20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report __________

Commission File Number 001-36588

Höegh LNG Partners LP

(Exact name of Registrant as specified in its charter)

Republic of the Marshall Islands

(Jurisdiction of incorporation or organization)

Canon’s Court

22 Victoria Street

Hamilton, HM 12 Bermuda

(Address of principal executive offices)

Håvard Furu

Canon’s Court

22 Victoria Street

Hamilton, HM 12 Bermuda

Telephone: +479-912-3443

Facsimile: +479-755-7401

havard.furu@hoeghlng.com

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

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

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common units representing limited partner interests	HMLP	New York Stock Exchange
Series A cumulative redeemable preferred units representing limited partner interests	HMLP PRA	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

33,308,439 common units representing limited partner interests

6,752,333 Series A cumulative redeemable preferred units representing limited partner interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes ⌧ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐  Yes  ⌧  No

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

⌧  Yes  ☐  No

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

Large accelerated filer   ☐ Accelerated filer   ⌧ Non-accelerated filer   ☐ 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 13(a) of the Exchange Act. ☐

+ The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP   ⌧	International Financial Reporting Standards as issued by the	Other   ☐
	International Accounting Standards Board   ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. ☐    Item 17    ☐ Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ☐  Yes  ⌧  No

HÖEGH LNG PARTNERS LP

INDEX TO FORM 20-F

Presentation of Information in this Report		4
Forward-Looking Statements		5
Part I		8
Item 1.	Identity of Directors, Senior Management and Advisers	8
Item 2.	Offer Statistics and Expected Timetable	8
Item 3.	Key Information	8
A.	Selected Financial Data	8
B.	Capitalization and Indebtedness	14
C.	Reasons for the Offer and Use of Proceeds	14
D.	Risk Factors	15
Item 4.	Information on the Partnership	56
A.	History and Development of the Partnership	56
B.	Business Overview	57
C.	Organizational Structure	103
D.	Property, Plant and Equipment	103
Item 4A.	Unresolved Staff Comment	103
Item 5.	Operating and Financial Review and Prospects	104
A.	Operating Results	115
B.	Liquidity and Capital Resources	124
C.	Research and Development, Patents and Licenses, Etc.	141
D.	Trend Information	141
E.	Off-Balance Sheet Arrangements	142
F.	Tabular Disclosure of Contractual Obligations	142
G.	Safe Harbor	143
Item 6.	Directors, Senior Management and Employees	143
A.	Directors and Senior Management	143
B.	Compensation	145
C.	Board Practices	148
D.	Employees	150
E.	Unit Ownership	150
Item 7.	Major Unitholders and Related Party Transactions	150
A.	Major Unitholders	150
B.	Related Party Transactions	151
C.	Interests of Experts and Counsel	163
Item 8.	Financial Information	164
A.	Consolidated Statements and Other Financial Information	164
B.	Significant changes	167
Item 9.	The Offer and Listing	167
A.	Offer and Listing Details	167
B.	Plan of Distribution	167
C.	Markets	167
D.	Selling Unitholders	167
E.	Dilution	167
F.	Expenses of the Issue	168
Item 10.	Additional Information	168
A.	Share Capital	168
B.	Memorandum and Articles of Association	168
C.	Material Contracts	168
D.	Exchange Controls	172
E.	Taxation	172
F.	Dividends and Paying Agents	178
G.	Statement by Experts	179
H.	Documents on Display	179

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I.	Subsidiary Information	179
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	179
Item 12.	Description of Securities Other than Equity Securities	180
		181
Part II		181
Item 13.	Defaults, Dividend Arrearages and Delinquencies
Item 14.	Material Modifications to the Rights of Securities Holders and Use of Proceeds	181
Item 15.	Controls and Procedures	181
Item 16A.	Audit Committee Financial Expert	182
Item 16B.	Code of Ethics	182
Item 16C.	Principal Accountant Fees and Services	182
Item 16D.	Exemptions from the Listing Standards for Audit Committees	183
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	183
Item 16F.	Change in Registrants’ Certifying Accountant	183
Item 16G.	Corporate Governance	183
Item 16H.	Mine Safety Disclosure	184
		185
Part III
Item 17.	Financial Statements	185
Item 18.	Financial Statements	185
Item 19.	Exhibits	185
SIGNATURE		192
Index to Financial Statements of Höegh LNG Partners LP		F-1

3

PRESENTATION OF INFORMATION IN THIS REPORT

This annual report on Form 20-F for the year ended December 31, 2020 (this “Annual Report”) should be read in conjunction with the consolidated financial statements and accompanying notes included in this Annual Report. Unless we otherwise specify, references in this Annual Report to “Höegh LNG Partners,” “we,” “our,” “us” and “the Partnership” refer to Höegh LNG Partners LP or any one or more of its subsidiaries, or to all such entities unless the context otherwise indicates. References in this Annual Report to “our general partner” refer to Höegh LNG GP LLC, the general partner of Höegh LNG Partners. References in this Annual Report to “our operating company” refer to Höegh LNG Partners Operating LLC, a wholly owned subsidiary of the Partnership. References in this Annual Report to "Höegh Lampung" refer to Hoegh LNG Lampung Pte Ltd., a wholly owned subsidiary of our operating company. References in this Annual Report to “Höegh FSRU III” refer to Höegh LNG FSRU III Ltd., a wholly owned subsidiary of our operating company (which was formally dissolved on May 4, 2020). References in this Annual Report to “PT Höegh” refer to PT Hoegh LNG Lampung, the owner of the PGN FSRU Lampung. References in this Annual Report to “Höegh Cyprus” refer to Hoegh LNG Cyprus Limited including its wholly owned branch, Hoegh LNG Cyprus Limited Egypt Branch (“Egypt Branch”), a wholly owned subsidiary of our operating company and the owner of the Höegh Gallant. References in this Annual Report to “Höegh Colombia Holding” refer to Höegh LNG Colombia Holding Ltd., a wholly owned subsidiary of our operating company. References in this Annual Report to “Höegh FSRU IV” refer to Höegh LNG FSRU IV Ltd., a wholly owned subsidiary of Höegh Colombia Holding and the owner of the Höegh Grace. References in this Annual Report to “Höegh Colombia” refer to Höegh LNG Colombia S.A.S., a wholly owned subsidiary of Höegh Colombia Holding. References in this Annual Report to our or the “joint ventures” refer to SRV Joint Gas Ltd. and/or SRV Joint Gas Two Ltd., the joint ventures that own two of the vessels in our fleet, the Neptune and the Cape Ann, respectively. References in this Annual Report to “Global LNG Supply” refer to Global LNG Supply S.A., and references to “Total Gas & Power” refer to Total Gas & Power Ltd., subsidiaries of Total S.A. (“Total”). References in this Annual Report to “PGN LNG” refer to PT PGN LNG Indonesia, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk (“PGN"), a subsidiary of PT Pertamina. References in this Annual Report to “SPEC” refer to Sociedad Portuaria El Cayao S.A. E.S.P.

References in this Annual Report to “Höegh LNG” refer, depending on the context, to Höegh LNG Holdings Ltd. and to any one or more of its direct and indirect subsidiaries, other than us. References in this Annual Report to “EgyptCo” refer to Höegh LNG Egypt LLC, a wholly owned subsidiary of Höegh LNG. References in this Annual Report to "CharterCo" refer to Höegh LNG Chartering LLC, a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh LNG Management” refer to Höegh LNG Fleet Management AS, a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh Maritime Management” refer to Höegh LNG Maritime Management Pte. Ltd., a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh Norway” refer to Höegh LNG AS, a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh Asia” refer to Höegh LNG Asia Pte. Ltd., a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh Shipping” refer to Höegh LNG Shipping Services Pte Ltd, a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Leif Höegh UK” refer to Leif Höegh (U.K.) Limited, a wholly owned subsidiary of Höegh LNG.

4

FORWARD-LOOKING STATEMENTS

This Annual Report contains certain forward-looking statements concerning future events and our operations, performance and financial condition. Forward-looking statements include, without limitation, any statement that may predict, forecast, indicate or imply future results, performance or achievements, and may contain the words “believe,” “anticipate,” “expect,” “estimate,” “future,” “project,” “will be,” “will continue,” “will likely result,” “plan,” “intend” or words or phrases of similar meanings. These statements involve known and unknown risks and are based upon a number of assumptions and estimates that are inherently subject to significant uncertainties and contingencies, many of which are beyond our control. Actual results may differ materially from those expressed or implied by such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to:

● the effects of outbreaks of pandemic or contagious diseases, including the length and severity of the recent worldwide outbreak of COVID-19, including its impact on our business liquidity, cash flows and operations as well as operations of our customers, suppliers and lenders;

● market conditions and trends for floating storage and regasification units (“FSRUs”) and liquefied natural gas (“LNG”) carriers, including hire rates, vessel valuations, technological advancements, market preferences and factors affecting supply and demand of LNG, LNG carriers, and FSRUs;

● our distribution policy and ability to make cash distributions on our units or any increases in the quarterly distributions on our common units;

● restrictions in our debt agreements and pursuant to local laws on our joint ventures’ and our subsidiaries’ ability to make distributions;

● the ability of Höegh LNG to meet its financial obligations to the Partnership pursuant to the Subsequent Charter and its guarantee and indemnification obligations;

● Höegh LNG’s ability to complete the Amalgamation (as defined below) the timing thereof, and any resulting change in the ability of Höegh LNG to compete with us;

● our ability to compete successfully for future chartering and newbuilding opportunities;

● demand in the FSRU sector or the LNG shipping sector, including demand for our vessels;

● our ability to purchase additional vessels from Höegh LNG in the future (including after the consummation of the Amalgamation);

● our ability to integrate and realize the anticipated benefits from acquisitions;

● our anticipated growth strategies, including the acquisition of vessels;

● our anticipated receipt of dividends and repayment of indebtedness from subsidiaries and joint ventures;

● effects of volatility in global prices for crude oil and natural gas;

● the effect of the worldwide economic environment;

● turmoil in the global financial markets;

● fluctuations in currencies and interest rates;

● general market conditions, including fluctuations in hire rates and vessel values;

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● changes in our operating expenses, including drydocking, on-water class surveys, insurance costs and bunker costs;

● our ability to comply with financing agreements and the expected effect of restrictions and covenants in such agreements;

● the financial condition liquidity and creditworthiness of our existing or future customers and their ability to satisfy their obligations under our contracts;

● our ability to replace existing borrowings, make additional borrowings and to access public equity and debt capital markets;

● planned capital expenditures and availability of capital resources to fund capital expenditures;

● the exercise of purchase options by our customers;

● our ability to perform under our contracts and maintain long-term relationships with our customers;

● our ability to leverage Höegh LNG’s relationships and reputation in the shipping industry;

● our continued ability to enter into long-term, fixed-rate charters and the hire rate thereof;

● the operating performance of our vessels and any related claims by Total S.A. or other customers;

● our ability to maximize the use of our vessels, including the redeployment or disposition of vessels no longer under long-term charters;

● timely acceptance of our vessels by their charterers;

● termination dates and extensions of charters;

● the cost of, and our ability to comply with, governmental regulations and maritime self-regulatory organization standards, as well as standard regulations imposed by our charterers applicable to our business;

● economic substance laws and regulations adopted or considered by various jurisdictions of formation or incorporation of us and certain of our subsidiaries;

● availability and cost of skilled labor, vessel crews and management, including possible disruptions, including but not limited to the supply chain of spare parts and service engineers, caused by the COVID-19 outbreak;

● the number of off-hire days and drydocking requirements, including our ability to complete scheduled drydocking on time and within budget;

● our general and administrative expenses as a publicly traded limited partnership and our fees and expenses payable under our ship management agreements, the technical information and services agreement and the administrative services agreement;

● the anticipated taxation of the Partnership, our subsidiaries and affiliates and distributions to our unitholders;

● estimated future maintenance and replacement capital expenditures;

● our ability to hire or retain key employees;

● customers’ increasing emphasis on environmental and safety concerns;

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● potential liability from any pending or future litigation;

● risks inherent in the operation of our vessels including potential disruption due to accidents, political events, piracy or acts by terrorists;

● future sales of our common units, Series A preferred units or other securities in the public market;

● our business strategy and other plans and objectives for future operations; and

● our ability to maintain effective internal control over financial reporting and effective disclosure controls and procedures.

Forward-looking statements in this Annual Report are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties, including those risks discussed in “Item 3.D. Risk Factors.” The risks, uncertainties and assumptions involve known and unknown risks and are inherently subject to significant uncertainties and contingencies, many of which are beyond our control.

We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement. We make no prediction or statement about the performance of our common units. The various disclosures included in this Annual Report and in our other filings made with the Securities and Exchange Commission (the “SEC”) that attempt to advise interested parties of the risks and factors that may affect our business, prospects and results of operations should be carefully reviewed and considered.

7

PART I

Item 1.Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.Offer Statistics and Expected Timetable

Not applicable.

Item 3.Key Information

A.Selected Financial Data

The following table presents, in each case for the years and as of the dates indicated, our selected consolidated financial and operating data. Prior to the closing of our initial public offering (“IPO”) on August 12, 2014, Höegh LNG contributed to the Partnership all of its equity interests in each of the entities that own the PGN FSRU Lampung and the joint ventures that own the Neptune and the Cape Ann. The transfer of these equity interests by Höegh LNG to the Partnership in connection with the IPO was recorded at Höegh LNG’s consolidated book values, as adjusted to US GAAP.

On October 1, 2015, the Partnership closed the acquisition of 100% of the shares of Höegh FSRU III, the entity that indirectly owned the Höegh Gallant (the "Höegh Gallant entities"). The results of operations of the Höegh Gallant are included in our results from the acquisition date.

On January 3, 2017, the Partnership closed the acquisition of a 51% ownership interest in the Höegh Colombia Holding, the owner of the entities that own and operate the Höegh Grace (the "Höegh Grace entities"). The results of operations of the Höegh Grace are included in our earnings for the full year of 2017. The interest not owned by the Partnership was reflected as non-controlling interest in net income and non-controlling interest in total equity.

On December 1, 2017, the Partnership closed the acquisition of the remaining 49% ownership interest in the Höegh Grace entities.

Two of the vessels in our fleet (the Neptune and the Cape Ann) are owned by our joint ventures, each of which is owned 50% by us. Under applicable accounting guidance, we do not consolidate the financial results of these two joint ventures into our financial results. We account for our 50% equity interests in these two joint ventures as equity method investments in our consolidated financial statements. We derived cash flows from the operations of these two joint ventures from interest payments on our shareholder loans to our joint ventures.

We have two segments, which are the “Majority held FSRUs” and the “Joint venture FSRUs.” As of December 31, 2020, 2019, 2018 and 2017, Majority held FSRUs included the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace. As of December 31, 2016, Majority held FSRUs included the PGN FSRU Lampung and the Höegh Gallant. As of December 31, 2020, 2019, 2018, 2017 and 2016, Joint venture FSRUs included two 50%-owned FSRUs, the Neptune and the Cape Ann.

8

We measure our segment profit based on segment EBITDA. Segment EBITDA is reconciled to net income for each segment in the segment tables below. The accounting policies applied to the segments are the same as those applied in the consolidated financial statements, except that i) Joint venture FSRUs are presented under the proportional consolidation method for the segment note in the consolidated financial statements and under equity accounting for the consolidated financial statements, ii) internal interest income and interest expense between the Partnership’s subsidiaries that eliminate in consolidation are not included in the segment columns for the other financial income (expense), net line and iii) non-controlling interest in Segment EBITDA is subtracted in the segment note to reflect the Partnership’s interest in Segment EBITDA as the Partnership’s segment profit measure, Segment EBITDA. Under the proportional consolidation method, 50% of the Joint venture FSRUs’ revenues, expenses and assets are reflected in the segment reporting. Management monitors the results of operations of our joint ventures under the proportional consolidation method and not the equity method. On January 1, 2017, the Partnership began consolidating its acquired 51% interest in the Höegh Grace entities. Since the Partnership obtained control of the Höegh Grace entities, it consolidates 100% of the revenues, expenses, assets and liabilities of the Höegh Grace entities and the interest not owned by the Partnership was reflected as non-controlling interest in net income and non-controlling interest in total equity. Management monitored the results of operations of the Höegh Grace entities based on the Partnership’s 51% interest in the Segment EBITDA of such entities and, therefore, subtracted the non-controlling interest in Segment EBITDA to present Segment EBITDA. The adjustment to non-controlling interest in Segment EBITDA is reversed to reconcile to operating income and net income in the segment presentation. On December 1, 2017, the Partnership acquired the remaining 49% ownership interest in the Höegh Grace entities and, as of that date, there is no longer a non-controlling interest in the Höegh Grace entities.

