)

On February 1, 2017 Golar Power Latam Participações e Comércio Ltda., a wholly-owned subsidiary of Hygo Energy Transition Ltd., entered into a management services agreement with CELSE to provide logistics and operation assistance regarding the development of the regasification terminal for the CELSE project in Sergipe.

(ii)	As at December 31, 2019, balances with CELSE include $32.6 million of pre-commissioning revenue under Golar Nanook’s charter agreement with CELSE as well as $5.0 million of pre-commissioning revenue under its operation and service agreement with CELSE.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

b) Transactions with Golar LNG and subsidiaries:

Income (expenses): The transactions with Golar LNG for the years ended December 31, 2019 and 2018 consisted of the following:

	2019	2018
	(in thousands of $)
Management and administrative services expense⁽ⁱ⁾	(5,904)	(6,180)
Ship management fees expense⁽ⁱⁱ⁾	(1,210)	(1,400)
Debt guarantee fee expense⁽ⁱⁱⁱ⁾	(693)	(725)
Other^(iv)	(2)	—
Share options expense recharge^(v)	—	247
Total	(7,809)	(8,058)

Receivables: The balances with Golar LNG and subsidiaries as of December 31, 2019 and 2018 consisted of the following:

	2019	2018
	(in thousands of $)
Trading balances due from Golar LNG and subsidiaries^(vi)	6,829	6,389
Total	6,829	6,389

(i)

Management and administrative services agreement - Hygo Energy Transition Ltd. entered into a management and administrative services agreement with Golar Management Ltd (“Golar Management”), a wholly-owned subsidiary of Golar LNG, pursuant to which Golar Management will provide to Hygo certain management and administrative services. The services provided by Golar Management are charged at cost plus a management fee equal to 5% of Golar Management’s costs and expenses incurred in connection with providing these services. Hygo may terminate the agreement by providing 6 months written notice.

(ii)

Ship management fees - Golar LNG and certain of its affiliates charge ship management fees to Hygo for the provision of technical and commercial management of Hygo’s vessels. Each of Hygo’s vessels is subject to management agreements pursuant to which certain commercial and technical management services are provided by Golar Management. Hygo may terminate these agreements by providing 30 days written notice.

(iii)

Debt guarantee fee expense - Upon formation, Golar LNG provided financial guarantees in relation to the debt financing of Golar Celsius and Golar Penguin. Hygo entered into agreements to compensate Golar LNG in relation to certain debt guarantees This compensation amounted to $0.7 million and $0.7 million for the years ended December 31, 2019 and 2018, respectively. The remaining liability relating to the counter guarantee is recorded in “Other current liabilities” and “Other non-current liabilities” in the Consolidated Balance Sheet.

(iv)	Other - In December 2019, we borrowed $7.0 million from Golar LNG at interest of LIBOR plus 5.0%. The loan was fully repaid, including USD two thousand of interest expense, in December 2019.

(v)	Share options expense - This relates to a recharge of share option expense from Golar LNG in relation to share options in Golar LNG granted to certain of Hygo’s directors, officers and employees.

(vi)

Trading balances - Receivables and payables with Golar LNG and its subsidiaries are comprised primarily of unpaid management fees, advisory and administrative services and may include working capital adjustments in connection with the initial formation of the joint venture and transaction with Stonepeak. In addition, certain receivables and payables arise when Golar LNG pays an invoice on our behalf. Receivables and payables are generally settled quarterly in arrears. Trading balances owing to or due from Hygo and its subsidiaries are unsecured, interest-free and intended to be settled in the ordinary course of business.

Other transactions:

Omnibus Agreement

In connection with our JV partnership in 2016, we entered into an Omnibus Agreement with Golar LNG and Golar LNG Partners LP and its subsidiaries (“Partnership Group”), governing, amongst other things, the business opportunities that Hygo will not pursue during the term of the Omnibus Agreement as well as the procedures whereby such business opportunities are to be offered to the Partnership Group. This includes the Partnership Group’s right of first offer to any of Hygo’s vessels which is employed under a charter agreement exceeding five years at its fair market value.

Golar Partners, an affiliate of Golar LNG, is an owner and operator of FSRUs and LNG carrier under long-term charters. As at December 31, 2019 and 2018 Golar LNG’s ownership in Golar Partners was 32.0% and 30.0%, respectively.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

Guarantees and other:

Debt guarantees - These debt guarantees were previously issued by Golar LNG to third party banks in respect of certain secured debt facilities relating to Hygo and its subsidiaries. In connection with the formation of Hygo, the Company entered into a counter guarantee with Golar LNG to indemnify Golar LNG in the event they are required to pay out any monies due under the debt guarantee. The liability for this counter guarantee is recorded in “Other current liabilities” and “Other non-current liabilities” and is being amortized over the remaining term of the respective debt facilities associated with Golar Penguin and Golar Celsius. In December 2019, the Golar Penguin was refinanced and simultaneously the guarantee terminated. Subsequently, a debt guarantee was provided on the Golar Penguin in connection with its new financing arrangement.

As described in (iii) above we pay Golar LNG a guarantee fee in relation to the provision of the guarantees. The debt facilities are secured against specific vessels.

Shipyard guarantee - Previously Golar LNG had provided a guarantee to cover the remaining milestone payments due to the shipyard for the Golar Nanook. In connection with the formation of Hygo in 2016, we entered into a counter guarantee with Golar LNG to indemnify Golar LNG in the event they are required to pay out any monies due under the shipyard guarantee. The liability for this counter guarantee was recorded in “Other non-current liabilities” and as at December 31, 2018 is fully amortised as the vessel was delivered from the yard in September 2018.

Hygo Purchase Option - Under the shareholders’ agreement (as agreed between the shareholders of the Company at formation), we had the right for 18 months from July 6, 2016 to purchase another two vessels from Golar LNG at their respective fair values. In connection with any such transaction, Ordinary Shares would have been issued based on the fair market value of the vessel(s) at the time of their respective contribution. The purchase option expired in January 2019.

d)	Golar LNG and Stonepeak contributions - under the Hygo shareholders’ agreement, Golar LNG and Stonepeak have agreed to contribute additional funding as may be required by Hygo, subject to the approval of its board of directors.

c) Transaction with other related parties:

Expenses: The transactions with other related parties for the years ended December 31, 2019 and 2018 consisted of the following:

	2019	2018
	(in thousands of $)
Magni Partners⁽ⁱ⁾	(1,416)	(888)
Total	(1,416)	(888)

Receivables (Payables): The balances with other related parties as of December 31, 2019 and 2018 consisted of the following:

	2019	2018
	(in thousands of $)
CELBA⁽ⁱⁱ⁾	407	93
Golar Power Brasil 2 Participações S.A. (“GPB2”)⁽ⁱⁱ⁾	32	998
Magni Partners⁽ⁱ⁾	(141)	(146)
Total	298	945

(i)

Magni Partners - Tor Olav Trøim, a Director of Hygo Energy Transition Ltd., is the founder of, and partner in, Magni Partners Limited (“Magni Partners”), a privately held UK company, as well as Magni Partners Bermuda Limited (“Magni Bermuda”), a Bermudan domiciled company. In his role, he is the ultimate beneficial owner of these two companies. Pursuant to management agreements between Magni Partners, Magni Bermuda and Hygo, Hygo was recharged $1.4 million and $0.9 million for salary and consulting expenses for all individuals working for Magni Partners and Magni Bermuda to the Company for the period ending December 31, 2019 and 2018 respectively. Of the aggregate amount re-charged, $0.1 million and $0.1 million remains to be settled as at December 31, 2019 and 2018 respectively. This amount is included in “Trade accounts payables” in the Consolidated Balance Sheet.

(ii)	As at December 31, 2019 and 2018, $0.4 million and $1.0 million respectively, in receivables from other related parties are short-term in nature.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

15.	OTHER CURRENT ASSETS

	2019	2018
	(in thousands of $)
Other receivables⁽ⁱ⁾	410	6,286
Inventories	425	2,334
Prepayments⁽ⁱⁱ⁾	2,747	343
Total	3,582	8,963

(i)	For the years ended December 31, 2019 and 2018, “Other receivables” includes $0.4 million and $6.2 million respectively, held by the lessor VIE that we are required to consolidate under U.S. GAAP into our financial statements as a VIE (see note 5).

(ii)

For the year ended December 31, 2019, “Prepayments” includes $2.2 million of pre-paid withholding tax in relation to Golar Nanook’s bareboat charter agreement and operation and services agreement. These amounts will be recovered from CELSE when payments under the charter agreement begin in 2020 (see note 14).

16.	INVESTMENTS IN AFFILIATES

At December 31, 2019 and 2018, we have the following participation in investments that are recorded using the equity method:

	2019	2018
CELSEPAR	50%	50%
CELBA	50%	50%
GPB2⁽¹⁾	50%	50%
Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”)	37.5%	37.5%
Centrais Termelétricas São Marcos S.A. (“São Marcos”)⁽²⁾	50%	—

(1)	On July 19, 2018, 50% of the common shares of GPB2 were sold to an unrelated third party. The Company recognised a net gain on loss of control of $72 thousand in the Consolidated Statement of Income (loss) for the year ended December 31, 2018.

GPB2 owns 75% of the common shares of CEBARRA. As such, the Company has a 37.5% in the CEBARRA project.

(2)	On March 14, 2019 the Company acquired 3,000,500 common shares in São Marcos at a subscription price of $BRL 1 per share.

The carrying amounts of our investments in our equity method investments as at December 31, 2019 and 2018 are as follows:

	2019	2018
	(in thousands of $)
CELSEPAR	310,368	265,072
CELBA	165	—
GPB2⁽³⁾	—	—
São Marcos	572	—
Equity in net assets of affiliates	311,105	265,072

(3)

As at December 31, 2019 and 2018 the Company has losses from the equity investment in GPB2 which exceed its investment. As such, we have not recognized further losses reducing the carrying value of this investment below zero as the Company has not incurred any obligation to make payments on behalf of the affiliate.

The components of equity in net assets of non-consolidated affiliates are as follows:

			(in thousands of $)
Equity in net assets of affiliates as at January 1, 2018			216,063
Capital contributions			82,386
Equity in net loss of affiliates			(5,748)
Capitalized interest			2,484
Foreign currency translation adjustment			(30,113)
Equity in net assets of affiliates as at December 31, 2018			265,072

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

			(in thousands of $)

Equity in net assets of affiliates as at January 1, 2019			265,072
Capital contributions			48,652
Equity in net loss of affiliates			(2,510)
Capitalised interest			4,731
Foreign currency translation adjustment			(4,840)
Equity in net assets of affiliates as at December 31, 2019			311,105

The components of equity loss from affiliates are as follows:

	2019	2018
	(in thousands of $)
CELSEPAR	(1,483)	(5,465)
CELBA	(853)	(283)
São Marcos	(174)	—
Equity in net loss in affiliates	(2,510)	(5,748)

The Company has capitalized interest of $4.7 million and $2.5 million for the years ended December 31, 2019 and 2018, respectively, on its investment in CELSEPAR as the equity method investment is deemed a qualifying asset from the date of our Final Investment Decision until the commencement of its planned principal operation.

CELSEPAR

On incorporation of Hygo Energy Transition Ltd., the Company through its wholly owned subsidiary, LNG Power Limited (“LNG Power”) and consequently 50% equity interest in Golar Brasil, held a 25% indirect investment in project company CELSE. On October 14, 2016, in a step-acquisition, the Company acquired the remaining 50% equity in Golar Brasil, resulting in a 50% investment in project company CELSE. The power project will deliver power to 26 committed off-takers for 25 years from 2020 in accordance with previously executed Power Purchase Agreement (“PPA”) contracts awarded by the Brazilian Government in 2015.

In March 2018, CELSEPAR was incorporated as a holding company of CELSE and the shares of CELSE were transferred to CELSEPAR. As CELSEPAR is jointly owned and operated with Ebrasil, we have adopted the equity method of accounting for our 50% investment.

On April 5, 2018 CELSE priced and closed financing of $1.4 billion for the power plant and LNG receiving terminal. The initial tranche of funding was disbursed on April 19, 2018. The financing comprises:

•	Brazilian Reais - BRL 3,370 million 9.85% Senior Secured Notes due 2032 (net proceeds of $874 million);

•	$288 million loan from Inter-American Development Bank due 2032 which comprises three tranches; and

•	$200 million loan from International Finance Company due 2032.

CELSE also secured a $120 million contingent equity facility from GE Capital to be drawn down in the event of cost overruns.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

Summarized consolidated financial information of CELSEPAR are shown on a 100% basis as follows:

	2019	2018
	(in thousands of $)
Balance Sheet
Current assets	184,681	160,960
Non-current assets	1,364,619	1,027,880
Current liabilities	128,286	26,849
Non-current liabilities	1,002,331	825,332

Statement of Operations
Net loss	(3,039)	(7,563)

CELBA

On March 14, 2017, the Company through its wholly owned subsidiary LNG Power, and its wholly owned subsidiary Golar Brasil, entered into an agreement with Evolution Power Partners S.A. to establish a jointly owned company CELBA. CELBA’s purpose is the production of electricity and development of an integrated LNG import terminal in the city of Barcarena in the State of Para.

The Company acquired 5,000 common shares in CELBA at a subscription price of $BRL 1 per share, representing a 50% interest in the voting rights of CELBA.

On January 17, 2018 Golar Power Latam Participações e Comércio Ltda, a wholly owned subsidiary of LNG Power, acquired 5,000 common shares in CELBA at nominal value from Golar Brasil.

Following the sale of the 50% interest, we have adopted the equity method of accounting for our 50% investment in CELBA , as we consider we have joint control. There was no gain or loss on the sale of the 50% interest.

GPB2

GPB2 was formed as a wholly owned subsidiary of the Company through LNG Power, and its wholly owned subsidiary Golar Brasil.

On July 19, 2018, Golar Brasil, a wholly owned subsidiary of LNG Power, sold 750 common shares in GPB2 at a subscription price of $BRL 1 per share, representing a 50% interest in the voting rights of GPB2 to an unrelated third party, Evolution Power Partners S.A (“Evolution”).

We have adopted the equity method of accounting for our 50% investment in GPB2 , as we consider we have joint control.

GPB2 holds a 75% interest in project company, CEBARRA, together with Ebrasil Energia Ltda. (25% interest). CEBARRA’s purpose is the generation and marketing of electricity, the implementation of thermoelectrical generating units from combustible natural gas and the import, export and vaporization of liquified natural gas and natural gas and holds the Sergipe power plant expansion rights.

Since July 19, 2018 with the sale of 50% of the interest in GPB2, we have adopted the equity method of accounting for our 37.5% investment in CEBARRA, as we do not exercise control.

SÃO MARCOS

On March 14, 2019, the Company through its wholly owned subsidiary LNG Power, and its wholly owned subsidiary Golar Power Maranhão Participações S.A., entered into an agreement with Eneva S.A. to establish a jointly owned company São Marcos. São Marcos’ purpose is the development of an integrated LNG import terminal as well as power plant in the city of São Luis in the State of Maranhão, Brazil.

The Company acquired 3,000,500 common shares in São Marcos at a subscription price of $BRL 1 per share, representing a 50% interest in the voting rights of São Marcos.

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

We have adopted the equity method of accounting for our 50% investment in São Marcos, as we consider we have joint control.

17.	ASSETS UNDER DEVELOPMENT

	2019	2018
	(in thousands of $)
Net book value, as of January 1	302,410	102,526
Installment payments	—	182,511
Interest costs capitalized	14,006	8,522
Other costs capitalized⁽ⁱ⁾	11,338	8,851
Net book value, as of December 31	327,754	302,410

The Golar Nanook is located offshore Sergipe, Brazil and is expected to become operational in Q1 2020.

(i)	Other capitalized costs include voyage charter, site supervision and other miscellaneous construction costs.

18.	VESSELS AND EQUIPMENT, NET

	2019	2018
	(in thousands of $)
Cost
As of Jan 1	388,788	387,373
Additions	7,462	4,394
Write-off of historical drydock costs	(1,944)	(2,979)
As of December 31	394,306	388,788

Depreciation and amortization
As of Jan 1	(24,895)	(16,694)
Charge for the year	(11,212)	(11,180)
Write-off of historical drydock costs	1,944	2,979
As of December 31	(34,163)	(24,895)
Net book value as of December 31	360,143	363,893

Capitalised drydocking costs of $4.1 million and $4.5 million are included in the vessel cost for December 31, 2019 and 2018, respectively. Accumulated amortization of those costs at December 31, 2019 and 2018 was $2.6 million and $1.7 million, respectively.

As at December 31, 2019 and 2018, vessels with a net book value of $174.3 million and $363.9 million, respectively, were pledged as security for certain debt facilities (see note 21).

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

19.	IMPAIRMENT OF VESSELS

Vessels

In assessing indicators of impairment, management compare the market value of our vessels with the carrying value. The market values are based on third party broker reports and reflect an amount that a willing buyer and seller would transact on at an arms-length basis. The following table presents the vessels where their market value was less than their carrying value as at December 31, 2019. However, when we tested for recoverability based on a “held and used” approach, the estimated future undiscounted cash flows of these vessels were significantly greater than their respective carrying values, and therefore, no impairment was recognized.

Vessel	2019 Market value⁽¹⁾	2019 Carrying value	Deficit
	(in thousands of $)
Golar Celsius	171,000	174,000	(3,000)
Golar Penguin	176,000	184,000	(8,000)

(1)

Market values are determined using reference to average broker values provided by independent brokers. Broker value is considered an estimate of the market value for the purpose of determining whether an impairment trigger exists. Broker value is commonly used and accepted by our lenders in relation to determining compliance with relevant covenants in applicable credit facilities for the purpose of assessing security quality.

Since vessel value can be volatile, our estimate of market value may not be indicative of either the current or future price we could obtain if we sold any of our vessels. In addition, the determination of estimated market value may involve considerable judgment, given the illiquidity of the second-hand markets for these types of vessel.

20.	OTHER NON-CURRENT ASSETS

	2019	2018
	(in thousands of $)
Other	28,905	23,682
Right of use lease asset	438	—
Total	29,343	23,682

As at December 31, 2019, $27.6 million (2018: $22.3 million) of “Other” relates to payments made relating to long lead items ordered in preparation for the expected conversion of one of our vessels. We do not depreciate these items as they are not yet ready for their intended use. $1.3 million (2018: $1.3 million) relates to the prepayment for the purchase of land from Companhia de Desenvolvimento Econômico de Sergipe, a Brazilian state government controlled company.

21.

DEBT

	2019	2018
	(in thousands of $)
Total debt, net of deferred financing costs	464,742	393,376
Less: current portion of long-term debt and short-term debt, net of deferred financing costs	(127,056)	(21,120)
Long-term debt, net of deferred financing costs	337,686	372,256

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Hygo Energy Transition Ltd.

Notes to Consolidated Financial Statements(Continued)

The outstanding debt as of December 31, 2019 is repayable as follows:

Year ending December 31	Hygo debt	Debt held in VIE⁽¹⁾	Total debt
	(in thousands of $)
2020	15,392	113,400	128,792
2021	23,356	—	23,356
2022	26,333	—	26,333
2023	33,978	—	33,978
2024	31,033	—	31,033
2025 and thereafter	8,554	217,178	225,732
Total	138,646	330,578	469,224
Deferred financing costs	(1,188)	(3,294)	(4,482)
Total	137,458	327,284	464,742

(1)	These amounts relate to certain lessor entities (for which legal ownership resides with financial institutions) that we are required to consolidate under U.S. GAAP into our financial statements as variable interest entities (see note 5).

At December 31, 2019 and 2018 our debt was as follows:

	2019	2018	Maturity date
	(in thousands of $)
Golar Penguin and Golar Celsius facility:
- Golar Celsius facility	64,212	74,914	2024/2026⁽¹⁾
- Golar Penguin facility⁽²⁾	—	85,922	NA
Debenture Loan	74,434	—	2024
Subtotal (excluding lessor VIE loan)	138,646	160,836
CCBFL VIE loan:
-Golar Nanook facility	217,178	235,878	2030
COSCO VIE loan:
- Golar Penguin facility	113,400	—	2020
Total debt (gross)	469,224	396,714
Deferred finance charges	(4,482)	(3,338)
Total debt	464,742	393,376

(1)

The commercial loan tranche matures at the earlier of the two dates, with the remaining balance maturing at the latter date. However, in the event that the commercial tranche is not refinanced within five years, the lenders have the option to demand repayment. In October 2018, the maturity of the commercial tranche, and consequently the option to the lenders, was extended by five years, to 2024.

(2)	In December 2019, the Golar Penguin was re-financed prior to maturity.

Golar Celsius Facility

This facility is guaranteed by Golar LNG and the Company pays a quarterly guarantee fee to the joint venture partner. The facility bears interest at LIBOR plus a margin. The facility is divided into three tranches with the following general terms:

Tranche	Proportion of facility	Term of loan from date of drawdown	Repayment terms
K-Sure	40%	12 years	Six-monthly installments
KEXIM	40%	12 years	Six-monthly installments
Commercial	20%	5 years	Six-monthly installments, unpaid balance to be refinanced after 5 years (extended by 5 years in October 2018)

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Notes to Consolidated Financial Statements(Continued)

The facility bears interest at LIBOR plus a margin of 2.10% for the K-Sure tranche of the facility and 2.75% for both the KEXIM and commercial tranche of the loan.

The K-Sure tranche is funded by a consortium of lenders of which 95% is guaranteed by a Korean Trade Insurance Corporation (or K-Sure) policy; the KEXIM tranche is funded by the Export Import Bank of Korea (or KEXIM). Repayments under the K-Sure and KEXIM tranches are due semi-annually with a 12 year repayment profile. The commercial tranche is funded by a syndicate of banks and is for a term of five years from date of drawdown with a final balloon payment depending on drawdown dates on each respective vessel. In the event the commercial tranche is not refinanced prior to the end of the five year, both K-Sure and KEXIM have an option to demand repayment of the balances outstanding under their respective tranches. In October 2018, the term of the commercial tranche, and consequently the option to K-Sure and KEXIM, was extended by 5 years.

In December 2019, the Company completed the refinancing of the Golar Penguin, which extinguished the borrowing facility associated with the vessel.

Debenture Loan

In September 2019, Golar Power Brasil, a wholly owned subsidiary of LNG Power, issued a simple, non-convertible Brazilian debenture in the amount of BRL 300 million. The debenture has a term of 5 years and bears interest at certificado de deposito interbancário plus a margin of 2.65%, with repayment commencing in September 2020 and due semi-annually thereafter. The Brazilian debentures are fully and unconditionally guaranteed by various factors, including 100% of the shares issued by Golar Brazil owned by our wholly owned subsidiary, LNG Power Ltd.