9

You should read the following selected financial and operating data in conjunction with “Item 5. Operating and Financial Review and Prospects” and our consolidated financial statements and the related notes thereto included elsewhere in this Annual Report.

(in thousands of U.S. dollars, except per unit	Year Ended December 31,
information and fleet data)	2020		2019		2018		2017		2016
Statement of Income Data:
Time charter revenues	$	143,095	$	145,321	$	144,952	$	143,531	$	91,107
Other revenue		—		115		1,609		—		—
Total revenues		143,095		145,436		146,561		143,531		91,107
Vessel operating expenses		(24,072)		(30,870)		(24,195)		(23,791)		(16,080)
Construction contract expenses		—		—		—		(151)		(315)
Administrative expenses		(9,740)		(9,861)		(8,916)		(9,910)		(9,718)
Depreciation and amortization		(20,937)		(21,477)		(21,146)		(21,054)		(10,552)
Total operating expenses		(54,749)		(62,208)		(54,257)		(54,906)		(36,665)
Equity in earnings of joint ventures		6,420		6,078		17,938		5,139		16,622
Operating income (loss)		94,766		89,306		110,242		93,764		71,064
Interest income		605		947		725		500		857
Interest expense		(24,430)		(27,692)		(26,814)		(30,085)		(25,178)
Gain (loss) on debt extinguishment		—		1,030		—		—		—
Gain (loss) on derivative instruments		—		—		4,681		2,463		1,839
Other items, net		(2,232)		(3,575)		(2,907)		(3,574)		(3,333)
Income (loss) before tax		68,709		60,016		85,927		63,068		45,249
Income tax expense		(5,564)		(7,275)		(8,305)		(3,878)		(3,872)
Net income (loss)	$	63,145	$	52,741	$	77,622	$	59,190	$	41,377
Non-controlling interest in net income		—		—		—		10,408		—
Preferred unitholders' interest in net income		14,802		13,850		12,303		2,480		—
Limited partners' interest in net income (loss)	$	48,343	$	38,891	$	65,319	$	46,302	$	41,377
Earnings per unit
Common unit public (basic and diluted)	$	1.40	$	1.12	$	1.93	$	1.37	$	1.58
Common unit Höegh LNG (basic and diluted)	$	1.51	$	1.84	$	2.03	$	1.44	$	1.52
Subordinated unit (basic and diluted)	$	—	$	0.70	$	2.03	$	1.45	$	1.52
Cash distributions declared per unit	$	1.76	$	1.76	$	1.76	$	1.72	$	1.65
Balance Sheet Data (at end of period):
Assets:
Cash and cash equivalents	$	31,770	$	39,126	$	26,326	$	22,679	$	18,915
Restricted cash		19,293		20,693		19,128		20,602		22,209
Current portion of advances to joint ventures		3,284		—		—		—		6,275
Accumulated earnings of joint ventures		9,690		3,270		—		—		—
Long term advances to joint ventures		869		3,831		3,536		3,263		943
Net investment in financing lease		274,257		278,904		283,073		286,626		290,111
Total assets		981,810		1,012,800		1,023,040		1,058,959		810,467
Liabilities and equity:
Accumulated losses of joint ventures		—		—		2,808		20,746		25,886
Amounts due to owners and affiliates		2,600		2,513		2,301		1,417		1,374
Long term debt		355,470		412,301		390,087		434,845		300,440
Revolving credit and seller’s credit due to owners and affiliates		18,465		8,792		39,292		51,832		43,005
Total Partners' capital (excluding other comprehensive income (loss))		522,887		519,453		525,774		477,407		370,526
Total liabilities and equity	$	981,810	$	1,012,800	$	1,023,040	$	1,058,959	$	810,467
Cash Flow Data:
Net cash provided by (used in) operating activities	$	85,825	$	85,252	$	91,681	$	79,947	$	36,599
Net cash provided by (used in) investing activities		(8)		(269)		3,067		(38,450)		(83,084)
Net cash provided by (used in) financing activities		(94,622)		(70,625)		(92,478)		(39,340)		29,059
Fleet data
Number of vessels		5		5		5		5		4
Average age (in years)		7.9		6.9		5.9		4.9		4.8
Average remaining charter length excluding charter options (in years)		8.5		9.5		10.5		11.5		13.1
Average remaining charter length including charter options (in years)		15.5		16.5		17.5		18.5		19.4
Other Financial Data:
Segment EBITDA (1)	$	143,403	$	138,094	$	145,687	$	112,156	$	99,159
Capital expenditures
Expenditures for vessels and equipment	$	8	$	269	$	747	$	21	$	537
Selected Segment Data:
Joint venture FSRUs (proportionate consolidation)(2)
Segment Statement of Income Data:
Time charter revenues	$	43,572	$	42,433	$	43,169	$	42,165	$	43,272
Segment EBITDA (1)		34,120		33,389		32,237		21,687		34,165
Operating income	$	24,155	$	23,359	$	22,512	$	11,872	$	24,640
Segment Balance Sheet Data (at end of year):
Vessels, net of accumulated depreciation	$	242,226	$	252,789	$	261,614	$	265,642	$	274,932
Total assets	$	267,003	$	284,174	$	286,283	$	287,562	$	298,712
Segment Capital expenditures:
Expenditures for vessels and equipment	$	77	$	1,108	$	5,795	$	524	$	783

(1) Segment EBITDA is a Non-GAAP financial measure. Please read “Non-GAAP Financial Measures” below.

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(2) Please read “Item 5. Operating and Financial Review and Prospects” below and note 3 of our consolidated financial statements for information on the basis of presentation for the Joint venture FSRUs segment.

Non-GAAP Financial Measures

Segment EBITDA. EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Segment EBITDA is defined as earnings before interest, taxes, depreciation, amortization and impairment, and other financial items less non-controlling interest in Segment EBITDA. Other financial items consist of gain (loss) on debt extinguishment, gain (loss) on derivative instruments and other items, net (including foreign exchange gains and losses and withholding tax on interest expenses). Segment EBITDA is used as a supplemental financial measure by management and external users of financial statements, such as the Partnership's lenders, to assess its financial and operating performance. The Partnership believes that Segment EBITDA assists its management and investors by increasing the comparability of its performance from period to period and against the performance of other companies in the industry that provide Segment EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest, depreciation, amortization, impairment, taxes, and other financial items, which items are affected by various and possibly changing financing methods, capital structure and historical cost basis and which items may significantly affect net income between periods. The Partnership believes that including Segment EBITDA as a financial and operating measure benefits investors in (a) selecting between investing in it and other investment alternatives and (b) monitoring its ongoing financial and operational strength in assessing whether to continue to hold common units or preferred units. Segment EBITDA is a non-GAAP financial measure and should not be considered an alternative to net income, operating income or any other measure of financial performance presented in accordance with US GAAP. Segment EBITDA excludes some, but not all, items that affect net income, and these measures may vary among other companies. Therefore, Segment EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following tables reconcile Segment EBITDA for each of the segments and the Partnership as a whole to net income (loss), the comparable US GAAP financial measure, for the periods presented:

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment				Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)			reporting
Reconciliation to net income (loss)
Net income (loss)	$	80,060	6,420	(23,335)	63,145			$	63,145	(3)
Interest income		(249)	(51)	(356)	(656)	51	(4)		(605)
Interest expense		7,460	11,695	16,970	36,125	(11,695)	(4)		24,430
Depreciation, amortization and impairment		20,937	9,965	—	30,902	(9,965)	(5)		20,937
Other financial items (2)		1,861	6,091	371	8,323	(6,091)	(6)		2,232
Income tax (benefit) expense		5,564	—	—	5,564				5,564
Equity in earnings of JVs:
Interest (income) expense, net		—	—	—	—	11,644	(4)		11,644
Equity in earnings of JVs:
Depreciation and amortization		—	—	—	—	9,965	(5)		9,965
Equity in earnings of JVs:
Other financial items (2)		—	—	—	—	6,091	(6)		6,091
Segment EBITDA	$	115,633	34,120	(6,350)	143,403			$	143,403

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	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)		reporting
Reconciliation to net income (loss)
Net income (loss)	$	70,934	6,078	(24,271)	52,741			$	52,741	(3)
Interest income		(449)	(415)	(498)	(1,362)	415	(4)		(947)
Interest expense		9,582	12,485	18,110	40,177	(12,485)	(4)		27,692
Depreciation, amortization and impairment		21,477	10,030	—	31,507	(10,030)	(5)		21,477
Other financial items (2)		2,348	5,211	197	7,756	(5,211)	(6)		2,545
Income tax (benefit) expense		7,278	—	(3)	7,275				7,275
Equity in earnings of JVs:
Interest (income) expense, net		—	—	—	—	12,070	(4)		12,070
Equity in earnings of JVs:
Depreciation and amortization		—	—	—	—	10,030	(5)		10,030
Equity in earnings of JVs:
Other financial items (2)		—	—	—	—	5,211	(6)		5,211
Segment EBITDA	$	111,170	33,389	(6,465)	138,094			$	138,094

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)		reporting
Reconciliation to net income (loss)
Net income (loss)	$	68,168	17,938	(8,484)	77,622			$	77,622	(3)
Interest income		(305)	(234)	(420)	(959)	234	(4)		(725)
Interest expense		23,875	13,270	2,939	40,084	(13,270)	(4)		26,814
Depreciation and amortization		21,146	9,725	—	30,871	(9,725)	(5)		21,146
Other financial items (2)		(1,870)	(8,462)	96	(10,236)	8,462	(6)		(1,774)
Income tax (benefit) expense		8,253	—	52	8,305				8,305
Equity in earnings of JVs:
Interest (income) expense, net		—	—	—	—	13,036	(4)		13,036
Equity in earnings of JVs:
Depreciation and amortization		—	—	—	—	9,725	(5)		9,725
Equity in earnings of JVs:
Other financial items (2)		—	—	—	—	(8,462)	(6)		(8,462)
Segment EBITDA	$	119,267	32,237	(5,817)	145,687			$	145,687

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	Year ended December 31, 2017
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)		reporting
Reconciliation to net income (loss)
Net income (loss)	$	63,628	5,139	(9,577)	59,190			$	59,190	(3)
Interest income		(18)	(76)	(482)	(576)	76	(4)		(500)
Interest expense		26,151	13,983	3,934	44,068	(13,983)	(4)		30,085
Depreciation and amortization		21,054	9,815	—	30,869	(9,815)	(5)		21,054
Other financial items (2)		1,060	(7,174)	51	(6,063)	7,174	(6)		1,111
Income tax (benefit) expense		3,893	—	(15)	3,878				3,878
Equity in earnings of JVs:
Interest (income) expense, net		—	—	—	—	13,907	(4)		13,907
Equity in earnings of JVs:
Depreciation and amortization		—	—	—	—	9,815	(5)		9,815
Equity in earnings of JVs:
Other financial items (2)		—	—	—	—	(7,174)	(6)		(7,174)
Non-controlling interest in Segment EBITDA		(19,210)	—	—	(19,210)				(19,210)
Segment EBITDA	$	96,558	21,687	(6,089)	112,156			$	112,156

	Year ended December 31, 2016
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)		reporting
Reconciliation to net income (loss)
Net income (loss)	$	35,803	16,622	(11,048)	41,377			$	41,377	(3)
Interest income		—	(2)	(857)	(859)	2	(4)		(857)
Interest expense		20,107	15,094	5,071	40,272	(15,094)	(4)		25,178
Depreciation and amortization		10,552	9,525	—	20,077	(9,525)	(5)		10,552
Other financial items (2)		1,435	(7,074)	59	(5,580)	7,074	(6)		1,494
Income tax (benefit) expense		3,852	—	20	3,872				3,872
Equity in earnings of JVs:
Interest (income) expense, net		—	—	—	—	15,092	(4)		15,092
Equity in earnings of JVs:
Depreciation and amortization		—	—	—	—	9,525	(5)		9,525
Equity in earnings of JVs:
Other financial items (2)		—	—	—	—	(7,074)	(6)		(7,074)
Segment EBITDA	$	71,749	34,165	(6,755)	99,159			$	99,159

(1) Eliminations reverse each of the income statement reconciling line items of the proportional amounts for Joint venture FSRUs that are reflected in the consolidated net income for the Partnership’s share of the Joint venture FSRUs net income (loss) on the Equity in earnings (loss) of joint ventures line item in the consolidated income statement. Separate adjustments from the consolidated net income to Segment EBITDA for the Partnership’s share of the Joint venture FSRUs are included in the reconciliation lines starting with “Equity in earnings of JVs.”

(2) Other financial items consist of gain and loss on debt extinguishment, gains and losses on derivative instruments and other items, net including foreign exchange gains or losses and withholding tax on interest expense.

(3) There is no adjustment between net income for Total Segment reporting and the Consolidated reporting because the net income under the proportional consolidation and equity method of accounting is the same.

(4) Interest income and interest expense for the Joint venture FSRUs is eliminated from the Total Segment reporting to agree to the interest income and interest expense in the Consolidated reporting and reflected as a separate adjustment to the equity accounting on the line Equity in earnings of JVs: Interest (income) expense for the Consolidated reporting.

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(5) Depreciation and amortization for the Joint venture FSRUs is eliminated from the Total Segment reporting to agree to the depreciation and amortization in the Consolidated reporting and reflected as a separate adjustment to the equity accounting on the line Equity in earnings of JVs: Depreciation and amortization for the Consolidated reporting.

(6) Other financial items for the Joint venture FSRUs is eliminated from the Segment reporting to agree to the Other financial items in the Consolidated reporting and reflected as a separate adjustment to the equity accounting on the line Equity in earnings of JVs: Other financial items for the Consolidated reporting.

B.Capitalization and Indebtedness

Not applicable.

C.Reasons for the Offer and Use of Proceeds

Not applicable.

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D.Risk Factors

The risk factors summarized and detailed below could materially and adversely affect our business, our financial condition, our operating results, cash available for distribution and the trading price of our preferred and common units. These material risks include, but are not limited to, those relating to:

● Any limitation on the availability or operation of our vessels could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to make distributions to our unitholders.

● We are dependent on four customers as the sole customers for our vessels. A deterioration of the financial viability of, or our relationship with, or the loss of any of these customers, would have a material adverse effect.

● Höegh LNG has financial obligations to us pursuant to the Subsequent Charter and its guarantee and indemnification obligations. The inability of Höegh LNG to meet its financial obligations to us would have a material adverse effect.

● Our growth depends on our ability to expand relationships with existing customers and obtain new customers, for which we will face substantial competition.

● Höegh LNG and its affiliates may compete with us.

● We may not be able to redeploy FSRUs on terms as favorable as our or our joint venture’s current FSRU charters or at all.

● Hire rates for FSRUs may fluctuate substantially.

● Fluctuations in overall LNG supply and demand growth could adversely affect our ability to secure future long-term charters.

● Outbreaks of epidemic and pandemic diseases and governmental responses thereto could adversely affect our business.

● PGN LNG and SPEC have options to purchase the PGN FSRU Lampung and Höegh Grace, respectively.

● Due to our lack of diversification, adverse developments in our LNG transportation, storage and regasification businesses could reduce our ability to make cash distributions to our unitholders.

● We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay distributions on our Series A preferred units or our common units.

● Our ability to grow and to meet our financial needs may be adversely affected by our cash distribution policy.