Lessor VIE debt

The following loans relates to our lessor VIE entities, including CCBFL and COSCO, that we consolidate as VIEs. Although we have no control over the funding arrangements of these entities, we consider ourselves the primary beneficiary of these VIEs and we are therefore required to consolidate the loan facilities into our financial statements

CCBFL - Golar Nanook facility

In September 2018, the SPV, Compass Shipping 23 Corporation Limited, the owner of the Golar Nanook, entered into a long-term loan facility for $277.0 million. The loan facility is denominated in USD, has a loan term of 12 years, bears interest at LIBOR plus a margin of 3.5% and is repayable in quarterly installments with a balloon payment on maturity. As the loan facility in nature is repayable at the end of maturity, the Company has classified the debt as non-current in the Consolidated Balance Sheet as at December 31, 2019. See note 5 for additional information.

COSCO - Golar Penguin facility

In December 2019, the SPV, Oriental Fleet LNG 02 Limited, the owner of the Golar Penguin, entered into a short-term financing agreement for $113.4 million. The loan facility, denominated in USD, bears interest at LIBOR plus a margin of 1.5%. The debt is classified as current in the Consolidated Balance Sheet as at December 31, 2019 as the facility has no repayment profile and is repayable on demand by the lender. See note 5 for additional information.

Debt restrictions

One of our debt facilities is collateralized by a ship mortgage. The existing financing agreement imposes operating and financing restrictions which may significantly limit or prohibit, among other things, our ability to incur additional indebtedness, create liens, sell capital shares of subsidiaries, make certain investments, engage in mergers and acquisitions, purchase and sell vessels, enter into time or consecutive voyage charters or pay dividends without the consent of the lenders. In addition, lenders may accelerate the maturity of indebtedness under financing agreements and foreclose upon the collateral securing the indebtedness upon the occurrence of

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Notes to Consolidated Financial Statements(Continued)

certain events of default, including a failure to comply with any of the covenants contained in the financing agreements. Many of our debt agreements contain certain covenants, which require compliance with certain financial ratios. Such ratios include current assets: current liabilities and equity ratio covenants.

As of December 31, 2019, we were in compliance with all our covenants under various loan agreements.

22.	ACCRUED EXPENSES

	2019	2018
	(in thousands of $)
Preferred dividends (see note 25)	33,009	21,134
Other	5,780	408
Accrued interest expense	3,409	1,901
Vessel operating and drydocking expenses	3,855	2,491
Total	46,053	25,934

As at December 31, 2019, $5.2 million (2018: nil) of “Other” relates to accrued expenses relating to long lead items ordered in preparation for the expected conversion of one of our vessels

Vessel operating and drydocking expense related accruals are comprised of vessel operating expenses including direct vessel operating costs associated with operating a vessel, such as crew wages, vessel supplies, routine repairs, maintenance, drydocking, lubricating oils, insurances and management fees for the provision of commercial and technical management services.

23.	OTHER CURRENT LIABILITIES

	2019	2018
	(in thousands of $)
Deferred consideration⁽ⁱ⁾	10,754	—
Deferred tax⁽ⁱⁱ⁾	3,468
Deferred revenue⁽ⁱⁱⁱ⁾	38,730	—
Other^(iv)	1,200	28
Guarantees issued to Golar LNG (see note 14)	172	496
Total	54,324	524

(i)

On July 19, 2018 following the execution of the Second Amendment to the Sale and Purchase Agreement of the additional investment in CELSEPAR, the election was made to proceed with the “Option Notice”. Pursuant to the agreement, $21.6 million was paid on October 2, 2018. The final payment of $10 million and adjusted for inflation ($9.2 million discounted as at December 31, 2018) is payable upon the Commercial Operation Date, which occurred in Q1 2020 and therefore has been classified as a current liability as at December 31, 2019. The final payment amount has been discounted using a 15.4% discount rate based on Management’s analysis as at the date of the execution of the Second Amendment to the Sale and Purchase Agreement.

(ii)	Deferred tax relates to the tax expense on the unrealized gain on the forward purchase energy contracts (see note 5).

(iii)

Deferred revenue includes $32.6 million of pre-commissioning revenue on Golar Nanook’s charter agreement with CELSE as well as $5.0 million of pre-commissioning revenue under its operation and service agreement with CELSE.

(iv)	$0.2 million of “Other” corresponds to our current portion of our lessee related liability for the future lease payments associated with our office lease in Brazil.

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Notes to Consolidated Financial Statements(Continued)

24.	OTHER NON-CURRENT LIABILITIES

	2019	2018
	(in thousands of $)
Deferred consideration (see note 23)	—	9,201
Guarantees issued to Golar LNG⁽ⁱ⁾	331	1,129
Other⁽ⁱⁱ⁾	334	216
Total	665	10,546

(i)

Prior to the formation of Hygo, Genpower, the project developer of the CELSE project entered into a surety bond in the maximum amount of BRL 164.7 million as security for its obligations to construct the power plant at Sergipe. On August 25, 2015, a counter agreement was entered into pursuant to which Genpower’s contingent liability was counter guaranteed by Ebrasil and Golar LNG in the amount of 51% and 49% respectively.

On June 30, 2016 an agreement was entered into between the Company and Golar LNG, indemnifying Golar LNG of its liability and transferring the obligation to Hygo. As at December 31, 2019 and 2018, $0.1 million and $0.2 million, respectively, of “Other” relates to the fair value of the surety bond indemnity agreement.

(ii)	$0.3 million of “Other” corresponds to our non-current portion of our lessee related liability for the future lease payments associated with our office lease in Brazil.

25.

EQUITY

In July 2016, the Company closed a subscription of 20 million preference shares to Stonepeak for net proceeds of $95.7 million. The preference shares have no voting rights, have priority over the dividend rights of any other class of shares and contain the following significant features:

each preference share holder has the right to, in cash, an annual fixed cumulative preferential dividend out of the profits of the Company available for distribution at a rate of 8.5% of the $5.00 par value of the share, payable semi-annually, which commenced six months after the subscription by Stonepeak of the preferred shares;

ii.	the preference shares may be redeemed at the Company’s option, any time prior to the date of an IPO at the Redemption Price¹;

iii.	in the event of an IPO, and assuming no prior redemption of the preference shares, the preference shares will be converted automatically into fully paid ordinary shares of the same par value at the Mandatory Conversion Rate² upon the date of such IPO;

iv.	in the event that an IPO has not been consummated by after the fifth anniversary date of the completion of the subscription for the preference shares:

a.	the rate of the preferential dividend will increase from 8.5% to 11.5% per annum; and

b.	at Stonepeak’s option, the preference shares will convert into fully paid ordinary shares of the same par value at the Mandatory Conversion Rate, and the Company will be required to redeem the converted preference shares within six months at the Redemption Price.

In June 2016, the Company issued 23,475,077 common shares to Stonepeak. At any time after the fifth anniversary of the completion of the subscription for the common shares, if an IPO has not occurred and if certain EBITDA requirements are met, Stonepeak has the right to convert such common shares into preference shares such that the aggregate value of all such preference shares equals the Conversion Value. The Conversion Value is equal to (i) the sum of all amounts paid by Stonepeak to acquire the common shares, increased by a compounded annual rate of 8.5%, (ii) less any distributions in cash or in kind on the common shares held by Stonepeak. Upon IPO, the conversion right of the common shares held by Stonepeak will terminate, such that none of the common shares will have such conversion right.

1	Redemption Price is defined as the Required Return Amount3 per preference share, less the aggregate amount of dividends accrued on such preference share, calculated up to the date on which such preference shares are redeemed.

2	Mandatory Conversion Rate is defined as 1.00 fully paid Ordinary Share for 1.20 Preference Shares.

Required Return Amount is defined as, if the redemption date is (i) any date prior to the 4th anniversary of the Effective Date (June 30, 2016), US $8.00, (ii) any date beginning on the 4th anniversary of the Effective Date and prior to the 5th anniversary of the Effective Date, US $9.00 and (iii) any date beginning on the 5th anniversary of the Effective Date, US $10.00.

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Notes to Consolidated Financial Statements(Continued)

On September 11, 2020, the Company changed the par value of its ordinary shares from $5.00 to $1.00 each, which has been retrospectively adjusted. The decrease in par value was recorded as a decrease in Convertible Share Capital (Mezzanine Equity) and Share Capital with a corresponding increase to Additional Paid-in Capital in Stockholders' Equity.

As at December 31, 2019 and 2018, authorized share capital is as follows:

Authorized share capital:

	2019	2018
	(in thousands of $)
23,475,077 ordinary shares of $1.00 each	23,475	23,475
23,475,077 convertible ordinary shares of $1.00 each	23,475	23,475
100,000,000 preference shares of $5.00 each	500,000	500,000

As at December 31, 2019 and 2018, issued share capital is as follows:

Issued share capital:

	2019	2018
	(in thousands of $)
23,475,077 ordinary shares of $1.00 each	23,475	23,475
23,475,077 convertible ordinary shares of $1.00 each	23,475	23,475
20,000,000 preference shares of $5.00 each, net of transaction costs	95,660	95,660

For the years ended December 31, 2019 and 2018, additional paid in capital of $10.0 million and $110.0 million respectively were contributed to the Company by joint venture partners.

For the years ended December 31, 2019 and 2018, preferred stock dividends of $11.9 million and $8.5 million respectively were declared and accrued by the Company.

For the years ended December 31, 2019 and 2018, other comprehensive income of $6.5 million and $32.4 million, respectively, relates to foreign currency translation adjustments.

26.	SHARE OPTIONS

In June 2018, our board of directors approved a Management Incentive Scheme (MIS) which granted 1,824,014 units to certain employees which entitled them to receive cash distributions on realization of value by the Shareholders from their investment in the Company from the proceeds of a liquidity event such as an IPO of the Company (the “performance condition”), provided that the proceeds from such liquidity event exceeds a target hurdle rate and the employees continue to be employed by the Company.

A waterfall calculation is used to determine the pay out with proceeds allocated to the MIS only after an internal rate of return and a return on Stonepeak’s outstanding investment in the Company as specified by the MIS is achieved. The MIS was approved by the shareholders in August 2018. The entire cost of the MIS will be funded by Stonepeak upon settlement which will be recorded as a capital contribution by the Company. The Company will not incur any cash outflow upon settlement. The grant date fair value of the MIS was determined using a Monte Carlo simulation model. The assumptions used in the Monte Carlo simulation model are described below:

•	Volatility factor - The volatility factor represents the extent to which the market price of a share of the Company’s ordinary shares is expected to fluctuate between the grant date and the end of the performance period.

•	Dividend yield - The dividend yield on the Company’s ordinary shares was assumed to be zero since the Company does not anticipate paying dividends within the requisite service period of the MIS.

•	Risk-free interest rate - The risk-free interest rate is based upon the yield of 2.53% with a 3 year term.

•	Expected term - The expected term represents the period of time that the MIS will be outstanding, which is the grant date to the end of the performance condition.

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Notes to Consolidated Financial Statements(Continued)

The grant date fair value of each MIS as determined by the Monte Carlo simulation model was $16.4, which was based on the following assumptions:

Number of simulations			50,000
Ordinary share price			$12.00
Volatility factor			30.5%
Dividend yield			—
Risk-free interest rate			2.53%
Expected term in year			3

The following table presents the MIS activity:

	Units	Weighted average grant date fair value per unit
Awards at August 31, 2018	1,824,014	$16.40
Granted	—
Forfeited	—
Awards at December 31, 2019	1,824,014	$16.40

We account for the MIS grants to employees that are paid out in cash upon vesting, throughout the requisite service period (the requisite service period is determined on the basis of the expected date of the liquidity event), by revaluing the MIS units outstanding at the end of each reporting period and recording a charge to the Consolidated Statement of Income (Loss) if it is probable that the performance condition will be met. No charge has been recognized in the Consolidated Statement of Income (Loss) for the years ended December 31, 2019 and 2018, respectively, as the occurrence of the liquidity event which is related to an IPO and related target hurdle rate is not considered probable until the event has occurred.

27.	FINANCIAL INSTRUMENTS

Foreign currency risk

Our two vessels’ gross earnings are receivable in U.S. dollars. The majority of our transactions, assets and liabilities are denominated in U.S. dollars, our functional currency. However, we incur expenditures in other currencies primarily from our Brazilian subsidiaries, most significantly, the Company’s investment in equity method investee, CELSEPAR. There is a risk that currency fluctuations will have a negative effect on the value of our cash flows.

Interest rate risk

Debt that we incur under our credit facilities bears interest at variable rates and exposes us to interest rate risk. Interest is calculated under the terms of each facility based on one of the index rates available to us plus an applicable margin that varies based on certain factors. We have not entered into any derivative arrangement to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Commodity price risk

A derivative asset, representing the fair value of the gain on our forward contract was recognised in December 31, 2019. There is a risk that commodity price fluctuations will have a negative effect on the value of our cash flows.

Fair values of financial instruments

We recognize our fair value estimates using a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on reliability of inputs used to determine fair value as follows:

Level 1: Quoted market prices in active markets for identical assets and liabilities;

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Notes to Consolidated Financial Statements(Continued)

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data; and

Level 3: Unobservable inputs that are not corroborated by market data.

There have been no transfers between different levels in the fair value hierarchy during the year.

The carrying value and fair value of our financial instruments, excluding short-term receivables and payables, at December 31, 2019 and 2018 are as follows:

	Fair value Hierarchy	2019 Carrying Value	2019 Fair Value	2018 Carrying Value	2018 Fair Value
	(in thousands of $)
Cash and cash equivalents	Level 1	49,949	49,949	25,808	25,808
Restricted cash	Level 1	22,902	22,902	24,705	24,705
Derivative asset	Level 2	10,200	10,200	—	—
Deferred consideration	Level 2	10,754	10,754	9,201	9,201
Current portion of long-term debt and short term debt⁽¹⁾⁽²⁾	Level 2	127,056	127,056	21,120	21,120
Long-term debt⁽²⁾	Level 2	337,686	337,686	372,256	372,256

(1)	The carrying amounts of our short-term debt approximate their fair values because of the near term maturity of these instruments

(2)	The amounts presented in the table, are gross of the deferred finance costs amounting to $4.5 million and $3.3 million for the years ended December 31, 2019 and 2018, respectively.

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

•	The carrying values of trade accounts receivable, trade accounts payable, accrued liabilities and working capital facilities approximate fair values because of the near term maturity of these instruments

•	The carrying value of cash and cash equivalents, which are highly liquid, is a reasonable estimate of fair value

•	The carrying value for restricted cash is considered to be equal to the estimated fair value because of their near term maturity

•

We classify our electricity forward purchase contracts as Level 2 as they are valued using observable market inputs such as energy prices in geographically appropriate markets. The impact of the credit valuation adjustment and time value of money is not significant due to the short-term nature of the contracts.

•	The estimated fair value of the deferred consideration is derived by using a discounted cashflow model. The most significant input into this valuation is the discount rate which takes into account, amongst other things, the equity and country risk.

•	The estimated fair value for the floating long-term debt are considered to approximate the carrying values since they bear variable interest rates, which are adjusted on a quarterly or six-monthly basis

Concentrations of risk

There is a concentration of credit risk with respect to cash and cash equivalents and restricted cash to the extent that substantially all of the amounts are carried with Nordea Bank of Finland PLC, Citibank, Santander, Itaú and Banco Bradesco. However, we believe this risk is remote, as they are established and reputable establishments with no prior history of default.

There is also a concentration of credit risk with respect to trade accounts receivable in relation to the amount due from CELSE as at December 31, 2019, however, we believe this risk is remote given the support provided to CELSE by their jointly owned ultimate parent undertaking who are established and have no prior history of default.

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Notes to Consolidated Financial Statements(Continued)

28.	SUBSEQUENT EVENTS

In February 2020, the Company entered into a partnership with Petrobras Distribuidora S.A. for the development of an LNG distribution business in Brazil. The intention is to introduce LNG as an alternative to the fuels currently available in Brazil’s cargo and people transportation, industrial, thermoelectric generation, commercial and residual sectors.

In March 2020, we completed the refinancing of the Golar Celsius. The financing structure funded 75% of the market value of the Golar Celsius. At funding, the vessel was simultaneously bareboat chartered by the Company at a fixed rate for a firm period of 7 years.

On March 21, 2020, the Sergipe power station received its commercial operations certificate from ANEEL (Brazilian Electricity Regulatory Agency). This allowed commercial operations to commence at the 1.5GW power station, which is now the largest thermal power station in South America and will supplement hydropower during dry seasons and help meet the growing demand for electricity in the region. The Sergipe power project, for which the Company’s has a 50% investment in through its interest in CELSEPAR, will deliver power to 26 committed off-takers for 25 years.

After the balance sheet date, we have seen significant macro-economic uncertainty as a result of the coronavirus (COVID-19) outbreak. Although the outbreak has not materially impacted our business to date, the scale and duration of this development remains uncertain and could therefore materially impact our operating results in 2020, specifically in relation to our LNG Carriers segment which is exposed to changes in the global demand for LNG.

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HYGO ENERGY TRANSITION LTD.

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

		Six months ended June 30,
(in thousands of $, except per share data)	Notes	2020	2019
Time charter revenues	4	22,787	14,425
Time charter revenues - collaborative arrangement	4	—	9,622
Total operating revenues		22,787	24,047

Vessel operating expenses	4	(6,622)	(6,531)
Voyage, charter-hire and commission expenses	4	(770)	(2,882)
Voyage, charter-hire and commission expenses - collaborative arrangement		—	(9,825)
Administrative expenses⁽¹⁾	4	(11,849)	(7,285)
Depreciation and amortization	4	(5,640)	(5,579)
Total operating expenses		(24,881)	(32,102)

Other operating income	5	3,714	—

Operating profit (loss)		1,620	(8,055)

Other non-operating (loss)/income
Loss on disposal of asset under development	12	(25,981)	—
Gain on derivative instruments	8	5,127	—
Total other non-operating loss		(20,854)	—

Financial income/(expenses)
Interest income	12	10,839	489
Interest expense		(5,669)	—
Other financial items, net		2,011	(1,144)
Net financial income/(expenses)		7,181	(655)

Losses before equity in net losses of affiliates, income taxes and non- controlling interest		(12,053)	(8,710)
Income taxes	6	(2,522)	(33)
Equity in net losses of affiliates	11	(37,276)	(778)

Net loss		(51,851)	(9,521)
Net income attributable to non-controlling interests		(3,346)	(2,806)
Preferred dividends		(5,652)	(4,250)
Net loss attributable to common stockholders		(60,849)	(16,577)
Loss per share attributable to common stockholders:
Basic and diluted loss per share ($)	7	(1.30)	(0.35)

(1)	This includes amounts arising from transactions with related parties (see note 16).

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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HYGO ENERGY TRANSITION LTD.

UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

		Six months ended June 30,
(in thousands of $)	Notes	2020	2019
Net loss		(51,851)	(9,521)

Other comprehensive loss:
Foreign exchange (loss)/gain on currency translation⁽¹⁾		(39,693)	1,184
Comprehensive loss		(91,544)	(8,337)

Comprehensive loss attributable to:

Stockholders of Hygo Energy Transition Ltd.		(94,890)	(11,143)
Non-controlling interests		3,346	2,806
Comprehensive loss		(91,544)	(8,337)

(1)	No tax impact for the periods ended June 30, 2020 and 2019.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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HYGO ENERGY TRANSITION LTD.

CONSOLIDATED BALANCE SHEETS

(in thousands of $)	Notes	June 30, 2020 Pro Forma Stockholder’s equity Unaudited⁽³⁾	June 30, 2020 Unaudited	December 31, 2019 Audited
ASSETS
Current
Cash and cash equivalents		—	74,633	49,949
Restricted cash and short-term deposits	9	—	33,062	22,861
Trade accounts receivable⁽¹⁾		—	9,108	30,479
Amounts due from related parties	16	—	7,454	9,335
Derivative Asset	8	—	5	10,200
Other current assets		—	3,089	3,582
Total current assets		—	127,351	126,406

Non-current
Restricted cash	9	—	30	41
Investments in affiliates	11	—	225,176	311,105
Net investment in leased asset	12	—	306,207	—
Assets under development	10	—	—	327,754
Vessels and equipment, net	4	—	354,645	360,143
Other non-current assets		—	29,211	29,343
Total assets		—	1,042,620	1,154,792

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current
Current portion of long-term debt and short-term debt	13	—	112,013	127,056
Trade accounts payable⁽¹⁾		—	2,255	2,583
Accrued expenses		—	48,561	46,053
Other current liabilities⁽¹⁾	14	—	11,813	54,324
Amounts due to related parties	16	—	139	2,184
Total current liabilities		—	174,781	232,200

Non-current
Long-term debt	13	—	378,885	337,686
Other non-current liabilities		—	1,909	665
Total liabilities		—	555,575	570,551

Mezzanine Equity⁽²⁾
Preferred capital 20,000,000 preferred shares of $5.00 each issued and outstanding		—	100,000	100,000
Convertible share capital 23,475,077 common shares of $1.00 each issued and outstanding		—	23,475	23,475
Total mezzanine equity		—	123,475	123,475

Stockholder’s Equity⁽²⁾
Share capital 23,475,077 common shares of $1.00 each issued and outstanding and 100,000,000 common shares of $0.47 each issued and outstanding pro forma (unaudited)		46,950	23,475	23,475
Additional paid in capital		584,696	527,324	527,324
Accumulated other comprehensive loss		(84,879)	(84,879)	(45,186)
Retained losses		(112,786)	(112,786)	(51,937)
Non-controlling interests		10,436	10,436	7,090
Total stockholder’s equity		444,417	363,570	460,766
Total liabilities, mezzanine equity and stockholders’ equity		—	1,042,620	1,154,792

(1)	These include amounts arising from transactions with related parties (see note 16).

(2)

On September 11, 2020, the Company changed the par value of its common shares from $5.00 to $1.00 each, which has been retrospectively adjusted. The decrease in par value was recorded as a decrease in Convertible Share Capital (Mezzanine Equity) and Share Capital with a corresponding increase in Additional paid-in Capital in Stockholders’ Equity.

(3)

The unaudited pro forma Stockholder's equity as at June 30, 2020 gives effect to (i) $180.0 million to be paid to Stonepeak for the redemption of the preference shares in the Recapitalization on mezzanine equity in connection with the consummation of this offering, which includes accrued and unpaid dividends. The $180.0 million to be paid to Stonepeak represents the contractual Required Return Amount for the preference shares, determined as $9.00 per share based on the redemption date, which includes the aggregate amount of approximately $41.5 million of accrued and unpaid dividends on such preference shares calculated up to the date of redemption; (ii) a subsequent 2.13-for-1 share split to be consummated after the effective date of the registration statement and prior to the consummation of the offering, which will further adjust the par value of the common shares from $1.00 to $0.46950154; and (iii) to reflect the settlement of the MIS which is accounted for as a capital contribution from Stonepeak, following the completion of the offering.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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HYGO ENERGY TRANSITION LTD.

UNAUDITED CONSOLIDATED STATEMENTS OF CASHFLOWS

	Notes	Six months ended June 30,
(in thousands of $)	Notes	2020	2019
OPERATING ACTIVITIES
Net loss		(51,851)	(9,521)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in net losses of affiliates	11	37,276	778
Net foreign exchange gain		(3,726)	(46)
Depreciation and amortization		5,648	5,579
Loss on recognition of net investment in leased vessel	12	25,981	—
Movement in credit loss allowance	12	1,899	—
Cash receipts from sales-type finance lease		3,664	—
Interest income from sales-type finance lease	12	(12,483)	—
Change in fair value of investment, net of unwind of discount		719	972
Recognition of guarantee net of amortization		(575)	(275)
Amortisation of deferred charges		917	—
Drydock expenditure		—	(336)
Change in assets and liabilities:
Trade accounts receivable		1,270	172
Inventories		424	1,060
Derivative asset		7,893	—
Prepaid expenses, accrued income and other current assets		(739)	5,601
Other non-current assets		54	(120)
Amounts due from/(to) related companies		(164)	3,066
Trade accounts payable		(328)	(1,090)
Accrued expenses		(4,695)	(593)
Deferred revenue		2,075	9,620
Other current and non-current liabilities		(1,535)	987
Net cash provided by operating activities		11,724	15,854

INVESTING ACTIVITIES
Additions to investments in affiliates	11	(14,521)	(1,425)
Additions to vessels and equipment		(673)	(460)
Additions to assets under development	10	(2,915)	(11,581)
Net cash used in investing activities		(18,109)	(13,466)

FINANCING ACTIVITIES
Proceeds from short-term and long-term debt (including related parties)	13	222,326	—
Repayments of short-term and long-term debt (including related parties)	13	(177,612)	(10,721)
Financing fees		(1,100)	—
Net cash provided by/(used in) by financing activities		43,614	(10,721)
Foreign exchange in cash		(2,355)	—
Net increase/(decrease) in cash, cash equivalents and restricted cash		34,874	(8,333)
Cash, cash equivalents and restricted cash at beginning of period		72,851	50,513
Cash, cash equivalents and restricted cash at end of period		107,725	42,180

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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Supplemental note to the consolidated statements of cash flows

The following table identifies the balance sheet line-items included in cash, cash equivalents and restricted cash presented in the consolidated statements of cash flows:

(in thousands of $)	June 30, 2020	December 31, 2019	June 30, 2019	December 31, 2018
Cash and cash equivalents	74,633	49,949	4,282	25,808
Restricted cash and short-term deposits	33,062	22,861	37,856	24,662
Restricted cash (non-current portion)	30	41	42	43
	107,725	72,851	42,180	50,513

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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HYGO ENERGY TRANSITION LTD.

UNAUDITED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands of $)	Preference Shares (Mezzanine)	Convertible Common Share Capital (Mezzanine)	Common Share Capital	Additional Paid-in Capital	Accumulated Other Comprehensive Loss	Retained Losses	Non-Controlling Interest	Total Stockholder’s Equity
Balance at December 31, 2018	100,000	23,475	23,475	517,324	(38,662)	(27,585)	1,541	476,093
Net (loss)/income	—	—	—	—	—	(12,327)	2,806	(9,521)
Dividends⁽¹⁾	—	—	—	—	—	(4,250)	—	(4,250)
Foreign currency translation adjustments	—	—	—	—	1,184	—	—	1,184
Balance at June 30, 2019	100,000	23,475	23,475	517,324	(37,478)	(44,162)	4,347	463,506

(in thousands of $)	Preference Shares (Mezzanine)	Convertible Common Share Capital (Mezzanine)	Common Share Capital	Additional Paid-in Capital	Accumulated Other Comprehensive Loss	Retained Losses	Non-Controlling Interest	Total Stockholder’s Equity
Balance at December 31, 2019	100,000	23,475	23,475	527,324	(45,186)	(51,937)	7,090	460,766
Net (loss)/income	—	—	—	—	—	(55,197)	3,346	(51,851)
Dividends⁽¹⁾	—	—	—	—	—	(5,652)	—	(5,652)
Foreign currency translation adjustments	—	—	—	—	(39,693)	—	—	(39,693)
Balance at June 30, 2020	100,000	23,475	23,475	527,324	(84,879)	(112,786)	10,436	363,570

(1)	This relates to accrued dividends to Preference Shareholders.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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GENERAL

The Company, through its equity method investment in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), has constructed and is operating, a combined cycle power plant in Brazil with investment partner Eletricidade do Brasil S.A. (“Ebrasil”). The Company, through its investment in equity method investee project company Centrais Elétricas Barcarena S.A. (“CELBA”), additionally plans to construct and operate a 605MW combined cycle power plant in the city of Barcarena in the State of Pará, Brazil.

As of June 30, 2020, the Hygo fleet consists of two LNG carriers, Golar Celsius and Golar Penguin and one Floating Storage Regasification Unit (“FSRU”), Golar Nanook, which commenced its 25-year charter with CELSE under a sales-type lease.

2.	ACCOUNTING POLICIES

Basis of accounting and presentation

The condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The condensed consolidated financial statements do not include all of the disclosures required under U.S. GAAP in the annual consolidated financial statements and should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2019, which are included in the Form F-1.

Use of estimates

The preparation of financial statements in accordance with United States Generally Accepted Accounting Principles (“U.S. GAAP”) requires that management make estimates and assumptions affecting the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

In assessing the recoverability of our vessels’ carrying amounts, we make assumptions regarding estimated future cash flows, estimates in respect of residual or scrap value, charter rates, ship operating expenses, utilization and drydocking requirements.

During the period ended June 30, 2020, as a result of the 2019 coronavirus (“COVID-19”) impact on our operations, we considered whether indicators of impairment existed that could indicate that the carrying amounts of the vessels may not be recoverable as of June 30, 2020 and concluded that no such events or changes in circumstances had occurred to warrant a change in the assumptions utilized in the December 31, 2019 impairment tests of our vessels. We will continue to monitor developments in the markets in which we operate for indications that the carrying value of our vessels are not recoverable.

Significant accounting policies

The accounting policies adopted in the preparation of the condensed consolidated financial statements for the six months ended June 30, 2020 are consistent with those followed in the preparation of our audited consolidated financial statements for the year ended December 31, 2019, except for those added and updated below as a result of adopting the requirements of ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments (Topic 326). The impact of these changes in accounting policies on the unaudited condensed consolidated financial statements is disclosed in note 3.

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Lease accounting

When a contract is designated as a lease, we make an assessment on whether the contract is an operating or sales-type lease. An agreement will be a sales-type lease is any of the following conditions are met:

•	ownership of the asset is transferred at the end of the lease term;

•	the contract contains an option to purchase the asset which is reasonably certain to be exercised;

•	the lease term is for a major part of the remaining useful life of the contract, although contracts entered into in the last 25% of the asset’s useful life are not subject to this criterion;

•	the discounted value of the fixed payments under the lease represent substantially all of the fair value of the asset; or

•	the asset is heavily customized such that it could not be used for another charter at the end of the term.

Lessor accounting

In making the classification assessment, we estimate the residual value of the underlying asset at the end of the lease term with reference to broker valuations. None of our lease contracts contain residual value guarantees and any purchase options are disclosed. Agreements with renewal and termination options in the control of the lessee are included together with the non-cancelable contract period in the lease term when “reasonably certain” to be exercised or if controlled by the lessor. The determination of reasonably certain depends on whether the lessee has an economic incentive to exercise the option. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, lease accounting will not commence until the asset has successfully passed the acceptance test or it becomes a formality. We assess a lease under the modification guidance when there is a change to the term and conditions of the contract that results in a change to the scope or consideration of the lease.

Costs directly associated with the execution of the lease or costs incurred after the lease inception or the execution of the contract but prior to the commence of the lease that directly relate to preparing the asset for the lease (i.e. bunker costs), are capitalized and amortized to the consolidated statement of operations over the lease term. We also defer upfront revenue payments (i.e. repositioning fees) to the consolidated balance sheet and amortize to the consolidated statement of operations over the lease term.

Allowance for credit losses

Financial assets recorded at amortized cost and off-balance sheet credit exposures not accounted for as insurance (including financial guarantees) reflect an allowance for current expected credit losses (“credit losses”) over the lifetime of the instrument. The allowance for credit losses reflects a deduction to the net amount expected to be collected on the financial asset. Amounts are written off against the allowance when management believes the un-collectability of a balance is confirmed or certain. Expected recoveries will not exceed the aggregate of amounts previously written-off or current credit loss allowance by financial asset category. We estimate expected credit losses based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. We have elected to calculate expected credit losses on the combined balance of both the amortized cost and accrued interest from the unpaid principal balance. Specific calculation of our credit allowances are included in the respective accounting policies included herein; all other financial assets are assessed on an individual basis calculated using the method we consider most appropriate for each asset.

Time charter sales-type leases

On inception of a sales-type lease for which we are lessor, we de-recognize the related asset and record “Net investment in leased asset” on our consolidated balance sheet. The day one gain or loss is presented in “Other non-operating income/(loss)” in our Consolidated Statement of Income (Loss). The net investment in leased asset represents the fixed payments due from the lessee, discounted at the rate implicit in the lease. We allocate sales-type lease income to the consolidated statements of operations in the “Interest income” line item to reflect a constant periodic rate of return on our sales-type lease investment (see note 12).

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For sales-type leases, non-lease revenue and operating and service agreements in connection with the time charters are recorded over the term of the charter as the service is provided. The transaction price is based on the standalone selling price for the service.

Amounts are presented net of allowances for credit losses, which are assessed at the individual lease level, reflecting the risk profile for each vessel unique to each project. The allowance is calculated by multiplying the balance exposed on default by the probability of default and loss given default over the term of the lease. The exposure at default is net of the vessel collateral that is returned on default. With forecasts for counterparty probability of default and loss given default not readily available or supportable for the life of the instrument, annualized rates have been applied based on a forecast 5-year period. A probability weighting has been applied to each period of default over the remaining instrument life.

Trade accounts receivables

Trade receivables are presented net of allowances for doubtful debt based on observable events and expected credit losses. At each balance sheet date, all potentially uncollectible accounts are assessed individually for purposes of determining the appropriate provision for doubtful accounts. The expected credit loss allowance is calculated using a loss rate applied against an aging matrix, with assets pooled based on the segment that generated the underlying revenue (LNG vessel operations) and individual FSRU, which reflects similar credit risk characteristics. Our trade receivables have short maturities so we have considered that forecasted changes to economic conditions will have an insignificant effect on the estimate of the allowance, except in extraordinary circumstances.

Related parties

Cash and cash equivalents

We consider all demand and time deposits and highly liquid investments with original maturities of three months or less to be equivalent to cash. Amounts are presented net of allowances for credit losses, which are assessed based on consideration of whether the balances have short-term maturities and whether the counterparty has an investment grade credit rating, limiting any credit exposure.

Restricted cash and short-term deposits

Restricted cash consists of cash collateral required to satisfy certain covenants outlined in the Company’s debt facilities and bid bonds associated with tenders for projects that we have entered into and other claims which require us to restrict cash. We also present short-term deposits and cash balances relating to our consolidated VIEs within restricted cash as we do not have the ability to use the cash freely for company purposes.

3.	RECENTLY ISSUED ACCOUNTING STANDARDS

Adoption of new accounting standards

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments, including ASU 2018-19, ASU 2019-04 and ASU 2019-11: Codification Improvements to Topic 326 “Financial Instruments-Credit Losses”. Topic 326 replaces the incurred loss impairment methodology with a requirement to recognize lifetime expected credit losses (measured over the contractual life of the instrument) immediately, based on information about past events, current conditions and forecasts of future economic conditions. This will reflect the net amount expected to be collected from the financial asset and is referred to as the current expected credit loss “CECL” methodology, with measurement applicable to financial assets measured at amortized cost as well as off-balance sheet credit exposures not accounted for as insurance (including financial

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guarantees). Topic 326 also makes changes to the accounting for available-for-sale debt securities and purchased credit deteriorated financial assets, however, no such financial assets existed on date of adoption or in the reporting periods covered by these consolidated financial statements.

Using the modified retrospective method, reporting periods beginning after January 1, 2020 are presented under Topic 326 while comparative periods continue to be reported in accordance with previously applicable GAAP and have not been restated. The adoption of Topic 326 did not have a material impact on our consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this ASU remove some disclosure requirements relating to transfers between Level 1 and Level 2 of the fair value hierarchy and introduces new disclosure requirements for Level 3 measurements. We adopted the disclosure improvements prospectively on January 1, 2020, but this amendment has not had a material impact on our disclosure requirements as we have no Level 3 measurements.

In October 2018, the FASB issued ASU 2018-17 Consolidation (Topic 810) - Targeted Improvements to Related Party Guidance for Variable Interest Entities. The amendments in this ASU specify that for the purposes of determining whether a decision-making fee is a variable interest, a company is now required to consider indirect interests held through related parties under common control on a proportionate basis as opposed to as a direct investment. We are required to adopt the codification improvements retrospectively using a cumulative-effect method to retained earnings of the earliest period presented herein, but the amendment had no impact on historic consolidation assessments or retained earnings.

In March 2020, the FASB issued ASU 2020-03 Financial Instruments (Topic 825) - Codification Improvements. The amendments in this ASU propose seven clarifications to improve the understandability of existing guidance, including that fees between debtor and creditor and third-party costs directly related to exchanges or modifications of debt instruments include line-of-credit or revolving debt arrangements. We adopted the codification improvements that were effective on issuance from January 1, 2020 under the specified transition approach connected with each of the codification improvements. This amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2020.

Accounting pronouncements that have been issued but not adopted

The following table provides a brief description of recent accounting standards that have been issued but not yet adopted:

Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2019-12 Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes.	The amendment removes certain exceptions previously available and provides some additional calculation rules to help simplify the accounting for income taxes.	January 1, 2021	Under evaluation

ASU 2020-04 Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.	The amendments provide temporary optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The applicable expedients for us are in relation to modifications of contracts within the scope of Topics 310, Receivables, 470, Debt, and Topic 842, Leases. This optional guidance may be applied prospectively from any date beginning March 12, 2020 and cannot be applied to modifications that occur after December 31, 2022.	Under evaluation	Under evaluation

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4.	SEGMENT INFORMATION

The split of the organization of the business into four reportable segments is based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure. As of June 30, 2020, we operate in the following four reportable segments:

•

LNG carriers – LNG carriers are vessels that transport LNG and are compatible with many LNG offloading and receiving terminals globally. We have two LNG carriers which are currently operating through the Cool Pool in the spot/short-term charter market. These vessels will continue to operate through the Cool Pool until their conversion to FSRUs.

•	FSRU and terminals – FSRUs are vessels that are permanently moored offshore and used to store and regasify LNG. We have one FSRU and terminal offshore Sergipe, Brazil, which is in service to CELSE pursuant to a 25-year charter.

•	Power – We have contracted with local partners to build cleaner and economically advantageous natural gas-fired power generation assets backed by long-term power purchase agreements in our core operating areas.

•	Downstream distribution – Our downstream distribution business is focused on the procurement of LNG or natural gas from our terminals and other sources to be able to deliver to our downstream customers under medium to long-term contracts.

	Six months ended June 30, 2020
(in thousands of $)	LNG carriers	FSRU and terminals	Power	Downstream distribution	Other business and corporate⁽¹⁾	Total
Statement of Operations:
Total operating revenues	21,092	1,695	—	—	—	22,787
Vessel operating expenses	(5,708)	(1,684)	—	—	—	(7,392)
Depreciation and amortization	(5,554)	—	—	(66)	(20)	(5,640)
Administrative expenses	(605)	(1,094)	(1,508)	(2,101)	(6,541)	(11,849)
Other operating income	3,714	—	—	—		3,714
Segment operating income/(loss)	12,939	(1,083)	(1,508)	(2,167)	(6,561)	1,620
Equity in net losses of affiliates	—	—	(37,276)	—	—	(37,276)

Balance Sheet:	June 30, 2020
(in thousands of $)	LNG carriers	FSRU and terminals	Power	Downstream distribution	Other business and corporate⁽²⁾	Total
Total assets	402,388	344,874	234,009	4,990	56,359	1,042,620
Investment in affiliates (note 11)	—	—	225,176	—	—	225,176
Net investment in leased asset (note 12)	—	306,207	—	—	—	306,207
Vessels and equipment, net	352,935	2	4	1,590	114	354,645
Other assets	49,453	38,665	8,829	3,400	56,245	156,592

(1)	Relates to corporate overheads not allocated to a segment but included to reflect total administrative costs in the consolidated statements of income/(loss).

(2)	Relates to corporate assets not allocated to a segment but included to reflect the total assets in the consolidated balance sheet.

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	Six months ended June 30, 2019
(in thousands of $)	LNG carriers	FSRU and terminals	Power	Downstream distribution	Other business and corporate⁽¹⁾	Total
Statement of Operations:
Total operating revenues	24,047	—	—	—	—	24,047
Vessel operating expenses	(19,238)	—	—	—	—	(19,238)
Depreciation and amortization	(5,564)	—	—	—	(15)	(5,579)
Administrative expenses	(484)	(1,361)	(815)	(1,158)	(3,467)	(7,285)
Segment operating income/(loss)	(1,239)	(1,361)	(815)	(1,158)	(3,482)	(8,055)
Equity in net losses of affiliates	—	—	(778)	—	—	(778)

Balance Sheet:	December 31, 2019
(in thousands of $)	LNG carriers	FSRU and terminals	Power	Downstream distribution	Other business and corporate⁽²⁾	Total
Total assets	410,930	369,902	332,363	1,662	39,935	1,154,792
Investment in affiliates (note 11)	—	—	311,105	—	—	311,105
Assets under development	—	327,754	—	—	—	327,754
Vessels and equipment, net	358,489	3	—	1,489	162	360,143
Other assets	52,441	42,145	21,258	173	39,773	155,790

(1)	Relates to corporate overheads not allocated to a segment but included to reflect total depreciation and administrative expenses in the consolidated statements of income (loss).

(2)	Relates to corporate assets not allocated to a segment but included to reflect the total assets in the consolidated balance sheet.

5.	OTHER OPERATING INCOME

For the period ended June 30, 2020, $3.7 million was recognized in the consolidated statement of income (loss) for insurance proceeds received in relation to one of our LNG carriers.

6.	INCOME TAXES

The components of income tax expense are as follows:

	Six months ended June 30,
(in thousands of $)	2020	2019
Current tax expense	5,990	33
Deferred tax expense (credit)	(3,468)	—
Total tax expense	2,522	33

Current tax expense for the six months ended June 30, 2020 and 2019 includes current and withholding tax charges in respect of our operations in Brazil. A deferred tax credit of $3.5 million was recognized following the realization of gains on financial instruments in Brazil.

As of June 30, 2020, there is a net deferred tax liability of $nil. As of December 31, 2019, a deferred tax liability of $3.5 million was recognized in relation to the unrealized gains on financial instruments in Brazil.

7.	LOSS PER SHARE

Basic loss per share (“EPS”) is calculated with reference to the weighted average number of common shares outstanding during the period.

The unaudited pro forma basic and diluted loss per share for the six months ended June 30, 2020 gives the effect to the redemption of the preference shares as well as a 2.13-for-1 share split, to be effected after the effective date of the registration statement and prior to the consummation of this offering.

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The components of the numerator for the calculation of basic and diluted EPS are as follows:

	Six months ended June 30,
(in thousands of $)	Pro forma (unaudited) 2020	2020	2019
Numerator - net loss available to common stockholders	(60,849)	(60,849)	(16,577)
Pro forma effect of redemption of preferred shares	5,652	—	—
Numerator – net loss attributable to common shareholders	(55,197)	(60,849)	(16,577)

The components of the denominator for the calculation of basic and diluted EPS are as follows:

	Six months ended June 30,
(in thousands of $)	Pro forma (unaudited) 2020	2020	2019
Weighted average number of common shares outstanding⁽¹⁾	100,000,000	46,950,154	46,950,154

(1)	Includes the common shares included in the mezzanine classification.

Loss per share are as follows:

	Six months ended June 30,
(in thousands of $)	Pro forma (unaudited) 2020	2020	2019
Basic and diluted	$(0.55)	$(1.30)	$(0.35)

The effects of the convertible ordinary and preference shares have been excluded from the calculation of diluted EPS for each of the six months ended June 30, 2020 and 2019 as these are contingent on the Initial Public Offering (“IPO”) event and therefore the effects were anti-dilutive. The effects of the contingent IPO event have been shown in the pro forma (unaudited) EPS calculation for the six months ended June 30, 2020.

8.	VARIABLE INTEREST ENTITIES (“VIE”)

8.1	Lessor VIEs

As of June 30, 2020, we leased three (December 31, 2019: two) vessels from VIEs as part of sale and leaseback arrangements, one with a CCB Financial Leasing Corporation Limited (“CCBFL”) entity, one with a COSCO Shipping Leasing Company Limited (“COSCO”) entity and one with an AVIC International Leasing Company Limited (“AVIC”) entity.

In each of these transactions, we sold our vessel and then subsequently leased back the vessel on a bareboat charter for a fixed term. We have options to repurchase each vessel at fixed predetermined amounts during their respective charter periods and an obligation to repurchase each vessel at the end of their lease period. Refer to note 5 to our consolidated financial statements for the year ended December 31, 2019 for additional details.

AVIC

In March 2020, we sold the Golar Celsius to an SPV owned by AVIC and subsequently leased back the vessel on a bareboat charter for a term of seven years. We have 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.

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The following table gives a summary of the sale and leaseback arrangement for the Golar Celsius, including repurchase options and obligations as of June 30, 2020:

Golar Celsius

March 2020

160.0

109.3

March 2021

45.0

March 2027

While we do not hold an equity investment in the SPVs, we have determined that we have a variable interest in these SPVs and that the lessor entities, that own the vessels, are VIEs. Based on our evaluation of the agreements, we have concluded that we are the primary beneficiary of these VIEs and, accordingly, these VIEs are consolidated into our financial results. We did not record any gains or losses from the sale of these vessels as they continued to be reported as vessels at their original costs in our consolidated financial statements at the time of each transaction. Similarly, the effect of the bareboat charter arrangements is eliminated upon consolidation of the SPV. The equity attributable to CCBFL, COSCO and AVIC in their respective VIEs are included in non-controlling interests in our consolidated financial statements. As of June 30, 2020, the Golar Penguin and Golar Celsius are reported under “Vessel and equipment, net” in our consolidated balance sheet. Following the commencement of operations of the Sergipe Power Plant by CELSE, the Golar Nanook was recognized as a sales-type lease and the vessel carrying value of the Golar Nanook was de-recognized from “Asset under development” and recognized in “Net investment in leased asset” (see note 12).

A summary of our payment obligations (excluding repurchase options and obligations) under the bareboat charters with the lessor VIEs as of June 30, 2020, are shown below:

(in thousands of $)	2020⁽¹⁾	2021	2022	2023	2024	2025+
Golar Nanook	12,218	23,878	23,181	22,484	21,816	111,781
Golar Penguin	6,733	13,200	12,778	12,369	11,935	8,688
Golar Celsius	8,579	16,683	16,075	15,468	14,872	27,216

(1)	For the six months ending December 31, 2020.