● We cannot require our joint ventures to act in our best interests.

● We must make substantial capital expenditures to maintain and replace the operating capacity of our fleet. Each quarter we will be required to deduct estimated maintenance and replacement capital expenditures from operating surplus.

● The required drydocking or on-water surveys of our vessels could be more expensive and time consuming than we anticipate.

● We may experience operational problems that could reduce revenue, increase costs or lead to termination of our charters.

● If capital expenditures are financed through cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage could increase, or our unitholders may be diluted.

● We may be unable to make or realize expected benefits from acquisitions.

● Our future performance and growth depend on continued growth in demand for the services we provide.

● Growth of the LNG market may be limited by many factors, including infrastructure constraints and community and political group resistance to new LNG infrastructure over concerns about environmental, safety and terrorism.

● Demand for FSRUs or LNG shipping could be affected by volatile natural gas prices and the overall demand for natural gas.

● The debt levels of us and our joint ventures may limit our and their flexibility in obtaining additional financing, refinancing credit facilities upon maturity or pursuing other business opportunities or our paying distributions to you.

● Our financing arrangements of us and our joint ventures are secured by our vessels and contain operating and financial restrictions and other covenants.

● Restrictions in our debt agreements and local laws may prevent us from paying distributions to our unitholders.

● Höegh LNG’s and its subsidiary’s failure to comply with certain obligations under the Lampung facility and the $385 million facility, and certain other events occurring at Höegh LNG, could result in defaults under such facilities.

● Höegh LNG has entered into a revolving credit facility pursuant to which it has pledged as collateral all of its interests in our general partner and all of its common units in order to secure the related loan.

● An increase in the global supply or aggregate capacities of FSRUs or LNG carriers, including conversion of existing tonnage, without a commensurate increase in demand may have an adverse effect on hire rates and the values of our vessels.

● Vessel values may fluctuate substantially, and a decline in vessel values may result in impairment charges, the breach of our financial covenants or, if these values are lower at a time when we are attempting to dispose of vessels, a loss on the sale.

● We depend on Höegh LNG and its affiliates for the management of our fleet and to assist us in operating our business.

● An incident involving significant loss of life or property or environmental consequences involving any of our vessels could harm us.

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

● An increase in operating expenses could adversely affect our financial performance.

● A shortage of qualified officers and crew, including possible disruptions caused by the COVID-19 outbreak, could harm us.

● We may be unable to attract and retain key management personnel.

● Exposure to currency exchange rate fluctuations could result in fluctuations in our cash flows and operating results.

● Acts of piracy on any of our vessels or on oceangoing vessels could adversely affect us.

● Terrorist attacks, increased hostilities, piracy or war could lead to economic instability, increased costs and disruption.

● We are exposed to political, regulatory, and economic risks associated with doing business in different countries.

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

● Our operations are subject to substantial environmental and other regulations, which may significantly increase our expenses.

● Changes to existing environmental laws applicable to international and national maritime trade may adversely affect us.

● Climate change and greenhouse gas restrictions may adversely impact our operations and markets.

● Maritime claimants could arrest our vessels, which could interrupt our cash flows.

● Governments could requisition our vessels during a period of war or emergency, resulting in loss of earnings.

● Compliance with safety and other vessel requirements imposed by classification societies may adversely affect us.

● Failure to comply with anti-corruption and anti-bribery legislation could adversely affect our business.

● If in the future our business activities involve countries, entities and individuals that are subject to restrictions imposed by the U.S. or other governments, we could be subject to enforcement action and our reputation could be adversely affected.

● If we fail to comply with the requirements of the Sarbanes-Oxley Act or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information.

● A cyber-attack could materially disrupt our business.

● Changing laws and evolving reporting requirements could have an adverse effect on our business.

● Increased regulatory oversight, uncertainty relating to the nature and timing of the potential phasing out of LIBOR, and agreement on any new alternative reference rates may adversely affect us.

● Unitholders have limited voting rights, and holders of more than 4.9% of our common units have restricted voting rights.

● Our general partner and its other affiliates own a significant interest in us and have conflicts of interest and limited fiduciary and contractual duties, which may permit them to favor their own interests to your detriment.

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

● Our partnership agreement limits our general partner’s and our directors’ fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner or our directors.

● Fees and expenses, which Höegh LNG determines for services provided to us and our joint ventures, are substantial.

● Our partnership agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or our general partner.

● The control of our general partner may be transferred to a third party without unitholder consent.

● Substantial future sales of our common units in the public market could cause the price of our common units to fall.

● Our operations may be subject to local economic substance regulations required by the European Union.

● Marshall Islands law lacks a bankruptcy statute or general statutory mechanism for insolvency proceedings.

● Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders unless otherwise provided for under the laws of the Marshall Islands.

● We rely on the master limited partnership (“MLP”) structure and its appeal to investors for accessing debt and equity markets to finance our growth and repay or refinance our debt.

● The Republic of the Marshall Islands does not have a well-developed body of partnership law.

● It may be difficult to serve us with legal process or enforce judgments against us, our directors or our management.

● Höegh LNG may elect to cause us to issue additional common units to it in connection with a resetting of the incentive distribution rights' target distribution levels.

● We may issue additional equity securities, including securities senior to the common units.

● In establishing cash reserves, our board of directors may reduce the amount of cash available for distribution to unitholders.

● Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.

● Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

● We can borrow money to make cash distributions, which would reduce the amount of credit available to operate our business.

● Increases in interest rates may cause the market price of our units to decline.

● Unitholders may have liability to repay distributions.

● The Series A preferred units represent perpetual equity interests.

● The Series A preferred units have not been rated.

● Our Series A preferred units are subordinated to our debt obligations, and the interests of holders of Series A preferred units could be diluted by the issuance of additional limited partner interests and by other transactions.

● The Series A preferred units rank junior to any Senior Securities and pari passu with any Parity Securities.

● The Series A preferred units do not have an established trading market.

● The Series A preferred units are redeemable at our option.

● We are subject to taxes, which reduces our cash available for distribution to you.

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

● U.S. tax authorities could treat us as a “passive foreign investment company.”

● We may have to pay tax on U.S. source income, which would reduce our cash flow.

● You may be subject to income tax in one or more non-U.S. jurisdictions as a result of owning our common units.

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Risks Inherent in Our Business

Our fleet consists of five vessels as of March 31, 2021. Any limitation on the availability or operation of those vessels could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to make distributions to our unitholders.

Our fleet consists of five vessels. If any of these vessels is unable to generate revenues as a result of off-hire time, early termination of the applicable time charter, purchase of the vessel by the charterer or otherwise, our financial condition and ability to make distributions to unitholders could be materially and adversely affected.

The charters relating to our vessels permit the charterer to terminate the charter in the event that the vessel is off-hire for any extended period. The charters also allow the charterer to terminate the charter upon the occurrence of specified defaults by us or in certain other cases, including termination without cause, due to force majeure or disruptions caused by war. Furthermore, PGN LNG was granted an option to purchase the PGN FSRU Lampung at specified prices commencing in June 2018 and SPEC has the option to purchase the Höegh Grace in year 10, year 15 and year 20 of its charter. The termination of any of our charters could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to make cash distributions to our unitholders. For further details regarding termination of our charters, please read “Item 4.B. Business Overview—Vessel Time Charters— Neptune Time Charter—Termination,” “— PGN FSRU Lampung Time Charter—Termination and —Purchase Option,” “—Höegh Gallant Time Charter—Termination,” “— Höegh Grace Charter—Term and Termination and —Purchase Option.” We may be unable to charter the applicable vessel, or replacement vessel, on terms as favorable to us as those of the terminated charter.

We are dependent on Total Gas & Power, PGN LNG, Höegh LNG and SPEC as the sole customers for our vessels. A deterioration of the financial viability of Total Gas & Power, PGN LNG, Höegh LNG or SPEC or our relationship with Total Gas & Power Global LNG Supply, PGN LNG, Höegh LNG or SPEC or the loss of Total Gas & Power, PGN LNG, Höegh LNG or SPEC as a customer, would have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

For each of the years ended December 31, 2020, 2019 and 2018, PGN LNG, Höegh LNG and SPEC accounted for all of the revenues in our consolidated income statement. For each of the years ended December 31, 2020, 2019 and 2018, Total Gas & Power or Global LNG Supply accounted for all of the revenues of our joint ventures from which we derived all of our equity in earnings of joint ventures. Our joint ventures’ time charters were novated from Global LNG Supply to Total Gas & Power in February 2020. A deterioration in the financial viability of Total Gas & Power, PGN LNG, Höegh LNG or SPEC or the loss of Total Gas & Power, PGN LNG, Höegh LNG or SPEC as a customer, or a decline in payments under any of the related charters, would have a greater adverse effect on us than for a company with a more diverse customer base, and could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

We or our joint ventures could lose a customer or the benefits of a charter as a result of a breach by the customer of a charter or other unanticipated developments, such as:

● the customer failing to make charter payments or reducing charter payments because of its financial inability, disagreements with us or our joint venture partners or otherwise;

● the insolvency, bankruptcy or liquidation of a customer or termination of the charter as a result thereof;

● the customer exercising its right to terminate the charter in certain circumstances, such as: (i) defaults of our or our joint ventures’ obligations under the applicable charter, including breaches of performance standards or prolonged periods of off-hire; (ii) with respect to the Neptune, the Cape Ann and the Höegh Gallant, in the event of war that would materially interrupt the performance of the time charter; or (iii) with respect to the PGN FSRU Lampung, in the event of specified types of force majeure;

● the charter terminating automatically if the vessel is lost or deemed a constructive loss;

● with respect to the Höegh Gallant, the inability of Höegh LNG to perform under the lease and maintenance agreement entered on April 30, 2020 entered into with CharterCo, a subsidiary of Höegh LNG, to charter the

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Höegh Gallant from May 1, 2020 until July 31, 2025 (the “Subsequent Charter”); see “Item 7.B. Related Party Transactions—Acquisition of the Höegh Gallant ”;

● with respect to the PGN FSRU Lampung or the Höegh Grace, the charterer exercising its option to purchase the vessel; or

● a prolonged force majeure event that materially interrupts the performance of the time charter.

If any charter is terminated, we or our joint ventures, as applicable, may be unable to re-deploy the related vessel on terms as favorable as the current charters or at all. In addition, any termination fee payable to us may not adequately compensate us for the loss of the charter. Furthermore, if there was a premature termination of our joint venture charters that does not result in termination fees, it would result in mandatory repayments of the outstanding balances under the loan facilities for the Neptune and the Cape Ann.

Any event, whether in our industry or otherwise, that adversely affects a customer’s financial condition, leverage, results of operations, cash flows or demand for our services may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of our customers, including their level of indebtedness and the economic conditions and government policies in their areas of operation. Further, not all of our charters have parent company guarantees. For example, Total Gas & Power’s obligations under the Neptune and the Cape Ann charters are not guaranteed by its parent, Total.

The ability of each of our customers to perform its obligations under its applicable charter depends on its future financial condition and economic performance, which, in turn, will depend on prevailing economic conditions and financial, business and other factors, many of which are beyond its control.

Höegh LNG has financial obligations to us pursuant to the Subsequent Charter and its guarantee and indemnification obligations. The inability of Höegh LNG to meet its financial obligations to us would have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Pursuant to an option agreement, we had the right to cause Höegh LNG to charter the Höegh Gallant from the expiration or termination of the EgyptCo charter until July 2025, at a rate equal to 90% of the rate payable pursuant to the current charter, plus any incremental taxes or operating expenses as a result of the new charter. On February 27, 2020, we exercised our option pursuant to the option agreement and we entered into a Subsequent Charter with Höegh LNG for the Höegh Gallant.

We are indemnified by Höegh LNG for our 50% share of the cash impact of the settlement agreements, effective April 1, 2020, related to the boil-off claims against the joint ventures, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreements.

Höegh LNG’s ability to make payments to us under the Subsequent Charter may be affected by events beyond either of the control of Höegh LNG or us, including opportunities to obtain new employment for the vessel, and prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Höegh LNG’s ability to meet its obligations to us may be impaired. If Höegh LNG is unable to meet its obligations to us under the Subsequent Charter or pursuant to its indemnification obligations, our financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected.

Our growth depends on our ability to expand relationships with existing customers and obtain new customers, for which we will face substantial competition.

One of our principal objectives is to enter into additional long-term charters for FSRUs, LNG carriers and other LNG infrastructure assets. The process of obtaining long-term charters for FSRUs, LNG carriers and other LNG infrastructure assets is competitive and generally involves an intensive screening process and competitive bids, and then often extends

18

for several months. We believe FSRU and LNG carriers time charters are awarded based upon a variety of factors relating to the vessel operator, including:

● FSRU or LNG carrier experience and quality of ship operations;

● quality of vessels;

● cost effectiveness;

● shipping industry relationships and reputation for customer service and safety;

● technical ability and reputation for operation of highly specialized vessels;

● quality and experience of seafaring crew;

● safety record;

● the ability to finance vessels at competitive rates and financial stability generally;

● relationships with shipyards and the ability to get suitable berths;

● construction management experience, including the ability to obtain on-time delivery of new FSRUs, LNG carriers and other LNG infrastructure assets according to customer specifications;

● willingness to accept operational risks pursuant to the charter, such as allowing termination of the charter for force majeure events; and

● competitiveness of the bid in terms of overall price.

We face substantial competition for providing floating storage and regasification services and marine transportation services for potential LNG projects from a number of experienced companies, including state-sponsored entities and major energy companies. As the FSRU market continues to grow and mature there are new competitors entering the market. Many of these competitors have significantly greater financial resources and larger fleets than we do. In particular, expectations of rapid growth in the FSRU market has given owners the confidence to place orders for FSRUs before securing charters. This has led to more competition for mid- and long-term FSRU charters. We anticipate that an increasing number of marine transportation companies—including many with strong reputations and extensive resources and experience—will enter the FSRU or LNG carrier markets. This increased competition has already and may in the future cause greater price competition for time charters. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a profitable basis, if at all, which would have a material adverse effect on our financial condition, results of operations and ability to make cash distributions to our unitholders.

Höegh LNG and its affiliates may compete with us.

Pursuant to the omnibus agreement that we and Höegh LNG entered into in connection with the closing of the IPO, Höegh LNG and its controlled affiliates (other than us, our general partner and our subsidiaries) generally have agreed not to acquire, own, operate or charter certain FSRUs and LNG carriers operating under charters of five or more years. The omnibus agreement, however, contains significant exceptions that may allow Höegh LNG or any of its controlled affiliates to compete with us, which could harm our business. Additionally, the omnibus agreement contains no restrictions on Höegh LNG’s ability to own, operate or charter FSRUs and LNG carriers operating under charters of less than five years. Thus, Höegh LNG may compete with us for rechartering for charters of less than five years. Also, pursuant to the omnibus agreement, we have agreed not to acquire, own, operate or charter FSRUs and LNG carriers operating under charters of less than five years.

On March 8, 2021, Höegh LNG announced a recommended offer by Leif Höegh & Co. Ltd. (“LHC”) and funds managed by Morgan Stanley Infrastructure Partners (“MSIP”) through a 50/50 joint venture, Larus Holding Limited

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(“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates (the “Amalgamation”). Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange. The Amalgamation has been approved by Höegh LNG’s shareholders and bondholders and is anticipated to close in the first half of 2021. The Amalgamation is subject to waivers of specific change of control and delisting provisions in relation to certain of our and Höegh LNG's credit agreements, as well as the satisfaction of other customary closing conditions.

Following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement that we entered into with Höegh LNG in connection with the closing of the IPO will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels (as defined in “Major Unitholders and Related Party Transactions – Related Party Transactions – Omnibus Agreement – Non Competition”), (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us. Please read “Item 7.B. Related Party Transactions—Omnibus Agreement—Noncompetition.”

We may not be able to redeploy our FSRUs on terms as favorable as our or our joint venture’s current FSRU time charters or at all.