The assets and liabilities of these lessor VIEs that most significantly impact our consolidated balance sheet as of June 30, 2020 and December 31, 2019, are as follows:

(in thousands of $)	Golar Nanook	Golar Penguin	Golar Celsius	June 30, 2020 Total	December 31, 2019 Total
Assets
Restricted cash and short-term deposits	17,448	—	9,864	27,312	11,072

Liabilities
Debt:
Current portion of long-term debt and short-term debt⁽¹⁾	—	104,126	—	104,126	113,400
Long-term interest bearing debt - non-current portion	217,178	—	118,200	335,378	217,178
	217,178	104,126	118,200	439,504	330,578

(1)	The long-term debt associated with the Penguin lessor VIE is classified as short-term as it has no repayment profile and is repayable on demand by the lender.

The most significant impact of the lessor VIEs cash flows on our consolidated statements of cash flows is net cash received in financing activities of $118.2 million for the six months ended June 30, 2020 (six months ended June 30, 2019: $nil).

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8.2

Mercurio

On October 9, 2019, the Company acquired 100% of the equity interest in Mercurio Comercializadora de Energia Ltda. (“Mercurio”). We have determined that the entity is a VIE as although we own 100% of the equity, some of the profits related to the trades were not executed on behalf of Hygo. However, we have determined that we have control over the most significant activities and the greatest exposure to variability in residual returns and expected losses of the entity. Accordingly, we have consolidated Mercurio as we are the primary beneficiary of the VIE. The profits related to the trades which were not executed on behalf of Hygo were immaterial for the six months ended June 30, 2020 and December 31, 2019, respectively.

Summarized financial information of Mercurio

The assets and liabilities of Mercurio that most significantly impact our consolidated balance sheet are as follows:

(in thousands of $)	June 30, 2020	December 31, 2019
Assets
Cash and cash equivalents	699	—
Trade accounts receivable	1,107	—
Derivative asset	5	10,200

Liabilities
Trade accounts payable	688	40
Current tax payable	59	—
Deferred tax liability	—	3,468

The most significant impact of Mercurio’s operations on our unaudited consolidated statements of income, and unaudited consolidated statements of cash flows, are as follows:

	Six months ended June 30,
(in thousands of $)	2020	2019
Statement of income (loss)
Gain on derivative instrument	5,127	—
Tax expense	(1,576)	—

The most significant impact of Mercurio’s cash flows on our consolidated statements of cash flows is net cash received in operating activities of $12.6 million for the six months ended June 30, 2020 (six months ended June 30, 2019: $nil).

9.	RESTRICTED CASH AND SHORT-TERM DEPOSITS

Our restricted cash and short-term deposits balances are as follows:

(in thousands of $)	June 30, 2020	December 31, 2019
Restricted cash and short-term deposits held by lessor VIEs⁽ⁱ⁾	27,312	11,072
Restricted cash relating to the Golar Celsius⁽ⁱⁱ⁾	—	6,039
Restricted cash relating to LC⁽ⁱⁱⁱ⁾	5,750	5,750
Restricted cash relating to Brazil office lease	30	41
Total restricted cash and short-term deposits	33,092	22,902
Less: Amounts included in current restricted cash and short-term deposits	(33,062)	(22,861)
Long-term restricted cash	30	41

(i)	These are amounts held by our lessor VIE entities that we are required to consolidate under U.S. GAAP into our financial statements as VIEs (see note 8).

(ii)	Restricted cash relating to the Golar Celsius refers to cash deposits required in connection with the financial covenant compliance related to the financing of this vessel. The Golar Celsius facility was refinanced in March 2020 (see note 13).

(iii)

This amount relates to an irrevocable stand-by letter of credit (“LC”) required in connection with the financing of the CELSE project.

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Restricted cash does not include $6.9 million and $3.9 million as of June 30, 2020 and December 31, 2019, respectively, which is the minimum cash position that we are required to maintain as part of the financial covenants for our sale and leaseback financing. These are included in “cash and cash equivalents” in the Consolidated Balance Sheet as of June 30, 2020 and December 31, 2019, respectively.

10.	ASSETS UNDER DEVELOPMENT

(in thousands of $)	June 30, 2020	December 31, 2019
Opening asset under development balance	327,754	302,410
Interest costs capitalized	3,530	14,006
Other costs capitalized⁽¹⁾	1,890	11,338
Transfer out of asset under development	(333,174)	—
Closing asset under development balance	—	327,754

(1)	Other capitalized costs include voyage charter, site supervision and other miscellaneous construction costs.

Following the commencement of the Sergipe power plant operations by the charterer in March 2020, the Golar Nanook commenced its sales-type lease. The vessel carrying value of the Golar Nanook was de-recognized from “Asset under development” and a “Net investment in leased asset” was recognized (see note 12).

11.	INVESTMENTS IN AFFILIATES AND JOINT VENTURES

The components of equity in net losses in affiliates are as follows:

	Six months ended June 30,
(in thousands of $)	2020	2019
CELSEPAR	(36,624)	(700)
CELBA	(595)	(78)
São Marcos	(57)	—
Equity in net losses in affiliates	(37,276)	(778)

The carrying amounts of our investments in our equity method investments as at June 30, 2020 and December 31, 2019 are as follows:

(in thousands of $)	June 30, 2020	December 31, 2019
CELSEPAR	224,561	310,368
CELBA	247	165
São Marcos	368	572
Investments in affiliates	225,176	311,105

The movement in the carrying amount of investments in affiliates are as follows:

(in thousands of $)
Investments in affiliates as of December 31, 2019			311,105
Capital contributions			1,021
Equity in net losses in affiliates			(37,276)
Capitalized interest			2,185
Foreign currency translation adjustment			(51,859)
Investments in affiliates as of June 30, 2020			225,176

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HYGO ENERGY TRANSITION LTD.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company has capitalized interest of $2.2 million and $1.9 million for the six months ended June 30, 2020 and 2019, respectively, on its investment in CELSEPAR as the equity method investment is deemed a qualifying asset from the date of our Final Investment Decision until the commencement of its planned principal operation in March 2020, upon which the capitalization of interest ceased.

Summarized consolidated financial information of CELSEPAR are shown on a 100% basis as follows:

(in thousands of $)	June 30, 2020	December 31, 2019
Balance Sheet
Current assets	221,167	184,681
Non-current assets	1,955,839	1,364,619
Current liabilities	284,429	128,286
Non-current liabilities	1,652,087	1,002,331

12.	NET INVESTMENT IN LEASED ASSET

On March 31, 2020, following the commencement of the Sergipe power plant operations by the charterer, the Golar Nanook commenced its sales-type finance lease. The commencement of the lease resulted in the de-recognition of the asset under development carrying value, the recognition of net investment in leased asset (consisting of present value of the future lease receivables and unguaranteed residual value), and a loss on disposal of $26.0 million which is presented in “Other non-operating loss” of our Consolidated Statement of Income (Loss). Subsequent to the recognition of the sales-type lease, all charter hire revenue from the Golar Nanook Finance Lease is to be recognized as interest income. We recognized interest income of $12.5 million and $nil for the six months ended June 30, 2020 and 2019, respectively, which is presented under “Interest income” in the Consolidated Statement of Income (Loss).

The following table list the components of our net investment in leased vessel and the maturity profile of the undiscounted lease receivables:

Year ending December 31
(in thousands of $)
2020⁽¹⁾			23,507
2021			47,132
2022			47,802
2023			48,482
2024			49,307
2025 and thereafter			1,147,010
Total minimum lease receivable			1,363,240
Unguaranteed residual value			134,940
Gross investment in sales-type lease			1,498,180
Less: Unearned interest income			(1,190,074)
Less: Current expected credit losses⁽²⁾			(1,899)
Net investment in leased vessel			306,207
Less: Current portion of net investment in leased asset			—
Non-current portion of net investment in leased asset			306,207

(1)	For the six months ending December 31, 2020.

(2)	A corresponding charge of $1.9 million was recognized in “Interest income” in the consolidated statement of income (loss).

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HYGO ENERGY TRANSITION LTD.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13.

DEBT

As of June 30, 2020, and December 31, 2019, our debt, net of deferred financing costs, is broken down as follows:

(in thousands of $)	June 30, 2020	December 31, 2019
Debenture loan	54,869	74,434
Golar Celsius facility⁽¹⁾	—	64,212
Subtotal (excluding lessor VIE loans)	54,869	138,646
CCBFL VIE loan⁽²⁾	217,178	217,178
COSCO VIE loan⁽²⁾	104,126	113,400
AVIC VIE loan⁽²⁾	118,200
Subtotal (VIE loans)	439,504	330,578
Total debt	494,373	469,224
Less: Deferred finance charges, net	(3,475)	(4,482)
Total debt, net of deferred financing costs	490,898	464,742

(1)	In March 2020, the Golar Celsius facility was re-financed prior to maturity.

(2)	These amounts relate to certain lessor entities (for which legal ownership resides with financial institutions) that we are required to consolidate under U.S. GAAP into our consolidated financial statements as variable interest entities (see note 8).

At June 30, 2020, our debt, net of deferred financing costs, is broken down as follows:

(in thousands of $)	Hygo debt	VIE debt⁽¹⁾	Total debt
Current portion of long-term debt and short-term debt	7,887	104,126	112,013
Long-term debt	46,335	332,550	378,885
Total	54,222	436,676	490,898

(1)	These amounts relate to certain lessor entities (for which legal ownership resides with financial institutions) that we are required to consolidate under U.S. GAAP into our financial statements as variable interest entities (see note 8).

AVIC Lessor VIE - Golar Celsius SPV facility

In March 2020, the AVIC owned SPV, Noble Celsius Shipping Limited, the owner of the Golar Celsius, entered a three-year facility for $118.2 million. The loan facility, denominated in USD, bears interest at 4.64% per annum.

14.	OTHER CURRENT LIABILITIES

(in thousands of $)	June 30, 2020	December 31, 2019
Deferred revenue⁽ⁱ⁾	10,327	38,730
Other	1,486	1,372
Deferred consideration⁽ⁱⁱ⁾	—	10,754
Deferred tax⁽ⁱⁱⁱ⁾	—	3,468
Total	11,813	54,324

(i)

Deferred revenue amounted to $10.3 million and $38.7 million as of June 30, 2020 and December 31, 2019, respectively. The decrease is driven by the de-recognition of $28.8 million of pre-commissioning revenue on Golar Nanook’s charter agreement following the commencement of the Sergipe power plant operations by the Charterer in March 2020, which triggered the commencement of the sales-type lease (see note 12). As of June 30, 2020, deferred revenue of $3.7 million relates to the CELSE voyage charter option fee, $5.3 million relates to pre-commissioning revenue under its operation and service agreement with CELSE and $1.3 million relates to deferred revenue associated with one of our vessels operating in the Cool Pool.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(ii)	Deferred consideration of $11.5 million was paid on the Sergipe power plant Commercial Operation Date of March 21, 2020 for which the outstanding amount as of December 31, 2019 was $10.8 million.

(iii)

Deferred tax as at December 31, 2019 related to the tax expense on the unrealized gain on the forward purchase energy contracts. During the period ended June 30, 2020, the unrealized gain was subsequently realized upon settlement of the forward purchase energy contracts.

15.	FINANCIAL INSTRUMENTS

Fair values

We recognize our fair value estimates using a fair value hierarchy based on the inputs used to measure fair value. The fair value of hierarchy has three levels based on reliability of inputs used to determine fair value as follows:

Level 1: Quoted market prices in active markets for identical assets and liabilities.

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data.

The carrying values and estimated fair values of our financial instruments at June 30, 2020 and December 31, 2019 are as follows:

	Fair value hierarchy	June 30, 2020		December 31, 2019
(in thousands of $)	Fair value hierarchy	Carrying value	Fair value	Carrying value	Fair value
Cash and cash equivalents	Level 1	74,633	74,633	49,949	49,949
Restricted cash and short-term deposits	Level 1	33,092	33,092	22,902	22,902
Derivative asset⁽¹⁾	Level 2	5	5	10,200	10,200
Deferred consideration⁽²⁾	Level 2	—	—	10,754	10,754
Current portion of long-term debt and short-term debt⁽³⁾⁽⁴⁾	Level 2	112,013	112,013	127,056	127,056
Long-term debt⁽⁴⁾	Level 2	378,885	378,885	337,686	337,686

(1)

(2)	The estimated fair value of the deferred consideration is derived by using a discounted cash flow model. The most significant input into this valuation is the discount rate which takes into account, amongst other things, the equity and country risk.

(3)	The carrying amounts of our short-term debt approximate their fair values because of the near-term maturity of these instruments.

(4)

Our debt obligations are recorded at amortized cost in the consolidated balance sheets. The amounts presented in the table above are net of the deferred finance charges amounting to $3.5 million and $4.5 million at June 30, 2020 and December 31, 2019, respectively. The estimated fair value for the floating long-term debt are considered to approximate the carrying values since they bear variable interest rates, which are adjusted on a quarterly or six-monthly basis.

16.	RELATED PARTY TRANSACTIONS

a) Transactions with CELSE:

Receivables/(payables): The balances with CELSE as of June 30, 2020 and December 31, 2019 consisted of the following:

(in thousands of $)	June 30, 2020	December 31, 2019
Deferred revenue⁽ⁱ⁾	(8,973)	(37,568)
Trade receivables⁽ⁱ⁾	7,934	28,601
Total	(1,039)	(8,967)

(i)

We have a charter agreement and operation and service agreement to lease the Golar Nanook to CELSE following its commissioning and commencement of operations of the Sergipe power plant. On March 31, 2020, following the commencement of the Sergipe power plant operations by the charterer, the Golar Nanook commenced its sales-type finance lease and as such, a net investment in leased asset of $305.4 million and a loss on disposal of $26.0 million were recognized (see note 12).

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HYGO ENERGY TRANSITION LTD.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As at June 30, 2020, the balances with CELSE include $3.7 million in relation to the voyage charter option fee under Golar Nanook’s charter agreement and $5.3 million of pre-commissioning revenue under the operation and service agreement.

As at December 31, 2019, the balances with CELSE include $32.6 million in relation to the voyage charter option fee and bareboat contract payments under Golar Nanook’s charter agreement and $5.0 million of pre-commissioning revenue under the operation and service agreement.

b) Transactions with Golar LNG and subsidiaries:

Expenses: The transactions with Golar LNG and its subsidiaries for the six months ended June 30, 2020 and 2019 consisted of the following:

	Six months ended June 30,
(in thousands of $)	2020	2019
Management and administrative services expense⁽ⁱ⁾	(2,668)	(3,011)
Ship management fees expense⁽ⁱⁱ⁾	(831)	(606)
Debt guarantee fee expense⁽ⁱⁱⁱ⁾	(605)	(352)
Total	(4,104)	(3,969)

Receivables: The balances with Golar LNG and its subsidiaries as of June 30, 2020 and December 31, 2019 consisted of the following:

(in thousands of $)	June 30, 2020	December 31, 2019
Trading balances due from Golar LNG and subsidiaries^(iv)(v)	7,117	6,829
Total	7,117	6,829

(i)

(ii)

(iii)

Debt guarantee fee expense - Upon formation, Golar LNG provided financial guarantees in relation to the debt financing of Golar Celsius and Golar Penguin. Hygo entered into agreements to compensate Golar LNG in relation to certain debt guarantees. The remaining liability relating to the counter guarantee is recorded in “Other current liabilities” and “Other non current liabilities” in the Consolidated Balance Sheet.

(iv)

The Cool Pool - On July 8, 2019 GasLog’s vessel charter contracts had concluded and withdrew their participation from the Cool Pool. Following Gaslog’s departure, Golar LNG assumed sole responsibility for the management of the Cool Pool and consolidated the Cool Pool. We ceased applying the collaborative accounting guidance to the Cool Pool. This had no impact on how we account for revenues and expenses that were attributable to our own vessels, however, net revenue and expenses relating to the other pool participants are now presented net within “Voyage, charter-hire and commission expenses” as opposed to being presented gross within “Time charter revenues - collaborative arrangement” and “Voyage, charter-hire and commission expenses - collaborative arrangement” under the previously adopted collaborative arrangement accounting principles. Net revenue relating to the other pool participants presented on our consolidated statement of loss under “Voyage, charter-hire and commission expenses” for the six months ended June 30, 2020 amounted to $3.1 million. There was no such net revenue for the same period in 2019 as the vessels were operating under a collaborative arrangement in the Cool Pool.

Amounts due from the Cool Pool as of June 30, 2020 included in trade accounts receivable amounted to $0.1 million (December 31, 2019: $1.3 million), trading balances due from Golar LNG and subsidiaries of $2.9 million (December 31, 2019: $3.9 million) and deferred revenue of $1.4 million (December 31, 2019: $1.2 million).

(v)

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Guarantees and other:

(a) Debt guarantees - These debt guarantees were previously issued by Golar LNG to third party banks in respect of certain secured debt facilities relating to Hygo and its subsidiaries. In connection with the formation of Hygo, the Company entered into a counter guarantee with Golar LNG to indemnify Golar LNG in the event they are required to pay out any monies due under the debt guarantee. The liability for this counter guarantee was recorded in “Other current liabilities” and “Other non-current liabilities” and was amortized over the remaining term of the respective debt facilities associated with Golar Penguin and Golar Celsius. In December 2019 and March 2020, respectively, the Golar Penguin and Golar Celsius were refinanced and simultaneously the guarantees terminated. Subsequently, debt guarantees were provided on the Golar Penguin and Golar Celsius in connection with their new financing arrangements.

As described in (iii) above we pay Golar LNG a guarantee fee in relation to the provision of the guarantees. The debt facilities are secured against specific vessels.

(b) Golar LNG and Stonepeak contributions - under the Hygo shareholders’ agreement, Golar LNG and Stonepeak have agreed to contribute additional funding as may be required by Hygo, subject to the approval of its board of directors.

c) Transactions with other related parties:

Expenses: The transactions with other related parties for the six months ended June 30, 2020 and 2019 consisted of the following:

	Six months ended June 30,
(in thousands of $)	2020	2019
Magni Partners⁽ⁱ⁾	(1,373)	(347)
Total	(1,373)	(347)

Receivables/(payables): The balances with other related parties as of June 30, 2020 and December 31, 2019 consisted of the following:

(in thousands of $)	June 30, 2020	December 31, 2019
CELBA⁽ⁱⁱ⁾	107	407
Golar Power Brasil 2 Participações S.A.⁽ⁱⁱ⁾	230	32
Magni Partners⁽ⁱ⁾	(41)	(141)
Total	296	298

(i)

Magni Partners - Tor Olav Trøim, a Director of Hygo Energy Transition Ltd., is the founder of, and partner in, Magni Partners Limited (“Magni Partners”), a privately held UK company, as well as Magni Partners Bermuda Limited (“Magni Bermuda”), a Bermudan domiciled company. In his role, he is the ultimate beneficial owner of these two companies. Pursuant to management agreements between Magni Partners, Magni Bermuda and Hygo, Hygo was recharged for salary and consulting expenses for all individuals working for Magni Partners and Magni Bermuda to the Company. Of the aggregate amount re-charged, $0.01 million and $0.1 million remains to be settled as at June 30, 2020 and December 31, 2019, respectively. This amount is included in “Trade accounts payables” in the Consolidated Balance Sheet.

(ii)	As of June 30, 2020 and December 31, 2019, $0.3 million and $0.4 million respectively, in receivables from other related parties are short-term in nature.

17.	SUBSEQUENT EVENTS

On September 11, 2020, the Company changed the par value of its common shares from $5.00 to $1.00 each, which has been retrospectively adjusted. The decrease in par value was recorded as a decrease in Convertible Share Capital and Share Capital with a corresponding increase in Additional paid-in Capital in Stockholders' Equity.

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Independent Auditors’ Report on consolidated financial statements

The Board of Directors

CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.

Report on the Consolidated Financial Statements

We have audited the accompanying consolidated financial statements of CELSEPAR - Centrais Elétricas de Sergipe Participações S.A. and its subsidiary, which comprise the consolidated statement of financial position as of December 31, 2019 and 2018, and the related consolidated statements of income and comprehensive income, changes in equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control.

Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CELSEPAR - Centrais Elétricas de Sergipe Participações S.A. and its subsidiary as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ KPMG Auditores Independentes

Salvador, Bahia – Brazil

August 14, 2020

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CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.

Consolidated statements of financial position as of December 31, 2019 and 2018

(In thousands of Reais)

	Note	2019	2018
Assets
Current
Cash and cash equivalents	8	197,125	102,768
Short-term investments	9	446,606	512,811
Recoverable taxes		13,154	2,272
Advances to suppliers		4,772	6,525
Derivative financial instruments	24	—	182
Inventories	12	63,975	—
Other receivables		1,999	159
Total current		727,631	624,717

Noncurrent
Other receivables		782	538
Transaction cost	11	29,326	47,432
Deferred tax	10	38,242	32,854
Advances for property, plant and equipment acquisition	13	141,265	2,375,906
Prepayments	18	111,357	—
Property, plant and equipment	14	5,186,989	1,532,552
Intangible assets		186	125
Total noncurrent		5,508,147	3,989,407
Total assets		6,235,778	4,614,124

Liabilities
Current
Accout payables	15	297,112	10,266
Loans and borrowing	16	31,410	20,997
Debentures	17	135,713	69,155
Taxes and social contributions	19	1,682	1,237
Other accounts payable		2,877	2,551
Total current		468,794	104,206

Accout payables	15 / 18	114,103	—
Loans and borrowing	16	1,592,772	890,596
Debentures	17	2,374,953	2,312,682
Total noncurrent		4,081,828	3,203,278
Equity	21
Capital		1,725,108	1,334,608
Capital reserve		36,346	36,346
Accumulated loss		(76,298)	(64,314)
Total equity		1,685,156	1,306,640
Total liabilities and equity		6,235,778	4,614,124

See the accompanying notes to the consolidated financial statements

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CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.

Consolidated statements of income and comprehensive income

Years ended December 31, 2019 and 2018

(In thousands of Reais)

	Note	2019	2018
Expenses
General and administrative expenses	22	(39,214)	(39,336)
Loss before financial income (expense) and tax		(39,214)	(39,336)
Finance results
Finance income	23	35,829	70,407
Finance expenses	23	(13,987)	(100,361)
		21,842	(29,954)

Net income before income and social contribution taxes		(17,372)	(69,290)

Income tax and social contribution
Deferred	10	5,388	32,854

Net loss for the year		(11,984)	(36,436)
Other comprehensive income		—	—
Total comprehensive loss for the year		(11,984)	(36,436)

See the accompanying notes to the consolidated financial statements

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CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.

Consolidated statement of changes in equity

Years ended December 31, 2019 and 2018

(In thousands of Reais)

			Capital reserve	Advance for future capital increase
	Note	Capital	Special reserve	Advance for future capital increase	Accumulated loss	Total equity
Balance at 1 January 2018		712,001	—	61,900	(27,878)	746,023
Capital increase		652,351	—	(61,900)	—	590,451
Loss for the year		—	—	—	(35,898)	(35,898)
Balances at December 31, 2018 - CELSE - Centrais Elétricas de Sergipe S.A.		1,364,352	—	—	(63,776)	1,300,576
Predecessor adjustments	2	(29,744)	36,346	—	(538)	6,064
Balances at December 31, 2018 - CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.		1,334,608	36,346	—	(64,314)	1,306,640
Capital increase	21	390,500	—	—	—	390,500
Loss for the year		—	—	—	(11,984)	—
Balances at December 31, 2019		1,725,108	36,346	—	(76,298)	1,685,156

See the accompanying notes to the consolidated financial statements

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CELSEPAR - Centrais Elétricas de Sergipe Participações S.A.

Consolidated statements of cash flows

Years ended December 31, 2019 and 2018

(In thousands of Reais)

	2019	2018
Cash flow from operating activities
Net loss for the year	(11,984)	(36,436)
Adjustments for:
Deferred income tax and social contribution	(5,388)	(32,854)
Depreciation	417	308
Exchange variation on overseas supplier	4,233	65,195
Derivative financial instruments	—	(30,890)
Interest on financial investments	(22,553)	(13,342)
	(35,275)	(48,019)
Changes in assets and liabilities
Recoverable taxes	(10,882)	(1,743)
Derivative financial instruments	182	30,708
Inventories	(63,975)	—
Other receivables	(331)	(6,498)
Accounts payable	(140,342)	(100,251)
Other accounts payable	(6,941)	3,933
Taxes and social contributions	445	(404)
Payment of interest on loans and debentures	(456,992)	(182,179)
Net cash used in operating activities	(714,111)	(304,453)

Cash flow from investment activities
Short-term investments deposits	(24,001)	(674,819)
Redemption of short-term investment deposits	112,759	175,350
Acquisition of intangible assets	(108)	(67)
Advance to supplier	(156,460)	(2,606,496)
Additions to property, plant and equipment	(177,169)	(194,754)
Net cash used in investing activities	(244,979)	(3,300,786)

Cash flow from financing activities
Capital increase	390,501	596,649
Principal of loans, borrowings and debentures	687,279	3,816,674
Costs on securing loans	(24,333)	(727,041)
Net cash provided by financing activities	1,053,447	3,686,282
Increase in cash and cash equivalents	94,357	81,043
Cash and cash equivalents at beginning of period	102,768	21,725
Cash and cash equivalents at end of period	197,125	102,768
Increase in cash and cash equivalents	94,357	81,043

See the accompanying notes to the consolidated financial statements

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Notes to the consolidated financial statements

(In thousands of Reais)

1	Description of Business

CELSEPAR - Centrais Elétricas de Sergipe Participações S.A. (CELSEPAR or the Company) is a privately held company domiciled in Brazil, founded on December 11, 2017. The Company’s current head office is at the address Av. José Machado de Souza, 220, sala 1208, Jardins – Aracaju-SE. The Company is a joint venture of Energias Brasil Ltda. and Golar Power Brasil Ltda., each with an interest of 50% in CELSEPAR.

At inception, the Company’s share capital was R$ 500.00 (five hundred Reais), equivalent to 500 (five hundred shares), all nominative and without par value. As of December 31, 2019, the Company’s share capital is R$ 1,725,107, consisting of 1,725,107 registered common shares, with no par value. The Company was founded to acquire interests in other companies as shareholder.

Corporate restructuring

On March 16, 2018, the current shareholders of the Company contributed to CELSEPAR their respective shares of interest directly held in CELSE – Centrais Elétricas de Sergipe S.A. (CELSE or Subsidiary), corresponding to 100% of CELSE´s share capital at an amount of R$ 1,160,720 recorded as capital. In addition, the shareholders made a cash contribution in the amount of R$ 72,000. As a result, CELSE became a wholly owned subsidiary of CELSEPAR.

CELSE - Centrais Elétricas de Sergipe S.A.

CELSE - Centrais Elétricas de Sergipe S.A. is a privately held company, domiciled in Brasil, founded on September 25, 2015, having its registered office at the address Rodovia Cesar Franco SE-100, Barra dos Coqueiros, Sergipe. It is a wholly owned subsidiary of CELSEPAR.

CELSE was founded to execute, acquire, build, manage, operate and own the facilities and activities of a 1.5-GW combined-cycle gas-fired thermoelectric power station consisting of three gas turbines and one steam turbine, in addition to heat recovery. This is the first venture in Brazil to deploy the high-efficiency air-cooled (“HA”) turbines model, a model recognized by Guinness World Cup records in March 2018, due to its highly efficient conversion of energy from fuel into electricity, known as “Porto de Sergipe I”, currently under construction in Sergipe state, in Brazil’s north-east or at the Plant. The plant will have dedicated liquefied natural gas, or LNG, from an offshore regasification terminal using a Floating Storage Regasification Unit (FSRU).

The Brazilian Government authorized CELSE to establish itself as an independent electric energy company in November 23, 2015 for a period of 35 years.

The production of electricity can be sold through long-term contracts in the regulated contracting environment, obtained in auctions promoted by the National Agency of Electricity Energy (ANEEL), with fixed prices indexed to inflation or through contracts in the open contracting environment, whose prices may fluctuate due to the offer and market demand for short-term operations or fixed prices indexed to inflation, in the case of long-term contracts.

In April 2015, CELSE was the winner of the New Energy Auction A-5, conducted by the Brazilian government, establishing 26 Regulated-Environment Power Purchase Agreements (CCEAR or PPA - Power Purchase Agreement) for 25 years with several energy distributors in Brazil. CELSE consequently implemented a PPA with 26 companies to supply electricity by selling the Project’s entire installed capacity of 1.5 GW, with energy scheduled to be delivered starting on January 1, 2020. Please refer to note 27 for further details about the commencement of operation.

Construction of the Plant

In October 2016, CELSE signed an Engineering, Procurement and Construction (EPC) turnkey contract with General Electric Switzerland GmbH, General Electric International, Inc., Alstom Energia Térmica e Indústria Ltda. and Grid Solutions Transmissão de Energia Ltda., jointly referred to as GE. The EPC contractor is responsible for the construction, design, engineering and acquisition of the Plant, consisting of generators and the required equipment, a high-voltage substation and a high-voltage transmission line, amongst other systems and

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components. The EPC is a “turn-key” contract, for a lump sum of R$ 3,405,379, which was performed in three different currencies: R$ 970,286, equivalent to EUR € 214,168; R$ 1,118,093 equivalent to USD 277,394 and R$ 1,317,000, covering all direct and indirect costs incurred by the EPC contractor, its subcontractors or suppliers, when delivering the contracted work.

Construction of the Plant began in November 2016 and CELSE was undergoing operational commissioning as of December 31, 2019. In this stage, initial startup and synchronization testing is performed on the turbine-generator sets and auxiliary systems, in which commissioning teams start and connect the newly built and assembled equipment to the national grid for the first time.

Project financing

In 2018 the Company concluded financing contracts under which the full amount of debentures, in the total amount of R$ 3,370,000 was funded. The project financing, of R$ 5 billion, is structured as follows: R$ 3.4 billion has been raised through the issuance by CELSE of nonconvertible, ordinary debentures secured by Swiss Export Risk Insurance (SERV) and with Goldman Sachs Brasil as lead arranger.

In addition, the project raised R$ 804 million (equivalent to US$ 200 million) from the International Finance Corporation (IFC), a World Bank Group member for private-sector investments, and R$ 1,018 million (equivalent to US$ 288 million) from IDB Invest, the private sector arm of the Inter-American Development Bank (IDB).

The financing was obtained after the Company received all environmental licenses required at the current stage of the project, the most recent of which, for the Offshore portion, was secured from IBAMA on March 28, 2018.

Floating storage and regasification unit (FRSU)

The Golar Nanook, a newly constructed floating storage and regasification unit (FSRU), approached the coast of Sergipe on March 17, 2019 and berthed at the port of Sergipe on April 1, 2019. The arrival of the vessel was an important milestone in the CELSE thermal power station project. The FSRU has a storage capacity of 163,000 m3 of LNG and a regasification capacity of 21 million cubic meters of natural gas per day.

All environmental and regulatory licenses and permits have been timely secured, and there are currently no contingencies.

Commercial operation

On January 1, 2020 the Company failed to initiate commercial operation as agreed in its regulated- environment Power Purchase Agreements (PPA) and required under the rules of the 21^st New Power Generation Project Auction.

Among the contributing factors to the Company’s failure to timely initiate commercial operation are the following (i) multiple strikes during the course of 2018, especially the customs strike, which significantly affected plant construction; and (ii) delayed delivery of the offshore component of the project due to poor performance by the relevant contractor, delaying the availability of gas for commissioning.

In the second half of 2019, to meet its contractual obligation of the PPA, which required the availability of 867 Megawatt per minute (MWm) per month, during the first three months of 2020. CELSE, following the Resolution 595/2013 of the National Agency of Electric Energy (ANEEL), which establishes criteria for contracting electricity in the event of a delay in the start of commercial operation, entered into energy purchase agreements with Centrais Elétricas de Pernambuco (EPESA). Therefore, for January, February and March 2020, CELSE purchased an average of 867 MWm of electricity per month, delivering the necessary amount to comply with its contractual obligation with the 26 distributors, for an average price of R$ 287 per MW, totaling an amount of R$547,189. As determined in the PPA, the effective delivery of energy when not required by the operator of the national electricity system is valued at market price on the date of the effective transaction, as the energy purchase and sale transactions were closed at the same date and following the spot price at the date of each transaction, the Company had no material impact as a result of these transactions.

As at December 31, 2019 the project was in a final stage of commissioning. The commercial operation started on April 1, 2020 (for further detail please refer to note 25) and based on the PPAs, CELSE’s revenues for

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the sale of energy include (i) a fixed Brazilian real denominated revenue component (indexed for inflation) for the availability of the power plant, and (ii) a variable revenue component based on the MWh amount of energy generated, if any. Each purchaser under the PPAs has executed a security agreement, providing for the encumbrance of part of each purchaser’s revenues to ensure the satisfaction of its payment obligations under its PPAs.

2	Statement of compliance

The consolidated financial statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (IASB). They were authorized for issue by Board of Directors on August 13, 2020.

a) Basis of presentation of Company’s consolidated financial statements – Predecessor method

The Company became CELSE’s holding company through the Corporate Restructuring described above. The transaction was recorded at book value since it was a transaction under common control.

Under IFRS there is no specific guidance applicable to business combinations of entities under common control, as IFRS 3, Business Combinations, excludes from its scope business combinations between such entities.

Due to the lack of specific guidance the Company has established an accounting policy as required by IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. In doing so, the Company considered guidance of other standards-setting bodies that use a similar conceptual framework to develop accounting standards as well as the accounting practices of entities subject to those standards such as the United States of America.

As a result, the Company accounted for the Corporate Restructuring using the predecessor method of accounting, and the consolidated financial statements are presented “as if” CELSE is the predecessor of the Company. Under the predecessor method, the historical operations of CELSE are deemed to be those of the Company. Thus, these consolidated financial statements reflect:

(i)	the historical operating results and financial position of CELSE prior to the Corporate Restructuring;

(ii)	the consolidated results of the CELSEPAR and CELSE following the Corporate Restructuring; and

(iii)

the assets and liabilities of CELSE at their historical cost.

b) Reconciliation of the Company and CELSE’s shareholders’ equity as of December 31, 2018:

	Company	CELSE	Predecessor adjustments
Capital^(a)	1,334,608	1,364,352	(29,744)
Special reserve^(a)	36,346	—	36,346
Accumulated loss^(b)	(64,314)	(63,776)	(538)

(a)

The Company formation resulted in a Capital of R$ 1,334,608 and a statutory reserve, called special reserve, of R$ 36,346. Considering that capital contributed by the controlling shareholders was measured based on the CELSE’s equity on March 16, 2018, the mathematical calculation determined a difference of R$ 29,744 to be adjusted so that the balance on December 31 reflects the corresponding corporate acts on December 31, 2018.

(b)	Accumulated losses – The sum of CELSE’s losses for the year ended 31, December 2018 of R$ 35,898, and the adjustment of R$ 538, corresponding to CELSEPAR´s individual losses for the same period, represents the Company results of operations during the year ended December 31, 2019 of R$ 36,436.

3	Functional currency and reporting currency

The financial statements are presented in Brazilian Reais (R$), which is also the Company’s and its subsidiary functional currency, since it is the currency of the primary economic environment in which they operate, generate and consume cash. All amounts have been rounded to the nearest thousand, unless otherwise indicated.

4	Use of estimates and judgments

In preparing these financial statements, management has made judgements and estimates that affect the application of the Company’s accounting policies and the reported amounts of assets, liabilities, income and

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expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to estimates are recognized prospectively.

(a) Judgments

Information about judgements made in applying accounting policies that have the most significant effects on the amounts recognized in the financial statements is included in the following notes:

•	Note 14 – fixed asset: evaluation of capitalizable cost.

(b) Assumptions and estimation uncertainties

Information about assumptions and estimation uncertainties that have a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities in the next financial year is included in the following notes:

•	Note 10 – recognition of deferred tax assets: availability of future taxable profit against which deductible temporary differences and tax losses carried forward can be utilized;

•	Note 14 – determination of the useful life of fixed assets;

A number of the Company’s accounting policies and disclosures require the measurement of fair value for financial and non-financial assets and liabilities.

Management regularly reviews significant unobservable data and valuation adjustments. If third-party information such as quotes from brokers or pricing services is used to measure fair value, management reviews the evidence obtained to support the conclusion that such assessments meet the accounting requirements, including the hierarchy level of fair value in such assessments should be classified.

In measuring the fair value of an asset or a liability, the Company uses observable market data whenever possible. The fair values are classified into different levels in a hierarchy based on the information (inputs) used in the valuation techniques as follows:

•	Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities;

•	Level 2: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (prices) or indirectly (derived from prices);

•	Level 3: Inputs for the asset or liability that are not based on observable market data (unobservable inputs).

5	Basis of measurement

The financial statements have been prepared on the historical cost basis excluding financial instruments measured at fair value through profit or loss.

6	Description of significant accounting policies

The Company’s main accounting policies are the following:

6.1	Consolidation basis

The consolidated financial statements include the financial statements of the Company and its subsidiary listed below:

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Subsidiary

Subsidiaries are entities controlled by the Company. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The financial statements of subsidiaries are included in the consolidated financial statements from the date on which controls commences until the date on which control ceases.

Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealized income and expenses arising from intra-group transactions, are eliminated.

6.2	Foreign currency

Transactions in foreign currencies are translated into the respective functional currencies at the exchange rates at the dates of the transactions.

Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the exchange rate at the reporting date. Non-monetary assets and liabilities that are measured at fair value in a foreign currency are translated to the functional currency at the exchange rate when the fair value was determined. Non-monetary items that are measured based on historical cost in a foreign currency are translated at the exchange rates at the date of the transaction. Any Foreign-currency differences arising from cost not directly related to the construction of the plant are generally recognized in profit or loss. Foreign-currency differences related to borrowing cost are capitalized during the construction phase of the plant.

6.3	Financial instruments

(i) Recognition and initial measurement

Trade accounts receivable and debt securities issued are initially recognized when they are originated. All other financial assets and financial liabilities are initially recognized when the Company becomes a party to the contractual provisions of the instrument.

A financial asset (unless it is a trade accounts receivable without a significant financing component) or financial liability is initially measured at fair value plus, for an item not measured at FVTPL, transaction costs that are directly attributable to its acquisition or issue.

(ii) Classification and subsequent measurement

Financial Assets

On initial recognition a financial asset is classified as measured: at amortized cost; at FVOCI (fair value through other comprehensive income) - debt investment; at FVOCI - equity instrument; or at FVTPL (fair value through profit or loss).

Financial assets are not reclassified subsequently to initial recognition, unless the Company changes its business model for managing financial assets in which case all affected financial assets are reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is measured at amortized cost if both of the following conditions are met and it is not designated as at FVTPL:

-	it is held within a business model whose objective is to hold assets to collect contractual cash flows; and

-	its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

A debt investment is measured at FVOCI if both of the following conditions are met and it is not designated as at FVTPL:

-	it is held within a business model whose objective is achieved by both the collecting contractual cash flows and the selling financial assets; and

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-	its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

All financial assets not classified as measured at amortized cost or FVOCI, as described above, are classified as FVTPL. On initial recognition, the Company may irrevocably designate a financial asset that otherwise meets the requirements to be measured at amortized cost or at FVOCI as at FVTPL if doing so eliminates or significantly reduces an accounting mismatch that would otherwise arise.

Financial assets - Business model assessment

Management assesses the objective of the business model in which a financial asset is held at a portfolio level because this best reflects the way the business is managed and information is provided to Management. The information considered includes:

the stated policies and objectives for the portfolio and the operation of those policies in practice. These include whether management´s strategy is focused on earning contractual interest income, maintaining a particular interest rate profile, matching the duration of the financial assets to the duration of any related liabilities or expected cash outflows, or the realization of cash flows through the sale the assets;

-	how the portfolio’s performance is evaluated and reported to Company´s management;

-	the risks affecting the performance of the business model (and the financial assets held within that business model) and how those risks are managed; and

-	the frequency, volume and timing of the sale of financial assets in prior periods, the reasons for such sales and expectations about future sales activities.

Transfers of financial assets to third parties in transactions that do not qualify for derecognition are not considered sales for this purpose, consistent with the Company’s continuing recognition of the assets.

Financial assets held-for-trading or managed whose performance is evaluated on a fair value basis are measured at fair value through profit or loss (FVTPL).

Financial assets - assessment whether contractual cash flows are solely payments of principal and interest.

For the purpose of this assessment, “principal” is defined as the fair value of the financial asset on initial recognition. “Interest” is defined as consideration for the time value of the money and for the credit risk associated with the principal amount outstanding during a particular period of time and for other basic lending risks and costs (e.g. liquidity risk and administrative costs), as well as a profit margin.

In assessing whether the contractual cash flows are solely payments of principal and interest, the Company considers the contractual terms of the instrument. This includes assessing whether the financial asset contains a contractual term that could change the timing or amount of contractual cash flows such that it would not meet this condition. In making this assessment the Company considers:

-	contingent events that would change the amount or timing of cash flows;

-	terms that may adjust the contractual coupon rate, including variable-rate features;

-	prepayment and extension features; and

-	terms limiting the Company’s claim to cash flows from specified assets (e.g. non-recourse features).

Financial liabilities - classification, subsequent measurement and gains and losses

Financial liabilities were classified as measured at amortized cost, expenses on interest, exchange variance gains and losses are recognized in profit or loss, when not directly related to the construction of the plant. Any gain or loss resulting from derecognition is also recognized in profit or loss.

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(iii) Derecognition

Financial liabilities

The Company derecognizes a financial liability when its contractual obligations are discharged or canceled, or expire. The Company also derecognizes a financial liability when its terms are modified and the cash flows of the modified liability are substantially different, in which case a new financial liability based on the modified terms and recognized at fair value.

On derecognition of a financial liability, the difference between the carrying amount extinguished and the consideration paid (including any non-cash assets transferred or liabilities assumed) is recognized in profit or loss.

(iv) Offsetting

Financial assets and liabilities are offset and the net amount presented in the statement of financial position when, and only when, the Company has a legally enforceable right to set off the amounts and it intends either to settle them on a net basis or to realize the asset and settle the liability simultaneously.

6.5	Impairment

(i) Non-derivative financial assets

The Company recognizes provisions for expected credit losses on financial assets measured at amortized cost;

The Company measures the provision for loss at an amount equal to lifetime expected credit losses, except for the items described below, which are measured as expected credit loss for 12 months:

•	Debt securities with low credit risk at the reporting date; and

•	Other debt securities and bank balances for which the credit risk (i.e. the risk of default over the expected lifetime of the financial instrument) has not increased significantly since initial recognition.

The Company considers a financial asset to be in default when:

•	It is highly unlikely that the debtor will pay all of its credit obligations to the Company without recourse by the Company to actions such as realizing security (if any is held); Lifetime ECLs are ECLs that result from all possible default events over the expected life of a financial instrument.

•	12-month ECLs are ECLs that result from possible default events within the 12 months after the reporting date (or a shorter period, if the instrument’s expected life is shorter than 12 months).

The maximum period considered to estimate the expected credit loss is the maximum contractual period during which the Company is subject to credit risks.

(ii) Impaired financial assets

At each reporting date, the Company assesses whether the financial assets carried at amortized cost are credit impaired. A financial asset is ‘credit-impaired’ when one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred.

Objective evidence that a financial asset is credit-impaired includes the following observable data:

•	Significant financial difficulty of the issuer or borrower;

•	Violation of contractual clauses, such as default or being more than 90 days overdue;

•	The restructuring of an amount due to the Company on terms that it would not consider otherwise;

•	It is probable that the borrower will enter bankruptcy or other type of financial reorganization; or

•	The disappearance of an active market for a security because of financial difficulties.

(iii) Presenting the provision for expected credit losses in the statement of financial position

The provision for financial asset losses measured at amortized cost is deducted from the gross carrying amount of the assets. The Company presents the provision of expected credit losses as a specific line item in the statement of profit or loss. As of December 31, 2019 and 2018, there is no provision recorded.

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(iv) Write-off

The gross carrying amount of financial asset is written off when the Company does not have a reasonable expectation to recover the financial asset in its entirety or in part. As of December 31, 2019 and 2018, the Company did not write off any financial asset.

(v) Non-financial assets

At each reporting date the Company reviews the carrying amounts of its non-financial assets (deferred taxes) for impairment indicators. If any such indication exists, the asset’s recoverable amount is estimated.

For impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or cash-generating units (CGUs).

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Value in use is based on the estimated future cash flows, discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU.

An impairment loss is recognized if the carrying amount of an asset or CGU exceeds its recoverable amount.

The Company did not record any impairment charge for the fiscal years 2018 and 2019.

6.6	Property, plant and equipment

Property, plant and equipment are stated at historical cost less accumulated depreciation, calculated by the depreciation rate according to the estimated useful life of each part of a property, plant and equipment item. The historical cost includes expenses directly attributable to buy the assets and includes financing costs related to the acquisition of qualifying assets.

Depreciation is calculated to write off the cost of items of property, plant and equipment less their estimated residual values using the straight-line basis over their estimated useful lives. Depreciation is recognized in profit or loss. Land is not depreciated.

The depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted when necessary.

As of December 31, 2018 and 2019 the Company was building its energy generation plant (pre-operating stage), thus depreciation expense included certain administrative assets in 2019 and 2018.

6.7	Income and social contribution taxes

The income and social contribution taxes, both current and deferred, are calculated based on the rates of 15% plus a surcharge of 10% on taxable income in excess of R$ 240 thousand for income tax and 9% on taxable income for social contribution on net income, and consider the offsetting of tax loss carryforwards and negative basis of social contribution limited to 30% of the taxable income.