Due to increased competition and the limitations on demand for FSRUs, in the event that any of the time charters on our vessels are terminated, we may be unable to recharter such vessel as an FSRU. While we may be able to employ such vessel as a traditional LNG carrier, the hire rates and/or other charter terms may not be as favorable to us as those in the existing time charter. If we acquire additional FSRUs and they are not, as a result of time charter termination or otherwise, subject to a long-term, profitable time charter, we may be required to bid for projects at unattractive rates in order to reduce our losses relating to the vessels.

Requirements for some new LNG projects continue to be provided on a long-term basis, though the use of medium term charters of up to five years has increased in recent years. More frequent changes to vessel sizes and propulsion technology together with an increasing desire by charterers to access modern vessels could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period, or to exercise options to extend their current charters. As a result, the duration of long-term charters could also decrease over time. We may also face increased difficulty entering into long-term time charters upon the expiration or early termination of our existing charters or of charters for any vessels that we acquire in the future. If as a result we contract our vessels on shorter term contracts, our earnings from these vessels are likely to become more volatile.

Hire rates for FSRUs may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings and ability to make distributions to our unitholders may decline.

Hire rates for FSRUs fluctuate over time as a result of changes in the supply-demand balance relating to current and future vessel supply. This supply-demand relationship largely depends on a number of factors outside our control. For example, driven in part by an increase in LNG production capacity, the market supply of FSRUs has been increasing as a result of the construction of new vessels before FSRU projects have matured to the point of entering FSRU contracts. The increase in supply has resulted in increased competition for FSRU contracts resulting in lower FSRU prices for recent contracts awarded. As of December 31, 2020, the FSRU order book totaled 8 vessels and the delivered FSRU fleet stood at 38 vessels. We believe any future expansion of the FSRU fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, which impact could be amplified if the expansion of LNG production capacity or the approval of FSRU projects does not keep pace with the growth of the global fleet. The LNG market is also closely connected to world natural gas prices and energy markets, which we cannot predict. An extended decline in natural gas prices that leads to reduced investment in new liquefaction facilities could adversely affect our ability to re-charter our vessels at acceptable rates or to acquire and profitably operate new FSRUs. Accordingly, this could have a material adverse effect on our earnings and our ability to make distributions to our unitholders.

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Fluctuations in overall LNG supply and demand growth could adversely affect our ability to secure future long-term charters.

Demand for LNG depends on a number of factors, including economic growth, the cost effectiveness of LNG compared to alternative fuels, environmental policy and the perceived need to diversify fuel mix for energy security reasons. The cost effectiveness of LNG compared to alternative fuels is also dependent on supply. A change in any of the factors influencing LNG demand, or an imbalance between supply and demand, could adversely affect the need for LNG infrastructure and our ability to secure additional long-term charters. Volatility in natural gas prices globally may limit the willingness and ability of developers of new LNG infrastructure projects to approve the development of such new projects. Delayed development decisions may materially adversely affect our growth prospects and results of operations.

Outbreaks of epidemic and pandemic diseases and governmental responses thereto could adversely affect our business.

Our operations are subject to risks related to outbreaks of infectious diseases. The COVID-19 outbreak has negatively affected economic conditions, energy prices and the demand for LNG and LNG shipping regionally as well as globally and may otherwise impact our operations and the operations of our customers and suppliers. Governments in affected countries have imposed travel bans, quarantines and other emergency public health measures. Those measures, though temporary in nature, may continue and increase depending on developments in the virus’ outbreak. As a result of these measures, our vessels may not be able to call on ports or may be restricted from embarking and disembarking from ports, located in regions affected by COVID-19.

Although our operations have not been materially affected by the COVID-19 outbreak to date, the ultimate length and severity of the COVID-19 outbreak is uncertain at this time and therefore we cannot predict the impact it may have on our future operations, which could be material and adverse. Although large scale distribution of vaccines may mitigate some of this uncertainty, it remains too early to definitively judge the speed, scale and overall effect of vaccination efforts.

We believe our primary risk and exposure related to uncertainty of cash flows from our long-term time charter contracts is due to the credit risk associated with the individual charterers. Payments are due under time charter contracts regardless of the demand for the charterers’ gas output or the utilization of the FSRU. It is therefore possible that charterers may not make payments for time charter invoices in times of reduced demand. Furthermore, should there be an outbreak of COVID-19 on board one of our FSRUs or an inability to replace critical supplies or replacement parts due to disruptions to third-party suppliers, adequate crewing or supplies may not be available to fulfill our obligations under our time charter contracts. This could result in off-hire or warranty payments under performance guarantees which would reduce revenues for the impacted period. In addition, if financial institutions providing our interest rate swaps or lenders under our revolving credit facility are unable to meet their obligations, we could experience higher interest expense or be unable to obtain funding. If our charterers or lenders are unable to meet their obligations to us under their respective contracts or if we are unable to fulfill our obligations under our time charter contracts, our financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected. The Lampung facility and Neptune facility must be refinanced in 2021. Should we be unable to obtain refinancing for the Lampung facility or the Neptune facility, we may not have sufficient funds or other assets to satisfy all of our obligations, which would have a material adverse effect on our business, results of operations and financial condition.

Failure to control the continued spread of COVID-19 could significantly impact economic activity and demand for our vessels, which could further negatively affect our business, financial condition, results of operations and cash available for distribution and could result in declines in our unit price.

PGN LNG and SPEC have options to purchase the PGN FSRU Lampung and Höegh Grace, respectively. If either charterer exercises its option, it could have a material adverse effect on our operating cash flows and our ability to make cash distributions to our unitholders.

PGN LNG currently has the option to purchase the PGN FSRU Lampung on June 1st of each year, at a price specified in the time charter. SPEC also has the option to purchase the Höegh Grace at a price specified in the Höegh Grace charter in year 10, year 15 and year 20 of such charter. Any compensation we receive for the purchase of the PGN FSRU Lampung or the Höegh Grace may not adequately compensate us for both the loss of the applicable vessel and related time charter. If either charterer exercises its option, it would significantly reduce the size of our fleet, and we may be

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unable to identify or acquire suitable replacement vessel(s) with the proceeds of the option exercise because, among other things that are beyond our control, there may be no replacement vessel(s) that are readily available for purchase at a price that is equal to or less than the proceeds from the option exercise and on terms acceptable to us. Even if we find suitable replacement vessel(s), the hire rate(s) of such vessel(s) may be significantly lower than the hire rate under the current time charters. Our inability to find suitable replacement vessel(s) or the chartering of replacement vessel(s) at lower hire rate(s) would have a material adverse effect on our results of operations, cash flows and ability to make cash distributions to our unitholders. Please read “Item 4.B. Business Overview—Vessel Time Charters— PGN FSRU Lampung Time Charter—Purchase Option” and “—Vessel Time Charters— Höegh Grace Charter—Purchase Option.”

Due to our lack of diversification, adverse developments in our LNG transportation, storage and regasification businesses could reduce our ability to make cash distributions to our unitholders.

We rely exclusively on the cash flows generated from our FSRUs. Due to our lack of diversification, an adverse development in the LNG transportation, storage and regasification industry could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets or lines of business.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distribution on our Series A preferred units or the minimum quarterly distribution on our common units.

We may not have sufficient cash from operations to pay the quarterly distributions on our Series A preferred units or our common units. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations. We generate cash from our operations and through distributions from our joint ventures, and as such our cash from operations is dependent on our operations and the cash distributions and operations of our joint ventures, each of which may fluctuate based on the risks described herein, including, among other things:

● the hire rates we and our joint ventures obtain from charters;

● the level of operating costs and other expenses, such as the cost of crews, insurance, performance guarantees and liquidated damages;

● demand for LNG;

● supply and capacities of FSRUs and LNG carriers;

● prevailing global and regional economic and political conditions;

● currency exchange rate fluctuations;

● interest rate fluctuations; and

● the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of our business.

In addition, the actual amount of cash we will have available for distribution on our units will depend on other factors, including:

● the level of capital expenditures we and our joint ventures make, including for maintaining or replacing vessels, building new vessels, acquiring existing vessels and complying with regulations;

● the number of off-hire or reduced-hire days for our fleet and the timing of, and number of days required for, scheduled drydocking of our vessels;

● our and our joint ventures’ debt service requirements, minimum free liquid asset requirements under debt covenants, and restrictions on distributions contained in our and our joint ventures’ current and future debt instruments;

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● fluctuations in interest rates;

● fluctuations in working capital needs;

● variable corporate income tax rates, payroll taxes, value added taxes and withholding taxes and to the extent applicable, the ability to recover under charters;

● our ability to make, and the level of, working capital borrowings; and

● the amount of any cash reserves established by our board of directors.

In addition, each quarter we are required by our partnership agreement to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted. Our ability to pay distributions will also be limited to the extent that we have sufficient cash after establishment of cash reserves.

The amount of cash we generate from our operations and the cash distributions received from our joint ventures may differ materially from our or their profit or loss for the period, which will be affected by non-cash items. As a result of this and the other factors mentioned above, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

At present, we only have two sources of available working capital borrowings that can be used to fund our general partnership purposes, including working capital and distributions: the $63 million revolving credit tranche under our $385 million facility and the $85 million revolving credit facility with Höegh LNG. Höegh LNG’s ability to make loans under the revolving credit facility may be affected by events beyond its and our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our and their ability to comply with the terms of the revolving credit facility may be impaired. If we request a borrowing under the revolving credit facility, Höegh LNG may not have, or be able to obtain, sufficient funds to make loans under the revolving credit facility. In the event that Höegh LNG is unable to make loans to us pursuant to the revolving credit facility, or a default or other circumstance prohibits us from borrowing loans thereunder our financial condition, results of operations and ability to make cash distributions to our unitholders could be materially adversely affected.

Our ability to grow and to meet our financial needs may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to pay the distribution on our Series A preferred units, which rank senior to our common units, and then distribute all of our available cash (as defined in our partnership agreement) to our common units each quarter. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

In determining the amount of cash available for distribution, our board of directors approves the amount of cash reserves to set aside, including reserves for future maintenance and replacement capital expenditures, working capital and other matters. We may also rely upon external financing sources, including commercial borrowings, to fund our capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may significantly impair our ability to meet our financial needs or to grow.

We are a holding entity that has historically derived a portion of our income from equity interests in our joint ventures. Neither we nor our joint venture partners exercise affirmative control over our joint ventures. Accordingly, we cannot require our joint ventures to act in our best interests. Furthermore, our joint venture partners may prevent our joint ventures from taking action that may otherwise be beneficial to us, including making cash distributions to us. A deadlock between us and our joint venture partners could result in our exchanging equity interests in one of our joint ventures for the equity interests in our other joint venture held by our joint venture counterparties or in us or our joint venture partner selling shares in a joint venture to a third party.

We are a holding entity and conduct our operations and businesses through subsidiaries. We have historically derived a portion of our income from our 50% equity interests in our joint ventures that own the Neptune and the Cape Ann. Please read “Item 4.B. Business Overview—Shareholder Agreements” for a description of the shareholders’ agreement governing our joint ventures. Our ability to make cash distributions to our unitholders will depend on the performance of

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our joint ventures, subsidiaries and other investments. If our joint venture partners do not approve cash distributions or if they are not sufficient, we will not be able to make cash distributions unless we obtain funds from other sources. We may not be able to obtain the necessary funds from other sources on terms acceptable to us. The approval of a majority of the members of the board of directors is required to consent to any proposed action by such joint ventures and, as a result, we will be unable to cause our joint venture to act in our best interests over the objection of our joint venture partners or make cash distributions to us. Our inability to require our joint ventures to act in our best interests may cause us to fail to realize expected benefits from our equity interests and could adversely affect our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Our joint venture partners for our joint ventures that own the Neptune and the Cape Ann are Mitsui O.S.K. Lines, Ltd (“MOL”) and Tokyo LNG Tanker Co., Ltd (“TLT”), whom we refer to in this Annual Report as our joint venture partners. These entities together exercise one half of the voting power on the board of directors of each joint venture. As such, our joint venture partners may prevent our joint ventures from making cash distributions to us or may act in a manner that would otherwise not be in our best interests.

If the directors nominated by us and our joint venture partner are unable to reach agreement on any decision or action, then the issue will be resolved in accordance with the procedures set forth in the shareholders’ agreement. After the board of directors has met a second time to consider the decision or action, if the deadlock persists, one or more of our senior executives will meet with their counterpart(s) from our joint venture partners. Should, after no more than 60 days, these efforts be unsuccessful and we and our joint venture partners, on a combined basis, each own 50% of the shares in each joint venture or, when the shareholdings in each joint venture are aggregated by party, we and our joint venture partners, on a combined basis, each own 50% of the aggregate shares, we and our joint venture partners will attempt to agree within 30 days that our shareholdings be exchanged so that we own 100% of one joint venture and our joint venture partners own 100% of the other joint venture. If, however, the shareholdings are not as described in the previous sentence or we and our joint venture partners cannot agree within the specified time, we or our joint venture partners may sell our shares, including to a third party, in accordance with the procedures set forth in the shareholders’ agreement. If any of these forms of resolution were to occur, the diversity of our fleet would be reduced, and our business, financial condition, results of operations and ability to make cash distributions to our unitholders may be adversely affected.

We must make substantial capital expenditures to maintain and replace the operating capacity of our fleet, which will reduce our cash available for distribution. In addition, each quarter we will be required, pursuant to our partnership agreement, to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance and replacement capital expenditures were deducted.

We must make substantial capital expenditures to maintain and replace, over the long-term, the operating capacity of our fleet. Maintenance and replacement capital expenditures include capital expenditures associated with drydocking a vessel, including costs for inspection, maintenance and repair, modifying an existing vessel, acquiring a new vessel or otherwise replacing current vessels at the end of their useful lives to the extent these expenditures are incurred to maintain or replace the operating capacity of our fleet. These expenditures could vary significantly from quarter to quarter and could increase as a result of changes in:

● the cost of labor and materials;

● customer requirements;

● fleet size;

● length of charters;

● vessel useful life;

● the cost of replacement vessels;

● re-investment rate of return;

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● resale or scrap value of existing vessels;

● governmental regulations and maritime self-regulatory organization standards relating to safety, security or the environment; and

● competitive standards.

Our partnership agreement requires our board of directors to deduct estimated maintenance and replacement capital expenditures, instead of actual maintenance and replacement capital expenditures, from operating surplus each quarter in an effort to reduce fluctuations in operating surplus as a result of significant variations in actual maintenance and replacement capital expenditures each quarter. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our board of directors at least once a year (with the approval of the conflicts committee of our board of directors). In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance and replacement capital expenditures were deducted from operating surplus. If our board of directors underestimates the appropriate level of estimated maintenance and replacement capital expenditures, we may have less cash available for distribution in periods when actual capital expenditures exceed our previous estimates. Refer to “Item 8.A. Consolidated Statements and Other Financial Information—The Partnership’s Cash Distribution Policy—Estimated Maintenance and Replacement Capital Expenditures” for a description of our estimated annual maintenance and replacement capital expenditures.

The required drydocking or on-water surveys of our vessels could be more expensive and time consuming than we anticipate, which could adversely affect our cash available for distribution.

The drydocking or on-water survey of our vessels could become longer and more costly than we expect, and in the case of the Neptune and the Cape Ann could be drydocked for longer than the allowable period under the time charters. Although the Neptune and Cape Ann time charters, require the charterer to pay the hire rate for up to a specified number of days of scheduled drydocking and reimburse us for anticipated drydocking costs, any significant increase in the number of days of drydocking beyond the specified number of days during which the hire rate remains payable could have a material adverse effect on our ability to make cash distributions to our unitholders. Furthermore, under the PGN FSRU Lampung time charter, the vessel will be deemed to be off-hire if drydocking exceeds designated allowances, and under the Höegh Grace and the Höegh Gallant time charters, the vessels will be deemed to be off-hire during drydocking. There are no pass-through provisions for drydocking or on-water expenses for the PGN FSRU Lampung, the Höegh Grace or the Höegh Gallant. A significant increase in the cost of repairs during drydocking could also adversely affect our cash available for distribution. We may underestimate the time required to drydock or perform on-water surveys of any of our vessels or unanticipated problems may arise. If more than one of our vessels is required to be out of service at the same time, if a vessel is drydocked longer than the permitted duration or if the cost of repairs during drydocking is greater than budgeted, our cash available for distribution could be adversely affected.