Income tax and social contribution expense comprises current and deferred income tax and social contribution. Current tax and deferred tax are recognized in profit or loss except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income.

(i) Income tax and social contribution expenses - current

Current tax comprises the expected tax payable or receivable on taxable income or loss for the year and any adjustment to tax payable or receivable in respect of previous years. The amount of current tax payable or receivable is recognized in the statement of financial position as an asset or liability and is the best estimate of the tax amount expected to be paid or received that reflects uncertainty related to income taxes, if any. It is measured using tax rates enacted at the reporting date.

Deferred tax assets and liabilities are offset only if certain criteria have been met.

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(ii) Deferred income tax and social contribution expense

The deferred income taxes (Imposto de Renda – Pessoa jurídica / IRPJ and Contribuição Social sobre o Lucro Líquido / CSLL) are calculated on differences between the balances of assets and liabilities in the Financial Statements and the corresponding tax bases. The probability of recovering these balances is reviewed at the end of each year, and when it is no longer probable that future taxable income will be available to enable the recovery of all or part of the taxes, the asset balance is reduced by the amount expected to be recovered.

Deferred tax assets are recognized for unused tax losses and unused deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary differences is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on the business plans of the Company.

Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, using tax rates enacted or substantively enacted at the reporting date, and reflects the uncertainty around the income tax, if applicable.

The measurement of deferred tax assets and liabilities reflects the tax consequences that would follow the manner in which the Company expects to recover or settle its assets and liabilities. Deferred tax assets and liabilities are offset only if certain criteria are met.

6.8	Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of resources will be required to settle the obligation. When applicable, provisions are calculated by discounting future expected cash disbursements at a rate that reflects current market assessments and specific risks posed by the liability.

6.9	Finance income and finance costs

Interest income or expense is recognized using the effective interest method, which means the rate that discounts the estimated future cash payments or receipts through the expected life of the financial instrument at:

-	gross carrying amount of the financial asset; or

-	at amortized cost of the financial liability.

When calculating the interest revenue or expense, the effective interest rate is charged on the gross carrying amount of the asset (when the asset is not impaired) or at the amortized cost of the liability. However, interest revenue is calculated by applying the effective interest rate to the amortized cost of the financial asset.

6.10	Revenue recognition

Contracts for the sale of electricity are carried out in the open and regulated Brazilian commercial environments, being fully registered at the Electric Energy Commercialization Chamber (CCEE), the agent responsible for accounting and settlement of the national integrated system.

The accounting measurement of the volume of energy to be billed results from the processing of the physical measurement (generation), adjusted to the proportional losses related to the system reported by the CCEE.

The accounting recognition of revenue results from the amounts to be billed to customers according to the methodology and prices established in each contract, adjusted to amounts of energy actually generated, when applicable. These adjustments result from the CCEE’s mechanisms that verify the Company’s net exposure (sale, generation and purchases), called energy balance, which credits or debits the difference between the Company’s sale and actual generation, usually at the value of the Settlement Price for Differences (PLD).

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The mechanisms explained above result in two types of revenue streams, as follows:

Revenue from the sale of energy contracted by availability (performance obligations satisfied over time): referring to fixed revenue, recognized by the plant availability contract. The Company has legal right in its contracts for the sale of electricity in the regulated environment (CCEAR), additionally there is no right of return or need of the customer acceptance. Revenue is recognized when the energy contracted is made available to customers, which represents the fulfillment of the performance obligation provided for in the contract.

Revenue from the sale of energy supplied (performance obligations satisfied at a point in time): referring to variable revenue, recognized through measurements to determine the volumes of energy supplied, related to the Unit Variable Cost (CVU) and the Short-Term Market (MCP), in addition to the reimbursement of energy purchased from CCEE. The revenue from energy supplied and the associated costs are recognized by the delivery of the energy generated to customers.

6.11	Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in the principal or, in its absence, the most advantageous market to which the Company has access at that date. The fair value of a liability reflects its non-performance risk. The risk of nonperformance includes the Company’s own credit risk, amongst other factors.

A number of the Company’s accounting policies and disclosures require the measurement of fair values, for both financial and non-financial assets and liabilities.

When one is available, the Company measures the fair value of an instrument using the quoted price in an active market for that instrument. A market is regarded as active if transactions for the asset or liability take place with sufficient frequency and volume to provide pricing information on an ongoing basis.

If there is no quoted price in an active market, then the Company uses valuation techniques that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. The chosen valuation technique incorporates all of the factors that market participants would take into account in pricing a transaction.

If an asset or a liability measured at fair value has a bid price and an ask price, then the Company measures assets and long positions at a bid price and liabilities and short positions at an ask price.

IFRS 7.28(a) The best evidence of the fair value of a financial instrument on initial recognition is normally the transaction price – i.e. the fair value of the consideration given or received. If the Company determines that the fair value on initial recognition differs from the transaction price and the fair value is evidenced neither by a quoted price in an active market for an identical asset or liability nor based on a valuation technique for which any unobservable inputs are judged to be insignificant in relation to the measurement, then the financial instrument is initially measured at fair value, adjusted to defer the difference between the fair value on initial recognition and the transaction price.

Subsequently, that difference is recognized in profit or loss on an appropriate basis over the life of the instrument but no later than when the valuation is wholly supported by observable market data or the transaction is closed out.

The best evidence of the fair value of a financial instrument on initial recognition is normally the transaction price - i.e. the fair value of the consideration given or received. If the Company determines that the fair value on initial recognition differs from the transaction price and the fair value is evidenced neither by a quoted price in an active market for an identical asset or liability nor based on a valuation technique for which any unobservable inputs are judged to be insignificant in relation to the measurement, then the financial instrument is initially measured at fair value, adjusted to defer the difference between the fair value on initial recognition and the transaction price. Subsequently, that difference is recognized in profit or loss on an appropriate basis over the life of the instrument but no later than when the valuation is wholly supported by observable market data or the transaction is closed out.

7	Changes in significant accounting policies

The Company initially adopted IFRS 16 on January 01, 2019. A series of other new standards are effective from this date, but do not materially affect the Company’s financial statements.

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IFRS 16 – Leases

The Company applied IFRS 16 - Leases, using the modified retrospective approach and, therefore, comparative information has not been restated and continues to be presented in accordance with IAS 17 - Leasing Operations and IFRIC 4 - Determining Whether an Arrangement Contains a Lease. At the beginning of a contract, the Company assessed whether a contract is or contains a lease, if the contract transfers the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract transfers the right to control the use of an identified asset, the Company uses the definition of lease in IFRS 16. The Company opted not to recognize right-of-use assets and lease liabilities for leasing low-value assets (assets less than US $ 5,000.00) (five thousand), and / or (ii) are short-term leases (with a term less than 12 months), including IT equipment. The Company recognizes lease payments associated with these leases as an expense on a straight-line basis over the lease term.

Management assessment

Based on Management’s assessment, the study of applicability and the criteria of the standard established, on January 1, 2019, by the adoption of IFRS 16, the Company came to the conclusion that the impacts were immaterial, causing no adjustment in this consolidated financial statement.

IFRIC 23 - Uncertainty over income tax treatment

This interpretation addresses the accounting of income taxes, recognition and measurements, when tax treatments involve uncertainty that affects the application of IAS 12 - Income Taxes and does not apply to taxes or charges outside the scope of IAS 12, nor does it specifically include treatment of interest and penalties associated with uncertain taxes.

Management assessment

Company’s Management conducted analyzes of tax treatments that could generate uncertainties in the calculation of income taxes, measuring and reassessing those that could potentially expose the Company to risks in view of the uncertainty of its tax treatment. The analysis extended to administrative and judicial tax processes that could incur a change in the calculation of said taxes. After the analysis, Management concluded that there is no uncertain tax position taken by the Company, and there are no adjustments related to IFRIC 23 in its consolidated financial statement.

New standards and interpretations not yet effective

A series of new standards will be effective for years beginning after January 1, 2020. The Company did not adopt these standards in the preparation of these financial statements. The following amended rules and interpretations are not expected to have a significant impact on the Company’s consolidated financial statements:

-	Changes in the references to the conceptual framework in IFRS standards.

-	Definition of a business (changes to IFRS 3).

-	Definition of materiality (amendments to IAS 1 and IAS 8).

8	Cash and cash equivalents

		12/31/2019	12/31/2018
Cash and bank deposits		13,104	60,405
Short-term investments
Santander - ContaMax Empresarial	10% CDI	13,616	14,970
CitiBank - Cash Blue RF Referenciado DI FI	94% CDI	170,405	27,393
Total		197,125	102,768

As of December 31, 2018 and 2019, cash and cash equivalents consist of cash, demand deposits and certain short-term investments. These securities are highly liquid, unrestricted, readily convertible into a known amount of cash and subject to an insignificant risk of impairment. These short-term investments are floating securities yielding from 10% to 94% of the Interbank Deposit Certificate (CDI) rate.

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9	Short-term investments

		12/31/2019	12/31/2018
Short-term investment - DSRA^(a) - Cash Blue RF Referenciado DI FI	92% CDI	399,689	371,132
Short-term investment - Swiss note^(b)	0.19% pm	46,917	141,679
Total		446,606	512,811

(a)

Debt Service Reserve Account (DSRA) consists of amounts deposited in accounts to secure financing. These amounts are invested in CDI-indexed investment funds. The amount to be maintained in these accounts is monthly calculated based on the rules of financing. If this account balance is greater than the amount minimum established, the Company may withdraw the difference; if it is less, the difference is deposited. The minimum balance to be kept in this accounts is subject to the following rules: (i) Debentures: whichever is greater between 1 (one) year of interest or 6 (six) months of interest plus principal; and (ii) Mandated Lead Arranger (MLA’s): 6 months of interest plus principal. The Company may use the funds allocated in these deposit accounts to make short-term interest and principal payments. However, the amounts withdrawn must be replaced by the Company in order to be in compliance with the rules above which is included in the loan and debentures agreements.

(b)	The Swiss note amounted to USD 11,304 (R$ 46,917) as of December 31, 2019 is kept in an interest- bearing current account in Switzerland, at Credit Suisse bank. The investment may be withdrawn at any time. The interest is fixed.

10	Deferred income and social contribution taxes

The Company and its subsidiary recognize tax credits, resulting from tax losses and negative bases. The credits recognition is based on future profitability of its operations. Deferred Corporate Income Tax (IRPJ) and Social Contribution on Net Income (CSLL) are presented as follows:

			Tax losses and negative bases
Balance as of 01/01/2018			—
Income statement impact			32,854
			32,854
Balance as of 12/31/2018
Income statement impact			5,388
Balance as of 12/31/2019			38,242

In December 31, 2018, the deferred income and social contribution taxes credits from prior years were fully recognized in the total amount of R$ 32,854. The total amount of tax loss carryforward is R$ 113,600 (R$ 96,630 in 2018)

Realization of deferred income and social contribution tax

When it is more likely than not all taxes will be realized, no provision for realization is made. Possibility of using tax losses does not expire, but the use of these losses accumulated in prior years is limited to 30% of taxable annual income.

In order to evaluate the realization of deferred tax assets, the taxable income projections from the Company´s business plan, which indicates trends and perspectives, demand effects, competition and other economic factors that represent management’s best estimate about the economic conditions existing during the period of realization of the deferred tax asset were taken into account.

Even though the Company had not started its operations as of December 31, 2019, the projection performed used reasonable assumption to conclude whether the deferred tax would be realized. The Company currently has in place 26 Purchase power agreements and contracts with main suppliers that provides insight to estimate future revenue and cost expectations. See further explanation about commercial operations at note 1 and the contracts signed with supplier at notes 25. Managements future taxable projection was performed to a period of 5 years, for which the deferred tax recognized was fully realizable.

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11	Transaction costs

The Company incurred in costs that are directly attributable to the acquisition / issuance of debentures and loans, such as fees and commissions paid to agents, advisers, brokers and dealers, levies by regulatory agencies, transfer taxes and duties. These costs do not include debt premium or discount, financing costs or internal administrative or holding costs.

Transaction costs are capitalized and amortized over the life of the related debt. Amount paid in advance of debt issuance are reflected as non-current assets. As of December 31, 2019 and 2018, R$ 29,326 and R$ 47,432 are held in non-current assets.

As of December 31, 2019 and 2018, the Company had incurred in transaction costs as follows:

		Financial liabilities acquired / issued
	Cost incurred – cash outflow	Debentures	IFC^(b)	IDB^(c)	IDB Invest^(d)	IDB China Fund^(e)	Total transaction cost
Balance at January 1, 2018	36,007	—	—	—	—	—	36,007
Total transaction cost incurred during the year	727,041						727,041
Transaction cost allocation:
Debentures - April 2018^(a)		(680,072)					(680,072)
1^st disbursement - June 2018			(9,274)	(9,029)	(1,762)	(2,320)	(22,385)
2^nd disbursement - September 2018			(6,258)	(4,428)	(1,068)	(1,405)	(13,159)
Balance at December 31,2018	763,048	(680,072)	(15,532)	(13,457)	(2,830)	(3,725)	47,432

Total transaction cost incurred during the year^(f)	24,333						24,333
Transaction cost allocation:
3^rd disbursement - February 2019		—	(13,047)	(13,139)	(2,431)	(3,198)	(31,815)
4^th disbursement - November 2019		—	(4,583)	(4,050)	(860)	(1,131)	(10,624)
Balance at December 31,2019	787,381	(680,072)	(33,162)	(30,646)	(6,121)	(8,054)	29,326

(a)

The main transaction cost is related to the issuance of debentures, which was the premium paid to Swiss Export Risk Insurance (SERV) for guaranteeing the transaction through the issuance of an insurance policy guaranteeing the amount of R$ 3,447,502 in in the event of Company default. (refer to note 15)

(b)	International Finance Corporation (IFC)

(c)	Inter-American Development Bank (IDB)

(d)	IDB Invest is the private section arm of the IDB Group

(e)	An agent representing IDB, IDB Invest will administer the Co-financing Fund of China for Latin America and the Caribbean.

(f)	In 2019, CELSEPAR recorded Transaction Costs in the amount of R$ 15,692 related to the GE Capital Loan. As disclosed in subsequent events explanatory note, such transactions was closed in January and March 2020.

The debt agreements with IFC, the IDB, the IDB Invest and the IDB China Fund have up to five tranches, which require the achievement of certain milestones related to the construction of the plant, social interventions, studies and analyzes, for the release of funds. The fifth and final tranche was released by the creditors in April 2020.

12	Inventories

	12/31/2019	12/31/2018
Liquified natural gas (LGN)	63,965	—
Consumption materials	10	—
Balances at December 31, 2019	63,975	—

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13	Advance for Property, plant and equipment acquisition

Advance to suppliers related to the acquisition of property, plant and equipment that will be transferred to property, plant and equipment as soon as the assets are delivered to the Company. The table below represents the movements on the advances through:

	2019	2018
Opening balance	2,375,906	558,628
(+) New advances	156,460	2,606,496
(-) Transfer to accounts payable	(2,391,101)	(789,218)
Final balance	141,265	2,375,906

14	Property, plant and equipment

Breakdown

		12/31/2019			12/31/2018
	Annual depreciation rates (%)	Cost	Accumulated depreciation	Total	Cost	Accumulated depreciation	Total
Machinery and equipment^(a)	3.33 to 10	118	(22)	97	109	(14)	95
Buildings^(a)	4 to 10	115	(16)	99	115	(5)	110
Furniture and fixtures^(a)	10	3,084	(849)	2,235	2,755	(451)	2,304
Land^(a)	—	7,567	—	7,567	7,567	—	7,567
Property, plant and equipment in progress^(a)	—	5,176,992	—	5,176,992	1,522,476	—	1,522,476
		5,187,876	(887)	5,186,989	1,533,022	(470)	1,532,552

(a)	On December 31, 2019 and 2018, all property, plant and equipment of the Company were pledged to guarantee loans and borrowing (Note 16).

b.	Reconciliation of the carrying amount

	Land	Machinery and equipment	Buildings	Furniture and fixtures	Total in operation	Property, plant and equipment in progress	Total
Balances at December 31, 2018	7,567	95	110	2,304	10,076	1,522,476	1,532,552
Write-off	—	—	—	—	—	—	—
Acquisition	—	9	—	329	338	3,654,516	3,654,854
Depreciation	—	(7)	(12)	(398)	(417)	—	(417)
Balances at December 31, 2019	7,567	97	99	2,235	9,998	5,176,992	5,186,989

	Land	Machinery and equipment	Buildings	Furniture and fixtures	Total in operation	Property, plant and equipment in progress	Total
Balances at December 31, 2017	7,567	91	8	1,518	9,184	160,375	169,559
Write-off	—	—	—	(22)	(22)	—	(22)
Acquisition	—	15	105	1,102	1,222	1,362,101	1,363,323
Depreciation	—	(11)	(3)	(294)	(308)	—	(308)
Balances at December 31, 2018	7,567	95	110	2,304	10,076	1,522,476	1,532,552

Land

Denotes the price paid to buy the land where the thermal power plant UTE Porto de Sergipe I is located.

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Property, plant and equipment in progress

As mentioned earlier, the Company and GE signed an EPC agreement in the form of lump sum turnkey to build the power station. The amounts recorded in property, plant and equipment in progress primarily consists of advances made to GE to acquire equipment to build the Power Station, secured by banks guarantees. The Company also classifies as property, plant and equipment in progress the expenses incurred on environmental licensing and development project studies. The balances have been recorded under property, plant and equipment in progress and will be transferred to property, plant and equipment in service when the Plant comes into operation.

Depreciation

Depreciation expenses of R$ 417 as of December 31, 2019 (R$ 308 as of December 31, 2018) incurred on offices’ equipment, buildings, furniture and fixtures were recorded in profit and loss for the year.

Capitalization of borrowing costs

Capitalized borrowing costs for the year ended December 31, 2019, R$ 661,307 was capitalized at an average rate of 10.27% p.a. (R$ 385,226 and 10.27% p.a. on December 31, 2018). The Company has classified capitalized interest as cash flows operating activities.

15	Account payables

	12/31/2019	12/31/2018
Alstom Energia Térmica e Indústria Ltda.	35,349	—
Sapura Energy do Brasil Ltda	38,647	—
AON UK Limited	833	3,993
General Electric Switzerland GMBH	195,957	—
Independent legal advisers	9	1,240
Grid Solutions Transmissão de Energia	1	120
Golar Nanook UK Limited^(a)	111,357	—
Golar Power Latam Serviços Marítimos Ltda.	2,746	—
Other	26,316	4,913
Total	411,215	10,266
Current	297,112	10,266
Non current	114,103	—

(a)

The logistical solution for supplying gas to UTE Porto de Sergipe I will consist of chartering the Golar Nanook FSRU (Floating Storage Regasification Unit) from the indirect parent company Golar Power Ltd. The FSRU is currently in Brazil, having moored at Porto de Sergipe on April 01, 2019. As of December 31, 2019, the FSRU has not been placed in service and is currently at the commissioning stage undergoing inspections, adjustments, and performance tests.

On December 31, 2019, the Company did not record the agreement as lease under IFRS 16, because the FSRU had not yet finalized the performance tests nor was there an execution of the certificate of acceptance, which are the triggers for the commencing period, and would represent the date that the underlying asset is made available and controls have been transferred to CELSE. Based on the agreement, the FSRU will be available for use when control has transferred to the charterer, which per the contract occurs when the charter hire commences on the acceptance date, which is defined in the agreement as the charterer’s acceptance of the owners’ delivery of the FSRU following the performance test, which shall be evidenced by and occur upon execution of the certificate of acceptance.

FSRU charter contract established that the Golar Nanook UK Limited was required to complete certain performance tests within 45 days of the date of delivery. However, because such performance tests required the power plant to be operational (which did not occur until March 2020), charter hire began to accrue beginning on May 17, 2019, the expiration of the 45-day period and date of provisional acceptance, pursuant to the contract. Based on the agreement any amount charged prior to the certificate of acceptance date should be deferred, and the deferred amount plus any interest incurred thereon should be paid by CELSE on an amortized loan basis, in equal installments, starting at the acceptance date and ending upon expiry of the agreement period. Given that this linked to the whole lease contract, as of December 31, 2020, CELSE recognized the amount of R$ 111,357 as a non-current lease prepayment asset and non- current accounts payable (lease liability).

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16	Loans and Borrowing

In April 2018, the Company entered into financing contracts, which funds will be available by banks and multilateral organizations throughout the years of 2018 and 2019. Please see below our financing structure:

IFC^(a)

Real

Capital improvements

IPCA* +10.14%

2018 - 2032

R$ 696,220

10.51%

IDB^(b)

Real

Capital improvements

IPCA* +10.34%

2018 - 2032

R$ 664,000

10.48%

IDB Invest^(c)

US dollar

Capital improvements

US Dollar +5.40%+Libor

2018 - 2032

USD 38,000

8.35%

IDB China Fund^(d)

US dollar

Capital improvements

US Dollar +5.40%+Libor

2018 - 2032

USD 50,000

8.35%

*	IPCA – Brazilian inflation index

(a)	International Finance Corporation (IFC)

(b)	Inter-American Development Bank (IDB)

(c)	IDB Invest is the private section arm of the IDB Group

(d)	An agent representing IDB, IDB Invest will administer the Co-financing Fund of China for Latin America and the Caribbean.

Below are the movements that occurred for the year ended December 31, 2019:

2019	IFC	IDB	IDB Invest	IDB China Fund	Total
Opening balance	400,825	339,653	73,891	97,224	911,593
(+) Inflow	297,444	258,960	56,514	74,361	687,279
(+) Interest	81,153	70,351	9,576	12,600	173,680
(+/-) Exchange Variance	—	—	6,379	8,393	14,772
(-) Interest Payment	(55,831)	(48,555)	(8,922)	(11,739)	(125,047)
(+) Commitment Fee	2,709	2,199	586	655	6,149
(-) Commitment Fee Payment	(3,394)	(2,806)	(711)	(828)	(7,739)
(-) Issuance costs	(17,630)	(17,189)	(3,291)	(4,329)	(42,439)
(+) Amortization Issuance costs	2,374	2,190	592	778	5,934
Final balance	707,650	604,803	134,614	177,115	1,624,182
Current	14,208	12,229	2,148	2,825	31,410
Noncurrent	693,442	592,574	132,466	174,290	1,592,772
Total	707,650	604,803	134,614	177,115	1,624,182

Below are the movements that occurred for the year ended December 31, 2018:

2018	IFC	IDB	IDB Invest	IDB China Fund	Total
Opening balance	—	—	—	—	—
(+) Inflow	399,628	338,640	75,929	99,907	914,104
(+) Interest	23,723	20,608	2,624	3,453	50,408
(+/-) Exchange Variance	—	—	(881)	(1,160)	(2,041)
(-) Interest Payment	(8,524)	(7,466)	(1,288)	(1,695)	(18,973)
(+) Commitment Fee	5,704	4,901	1,058	1,391	13,054
(-) Commitment Fee Payment	(4,671)	(4,016)	(860)	(1,132)	(10,679)
(-) Issuance costs	(15,532)	(13,457)	(2,830)	(3,725)	(35,544)
(+) Amortization Issuance costs	497	443	139	185	1,264
Final balance	400,825	339,653	73,891	97,224	911,593
Current	9,401	8,113	1,504	1,979	20,997
Noncurrent	391,424	331,540	72,387	95,245	890,596
Total	400,825	339,653	73,891	97,224	911,593

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In addition to the amounts of interest paid detailed in the tables above, the company paid as a commitment fee the amounts of R$ 7,738 and R$ 10,679 in 2019 and 2018, respectively.