We may experience operational problems with vessels that could reduce revenue, increase costs or lead to termination of our time charters.

FSRUs are complex and their operations are technically challenging. The operations of our vessels may be subject to mechanical risks. Operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Moreover, pursuant to each time charter, the vessels in our fleet must maintain certain specified performance standards, which may include a guaranteed speed or delivery rate of regasified natural gas, consumption of no more than a specified amount of fuel, not exceed a maximum average daily boil-off or energy balance, loss of earnings and certain liquidated damages payable under the charterer's charter and other performance failures. For example, we received and subsequently settled the boil-off performance claims related to the Neptune and the Cape Ann described in note 17 of our consolidated financial statements under “Joint ventures boil-off settlement.” Please read “Item 4.B. Business Overview—Vessel Time Charters.” If we fail to maintain these standards, we may be liable to our customers for reduced hire, damages, loss of earnings and certain liquidated damages payable. Under the charterer’s charter and, in certain circumstances, our customers may terminate their respective time charters. Any of these results could harm our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

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If capital expenditures are financed through cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage could increase, or our unitholders may be diluted.

Use of cash from operations to expand our fleet will reduce cash available for distribution to unitholders. Our ability to obtain bank financing or to access the capital markets may be limited by our financial condition at the time of any such financing or offering as well as by adverse market conditions resulting from, among other things, general economic conditions, changes in the LNG industry and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders. Even if we are successful in obtaining necessary funds, the terms of any debt financings could limit our ability to pay cash distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to pay distributions to our unitholders.

We may be unable to make or realize expected benefits from acquisitions, which could have an adverse effect on our expected plans for growth.

Our growth strategy includes selectively acquiring FSRUs, LNG carriers and other LNG infrastructure assets that are operating under long-term charters with stable cash flows. Any acquisition of a vessel or business may not be profitable to us at or after the time we acquire such vessel or business and may not generate cash flows sufficient to justify our investment. In addition, our acquisition growth strategy exposes us to risks that may harm our business, financial condition and results of operations, including risks that we may:

● fail to realize anticipated benefits, such as new customer relationships, or cash flows enhancements;

● be unable to hire, train or retain qualified onshore and seafaring personnel to manage and operate our growing business and fleet;

● decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

● significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

● incur or assume unanticipated liabilities, losses or costs associated with the business or vessels acquired; or

● incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

Our future performance and growth depend 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 maritime transportation sector, each within the LNG transportation, storage and regasification industry. The rate of LNG growth has fluctuated due to several reasons, including the global economic crisis, natural gas production from unconventional sources in certain regions, the relative competitiveness of alternative fossil fuels such as oil and coal, improvements in the competitiveness of renewable energy sources and the highly complex and capital intensive nature of new or expanded LNG projects. Accordingly, our growth depends on continued growth in world and regional demand for LNG, FSRUs, LNG carriers and other LNG infrastructure assets, which could be negatively affected by a number of factors, including:

● increases in the cost of LNG;

● increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

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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, regulation or other factors making consumption of natural gas less attractive;

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

● negative global or regional economic or political conditions, particularly in LNG consuming regions, which could reduce energy consumption or its growth.

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

Growth of the LNG market may be limited by many factors, including infrastructure constraints and community and political group resistance to new LNG infrastructure over concerns about environmental, safety and terrorism.

A complete LNG project includes production, liquefaction, regasification, storage and distribution facilities and FSRUs or LNG carriers. Existing LNG projects and infrastructure are limited, and new or expanded LNG projects are highly complex and capital intensive, with new projects often costing several billion dollars. Many factors could negatively affect continued development of LNG infrastructure and related alternatives, including floating storage and regasification, or disrupt the supply of LNG, including:

● the availability of sufficient financing for LNG projects on commercially reasonable terms;

● the availability long-term contracts that can support such financing;

● decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;

● the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

● local community resistance to proposed or existing LNG facilities based on safety, environmental or security concerns;

● any significant explosion, spill or similar incident involving an LNG facility or vessel involved in the LNG transportation, storage and regasification industry, including an FSRU or LNG carrier; and

● labor or political unrest affecting existing or proposed areas of LNG production and regasification.

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We expect that, in the event any of the factors discussed above negatively affect us, some of the proposals to expand existing or develop new LNG liquefaction and regasification facilities may be abandoned or significantly delayed. If the LNG supply chain is disrupted or does not continue to grow, or if a significant explosion, spill or similar incident occurs within the LNG transportation, storage and regasification industry, it could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Demand for FSRUs or LNG shipping could be significantly affected by volatile natural gas prices and the overall demand for natural gas.

LNG prices are volatile and affected by numerous factors beyond our control, including, but not limited to, the following:

● worldwide demand for natural gas and LNG;

● the cost of exploration, development, production, transportation and distribution of natural gas;

● expectations regarding future energy prices for both natural gas and other sources of energy;

● the level of worldwide LNG production and exports;

● government laws and regulations, including but not limited to environmental protection laws and regulations;

● local and international political, economic and weather conditions;

● political and military conflicts; and

● the availability and cost of alternative energy sources, including alternate sources of natural gas.

Weakness in the LNG market may adversely affect our future business, results of operations and financial condition and our ability to make cash distributions, as a result of, among other things:

● lower demand for LNG carriers, reducing available charter rates and revenue to us from short term redeployment of our vessels between FSRU projects or following expiration or termination of existing contracts;

● customers potentially seeking to renegotiate or terminate existing vessel contracts, or failing to extend or renew contracts upon expiration; or

● the inability or refusal of customers to make charter payments to us due to financial constraints or otherwise.

Weakness in demand for FSRUs or LNG carriers could come about because of excess capacity in the market, newly built vessels entering the market and existing vessels coming off contract.

In general, reduced demand for LNG, FSRUs or LNG carriers would have a material adverse effect on our future growth and could harm our business, results of operations and financial condition.

The debt levels of us and our joint ventures may limit our and their flexibility in obtaining additional financing, refinancing credit facilities upon maturity or pursuing other business opportunities or our paying distributions to you.

As of December 31, 2020, we had outstanding principal on long-term bank debt of $421.5 million, and revolving credit due to owners and affiliates of $18.5 million and our joint ventures had outstanding principal on long-term debt of $375.9 million, of which 50% is our share.

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As of March 31, 2021, we had outstanding principal on long-term bank debt of $410.3 million and revolving credit due to owners and affiliates of $18.2 million and our 50% share of our joint ventures had outstanding principal on long-term debt of $368.5 million. In addition, we have the ability to incur additional debt, and as of March 31, 2021 we had the ability to borrow an additional $66.8 million under our $85 million revolving credit facility with Höegh LNG and $14.7 million on the $63 million revolving credit tranche of the $385 million facility, subject to certain limitations. If we acquire additional vessels or businesses, our consolidated debt may significantly increase. We may incur additional debt under these or future credit facilities. Our joint ventures’ credit facilities will mature in November 2021 and June 2022, respectively, and require an aggregate principal repayment of approximately $337.9 million, of which 50% is our share. A portion of the credit facility secured by the PGN FSRU Lampung will mature in October 2021 and requires that an aggregate principal amount of $15.5 million be refinanced. If such principal repayment is not refinanced, the export credit tranche of the PGN FSRU Lampung financing that will have an outstanding balance of $68.2 million at this time may be accelerated together with the attendant hedges. A portion of the $385 million facility secured by the Höegh Gallant and the Höegh Grace will mature in 2026, and requires that an aggregate principal amount of $136.1 million be refinanced. If the principal repayment is not refinanced, the export credit tranche secured by the Höegh Gallant and the Höegh Grace financing, that will have an outstanding balance of $9.5 million may be accelerated. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt—Lampung Facility” and “—$385 million Facility.”

Our level of debt could have important consequences to us, including the following:

● our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be limited, or such financing may not be available on favorable terms;

● we will need a substantial portion of our cash flows to make principal and interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

● our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally;

● our debt level may limit our flexibility in responding to changing business and economic conditions; and

● if we are unable to satisfy the restrictions included in any of our financing arrangements or are otherwise in default under any of those arrangements, as a result of our debt levels or otherwise, we will not be able to make cash distributions to you, notwithstanding our stated cash distribution policy.

Our ability to service or refinance our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service or refinance our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring our debt, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all. In addition, the recent COVID-19 outbreak has negatively impacted, and may continue to negatively impact, global economic activity, demand for energy (including LNG and LNG shipping) and funds flows and sentiment in the global financial markets. Continued economic disruption caused by the continued failure to control the spread of the virus could significantly impact our ability to obtain additional debt financing.

The financing arrangements of us and our joint ventures are secured by our vessels and contain operating and financial restrictions and other covenants that may restrict our business and financing activities as well as our ability to make cash distributions to our unitholders.

The operating and financial restrictions and covenants in the financing arrangements of us and our joint ventures, including lease agreements and any future financing agreements, could adversely affect our and their ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, the financing agreements may restrict the ability of us and our subsidiaries to:

● incur or guarantee indebtedness;

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● change ownership or structure, including mergers, consolidations, liquidations and dissolutions;

● make dividends or distributions;

● make certain negative pledges and grant certain liens;

● sell, transfer, assign or convey assets;

● make certain investments; and

● enter into a new line of business.

In addition, our financing agreements require us and Höegh LNG to comply with certain financial ratios and tests, including maintaining a minimum liquidity and a minimum book equity ratio and require that our current assets exceed current liabilities, as defined by the financing agreements, and that our subsidiaries maintain minimum EBITDA to debt service ratios. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt—Lampung Facility” and “—$385 million Facility.”

Our joint ventures’, Höegh LNG’s and our ability to comply with covenants and restrictions contained in financing arrangements may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our and their ability to comply with these covenants may be impaired. If restrictions, covenants, ratios or tests in debt instruments are breached, a significant portion of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. We and/or our joint ventures or Höegh LNG may not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, obligations under our and our joint ventures’ financing arrangements are secured by our vessels and the Lampung facility is guaranteed by Höegh LNG, and if they are unable to repay debt under our financing arrangements, the lenders could seek to foreclose on those assets. Please read “Item 5.B. Liquidity and Capital Resources.”

Restrictions in our debt agreements and local laws may prevent us from paying distributions to our unitholders.

The payment of principal and interest on our debt will reduce our cash available for distribution. Our and our joint ventures’ financing arrangements prohibit the payment of distributions upon the occurrence of certain events, including, but not limited to:

● failure to pay any principal, interest, fees, expenses or other amounts when due;

● certain material environmental incidents;

● breach or lapse of insurance with respect to vessels securing the facilities;

● breach of certain financial covenants;

● failure to observe any other agreement, security instrument, obligation or covenant beyond specified cure periods in certain cases;

● default under other indebtedness (including certain hedging arrangements or other material agreements);

● bankruptcy or insolvency events;

● inaccuracy of any representation or warranty;

● a change of ownership of the vessel-owning subsidiary, as defined in the applicable agreement; and

● a material adverse change, as defined in the applicable agreement.

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Furthermore, our financing arrangements require that we maintain minimum amounts of free liquid assets and our subsidiaries and joint ventures to hold cash reserves that are, in certain cases, held for specifically designated uses, including working capital, operations and maintenance and debt service reserves, and are generally subject to “waterfall” provisions that allocate project revenues to specified priorities of use (such as operating expenses, scheduled debt service, targeted debt service reserves and any other reserves) and the remaining cash is distributable to us only on certain dates and subject to satisfaction of certain conditions, including meeting a 1.20 historical and in some cases, projected, debt service coverage ratio. In addition, the laws governing our joint ventures and subsidiaries may prevent us from making dividend distributions. Our joint ventures are subject to restrictions under the laws of the Cayman Islands and may only pay distributions out of profits or capital reserves if the joint venture entity is solvent after the distribution, Höegh Lampung is subject to Singapore laws and may make dividend distributions only out of profits. Dividends may only be paid by PT Höegh if its retained earnings are positive under Indonesian law and requirements are fulfilled under the Lampung facility. In addition, PT Höegh as an Indonesian incorporated company is required to establish a statutory reserve equal to 20% of its paid up capital. The dividend can only be distributed if PT Höegh’s retained earnings are positive after deducting the statutory reserve. PT Höegh is in the process of establishing the required statutory reserves as of December 31, 2020 and therefore cannot make dividend payments to us under Indonesia law. However, subject to meeting a debt service ratio of 1.20 to 1.00, PT Höegh can distribute cash from its cash flow from operations to us as payment of intercompany accrued interest and / or intercompany debt, after quarterly payments of the Lampung facility and fulfilment of the “waterfall” provisions to meet operating requirements as defined by the Lampung facility. Under Cayman Islands law, Höegh FSRU IV and Höegh Colombia Holding may only pay distributions out of profits or capital reserves if the entity is solvent after the distribution. Dividends from Höegh Cyprus may only be distributed out of profits and not from the share capital of the company. Dividends and other distributions from Höegh Cyprus, Höegh Colombia and Höegh FSRU IV may only be distributed if after the dividend payment, the Partnership would remain in compliance with the financial covenants under the $385 million facility. Please read “Item 8.A. Consolidated Statements and Other Financial Information—The Partnership’s Cash Distribution Policy—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

Höegh LNG’s failure to comply with certain obligations under the Lampung facility, and certain other events occurring at Höegh LNG, could result in defaults under the Lampung credit facility.

Höegh LNG guarantees the obligations of PT Höegh, the owner of the PGN FSRU Lampung, under the Lampung facility (as described in “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt”). Pursuant to the terms of the Lampung facility, Höegh LNG must, among other things, maintain minimum book equity and comply with certain minimum liquidity financial covenants. Failure by Höegh LNG to satisfy any of the covenants applicable to Höegh LNG would result in a default under the Lampung facility. The lenders of the Lampung facility may foreclose upon any collateral securing that debt, including arrest and seizure of the PGN FSRU Lampung, even if Höegh LNG were to subsequently cure its default in the event of such acceleration and foreclosure, PT Höegh and the Partnership, as the case may be, might not have sufficient funds or other assets to satisfy all of their obligations under the related credit facility, which would have a material adverse effect on our business, results of operations and financial condition and would significantly reduce our ability, or make us unable, to make cash distributions to our unitholders for so long as such default is continuing. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt—Lampung Facility.”

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Höegh LNG has entered into a revolving credit facility pursuant to which it has pledged as collateral all of its interests in our general partner and all of its common units in order to secure the related loan. A default by Höegh LNG under the facility which causes the lenders to foreclose on such collateral would have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

On March 27, 2020, Höegh LNG entered into a revolving credit facility which is secured by all of the limited liability company interests in our general partner as well as all 15,257,498 of our common units that are owned by Höegh LNG. A default by Höegh LNG under this facility which causes the lender to foreclose on the collateral would cause an event of default under all of our long-term credit facilities and our joint venture shareholder agreements. Our long-term credit facilities and our joint venture shareholder agreements require Höegh LNG to own at least 25% of our common units as well as to own and control our general partner. Höegh LNG’s ability to comply with the terms of the revolving credit facility may be affected by events beyond the control of Höegh LNG or us, including decreases in the trading price of our common units, our ability to maintain employment for our vessels and prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate and the trading price of our common units falls, Höegh LNG’s ability to meet its obligations under the facility may be impaired. A default by Höegh LNG under the facility which causes the lenders to foreclose on the collateral and the corresponding default under our long-term credit facilities and joint venture shareholder agreements would have a material adverse effect on our  financial condition, results of operations and ability to make cash distributions to unitholders.

An increase in the global supply or aggregate capacities of FSRUs or LNG carriers, including conversion of existing tonnage, without a commensurate increase in demand may have an adverse effect on hire rates and the values of our vessels, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

The supply of FSRUs, LNG carriers and other LNG infrastructure assets in the industry is affected by, among other things, assessments of the demand for these vessels by charterers. Any over-estimation of demand for vessels may result in an excess supply of new vessels. This may, in the long term when existing contracts expire, result in lower hire rates and depress the values of our vessels. If hire rates are lower when we are seeking new time charters upon expiration or early termination of our current time charters, or for any new vessels we acquire, our business, financial condition, results of operations and ability to make cash distributions to our unitholders may be adversely affected.

During periods of high utilization and high hire rates, industry participants may increase the supply of FSRUs and/or LNG carriers by ordering the construction of new vessels. This may result in an over-supply and may cause a subsequent decline in utilization and hire rates when the vessels enter the market. Lower utilization and hire rates could adversely affect revenues and profitability. Prolonged periods of low utilization and hire rates could also result in the recognition of impairment charges on our vessels if future cash flow estimates, based upon information available at the time, indicate that the carrying value of these vessels may not be recoverable. Such impairment charges may cause lenders to accelerate loan payments under our or our joint ventures’ financing agreements, which could adversely affect our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Vessel values may fluctuate substantially, and a decline in vessel values may result in impairment charges, the breach of our financial covenants or, if these values are lower at a time when we are attempting to dispose of vessels, a loss on the sale.

Vessel values for FSRUs and LNG carriers can fluctuate substantially over time due to a number of different factors, including:

● prevailing economic conditions in the natural gas and energy markets;

● a substantial or extended decline in demand for LNG;

● increases in the supply of vessel capacity;

● the size and age of a vessel;

● the remaining term on existing time charters; and

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● the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.

As our vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on our business and operations if we do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel would be significant.

If a charter terminates, we may be unable to re-deploy the affected vessel at attractive rates and, rather than continue to incur costs to maintain and finance the vessel, we may seek to dispose of the vessel. Our inability to dispose of a vessel at a reasonable value could result in a loss on the sale and adversely affect our ability to purchase a replacement vessel, financial condition, results of operations and ability to make cash distributions to our unitholders. A decline in the value of our vessels may also result in impairment charges or the breach of certain of the ratios and financial covenants we are required to comply with in our credit facilities.

We depend on Höegh LNG and its affiliates for the management of our fleet and to assist us in operating and expanding our business.

Our ability to enter into new charters and expand our customer relationships will depend largely on our ability to leverage our relationship with Höegh LNG and its reputation and relationships in the shipping industry. If Höegh LNG suffers material damage to its reputation or relationships, it may harm our ability to:

● renew existing charters upon their expiration;

● obtain new charters;

● successfully interact with shipyards;

● obtain financing on commercially acceptable terms;

● maintain access to capital under the revolving credit facility; or

● maintain satisfactory relationships with suppliers and other third parties.

In addition, all our vessels are subject to management and services agreements with affiliates of Höegh LNG. Moreover, pursuant to an administrative services agreement, Höegh Norway provides us and our operating company with certain administrative, financial and other support services. Our operational success and ability to execute our growth strategy will depend significantly upon the satisfactory performance of these services. Our business will be harmed if our service providers fail to perform these services satisfactorily, if they cancel their agreements with us or if they stop providing these services to us. Please read “Item 7.B. Related Party Transactions.”

The operation of FSRUs, LNG carriers and other LNG infrastructure assets is inherently risky, and an incident involving significant loss of life or property or environmental consequences involving any of our vessels could harm our reputation, business and financial condition.

Our vessels and their cargoes are at risk of being damaged or lost because of events such as:

● marine disasters;

● piracy;

● environmental accidents;

● bad weather;

● mechanical failures;

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● grounding, fire, explosions and collisions;

● human error; and

● war and terrorism.

An accident involving any of our vessels could result in any of the following:

● death or injury to persons, loss of property or damage to the environment, natural resources or protected species, and associated costs;

● delays in taking delivery of cargo or discharging LNG or regasified LNG, as applicable;

● loss of revenues from or termination of time charters;

● governmental fines, penalties or restrictions on conducting business;

● higher insurance rates; and

● damage to our reputation and customer relationships generally.

Any of these results could have a material adverse effect on our business, financial condition and results of operations.

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, for example, due to insufficient coverage amounts or the refusal by our insurance provider to pay a claim. The loss of earnings while these vessels are being repaired, as well as the actual cost of these repairs not otherwise covered by insurance, would decrease our results of operations. If any of our vessels are involved in an accident with the potential risk of environmental consequences, the resulting media coverage could have a material adverse effect on our business, our results of operations and cash flows, weaken our financial condition and negatively affect our ability to make cash distributions to our unitholders.

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

The operating of FSRUs, LNG carriers and other LNG infrastructure assets is inherently risky. Although we carry protection and indemnity insurance consistent with industry standards, all of the risks associated with operating FSRUs, LNG carriers and other LNG infrastructure assets 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. Certain of our insurance coverage is maintained through mutual protection and indemnity associations, and as a member of such associations we may be required to make additional payments over and above budgeted premiums if member claims exceed association reserves.

We may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, more stringent 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 marine disaster could exceed our insurance coverage, which could harm our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders. Any uninsured or underinsured loss could harm our business and financial condition. In addition, our insurance may be voidable by the insurers as a result of certain of our actions, such as our ships failing to maintain certification with applicable maritime self-regulatory organizations.

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

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An increase in operating expenses could adversely affect our financial performance.

Our operating expenses, on water survey costs and drydock capital expenditures depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control and affect the entire shipping industry. While many of these costs are borne by the charterers under our time charters, there are some circumstance where this is not the case. For example, we bear the cost of fuel (bunkers) for the Höegh Gallant (when operating in FSRU mode) and Höegh Grace time charters, and fuel is a significant expense in our operations when our vessels are, for example, moving to or from drydock or when off-hire. The price and supply of fuel is unpredictable and fluctuates based on events outside our control, including geopolitical developments, supply and demand for oil and gas, actions by the Organization of the Petroleum Exporting Countries and other oil and gas producers, war and unrest in oil-producing countries and regions, regional production patterns and environmental concerns. These may increase vessel operating costs further. If costs continue to rise, they could materially and adversely affect our results of operations.

A shortage of qualified officers and crew, including possible disruptions caused by the COVID-19 outbreak, could have an adverse effect on our business and financial condition.

FSRUs and LNG carriers require a technically skilled officer staff with specialized training. As the global FSRU fleet and LNG carrier fleet continues to grow, the demand for technically skilled officers and crew has been increasing, which has led to a more competitive recruiting market. Increases in our historical vessel operating expenses have been attributable primarily to the rising costs of recruiting and retaining officers for our fleet. Furthermore, each key officer crewing an FSRU or LNG carrier must receive specialized training related to the operation and maintenance of the regasification equipment. If Höegh LNG Management and Höegh Maritime Management are unable to recruit and employ technically skilled staff and crew, they will not be able to adequately staff our vessels. Furthermore, should there be an outbreak of COVID-19 on board, adequate crewing my not be available to fulfill the obligations under the contract. In addition, the officers and crew work on a rotating schedule. Due to COVID-19, we could face (i) difficulty in finding healthy qualified replacement officers and crew; (ii) local quarantine restrictions limiting the ability to transfer infected crew members off the vessel or bring new crew on board, or (iii) restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives. A material decrease in the supply of technically skilled officers or an inability of Höegh LNG Management or Höegh Maritime Management to attract and retain such qualified officers, or rotate and replace virus infected crew, could impair our ability to operate or increase the cost of crewing our vessels, which would materially adversely affect our business, financial condition and results of operations and significantly reduce our ability to make cash distributions to our unitholders.

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

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 growth, business and results of operations.

Exposure to currency exchange rate fluctuations could result in fluctuations in our cash flows and operating results.

Currency exchange rate fluctuations and currency devaluations could have an adverse effect on our results of operations from quarter to quarter. Historically, the substantial majority of our revenue has been generated in U.S. Dollars, but we incur a minority of our operating expenses in other currencies. All of our long-term debt is U.S. dollar denominated, but we incur a minority of short-term liabilities in other currencies. Please read “Item 5.B. Liquidity and Capital Resources—Critical Accounting Estimates—Use of Exchange Rates” and “Item 11. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk.”

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Acts of piracy on any of our vessels or on oceangoing vessels could adversely affect our business, financial condition and results of operations.

Acts of piracy have historically affected oceangoing vessels trading in regions of the world such as the South China Sea, the Gulf of Aden off the coast of Somalia and the Gulf of Guinea. If such piracy attacks result in regions in which our vessels are deployed being named on the Joint War Committee Listed Areas, war-risk insurance premiums payable for such insurance coverage could increase significantly and such insurance coverage might become more difficult to obtain. In addition, crew costs, including costs that may be incurred to the extent we employ onboard security guards, could increase in such circumstances. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition and results of operations.

Terrorist attacks, increased hostilities, piracy or war could lead to further economic instability, increased costs and disruption of business.

Terrorist attacks may adversely affect our business, financial condition, results of operations, ability to raise capital and future growth. Continuing hostilities in the Middle East may lead to additional armed conflicts or to further acts of terrorism and civil disturbance in the United States or elsewhere, which may contribute further to economic instability and disruption of production and distribution of LNG, which could result in reduced demand for our services.

Terrorist attacks on vessels may in the future adversely affect our business, financial condition and results of operation. In addition, LNG facilities, shipyards, vessels, pipelines and natural gas fields could be targets of future terrorist attacks. Any such attacks could lead to, among other things, bodily injury or loss of life, vessel or other property damage, increased vessel operational costs, including insurance costs, and the inability to transport LNG to or from certain locations. Terrorist attacks, piracy, war or other events beyond our control that adversely affect the distribution, production or transportation of LNG to be shipped by us could entitle customers to terminate our charters, which would harm our cash flows and business. Terrorist attacks, or the perception that LNG facilities, FSRUs and LNG carriers are potential terrorist targets, could materially and adversely affect expansion of LNG infrastructure and the continued supply of LNG. Concern that LNG facilities may be targeted for attack by terrorists has contributed to a community and environmental resistance to the construction of a number of LNG facilities. In addition, the loss of a vessel as a result of terrorism or piracy would have a material adverse effect on our business, financial condition and results of operations.

We are exposed to political, regulatory, and economic risks associated with doing business in different countries, including in emerging market countries.

We conduct all of our operations outside of the United States and expect to continue to do so for the foreseeable future. Some of the countries in which we are engaged in business or where our vessels are registered, for example, Indonesia and Colombia, are historically less developed and stable than the United States. We are affected by economic, political, and governmental conditions in the countries where we are engaged in business or where our vessels are registered. We are also affected by policies related to labor and the crewing of FSRUs. Any disruption caused by these factors could harm our business. Further, we derive a substantial portion of our revenues from shipping and regasifying LNG from politically unstable regions. Future hostilities or other political instability where we operate or may operate could have a material adverse effect on the growth of our business, financial condition, results of operations and ability to make cash distributions to our unitholders. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, South America or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could harm our business and ability to make cash distributions to our unitholders.

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

Our vessels traveling in international waters are subject to various existing regulations published by the International Maritime Organization ("IMO"), as well as marine pollution and prevention requirements imposed by the IMO International Convention for the Prevention of Pollution from Ships of 1975, as from time to time has been or may be amended (the “MARPOL Convention”). In addition, our FSRUs 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, as amended by the April 2010 Protocol to the HNS Convention (the “2010 HNS Convention”), if it is entered into force. In July 2019, South Africa became the 5^th state to ratify the protocol, which must be ratified or acceded to by at least 7 more states to enter into effect. The 2010 HNS Convention is intended to put in place a comprehensive regime to address the risks of fire and explosion and to cover pollution damage from hazardous and noxious substances carried by ships, including loss of life, personal injury, and property loss of damage. If the 2010 HNS Convention were to enter into force, we cannot estimate with any certainty at this time the costs that may be needed to comply with any such requirements that may be adopted. Please read “Item 4.B. Business Overview –– Environmental and Other Regulation” for a more detailed discussion on these topics.

Our operations are subject to substantial environmental and other regulations, which may significantly increase our expenses.

Our operations are materially affected by extensive and changing international, national and local environmental protection laws, regulations, treaties, conventions and standards 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 relating to equipping and operating FSRUs and LNG carriers, providing security and minimizing the potential for adverse impacts to the environment, natural resources and protected species from their operations. These include regulations of the IMO, including the International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended, the MARPOL Convention, the International Convention for the Prevention of Marine Pollution of 1973, the IMO International Convention for the Safety of Life at Sea of 1974, as from time to time amended (“SOLAS”), the IMO International Convention on Load Lines of 1966, as from time to time amended, and the International Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”) and national laws such as the U.S. Oil Pollution Act of 1990 (“OPA 90”), the U.S. Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the U.S. Clean Water Act (the “CWA”), and the U.S. Maritime Transportation Security Act of 2002 and any counterpart laws in other jurisdictions with laws governing our operations. We may become subject to additional laws and regulations if we enter new markets or trades.

Many of these requirements are designed to reduce the risk of oil spills and other pollution. In addition, we believe that the heightened environmental, quality and security concerns of insurance underwriters, regulators and charterers will lead to additional regulatory requirements, including enhanced risk assessment and security requirements and greater inspection and safety requirements on vessels. We have incurred, and expect to continue to incur, substantial expenses in complying with these laws and regulations, including expenses for vessel modifications and changes in operating procedures.

The design, construction, and operation of FSRUs and interconnecting pipelines and the transportation of LNG are also subject to governmental approvals and permits. The permitting rules, and the interpretations of those rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical and may increase the time it takes to secure needed approvals. The length of time it takes to receive regulatory approval for offshore LNG operations is one factor that has affected our industry, including through increased expenses.

Environmental and other regulatory requirements can affect the resale value or useful lives of our vessels, require ship modifications or operational changes or restrictions, lead to decreased availability of insurance coverage for environmental matters or result in the denial of access to certain jurisdictional waters or ports, or detention in, certain ports. Under local and national laws, as well as international treaties and conventions, we could incur material liabilities, including cleanup obligations, in the event that there is a release of hazardous substances from our vessels or otherwise in connection with our operations. We could also become subject to personal injury, property or natural resource damage claims relating to the release of or exposure to hazardous materials associated with our operations. In addition, failure to comply with applicable laws and regulations may result in administrative or civil penalties, criminal sanctions or the suspension or termination of our operations, including, in certain instances, seizure or detention of our vessels.

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Please read “Item 4.B. Business Overview—Environmental and Other Regulation.”

Further changes to existing environmental laws applicable to international and national maritime trade may have an adverse effect on our business.

We believe that the heightened environmental, quality and security concerns of insurance underwriters, regulators and charterers will generally lead to additional regulatory requirements, including enhanced risk assessment and security requirements and greater inspection and safety requirements on all vessels in the marine LNG transportation markets and offshore LNG terminals. These requirements are likely to add incremental costs to our operations and the failure to comply with these requirements may affect the ability of our vessels to obtain and, possibly, collect on insurance or to obtain the required certificates for entry into the different ports where we operate.

Further legislation, or amendments to existing legislation, applicable to international and national maritime trade are expected over the coming years in areas such as ship recycling, sewage systems, emission control (including emissions of greenhouse gases) and ballast treatment and handling. Such legislation or regulations may require additional capital expenditures or operating expenses (such as increased costs for low-sulfur fuel needed to meet IMO 2020 requirements) for us to maintain our vessels’ compliance with international and/or national regulations.

Climate change and greenhouse gas regulations and impacts may adversely impact our operations and markets.