Non-current borrowings are scheduled to fall due as follows:

Year	Principal	Transaction costs	Loans and borrowings noncurrent
2021	94,369	(8,038)	86,331
2022	73,820	(7,964)	65,856
2023	128,593	(7,811)	120,782
2024	106,468	(7,652)	98,816
2025	136,827	(7,285)	129,542
2026	155,542	(6,639)	148,903
2027	169,100	(5,926)	163,174
2028	196,300	(4,851)	191,449
2029	217,344	(3,524)	213,820
2030	186,972	(2,068)	184,904
2031	126,906	(1,022)	125,884
2032	63,458	(147)	63,311
Total	1,655,699	(62,927)	1,592,772

Guarantees

The financing agreements of CELSE are guaranteed by the following assets:

•	All shares issued by CELSE and held by CELSEPAR;

•	Machinery, land, properties, equipment and mobile assets;

•	Current and future rights arising from the Contracts for the Purchase and Sale of Energy in the Regulated Environment or related thereto, as well as any and all rights arising from ANEEL’s authorization;

•	Bank accounts in relation to all credit rights of each of the respective bank accounts;

•	Brazilian Project Documents entered by the Company with respect to the Project – Porto de Sergipe I;

•	Insurance and reinsurance policies; and

•	All tangible and intangible assets.

Financial Covenants

Contracts with various creditors contain covenants. The most important financial covenant is the requirement to maintain, beginning in March 2021, the Debt Service Coverage Ratio (DSCR) for the 12-month period, immediately prior to the calculation date, at no less than 1.10. The DSCR is a measurement of a firm’s available cash flow to pay current debt obligations. The DSCR shows investors whether a company has enough income to pay its debts.

DSCR =			Cash Flow Available for Debt Service
			Debt Service

The “Cash Flow Available for Debt Service” is calculated as follows:

(a)	net proceeds

(b)	Project Document payments

(c)	business interruption proceeds

Less:

(d)

penalties

(e)	Operating Expenses

(f)	insurance premiums

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Equals

Cash Flow Available for Debt Service

The “Cash Flow Available for Debt Service” means, for any calculation period, the amount that is equal to:

a.	all net proceeds received by the Borrower in relation to contracted or spot market sales of capacity and energy, including any other electricity related payments such as transmission revenues, ancillary or complementary services; plus

all (A) earnings on Project Accounts, (B) cash payments received in respect of delay liquidated damages received by the Borrower; and (C) other payments received by the Borrower under the Project Documents other than Liquidated Damages Proceeds and other amounts that are required to be mandatorily prepaid pursuant to Section 2.06(b)(i) (Voluntary and Mandatory Prepayments; Mandatory Prepayments) of the Common Terms Agreement); plus

c.	any business interruption insurance proceeds paid to the Borrower; less

d.	any penalties required to be paid during such period to the relevant Authority (except to the extent paid by the Sponsors) pursuant to any Power Purchase Agreement; less

e.	Operating Expenses (including taxes and Capital Expenditures) paid or required to be paid during such period, for the avoidance of doubt including pursuant to the Project Documents; less

f.	insurance premiums payable by the Borrower during such period (to the extent not already included in clause (e) above),

The “Debt Service” is calculated considering the sum of the following payments:

(a)	debt instrument payments

(b)	security instrument payments

(c)	other payments

Equals

Debt Service

The “Debt Service” means, for any calculation period, the aggregate of:

all scheduled payments due on account of principal of the Senior Debt during such calculation period, any scheduled payments of interest, costs, charges and other amounts under the Senior Debt and under any working capital facility that constitutes Permitted Indebtedness and that are due and permitted to be paid pursuant to the Accounts Agreement; plus

b.	(b) all payments of principal or reimbursement obligations due during such calculation period on account of any surety bonds, performance bonds, bankers’ acceptances, letters of credit or similar instruments that constitute Permitted Indebtedness; plus

(c) without double counting any payment already counted in the preceding sub-clauses (a) and (b), any payment made or required to be made during such calculation period to any debt service account under the terms of any agreement providing for Financial Debt and that is pari passu or senior in right of payment to the Senior Debt, but excluding voluntary and mandatory prepayments and deposits into any Debt Service Reserve Account or any other debt service reserve account.

17	Debentures

Debenture issuance

In April 18, 2018, the Company issued non-convertible debentures raising R$ 3,370,000 in a single series consisting of 337,000 debentures, with a unit value of R$ 10 thousand at the issuance date. The Company will use the capital raised to build, finance, operate and maintain the thermoelectric power plant. The first principal amortization will take place on October 15, 2020, and the first interest amortization took place on October 15, 2018 in the amount of R$163,206. In 2019, interest was paid in the amount of R $ 331,945 (R$ 163,206 in 2018). The effective interest rate on this debenture is 13.67% per annum.

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	2019
Local Currency	Current liabilities	Noncurrent liabilities	Total
Face value	66,558	3,303,442	3,370,000
Accrued interest	69,155	—	69,155
(-) Discounts	—	(378,214)	(378,214)
(-) Transaction costs	—	(550,275)	(550,275)
Balance at 12/31/2019	135,713	2,374,953	2,510,666

	2018
Local Currency	Current liabilities	Noncurrent liabilities	Total
Face value	—	3,370,000	3,370,000
Accrued interest	69,155	—	69,155
(-) Discounts	—	(430,692)	(430,692)
(-) Transaction costs	—	(626,626)	(626,626)
Balance at 12/31/2018	69,155	2,312,682	2,381,837

	2019	2018
Opening balance	2,381,837	—
(+) Inflow	—	3,370,000
(-) Discounts	—	(467,427)
(-) Issuance costs	—	(680,072)
(+) Interest	460,774	322,542
(-) Interest Payment	(331,945)	(163,206)
Final balance	2,510,666	2,381,837

Non-current debentures are scheduled to fall due as follows:

Year			Principal
2021			190,237
2022			149,544
2023			260,501
2024			215,680
2025			277,182
2026			315,095
2027			342,560
2028			397,660
2029			440,291
2030			366,339
2031			232,233
2032			116,120
			3,303,442
Discounts			(378,214)
Transactions costs			(550,275)
Total non current			2,374,953

18	Related parties

a.	Parent companies and subsidiaries

As of December 31, 2019, the Company is a joint venture of Ebrasil Energia Ltda. and Golar Power Participações S.A. which in turn have as ultimate parent companies DC Energia e Participações S.A., Golar LNG Ltd. and Stonepeak Infrastructure Partners.

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b.	Related party transactions

	12/31/2019	12/31/2018
Non current assets
Golar Nanook UK Limited^(a)	111,357	—
Total assets	111,357	—
Current liabilities
Commercial operation
Golar Power Latam Serviços Marítimos Ltda.	(2,746)	—
Non current liabilities
Golar Nanook UK Limited^(a)	(111,357)	—
Total liabilities	(114,103)	—
Financial results
Golar Nanook UK Limited	2,746	—
	2,746	—

(a)	Refer to note 15 for further information.

c.	Compensation of key management

The Company considers key management personnel as those elected by the Board of Directors in accordance with its bylaws, whose responsibilities include the power of decision making and controlling the Company’s activities.

Key management personnel compensation for the financial years ended December 31, 2019 and 2018 was R$ 2,107 and R$ 2,287 respectively.

As of December 31, 2019 and 2018 the Company does not have private pension plans or any other retirement or post-employment benefit plan.

19	Taxes and contributions payable

	12/31/2019	12/31/2018
Withheld income taxes - IRRF	762	848
PIS and COFINS	182	278
City service tax - ISS	284	13
Payroll taxes - INSS and FGTS	453	97
Other	1	1
	1,682	1,237

20	Provision for contingencies

Provisions for legal proceedings are recognized as expenses when the Company has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated.

As of December 31, 2019 and 2018, the Company, based on input from its legal advisors, had no provision recorded related to any civil, labor or tax claims classified as probable loss.

CELSE has other lawsuits that are considered possible, and for which no provision is required. The most relevant claim is against Sapura Energy do Brasil Ltda. In the second half of 2019, CELSE made several statements demonstrating dissatisfaction with the quality and work progress to the executives of Sapura Energy do Brasil Ltda., company contracted to build the offshore facilities in the EPC (Engineering, Procurement And Construction) regime. On December 20, 2019, Sapura filed a preliminary injunction, granted by a lower court judge, to suspend the performance bond of the contract and to avoid CELSE from collecting payment of such performance bond issued by Maybank, in Malaysia, until a final decision by the Arbitral Tribunal to be formed.

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On January 3, 2020, Sapura presented its request for arbitration against CELSE in the International Court of Arbitration – International Chamber of Commerce (“ICC”). Both companies submitted their claims, however, both parties have not yet specified the amounts of their claims. Based on Sapuras’ request for arbitration, CELSE is exposed to losses related to the contract that amount to R$ 201,535 (USD 50,000), without interests or inflation adjustment. Pursuant to CELSE’s request, the claims subject to confirmation amount to R$ 274,088 (USD 68,000), also without interests or inflation adjustment. At this stage, management believes that CELSE’s chances of loss on its claims as well as on Sapura’s claims are possible.

Equity

Share capital

As of December 31, 2019, the Company’s share capital was R$ 1,725,108 (R$ 1,334,608 as of December 31, 2018), consisting of 1,725,107,822 registered common shares with no par value (1,334,607,822 shares as of December 31, 2018), distributed as follows:

	12/31/2019
	Shares	%
Ebrasil Energia Ltda.	862,553,911	50%
Golar Power Brasil Participações S.A.	862,553,911	50%
	1,725,107,822	100%

	12/31/2018
	Shares	%
Ebrasil Energia Ltda.	667,303,911	50%
Golar Power Brasil Participações S.A.	667,303,911	50%
	1,334,607,822	100%

Capital increases

On March 16, 2018, the Extraordinary General Meeting approved the increase in capital in the amount of R$ 1,233,656, being R$ 72,936 in cash and the remaining balance of R$ 1,160,720 on shares of CELSE – Centrais Elétricas de Sergipe S.A.

April 16, 2018, the Extraordinary General Meeting approved the increase in capital in the amount of R$ 26,320 in cash. On April 25, 2018, it approved the increase of additional R$ 17,084. On April 30, 2018, it approved an additional capital increase of R$ 51,349. On May 25, 2018, the Extraordinary General Meeting approved the Company’s capital increase of R$ 1,400, and on November 27, 2019 a final capital increase of R$ 4,798 during the fiscal year ended December 31, 2018. All capital contributions performed by the shareholders were performed by cash.

On May 27, 2019, the Extraordinary General Meeting approved a capital increase of R$ 5,200. On August 21, 2019, it approved an additional increase of R$ 127,000. On September 05, 2019, it approved another capital increase of R$ 150,000. On September 17, 2019, the Extraordinary General Meeting approved the Company’s capital increase of R$ 103,000, and on November 24, 2019 a final capital increase of R$ 5,300 during the fiscal year ended December 31, 2019. All capital contributions performed by the shareholders were performed by cash.

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The following table demonstrates the shares rollforward in 2019.

	Shares	Amount
Share capital - December 31, 2018	1,334,607,822	1,334,608
May 27, 2019	5,200,000	5,200
August 21, 2019	127,000,000	127,000
September 05, 2019	150,000,000	150,000
September 17, 2019	103,000,000	103,000
November 24, 2019	5,300,000	5,300
Share capital - December 31, 2019	1,725,107,822	1,725,108

22	General and administrative expenses

	12/31/2019	12/31/2018
Personnel and management	(22,139)	(19,041)
Materials and services	(14,359)	(16,599)
Insurance	(187)	(44)
Taxes	(706)	(757)
Other	(1,358)	(2,558)
Depreciation and amortization	(464)	(337)
Total	(39,214)	(39,336)

23	Finance results

	12/31/2019	12/31/2018
Finance income
Exchange variance^(a)	5,058	10,237
Swap / put option gain^(b)	—	46,705
Earnings on short-term investments	30,637	13,465
Other	133	—
	35,829	70,407
Finance expenses
Exchange variance^(a)	(6,545)	(75,431)
Swap / put option loss^(c)	(182)	(15,815)
Tax on financial transactions	(2,009)	(6,949)
PIS and COFINS on financial income	(1,439)	(624)
Other	(3,812)	(1,542)
	(13,987)	(100,361)
Net finance income	21,842	(29,954)

(a)

Exchange variance gains and losses are related to the overseas supplies. In 2018, the Company was in the process of raising funds for the construction of the plant. Thus, until sufficient funds were received, the Company was exposed to the exchange rate variation related to payable due to foreign suppliers contracted for the construction of the plant. With the funding process successfully closed during 2018, the situation is regularized, with the exposure liquidated. From the entry of funds until December 31, 2019, the main suppliers of the Company work through cash advances for subsequent delivery of products or services, thus reducing CELCEPAR’s exposure to exchange rate variations.

(b)	Gain originated from foreign exchange derivative operations to protect cash flow operations with foreign suppliers during 2018.

(c)	Losses due to fair value of foreign exchange put option contracts.

24	Financial instruments

This note explains the Company’s exposure to financial risks as these risks could affect its future financial performance. The management of Company’s financial risk is performed by the financial department based on

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policies approved by its Board of Directors. The Board provides written principles for managing the overall risk, in addition to policies for specific areas, such as currency risk, interest-rate risks, credit risk, the use of derivative and non-derivative financial instruments and cash surplus investments.

Accounting classifications and fair values

The following table shows the carrying amounts and fair values of financial assets and financial liabilities, including their levels in the fair value hierarchy. It does not include the fair value information for financial assets and liabilities not measured at fair value if the carrying amount is a reasonable approximation to the fair value.

	12/31/2019
Financial assets	Carrying amount	Fair value - Level 2
Financial assets measured at fair value through profit and loss
Short-term investments – cash equivalent	184,021	184,021
Swiss note - short-term investment	46,917	46,917
Short-term investment – DSRA	399,689	399,689
	630,627
Financial assets measured at amortized cost
Other receivables	2,781
Cash	13,104
	15,885

	12/31/2018
	Carrying amount	Fair Value - Level 2
Financial assets measured at fair value through profit and loss
Short-term investments – cash equivalent	42,363	42,363
Swiss note - short-term investment	141,679	141,679
Short-term investment – DSRA	371,132	371,132
Swap – derivative financial instrument	182	182
	555,356
Financial assets measured at amortized cost
Other receivables	697
Cash	60,405
	61,102

			12/31/2019
Financial liabilities			Carrying amount
Financial liability at amortized cost
Debenture			(2,510,665)
Loans and financing in local currency			(1,312,453)
Loans and financing in foreign currency			(311,729)
Accounts payables			(297,112)
Related parties			(114,103)
			(4,546,061)

			12/31/2018
			Carrying amount
Financial liability at amortized cost
Debenture			(2,381,837)
Loans and financing in local currency			(740,478)
Loans and financing in foreign currency			(171,115)
Trade payables			(10,266)
			(3,303,696)

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Risk management

The Company has exposure to the following risk arising from financial instruments:

a.	Market Risk

b.	Liquidity Risk

c.	Credit Risk

The Company’s risk management practice aims to detect and analyze risks it is exposed to and to establish appropriate risk controls and limits in addition to monitoring the risks and ensuring compliance with the limits. By managing its activities, the Company is aiming to create a disciplined and constructive system of controls in which all employees are aware of their responsibilities and obligations.

Management oversees the compliance with and development of risk control activities and reviews the adequacy of the risk management framework in relation to the risks faced by the Company.

a.	Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and equity prices, will affect the Company’s income or the value of its holdings of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

Currency risk

The Company currently has two sources of exchange rate exposure, (i) foreign-currency obligations to suppliers and (ii) USD-denominated financing, primarily mid- and long-term exposure. The table below demonstrates the currency risk exposure:

December 31, 2019
(In thousands of reais)	Up to 6 months	6 to 12 months	Over 12 months
Short-term investment DSRA* in USD	12,084	—	—
Short-term investment - Swiss note	46,917	—	—
Exposure to USD trade payables	(198,159)	—	—
Exposure to related parties USD	(1,152)	(2,305)	(110,646)
Exposure to USD financing	(11,714)	(13,496)	(286,518)
	(152,024)	(15,801)	(397,164)

(*)	Debt Service Reserve Account

December 31, 2018
(In thousands of reais)	Up to 6 months	6 to 12 months	Over 12 months
Short-term investment DSRA* in USD	7,016	—	—
Short-term investment - Swiss note	141,679	—	—
Exposure to USD trade payables	(4,615)	—	—
Exposure to USD financing	(7,064)	(7,338)	(156,713)
	137,016	(7,338)	(156,713)

(*)	Debt Service Reserve Account

Sensitivity analysis for exchange rate exposure:

The probable scenario was determined based on US dollar market rates projected to December 31, 2020. Stressed scenarios (positive and negative effects, before tax) were determined based on adverse impacts of 25% and 50% on the USD exchange rates used in the probable scenario.

Based on the USD-denominated financial instruments ascertained as of December 31, 2019, the Company conducted a sensitivity analysis by raising and lowering exchange rates (R$ /US$) by 25% and 50%.

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Sensitivity analysis of exchange rates (R$ /US$) – Consolidated

		Scenarios
	As of 12/31/2019	Probable	25%	50%	-25%	-50%
US dollar exchange rate	4.0307	4.2000	5.2500	6.3000	3.1500	2.1000

Financial asset or liability	Impact in BRL
Financial asset or liability	Probable	25%	50%	-25%	-50%
Offshore DSRA* in USD	508	3,655	6,803	(2,640)	(5,788)
Short-term investment - Swiss note	1,971	14,193	26,414	(10,251)	(22,473)
Exposure to USD trade payables	(8,323)	(59,944)	(111,564)	43,297	94,918
Exposure to related parties USD	(4,793)	(34,517)	(64,240)	24,931	54,655
Exposure to USD financing	(20,957)	(150,934)	(280,911)	109,020	238,996
Net impacts (loss)/gain	(31,594)	(227,547)	(423,498)	164,357	360,308

Interest rate risk

This risk derives from the possibility of the Company incurring losses due to changes in interest rates or other debt indexes, which impact the financial expenses financing or the yields on short-term investments.

The Company continuously monitors the market interest rates in order to assess any requirement to use hedges to protect itself against the risk of variation to these rates. The table below demonstrates the Company´s exposure:

(In thousands of reais)	Up to 6 months	6 to 12 months	Over 12 months
Exposure to financing - ICE LIBOR6M USD	(11,714)	(13,496)	(473,740)
Exposure to financing – IPCA	(62,934)	(71,111)	(2,180,936)
	(74,648)	(84,607)	(2,654,676)

Sensitivity analysis for interest rate exposure:

The probable scenario uses the interest rate estimated by the Brazilian Central Bank (BACEN) as follows:

	Interest rate sensitivity analysis – Consolidated
	Scenarios
	Probable	25%	50%	-25%	-50%
LIBOR	1.52%	1.90%	2.28%	1.14%	0.76%
SELIC	4.25%	5.31%	6.38%	3.19%	2.13%
CDI	3.65%	4.56%	5.48%	2.74%	1.83%
IPCA	3.20%	4.00%	4.80%	2.40%	1.60%

A sensitivity analysis on the interest rates of loans and borrowings in compensation of short-term investments is shown below:

	Interest rate sensitivity analysis – Consolidated
	Scenarios
	Probable	25%	50%	-25%	-50%
Cash equivalents	6,835	8,539	10,262	5,131	3,427
Short-term investments	15,486	19,347	23,250	11,625	7,764
Loans and borrowings	(668,241)	(680,603)	(692,965)	(655,877)	(643,512)
Impacts of (loss) or gains in the year	(645,920)	(652,717)	(659,453)	(639,121)	(632,321)

b.	Liquidity Risk

The liquidity risk consists of the possibility of the Company not honoring its commitments by the respective due dates. The Company’s financial management practice aims to constantly mitigate the liquidity risk, being the most important factor the extension on maturity of loans and borrowings, spreading maturities, usage of different financial instruments and hedging foreign-currency debt.

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The permanent monitoring of cash flow makes it possible to detect any financing needed with enough time to structure the debt and choose the best options.

Any cash surpluses are invested in order to preserve the Company’s liquidity.

Projecting cash flows, liquidity stress tests and monitoring payment concentration are the main procedures set out in the Company’s liquidity management framework.

(i)	Cash flow projection: identifies future cash inflows and outflows in order to prevent possible mismatches.

(ii)	Liquidity stress test: simulates the impact of changes on the contracted liability, changes in market prices amongst other risks, additional security and bond requirements, etc.

(iii)

Payment concentration monitoring: assesses the volume of the contracted liability concentrated in the forward payment structure, observing the payment capacity against scheduled inflows and the cash reserve.

The Company has the following strategies for securing funding in the event of contingencies:

•	Debt Service Reserve Account (DSRA) with enough funds to pay 01 year of the debt service related to the venture’s senior financing.

•	Credit Facility issued by GE Capital in the amount of 120 million US dollars.

The Company’s financial liabilities classified by maturity date (based on contracted non-discounted cash flows) are as follows:

Non-derivative financial liabilities	Carrying Amount	Total contractual cash flow	2 months or less	2-12 months	1 – 2 years	2-25 years
Loans and borrowings	1,624,182	1,694,966	—	39,728	93,908	1,561,330
Debentures	2,510,665	3,439,156	—	135,712	190,237	3,113,207
Trade payables	297,112	297,112	27,168	269,944	—	—
Related parties	114,103	114,103	—	114,103	—	—
Taxes and social contributions	1,682	1,682	1,682	—	—	—
Other accounts payable	2,877	2,877	1,135	1,742	—	—
Total	4,550,632	5,549,896	29,985	561,239	284,145	4,674,537

c.	Credit Risk

Credit risk is the possibility of the Company incurring losses due to counterparties not performing obligations and commitments.

The Company mitigates the risks associated to cash and cash equivalents, investments and derivatives by diversifying its investments among financial institutions with good credit quality.

It also monitors the exposure with each counterparty, their credit quality and long-term ratings published by rating agencies for the main financial institutions with which the Company has outstanding operations.

See below the Company’s total credit exposure in financial assets. The amounts are those recorded in the financial position and do not include any provision for expected losses.

	12/31/2019	12/31/2018
Cash and bank deposits	13,104	60,405
Short-term investments – cash equivalents	184,021	42,363
Short-term investment – DSRA	399,689	371,132
Short-term investment – Swiss note	46,917	141,679
Total	643,731	615,579

d.	Supplementary information about derivative instruments

As of December 31, 2019, there was no derivative position outstanding.