Due to concern over the risk of climate change, a number of countries and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions from vessels. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards and incentives or mandates for renewable energy. Although the emissions of greenhouse gases from international shipping currently are not subject to the international treaty on climate change known as the Paris Agreement, a new treaty or IMO regulations may be adopted in the future that includes restrictions on shipping emissions. In 2016, the IMO reaffirmed its strong commitment to continue to work to address greenhouse gas emissions from ships engaged in international trade. The IMO adopted an initial GHG reduction strategy in 2018 as a framework for further action with adoption of a revised IMO strategy targeted for 2023 (the “IMO GHG Strategy”). Consistent with the IMO GHG Strategy target of a 40% carbon reduction for international shipping by 2030, as compared to 2018, IMO’s Marine Environment Protection Committee (“MEPC”) agreed upon draft amendments to MARPOL Annex VI that would establish an enforceable regulatory framework to reduce greenhouse gas emissions form international shipping, consisting of technical and operational carbon reduction measures, including use of an Energy Efficiency Existing Ship Index, an operational Carbon Intensity Indicator and an enhanced Ship Energy Efficiency Management Plan.

These amendments will be proposed for formal adoption at the 2021 MEPC session and, if adopted, are expected to enter into force on January 1, 2023. The EU has indicated it intends to implement regulations to limit emissions of greenhouse gases from vessels if such emissions are not regulated through the IMO and, in September 2020, the European Parliament approved draft legislation that would put in place measures to address greenhouse gas emissions from shipping. Compliance with changes in laws and regulations relating to climate change could increase our costs of operating and maintaining our vessels and could require us to make significant financial expenditures that we cannot predict with certainty at this time. Further, our business may be adversely affected to the extent that climate change results in sea level changes or more intense weather events.

Maritime claimants could arrest our vessels, which could interrupt our cash flows.

Crew members, suppliers of goods and services to our vessels, owners of cargo or other parties may be entitled to a maritime lien against one or more of our vessels for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in our fleet for claims relating to another of our vessels. The arrest or attachment of one or more of our vessels could interrupt our cash flows and require us to pay to have the arrest lifted.

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Governments could requisition our vessels during a period of war or emergency, resulting in loss of earnings.

The government of a jurisdiction where one or more of our vessels are registered could requisition for title or seize our vessels. Requisition for title or seizure occurs when a government takes control of a vessel and becomes her owner. Also, a government could requisition our vessels for hire. Requisition for hire occurs when a government takes control of a vessel and effectively becomes the charterer at dictated hire rates. Generally, requisitions occur during a period of war or emergency, although governments may elect to requisition vessels in other circumstances. Although we would expect to be entitled to government compensation in the event of a requisition of one or more of our vessels, the amount and timing of payments, if any, would be uncertain. A government requisition of one or more of our vessels would result in off-hire days under our time charters and may cause us to breach covenants in certain of our credit facilities. Furthermore, a requisition for title of either the Neptune or the Cape Ann constitutes a total loss under the terms of the related facility agreements, in which case we would have to repay all loans. If a government requisition of one or more of our vessels were to occur, it could have a material adverse effect on our business, financial condition, results of operations and cash flows, including cash available for distribution to our unitholders.

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 her 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 SOLAS. Each of our vessels is certified by Det Norske Veritas, compliant with the ISM Code and “in class.” In order to maintain valid certificates from the classification society, a vessel must undergo annual surveys, intermediate surveys and renewal surveys. A vessel’s machinery may be on a continuous survey cycle, under which the machinery would be surveyed periodically over a five-year period. Each of the vessels in our fleet has implemented a certified planned maintenance system. The classification society attends onboard once every year to verify that the maintenance of the equipment onboard is done correctly. For each of the Neptune and the Cape Ann, a renewal survey is conducted every five years and an intermediate survey is conducted within 30 months after a renewal survey. During the first 15 years of operation, the vessels have an extended drydock interval which allow them to be drydocked every 7.5 years, while intermediate surveys and certain renewal surveys occur while they are afloat, using an approved diving company in the presence of a surveyor from the classification society. After these vessels are 15 years old, they are expected to be drydocked every five years or, if required by the charterers, every 30 months. We do not anticipate drydocking of the PGN FSRU Lampung for the first 20 years as all the required surveys can be done afloat. In the first 15 years after its delivery from the shipyard, we expect the Höegh Gallant to have a renewal survey every five years and to be drydocked every 7.5 years. The Höegh Grace is also designed to carry out renewal surveys afloat which is conducted every five years and is not expected to go into drydocking for the duration of its current charter. The Höegh Grace is scheduled to carry out renewal survey afloat before the end of the second quarter of 2021. If any vessel does not maintain her class or fails any annual survey, renewal 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. This would negatively impact our revenues and reduce our cash available for distribution to unitholders.

Failure to comply with the U.S. Foreign Corrupt Practices Act, the UK Bribery Act, the anti-corruption provisions in the Norwegian Criminal Code and other anti-bribery legislation in other jurisdictions could result in fines, criminal penalties, contract termination and an adverse effect on our business.

We may operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and have adopted a code of business conduct and ethics which is consistent and in full compliance with the U.S. Foreign Corrupt Practices Act of 1977 (the “FCPA”), the Bribery Act 2010 of the Parliament of the United Kingdom (the “UK Bribery Act”) and the anti-corruption provisions of the Norwegian Criminal Code of 1902 (the “Norwegian Criminal Code”), respectively. We are subject, however, to the risk that we, our affiliated entities or our or their respective officers, directors, employees and agents may take actions determined to be in violation of such anti-corruption laws, including the FCPA, the UK Bribery Act and the Norwegian Criminal Code. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

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If in the future our business activities involve countries, entities and individuals that are subject to restrictions imposed by the U.S. or other governments, we could be subject to enforcement action and our reputation and the market for our preferred and common units could be adversely affected.

The tightening of U.S. sanctions in recent years has affected non-U.S. companies. In particular, sanctions against Iran have been significantly expanded. In 2012, for example, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012 (“TRA”), which placed further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. A major provision in the TRA is that issuers of securities must disclose to the SEC in their annual and quarterly reports filed after February 6, 2013 if the issuer or ‘‘any affiliate’’ has ‘‘knowingly’’ engaged in certain activities involving Iran during the timeframe covered by the report. This disclosure obligation is broad in scope in that it requires the reporting of activity that would not be considered a violation of U.S. sanctions as well as violative conduct and is not subject to a materiality threshold. The SEC publishes these disclosures on its website and the President of the United States must initiate an investigation in response to all disclosures.

In addition to the sanctions against Iran, the U.S. also has sanctions that target other countries, entities and individuals. These sanctions have certain extraterritorial effects that need to be considered by non-U.S. companies. It should also be noted that other governments have implemented versions of U.S. sanctions. We believe that we are in compliance with all applicable sanctions and embargo laws and regulations imposed by the U.S., the United Nations or European Union (the "EU") countries and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our units. Additionally, some investors may decide to divest their interest, or not to invest, in our units simply because we may do business with companies that do business in sanctioned countries. Investor perception of the value of our units may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

We are subject to the requirements of the Sarbanes-Oxley Act. If we fail to comply with the requirements of the Sarbanes-Oxley Act or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and it could materially and adversely affect us.

The Sarbanes-Oxley Act requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of the Sarbanes-Oxley Act or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common units. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

A cyber-attack could materially disrupt our business.

We rely on information technology systems and networks, which are provided by Höegh LNG, in our operations and the administration of our business, to collect payments from customers and to pay agents, vendors and employees. Our data protection measures and measures taken by our customers, agents and vendors may not prevent unauthorized access of information technology systems. Threats to our information technology systems and the systems of our customers, agents and vendors associated with cybersecurity risks or attacks continue to grow. Threats to our systems and our customers’, agents’ and vendors’ systems may derive from human error, fraud or malice or may be the result of accidental technological failure. Our 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, or lead to unauthorized release of information or alteration of information on our systems. In addition, breaches to our systems and systems of our customers, agents and vendors could go unnoticed for some period of time. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.

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Changing laws and evolving reporting requirements could have an adverse effect on our business.

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 EU on May 25, 2018 and 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. GDPR 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. Complying with 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, which could have an adverse effect on our business, financial conditions, results of operations, cash flows and ability to pay distributions.

Increased regulatory oversight, uncertainty relating to the nature and timing of the potential phasing out of LIBOR, and agreement on any new alternative reference rates may adversely impact our ability to manage our exposure to fluctuations in interest rates and borrowing costs.

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 United Kingdom Financial Conduct Authority (“FCA”) 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”). On March 5, 2021, the FCA updated the FCA Announcement by specifying that U.S. dollar LIBOR will either cease to be provided by any administrator or no longer be representative immediately after December 31, 2021, or, in the case of some more frequently used U.S. dollar LIBOR settings, immediately after June 30, 2023. It is unclear whether an extension will be granted or whether new methods of calculating LIBOR will be established such that it continues to exist after 2023, or if alternative rates or benchmarks will be adopted. The impact of such transition away from LIBOR could be significant for us because of our substantial indebtedness.

Various alternative reference rates are being considered in the financial community. The Secured Overnight Financing Rate has been proposed by the Alternative Reference Rates Committee, a committee convened by the U.S. Federal Reserve that includes major market participants and on which regulators participate, as an alternative rate to replace U.S. dollar LIBOR. However, it is not possible at this time to know the ultimate impact a phase-out of LIBOR may have. The changes may adversely affect the trading market for LIBOR based agreements, including our credit facilities and interest rate swaps. We may need to negotiate the replacement benchmark rate on our credit facilities and interest rate swaps and the use of an alternative rate or benchmark, may negatively impact our interest rate expense. Any other contracts entered into in the ordinary course of business which currently refer to, use or include LIBOR, may also be impacted.

Further, if a LIBOR rate is not available on a determination date during the floating rate period for any of our LIBOR based agreements, the terms of such agreements will require alternative determination procedures which may result in interest payments differing from expectations and could affect our profit.

In addition, any changes announced by the FCA, the ICE Benchmark Administration Limited (the independent administrator of LIBOR) or any other successor governance or oversight body, or future changes adopted by such body, in the method pursuant to which LIBOR rates are determined may result in sudden or prolonged increase or decrease in reported LIBOR rates. If that were to occur, the level of interest during the floating rate period for our LIBOR based agreements would be affected and could affect our profit.

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Risks Inherent in an Investment in Us

Unitholders have limited voting rights, and our partnership agreement restricts the voting rights of the unitholders owning more than 4.9% of our common units.

Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. We will hold a meeting of the limited partners every year to elect one or more members of our board of directors and to vote on any other matters that are properly brought before the meeting. Common unitholders are entitled to elect only four of the seven members of our board of directors. The elected directors are elected on a staggered basis and will serve for staggered terms. Our general partner in its sole discretion appoints the remaining three directors and set the terms for which those directors will serve. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unitholders will have no right to elect our general partner, and our general partner may not be removed except by a vote of the holders of at least 75% of the outstanding common units, including any units owned by our general partner and its affiliates, voting together as a single class.

Our partnership agreement further restricts unitholders’ voting rights by providing that if any person or group owns beneficially more than 4.9% of any class of units then outstanding, any such units owned by that person or group in excess of 4.9% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to our board of directors), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 4.9% will effectively be redistributed pro rata among the other common unitholders holding less than 4.9% of the voting power of all classes of units entitled to vote. Our general partner, its affiliates and persons who acquired common units with the prior approval of our board of directors will not be subject to this 4.9% limitation except with respect to voting their common units in the election of the elected directors. Holders of the Series A preferred units generally have no voting rights. However, in the event that six quarterly dividends, whether consecutive or not, payable on Series A preferred units or any other class or series of limited partner interests or other equity securities established after the original issue date of the Series A preferred units that is not expressly subordinated or senior to the Series A preferred units as to the payment of distributions and amounts payable upon liquidation, dissolution or winding up, whether voluntary or involuntary (“Parity Securities”) are in arrears, the holders of Series A preferred units will have the right, voting together as a class with all other classes or series of Parity Securities upon which like voting rights have been conferred and are exercisable, to replace one of the members of our board of directors appointed by our general partner with a person nominated by such holders (unless the holders of Series A preferred units and Parity Securities upon which like voting rights have been conferred, voting as a class, have previously elected a member of our board of directors, and such director continues then to serve on the board of directors). The right of such holders of Series A preferred units to elect a member of our board of directors will continue until such time as all accumulated and unpaid dividends on the Series A preferred units have been paid in full.

Our general partner and its other affiliates own a significant interest in us and have conflicts of interest and limited fiduciary and contractual duties, which may permit them to favor their own interests to your detriment.

As of March 31, 2021, Höegh LNG owns approximately 45.7% of our common units, representing their limited partner interest in us. Certain of our directors will also serve as directors of Höegh LNG or its affiliates and, as such, they will have fiduciary duties to Höegh LNG that may cause them to pursue business strategies that disproportionately benefit Höegh LNG or its affiliates or which otherwise are not in the best interests of us or our unitholders.

Conflicts of interest may arise between Höegh LNG and its affiliates (including our general partner) on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner and its affiliates may favor their own interests over the interests of our unitholders. These conflicts include, among others, the following situations:

● neither our partnership agreement nor any other agreement requires our general partner or Höegh LNG or its affiliates to pursue a business strategy that favors us or utilizes our assets, and Höegh LNG’s officers and directors have a fiduciary duty to make decisions in the best interests of the shareholders of Höegh LNG, which may be contrary to our interests;

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● our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. Specifically, our general partner will be considered to be acting in its individual capacity if it exercises its call right, pre-emptive rights or registration rights, consents or withholds consent to any merger or consolidation of the Partnership, appoints any directors or votes for the election of any director, votes or refrains from voting on amendments to our partnership agreement that require a vote of the outstanding units, voluntarily withdraws from the Partnership, transfers (to the extent permitted under our partnership agreement) or refrains from transferring its units or general partner interest or votes upon the dissolution of the Partnership;

● our general partner and our directors have limited their liabilities and restricted their fiduciary duties under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders, and, as a result of purchasing common units, unitholders are treated as having agreed to the modified standard of fiduciary duties and to certain actions that may be taken by our general partner and our directors, all as set forth in our partnership agreement;

● our general partner is entitled to reimbursement of all reasonable costs incurred by it and its affiliates for our benefit;

● our partnership agreement does not restrict us from paying our general partner or its affiliates for any services rendered to us on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities on our behalf;

● our general partner may exercise its right to call and purchase our common units if it and its affiliates own more than 80% of our common units; and

● our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of its limited call right.

Although a majority of our directors are elected by common unitholders, our general partner will likely have substantial influence on decisions made by our board of directors.

Furthermore, following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement that we entered into with Höegh LNG in connection with the IPO will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels (as defined in “Major Unitholders and Related Party Transactions – Related Party Transactions – Omnibus Agreement – Non Competition”), (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

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

Our Chief Executive Officer and Chief Financial Officer also serve as officers of Höegh LNG. These and any future officers may face conflicts in the allocation of their time to our business. The affiliates of our general partner, including Höegh LNG, conduct substantial businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of our officers who also provide services to our general partner’s affiliates, which could have a material adverse effect on our business, financial condition and results of operations. Additionally, while our Chief Executive Officer and Chief Financial Officer are expected to devote substantial time to our business, they may participate in activities for Höegh LNG that are linked to opportunities or challenges for us.

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Our partnership agreement limits our general partner’s and our directors’ fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner or our directors.

Our partnership agreement provides that our general partner has irrevocably delegated to our board of directors the authority to oversee and direct our operations, management and policies on an exclusive basis, and such delegation will be binding on any successor general partner of the Partnership. Our partnership agreement also contains provisions that reduce the standards to which our general partner and directors may otherwise be held by Marshall Islands law. For example, our partnership agreement:

● provides that our general partner may make determinations or take or decline to take actions without regard to our or our unitholders’ interests. Our general partner may consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or our unitholders. Decisions made by our general partner will be made by its sole owner. Specifically, our general partner may decide to exercise its right to make a determination to receive common units in exchange for resetting the target distribution levels related to the incentive distribution rights, call right, pre-emptive rights or registration rights, consent or withhold consent to any merger or consolidation of the Partnership, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our partnership agreement that require a vote of the outstanding units, voluntarily withdraw from the Partnership, transfer (to the extent permitted under our partnership agreement) or refrain from transferring its units, the general partner interest or incentive distribution rights or vote upon the dissolution of the Partnership;

● provides that our general partner and our directors are entitled to make other decisions in “good faith” if they believe that the decision is in our best interests;

● generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our board of directors and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our board of directors may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

● provides that neither our general partner nor our officers or our directors will be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or directors or its officers or directors or those other persons engaged in actual fraud or willful misconduct.