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e.	Derivative financial instrument

In order to protect future disbursements from the financings in foreign currency (Notes 14 and 15), in 2018 the Subsidiary CELSE took out 6 (six) foreign exchange put options derivatives from Goldman Sachs do Brasil Banco Múltiplo S.A. (“GSBR”). Such options had their settlement in June, September and December 2018 and March, June and September 2019. The premium paid and expensed in the income statement of such options were R$ 10,800.

Non Delivery Option	JUN/18	SEP/18	DEC/18	MAR/19	JUN/19	SEP/19	Total
Settlement Date:	6/18/2018	9/18/2018	12/18/2018	3/18/2019	6/18/2019	9/17/2018
Notional value of reference currency (USD):	35,530	33,280	31,120	26,990	8,500	20,430	155,850
Notional Value (R$):	115,174	107,880	100,879	87,491	27,597	66,679	505,700
Strike price:	3.2416	3.2416	3.2416	3.2416	3.2467	3.2638
Premium (R$):	863	1,724	2,463	2,474	886	2,390	10,800

25	Commitments

Commitments undertaken by the investee CELSE

The commitments of the Company related to long-term contracts for the purchase of energy and for projects for the construction of power plants, as of December 31, 2019, are as follows:

Contractual obligations as of December 31,2019	Term	Less than 1 year	1 to 3 years	4 to 5 years	More than 5 years	Total
Energy purchase agreement^(a)
Fixed revenue	25 years	1,623,882	3,247,764	3,247,764	32,477,640	40,597,050
Variable revenue (*)	25 years	1,400,079	2,800,158	2,800,158	28,001,580	35,001,975
Gas Supply agreement (*)^(b)	25 years	1,204,330	2,408,660	2,408,660	24,086,600	30,108,250
Service contract to operate and maintain the plant (*)^(c)	25 years	17,206	34,412	34,412	344,120	430,150

(*)	Considering the plant’s usage as 50% of its capacity per year

(a)

Regulated energy purchase contract between CELSE, the supplier, and twenty-six contracts with energy distributors, for a period of 25 years Beginning January 2020, CELSE will be required to provide a monthly physical guarantee or a monthly availability of 867 MW (Mega Watts), for this contractual obligation, CELSE will be remunerated through fixed revenue for an annual amount of R$ 1,623,882, updated annually by IPCA. In addition, the contract also provides for the effective delivery of electricity to distributors, if physical delivery requests occur, the amount of energy to be delivered will be informed by the system operator and valued at the price of the energy traded in the market.

(b)

In November 2016, CELSE signed a gas purchase agreement for its thermoelectric power plant with Ocean LNG, a joint venture formed by Qatar Petroleum and ExxonMobil. The purchase agreement contract has been negotiated for a term of 25 years as from commercial start-up, whereupon the contractual obligation to deliver energy begins within the CCEAR (Environment Power Purchase Agreements) contracts signed at auction A-5/2015. The settlement price at each purchase date will be based on then market prices. The base contract consists of an annual 68,400,000 MMBTU (Million British Thermal Units), multiplied by the number of days in the respective contractual year and divided by the number of days in the respective civil year. The contract’s total value is estimated at R$ 49,234,194 (USD 12,214,800, assuming a brent price of US$ 60.00 and an exchange rate of R$ 4.0307/US$).

(c)	In December 2016, the subsidiary CELSE and GE Power Services signed a service provision agreement to operate and maintain the plant (O&M) for the term of up to 25 years, as from the date commercial operations commence at the plant.

26	Additional statements of cash flows

The following table presents additional information on transactions related to the cash flow statement:

	12/31/2019	12/31/2018
Non-cash items
Capital contribution by realization of advances for future capital increase	—	61,900
Property, plant and equipment addition:
Accrued interest (effective interest rate)	(198,169)	(189,994)
Acquisition of fixed assets related to the Engineering, procurement, and construction contract	(2,391,101)	(450,256)

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27	Subsequent events

On January 1, 2020, despite the fact that CELSE did not reach the conclusion of the power plant construction and, consequently, did not obtain the Declaration of Commercial Operation (DOC) issued by the National Electric Energy Agency (ANEEL), the Energy Purchase Agreement in the Regulated Environment (CCEAR) started with the 26 distributors. Therefore, CELSE was required to acquire electricity in the market to meet these contracts. Additionally, it should be noted that CELSE was not entitled, in the period in which it did not obtain the DOC, to the fixed monthly revenue (physical guarantee of 867 MWm), amounting to R$ 135,000 per month.

On March 20, 2020, through Order No. 830, ANEEL granted CELSE partial Declaration of Commercial Operation and authorizing the start of operations of (i) Generating Units (UG) 1 to UG3, of 332.724 MW each, starting commercial operation on March 21, 2020; and (ii) UG4, of 517.470 MW, starting commercial operation on March 21, 2020, with limited power of 445.022 MW.

On April 14, 2020, through Order No. 1,039, ANEEL granted CELSE full DOC and authorized the operation of UG4 of 517.468 MW, at full power as of April 15, 2020. After obtaining the final approval of the operation until the present date, CELSE was only required to generate and deliver energy from March 28 to April 3, 2020. The Company is not forecasting any additional generation and delivery of energy for the fiscal year 2020.

On April 1, 2020 CELSE and GOLAR, after all necessary performance tests, signed the acceptance term of the Navar Golar Nanook contract, recognizing the contract as a lease agreement under IFRS 16 – Lease. Additionally, with the beginning of the charter contract, the OSA contract was formally accepted by CELSE at the same date.

Regarding the company’s indebtedness, two important events occurred in the first half of 2020:

(1)	GE Capital financing line of credit, in the amount of R$ 526,680 (US$ 120,000) was released to CELSEPAR, of which R$ 378,630 (US$ 90,000) in January 2020 and R$ 148,050 (US$ 30,000) in March 2020; and

(2)	Fifth and last disbursement of IDB and IFC to CELSE took place in June 2020, in the total amount of R$ 220,371, as follows:

Credit Facilities	R$	Credit Facility
IFC	106,924	USD 20,000
IDB	66,400	R$ 66,400
IDB Invest	20,316	USD 3,800
IDB China Fund	26,731	USD 5,000

In relation to COVID-19, the impacts on CELSEPAR’s activities were impacted in the following manner: the company (a) placed all employees, not related to the plant’s operation and maintenance activities, working from home; (b) and took all necessary actions for the safety of those who had to continue their activities at the plant. In relation to the Brazilian electric sector, in which CELSEPAR’s businesses are inserted in, the Federal Government has been adopting a series of measures to minimize the economic effects of the pandemic in the sector. The objective is to alleviate the impacts of the crisis on electricity bills paid by consumers and also to preserve the liquidity of companies in the sector, which has been suffering from the reduction in revenue, due to the reduction in demand and the increase in defaults. Energy consumption decreased approximately 14% and client defaults have increased around 10% in the country compared to the same period in 2019. With social isolation, industries, businesses and service providers have decreased or paralyzed their activities and people are losing their jobs. As a result, ANEEL approved the regulation of Conta-Covid that establishes the criteria for loans to companies in the amount of up to R $ 16.1 billion which will be released to the sector during the second half of 2020. The funds will be offered to the energy sector by a group of banks led by the National Bank for Economic and Social Development (BNDES) and must be paid over 60 months. According to ANEEL, the funds will guarantee cash flow for companies in the sector to honor their contracts and to overcome the effects of the pandemic.

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APPENDIX A – GLOSSARY

ABRACEEL			Brazilian Association of Electricity Traders (Associação Brasileira dos Comercializadores de Energia).

ADO			Automotive diesel oil.

ANEEL			Brazilian Electricity Regulatory Agency (Agência Nacional de Energia Elétrica).

ANP			National Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis).

ANTAQ			National Agency for Water Transportation.

Bareboat			The hiring or leasing of a vessel from one company to another (the charterer), which in turn provides crew, bunkers, stores etc. and pays all operating costs.

Bcm			Billion cubic meters.

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.

Bunkers			The ship’s fuel.

Captive Consumers			Consumers in a Captive Market that acquire energy from the distribution company or holder of a permit to whose network the consumer is connected. Captive Consumers include all residential consumers, as well as certain companies, industries and rural consumers.

Captive Market			Market segment in which each Captive Consumer is obliged to purchase electricity solely from the local distributor. In the Captive Market, tariffs are determined by ANEEL and not subject to negotiation.

CCEE			Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica).

Charter			The hiring of a vessel, or use of its carrying capacity, for a specified period of time.

Charterer			A person, firm, cargo owner or company hiring a vessel for the carriage of goods or other purposes.

Charter hire			The gross revenue earned by a vessel pursuant to a bareboat, time or voyage charter.

Charter party			A contract covering the transportation of cargo by sea, including the terms of the carriage, remuneration and other terms.

Classification society			An independent society which certifies that a vessel has been built and maintained in accordance with the rules of such society and complies with the applicable rules and regulations of the flag state of such vessel and the international conventions of which that country is a member.

COD			The commencement of commercial operations.

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Crude (oil)			Unrefined oil directly from the reservoir.

CVM			Commisão de Valores Mobiliários.

Distributor			An entity supplying electric energy to a group of consumers by means of a Distribution Network.

Document of compliance			A document issued to a company which certifies that it complies with the requirements of the ISM Code.

Drydocking			The removal of a vessel from the water for inspection, maintenance and/or repair of submerged parts. Normally done on a regular basis every 3 or 5 years.

Dwt (deadweight ton)			A measure expressed in metric tons (1,000 kg) or long tons (1,016 kg) of a ship’s carrying capacity, including bunker oil, fresh water, crew and provisions. This is the most important commercial measure of the capacity.

EIA			The U.S. Energy Information Administration.

EPC			Engineering, Procurement and Construction.

EPE			The Brazilian Energy Research Office (Empresa de Pesquisa Energética).

FID			Final investment decision.

Final Consumer			A party that uses electricity for its own needs.

Flag state			The county where a vessel is registered.

Free Consumer			Consumers that may choose to purchase electricity through negotiations with any available electricity distributor.

Free Market			Market segment that permits a certain degree of competition (Ambiente de Contratação Livre – ACL). The Free Market specifically contemplates purchases of electricity by non-regulated entities such as Free Consumers and energy traders.

FSRU			A floating storage and regasification unit used to store and regasify LNG.

FSU			A floating storage unit.

GHGs			Greenhouse gases.

GW			Gigawatt. We estimate 2,500,000 LNG gallons would be required to produce one gigawatt.

HCV			Heavy Commercial Vehicles.

HFO			Heavy fuel oil.

HNS Convention			The International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea.

Hull			Shell of body of a ship.

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ICMS			Imposto sobre Circulação de Mercadorias e Serviços.

ICZM			Brazil’s Integration Coastal Zone Management program.

IGC			The International Gas Carrier Code, which 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.

IMDG code			The International Maritime Dangerous Goods Code.

IMO			International Maritime Organization, a United Nations agency that issues international trade standards for shipping.

Independent Power Producer			A legal entity or consortium holding a concession or authorization for power generation for sale for its own account to public utility concessionaires.

Installed Capacity			The level of electricity which can be delivered from a particular generator on a full-load continuous basis under specified conditions as designated by the manufacturer.

ISPS code			International Ship and Port Facility Security Code.

ISS			The Imposto sobre Serviços

ISM Code			International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, which, among other things, requires vessel owners to obtain a safety management certification for each vessel they manage.

Knot			A measure of the speed of the vessel. 1 knot = 1 nautical mile per hour, that is 1.85 km/hr.

kV			Kilovolt. One thousand volts.

LNG			Liquefied natural gas.

Long-term charter			A charter for a term of five of more years.

LPG			Liquefied petroleum gas.

MARPOL			The International Convention for the Prevention of Pollution from Ships.

MME			Brazilian Ministry of Mines and Energy (Ministério de Minas e Energia).

MMBtu			One million Btus.

Mtpa			Million tonnes per annum

MTSA			The Maritime Transportation Security Act.

MW			Megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt.

National Privatization Program			Program created by the Brazilian government in 1990 to promote the process of privatization of state-owned companies.

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Newbuilding			A new vessel under construction or on order.

NWRP			The federal National Water Resources Policy (Federal Law 9433/1997)

Off-hire			The time during which a vessel is not available for service.

ONS			National Electric System Operator (Operador Nacional do Sistema Elétrico).

Operating costs			The costs of the vessels including crewing costs, insurance, repairs and maintenance, stores, spares, lubricants and miscellaneous expenses (but excluding capital costs and voyage costs).

PIS			Contribuição para o Programa de Integração Social.

PLD			Spot price used to evaluate the energy traded in the spot market (Preço de Liquidação de Diferenças).

Polar Code			The International Code for Ships Operating in Polar Water, which entered into force on January 1, 2017.

PPA			Power purchase agreement.

Regasification			The process of returning LNG to its gaseous state.

Regulated Market			Market segment in which distribution companies purchase all the electricity needed to supply customers through public auctions. The auction process is administered by ANEEL, either directly or through CCEE, under certain guidelines provided by the MME. The Regulated Market is generally considered to be more stable in terms of supply of electricity.

Ship management			The technical administration of a ship, including services such as technical operation, maintenance, repair, crewing and insurance.

Special Consumers			Individual or groups of consumers whose contracted energy demand is between 500 kV and 3 MW. Special Consumers may only purchase energy from renewable sources: (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 3,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW, and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW.

Spot market			The market for chartering a vessel for single voyages normally not longer than three months in duration.

STCW			The International Convention on the Standards of Training and Certification of Watchkeeping Officers.

TBtu			One trillion Btus, which corresponds to approximately 12,100,000 LNG gallons.

Tcf			Trillion cubic feet, a measure of gas production.

TFDE			Tri-fuel diesel electric.

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Thermoelectric power plant			A generator which uses combustible fuel, such as coal, oil, diesel, natural gas or other hydrocarbons as the source of energy to drive the electric generator.

Time charter			A charter in which the charterer pays for the use of a ship’s cargo capacity for a specified period of time. The owner provides the ship with crew, stores and provisions, ready in all aspects to load cargo and proceed on a voyage as directed by the charterer. The charterer usually pays for substantially all of the vessel voyage expenses.

Tonnes			1,000 kilos (metric ton = 2,204 lb).

Transmission			The bulk transfer of electricity from generating facilities to the distribution system at load center station by means of the transmission network.

TUPs			Private Use Terminals.

Vessel operating expenses			Direct expenses associated with operating a vessel, such as crew wages, vessel supplies, routine repairs, maintenance, lubricating oils, insurance and management fees payable for the provision of commercial and technical management services.

Voyage charter			The transportation of cargo from port(s) of loading to port(s) of discharge. Payment is normally per day, and the ship-charterer pays for bunker, port and canal charges etc.

Voyage expenses			Expenses directly attributable to the vessel voyage which are primarily fuel costs but which also include other costs such as port and canal charges.

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Hygo Energy Transition Ltd.

23,100,000 Common Shares

Prospectus

, 2020

Morgan Stanley

Goldman Sachs & Co. LLC

Citigroup

Barclays

BofA Securities

BTG Pactual

BTIG

Credit Suisse

Itaú BBA

UBS Investment Bank

XP Investimentos

Arctic Securities

DNB Markets

Fearnley Securities

Through and including , 2020 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 6.

Indemnification of Directors and Officers.

The Companies Act provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. In addition, the Companies Act provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favor or in which they are acquitted or granted relief by the Supreme Court of Bermuda.

Our bye-laws will provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, and that we shall advance funds to our officers and directors for expenses incurred in their defense upon receipt of an undertaking to repay the funds if any allegation of fraud or dishonesty is proved. Our bye-laws will provide that the shareholders waive all claims or rights of action that they might have, individually or in right of the Company, against any of the Company’s directors or officers for any act or failure to act in the performance of such director’s or officer’s duties, except in respect of any fraud or dishonesty of such director or officer. The Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director. We have purchased and maintain a directors’ and officers’ liability policy for such purpose.

We have agreed to indemnify our directors and executive officers against certain liabilities and expenses incurred by such persons in connection with claims made by reason of their being such a director or officer.

The underwriting agreement, the form of which will be filed as Exhibit 1.1 to this registration statement, will also provide for indemnification by the underwriters of us and our officers and directors for certain liabilities, including liabilities arising under the Securities Act, but only to the extent that such liabilities are caused by information relating to the underwriters furnished to us in writing expressly for use in this registration statement and certain other disclosure documents.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 7.

Recent Sales of Unregistered Securities.

There have been no sales of unregistered securities within the past three years.

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Item 8.

Exhibits and Financial Statement Schedules.

Exhibit No.			Description
1.1*			Form of Underwriting Agreement
3.1*			Memorandum of Association of Hygo Energy Transition Ltd.
3.2*			Form of Amended and Restated Bye-laws of Hygo Energy Transition Ltd.
4.1*			Indenture, dated March 28, 2018, by and among CELSE - Centrais Elétricas De Sergipe S.A., Pentágono S.A. Distribuidora de Títulos e Valores Mobiliários, and Credit Suisse AG (English Translation)
4.2*			First Amendment to Indenture, dated April 10, 2018, by and among CELSE - Centrais Elétricas De Sergipe S.A., Pentágono S.A. Distribuidora de Títulos e Valores Mobiliários, and Credit Suisse AG (English Translation)
5.1			Form of Opinion of MJM Limited as to the legality of the securities being registered
8.1			Form of Opinion of Vinson & Elkins L.L.P. relating to U.S. tax matters
10.1*			Form of Amended and Restated Management and Administrative Services Agreement between Hygo Energy Transition Ltd. and Golar Management Limited
10.2*			Form of Shareholders’ Agreement
10.3*†			Form of Indemnification Agreement for Directors and Officers
10.4 *+++			Bareboat Charter Agreement, dated March 23, 2018, by and between Golar Nanook UK Limited, as the owner, and CELSE – Centrais Eléctricas de Sergipe S.A., as the charterer
10.5*			Form of Agreement for the Marketing of Energy in the Regulated Environment (English Translation)
10.6*			Form of Amendment to the Contract for Marketing Electric Energy in the Regulated Environment (English Translation)
10.7*			Form of Assignment of Contract for Marketing of Electric Energy in Regulated Environment (English Translation)
10.8 *+++			Operation and Services Agreement, dated March 23, 2018, by and between Golar Power LatAm Serviços Marítimos Ltda. and CELSE – Centrais Eléctricas de Sergipe S.A.
10.9 *+			Bareboat Charter Agreement, dated September 25, 2018, by and between Compass Shipping 23 Corporation Limited, as owner, and Golar FSRU8 Corporation, as charterer
10.10 *+++			Memorandum of Agreement, dated September 25, 2018, by and between Compass Shipping 23 Corporation Limited and Golar FSRU8 Corporation
10.11*			Bareboat Charter Agreement, dated December 17, 2019, by and between Oriental Fleet LNG 02 Limited, as owner, and Golar Hull M2023 Corp., as charterer
10.12 *+			Memorandum of Agreement, dated December 17, 2019, by and between Oriental Fleet LNG 02 Limited and Golar Hull M2023 Corp.
10.13 *+			Bareboat Charter Agreement, dated March 3, 2020, by and between Noble Celsius Limited, as owner, and Golar Hull M2026 Corp., as charterer
10.14 *+			Memorandum of Agreement, dated March 3, 2020, by and between Golar Hull M2026 Corp. and Noble Celsius Shipping Limited
10.15 *+++			Operation and Maintenance Agreement, dated December 22, 2016 by and among CELSE – Centrais Eléctricas de Sergipe S.A., GE Power & Water Equipamentos e Serviços de Energia e Tratamento de Agua Ltda., General Electric International Inc. and GE Global Parts and Products GMBH
10.16*			Loan Agreement, dated April 12, 2018, by and between CELSE - Centrais Elétricas De Sergipe S.A. and International Finance Corporation
10.17*			Loan Agreement, dated April 12, 2018, by and among CELSE - Centrais Elétricas De Sergipe S.A., Inter-American Investment Corporation, Inter-American Investment Corporation, as Agent acting on behalf of the Inter-American Development Bank, and Inter-American Investment Corporation, as Agent acting on behalf of the Inter-American Development Bank, in its capacity as Administrator of the China Co-Financing Fund for Latin America and the Caribbean
10.18*†+			Secondment and Consultancy Agreement, dated April 4, 2017, by and among Magni Partners (Bermuda) Ltd. and Golar Power Limited
10.19*			Cooperation Agreement, dated August 31, 2020, by and among Hygo Energy Transition Ltd. and Golar LNG Partners LP

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Exhibit No.			Description
10.20 †			Supplemental Agreement, dated August 31, 2018, by and among Hygo Energy Transition Ltd. (f/k/a Golar Power Limited), Golar LNG Limited and Stonepeak Infrastructure Fund II Cayman (G) Ltd.
21.1*			List of Subsidiaries of Hygo Energy Transition Ltd.
23.1			Consent of Ernst & Young LLP
23.2			Consent of KPMG Auditores Independentes
23.3			Consent of MJM Limited (contained in Exhibit 5.1)
23.4			Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
23.5			Consent of Rystad Energy, Inc.
24.1*			Power of Attorney (included in signature page)
99.1			Consent of Kate Blankenship, as director nominee
99.2			Consent of Paul Hanrahan, as director nominee

*	Previously filed

†	Management contract or compensatory plan or agreement

+	Portions of this exhibit (indicated by asterisks) will be omitted in accordance with the rules of the Securities and Exchange Commission.

++	Certain schedules and exhibits to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission upon request.

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Item 9.

Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and this offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of London, United Kingdom on the 16th day of September, 2020.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date

*	Chief Executive Officer (Principal Executive Officer)	September 16, 2020
Eduardo Antonello	Chief Executive Officer (Principal Executive Officer)	September 16, 2020

/s/ Eduardo Maranhão	Chief Financial Officer (Principal Financial and Principal Accounting Officer)	September 16, 2020
Eduardo Maranhão		September 16, 2020

*	Director	September 16, 2020
Tor Olav Trøim

*	Director	September 16, 2020
Luke Taylor

*	Director	September 16, 2020
Jeffry Myers

*	Director	September 16, 2020
Georgina Sousa

*By:			/s/ Eduardo Maranhão
			Eduardo Maranhão
			Attorney-in-fact

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SIGNATURE OF AUTHORIZED REPRESENTATIVE OF THE REGISTRANT

Pursuant to the Securities Act of 1933, as amended, the undersigned, a duly authorized representative of Hygo Energy Transition Ltd. in the United States, has signed the Registration Statement in the City of Newark, State of Delaware on the 16th day of September, 2020.

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Initial public offering price per common share

Pro forma net tangible book value per common share before the offering⁽¹⁾

Increase in net tangible book value per share attributable to purchasers in the offering

Less: Pro forma net tangible book value per share after the offering⁽²⁾

Immediate dilution in net tangible book value per common share to purchasers in the offering⁽³⁾