By purchasing a common unit, a common unitholder is deemed to have agreed to become bound by the provisions of our partnership agreement, including the provisions discussed above.

Fees and expenses, which Höegh LNG determines for services provided to us and our joint ventures, are substantial, are payable regardless of our profitability and will reduce our cash available for distribution to you.

Pursuant to the ship management agreements and related agreements, we and our joint ventures pay fees for services provided directly or indirectly by Höegh LNG Management, and we and our joint ventures reimburse Höegh LNG Management for all expenses incurred on our behalf. These fees and expenses include all costs and expenses incurred in providing certain crewing and technical management services to the Neptune, the Cape Ann, the Höegh Gallant and the Höegh Grace. In addition, pursuant to a technical information and services agreement for the PGN FSRU Lampung, we reimburse Höegh Norway for expenses Höegh Norway incurs pursuant to the sub-technical support agreement that it is party to with Höegh LNG Management.

Moreover, pursuant to an administrative services agreement, Höegh Norway provides us and our operating company with certain administrative, financial and other support services. We reimburse Höegh Norway for their reasonable costs and expenses incurred in connection with the provision of these services. In addition, under our administrative services agreement, we pay Höegh Norway a service fee equal to 3.0% of its costs and expenses incurred in connection with providing services to us.

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For a description of the ship management agreements, the technical information and services agreement and the administrative services agreement, please read “Item 7.B. Related Party Transactions.” The fees and expenses payable pursuant to the ship management agreements, the technical information and services agreement and the administrative services agreement are payable without regard to our financial condition or results of operations. The payment of fees to and the reimbursement of expenses of Höegh LNG Management, and Höegh Norway could adversely affect our ability to pay cash distributions to you.

Our partnership agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or our general partner, and even if public unitholders are dissatisfied, they will be unable to remove our general partner without Höegh LNG’s consent, unless Höegh LNG’s ownership interest in us is decreased, all of which could diminish the trading price of our common units.

Our partnership agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or our general partner.

● The unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 75% of all outstanding common units is required to remove the general partner. Höegh LNG owns approximately 45.7% of the outstanding common units. Additionally, during the term of the SRV Joint Gas shareholders’ agreement, Höegh LNG has agreed to continue to own common units representing a greater than 25% limited partner interest in us in the aggregate.

● Common unitholders are entitled to elect only four of the seven members of our board of directors. Our general partner in its sole discretion appoints the remaining three directors.

● Election of the four directors elected by unitholders is staggered, meaning that the members of only one of four classes of our elected directors will be selected each year. In addition, the directors appointed by our general partner will serve for terms determined by our general partner.

● Our partnership agreement contains provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about our operations as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

● Unitholders’ voting rights are further restricted by our partnership agreement provision providing that if any person or group owns beneficially more than 4.9% of any class of units then outstanding, any such units owned by that person or group in excess of 4.9% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to our board of directors), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 4.9% will effectively be redistributed pro rata among the other common unitholders holding less than 4.9% of the voting power of all classes of units entitled to vote. Our general partner, its affiliates (including Höegh LNG) and persons who acquired common units with the prior approval of our board of directors will not be subject to this 4.9% limitation except with respect to voting their common units in the election of the elected directors.

● There are no restrictions in our partnership agreement on our ability to issue equity securities, including securities senior to the common units.

The effect of these provisions may be to diminish the price at which the common units will trade.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its non-economic general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. In addition, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party.

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Substantial future sales of our common units in the public market could cause the price of our common units to fall.

We have granted registration rights to Höegh LNG and certain of its affiliates. These unitholders have the right, subject to some conditions, to require us to file registration statements covering any of our common or other equity securities owned by them or to include those securities in registration statements that we may file for ourselves or other unitholders. As of March 31, 2021, Höegh LNG owns 15,257,498 common units and all of the incentive distribution rights. Following their registration and sale under the applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of our common units to decline.

As a Marshall Islands partnership with principal executive offices in Bermuda, and also having subsidiaries in the Marshall Islands and the Cayman Islands, our operations may be subject to local economic substance regulations required by the European Union, which could harm our business.

We are a Marshall Islands limited partnership with principal executive offices in Bermuda. Our operating company is also a Marshall Islands entity and several of our subsidiaries are organized in the Cayman Islands.

In December 1997, the Council of the EU (“Council”) adopted a resolution on a Code of Conduct for business taxation, with the objective of counteracting the effects of zero tax and preferential tax regimes around the world. In 2017 the Code of Conduct Group (“Code Group”) investigated the tax policies of both EU member states and third countries, assessing practices in the areas of: (i) tax transparency; (ii) fair taxation; and (iii) implementation of anti-base erosion and profit shifting measures. On December 5, 2017, following an assessment of the tax policies of various countries by the Code Group, the Council approved and published Council conclusions containing a list of “non-cooperative jurisdictions” for tax purposes”). On February 18, 2020, the Council adopted a revised list of non-cooperative jurisdictions for tax purposes. This revised list included the Cayman Islands. EU member states have agreed upon a set of measures, which they can choose to apply against the listed countries, including increased monitoring and audits, withholding taxes, special documentation requirements and anti-abuse provisions. The EU list of non-cooperative jurisdictions is reconsidered at least once a year, and generally at six monthly intervals. The Council also confirmed on February 18, 2020 that Bermuda and the Marshall Islands had implemented all the necessary reforms to comply with the Council’s tax good governance principles ahead of the agreed deadline and were therefore moved to the list of cooperative tax jurisdictions. The effect of the Cayman Islands or the Marshall Islands being included in the list of non-cooperative jurisdictions could have a material adverse effect on our business, financial conditions and operating results.

In addition, the Marshall Islands, Bermuda and the Cayman Islands have enacted economic substance laws and regulations with which we are obligated to comply. Bermuda has adopted the Economic Substance Act 2018 (as amended) (the “Economic Substance Act”), and the Economic Substance Regulations 2018 (as amended) (“Economic Substance Regulations”). The Economic Substance Act requires each registered entity to maintain a substantial economic presence in Bermuda and provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (i) it is directed and managed in Bermuda, (ii) its core income-generating activities (as are prescribed in the Economic Substance Regulations) are undertaken in Bermuda with respect to the relevant activity, (iii) it maintains adequate physical presence in Bermuda, (iv) it has adequate full time employees in Bermuda with suitable qualifications and (v) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity. Additionally, legislation has been adopted in the Cayman Islands (which came into force on January 1, 2019) which requires certain entities that carry out particular activities to comply with an economic substance test whereby the entity must show that it (i) carries out activities that are of central importance to the entity from the Cayman Islands, (ii) has held an adequate number of its board meetings in the Cayman Islands when judged against the level of decision-making required and (iii) has an adequate (a) amount of operating expenditures in the Cayman Islands, (b) physical presence in the Cayman Islands and (c) number of full-time employees in the Cayman Islands. Regulations adopted in the Marshall Islands (which came into force on January 1, 2019) require certain entities that carry out particular activities to comply with an economic substance test whereby the entity must show that it (i) is directed and managed in the Marshall Islands in relation to that relevant activity, (ii) carries out core income-generating activity in relation to that relevant activity in the Marshall Islands (although it is being understood and acknowledged by the regulators that income-generated activities for shipping companies will generally occur in international waters) and (iii) having regard to the level of relevant activity carried out in the Marshall Islands has (a) an adequate amount of expenditures in the Marshall Islands, (b) adequate physical presence in the Marshall Islands and (c) an adequate number of qualified employees in the Marshall Islands.

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If we fail to comply with our obligations under this legislation or any similar law or regulations applicable to us in any other jurisdictions, we could be subject to financial penalties and spontaneous disclosure of information to foreign tax officials, or could be struck from the register of companies, in related jurisdictions. Any of the foregoing could be disruptive to our business and could have a material adverse effect on our business, financial conditions and operating results.

We are subject to Marshall Islands law, which lacks a bankruptcy statute or general statutory mechanism for insolvency proceedings.

We are a Marshall Islands limited partnership, and we have limited operations in the United States and maintain limited assets in the United States. Consequently, in the event of any bankruptcy, insolvency, liquidation, dissolution, reorganization or similar proceeding involving us, bankruptcy laws other than those of the United States could apply. The Republic of the Marshall Islands does not have a bankruptcy statute or general statutory mechanism for insolvency proceedings. If we become a debtor under U.S. bankruptcy law, bankruptcy courts in the United States may seek to assert jurisdiction over all of our assets, wherever located, including property situated in other countries. There can be no assurance, however, that we would become a debtor in the United States, or that a U.S. bankruptcy court would be entitled to, or accept, jurisdiction over such a bankruptcy case, or that courts in other countries that have jurisdiction over us and our operations would recognize a U.S. bankruptcy court’s jurisdiction, if any other bankruptcy court would determine it had jurisdiction. These factors may delay or prevent us from entering bankruptcy in the United States and may affect the ability of our unitholders to receive any recovery following our bankruptcy.

Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders unless otherwise provided for under the laws of the Marshall Islands. This limits our unitholders’ ability to choose the judicial forum for disputes with us or our directors, officers or other employees.

Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware is the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, our limited partners or us); (2) brought in a derivative manner on our behalf; (3) asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or our limited partners; (4) asserting a claim arising pursuant to any provision of the Marshall Islands Act; and (5) asserting a claim governed by the internal affairs doctrine. This exclusive forum provision does not apply to actions arising under the U.S. Securities Act of 1933, as amended (the “Securities Act”) or the U.S. Securities and Exchange Act of 1934, as amended (the "Exchange Act"). Any person or entity purchasing or otherwise acquiring any interest in our units is deemed to have received notice of and consented to the foregoing provisions.

Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar forum selection provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could find that the forum selection provision contained in our partnership agreement is inapplicable or unenforceable in such action or actions. Limited partners will not be deemed, by operation of the forum selection provision alone, to have waived claims arising under the federal securities laws and the rules and regulations thereunder. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

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We rely on the master limited partnership (“MLP”) structure and its appeal to investors for accessing debt and equity markets to finance our growth and repay or refinance our debt. The volatility in energy prices over the past few years has, among other factors, caused increased volatility and contributed to a dislocation in pricing for MLPs.

The volatility in energy prices and, in particular, the price of oil, among other factors, has contributed to increased volatility in the pricing of MLPs and the energy debt markets, as a number of MLPs and other energy companies may be adversely affected by a lower energy prices environment. A number of MLPs, including certain maritime MLPs, have reduced or eliminated their distributions to unitholders.

We rely on our ability to obtain financing and to raise capital in the equity and debt markets to fund our capital replacement, growth and investment expenditures, and to refinance our debt. A protracted deterioration in the valuation of our common units would increase our cost of capital, make any equity issuance significantly dilutive and may affect our ability to access capital markets and, as a result, our capacity to pay distributions to our unitholders and service or refinance our debt.

We have been organized as a limited partnership under the laws of the Republic of the Marshall Islands, which does not have a well-developed body of partnership law.

The Partnership’s affairs are governed by our partnership agreement and by the Marshall Island Limited Partnership Act (the “Marshall Islands Act”). The provisions of the Marshall Islands Act resemble provisions of the limited partnership laws of a number of states in the United States, most notably Delaware. The Marshall Islands Act also provides that it is to be applied and construed to make the laws of the Marshall Islands, with respect to the subject matter of the Marshall Islands Act, uniform with the laws of the State of Delaware and, so long as it does not conflict with the Marshall Islands Act or decisions of the High and Supreme Courts of the Marshall Islands, the non-statutory law (“case law”) of the State of Delaware is adopted as the law of the Marshall Islands, with respect to non-resident limited partnerships like us. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited partnership statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of our unitholders and the fiduciary responsibilities of our general partner under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. As a result, unitholders may have more difficulty in protecting their interests in the face of actions by our general partner and its officers and directors than would unitholders of a similarly organized limited partnership in the United States.

Because we are organized under the laws of the Marshall Islands, it may be difficult to serve us with legal process or enforce judgments against us, our directors or our management.

We are organized under the laws of the Marshall Islands, and substantially all of our assets are located outside of the United States. In addition, our general partner is a Marshall Islands limited liability company, and a majority of our directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to bring an action against us or against these individuals in the United States if you believe that your rights have been infringed under securities laws or otherwise. Even if you are successful in bringing an action of this kind, the laws of the Marshall Islands and of other jurisdictions may prevent or restrict you from enforcing a judgment against our assets or the assets of our general partner or our directors or officers.

Höegh LNG, as the initial holder of all of the incentive distribution rights, may elect to cause us to issue additional common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights without the approval of the conflicts committee of our board of directors or holders of our common units. This may result in lower distributions to holders of our common units in certain situations.

Höegh LNG, as the initial holder of all of the incentive distribution rights, has the right, at a time when Höegh LNG has received incentive distributions at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such total distribution did not exceed adjusted operating surplus for each such quarter), to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution amount will be reset to the reset minimum quarterly distribution amount, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount.

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In connection with resetting these target distribution levels, Höegh LNG will be entitled to receive a number of common units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to Höegh LNG on the incentive distribution rights in the prior fiscal quarter. We anticipate that Höegh LNG would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distribution per common unit without such conversion; however, it is possible that Höegh LNG could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued additional common units to Höegh LNG in connection with resetting the target distribution levels related to its incentive distribution rights.

We may issue additional equity securities, including securities senior to the common units with respect to distributions, liquidation and voting which would dilute the ownership interests of common unitholders.

We may, without the approval of our common unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue units that are senior to the common units in right of distribution, liquidation and voting. For example, as of March 31, 2021 we have outstanding 7,089,325 8.75% Series A preferred units. The Series A preferred units rank senior to the Partnership’s common units as to the payment of distributions and amounts payable upon liquidation, dissolution or winding up but junior to all of the Partnership’s debt and other liabilities. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

● our unitholders’ proportionate ownership interest in us will decrease;

● the amount of cash available for distribution on each unit may decrease;

● we will not be able to pay our distributions to common unitholders if we have failed to pay the distributions on our Series A preferred units;

● because the amount payable to holders of incentive distribution rights is based on a percentage of total available cash, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on the common units remains the same;

● the relative voting strength of each previously outstanding unit may be diminished; and

● the market price of the common units may decline.

In establishing cash reserves, our board of directors may reduce the amount of cash available for distribution to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. These reserves also will affect the amount of cash available for distribution to our unitholders. As described above in “—Risks Inherent in Our Business—We must make substantial capital expenditures to maintain and replace the operating capacity of our fleet, which will reduce our cash available for distribution. In addition, each quarter we will be required, pursuant to our partnership agreement, to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted,” our partnership agreement requires our board of directors each quarter to deduct from operating surplus estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, which could reduce the amount of available cash for distribution. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our board of directors at least once a year, with the approval of the conflicts committee of our board of directors.

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Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price of our common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right. As a result, unitholders may be required to sell common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.

As of March 31, 2021, Höegh LNG, which owns and controls our general partner, owns approximately 45.7% of our common units.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

As a limited partner in a limited partnership organized under the laws of the Marshall Islands, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities. In addition, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions in which we do business.

We can borrow money to make cash distributions, which would reduce the amount of credit available to operate our business.

Our partnership agreement allows us to make working capital borrowings to make cash distributions. Accordingly, if we have available borrowing capacity, we can make cash distributions on all our units even though cash generated by our operations may not be sufficient to pay such distributions. Any working capital borrowings by us to make cash distributions will reduce the amount of working capital borrowings we can make for operating our business.

Increases in interest rates may cause the market price of our units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general and in particular for yield based equity investments such as our units. Any such increase in interest rates or reduction in demand for our units resulting from other relatively more attractive investment opportunities may cause the trading price of our units to decline.

Unitholders may have liability to repay distributions.

Under some circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the Marshall Islands Act, we may not make a distribution to unitholders if, after giving effect to the distribution, our liabilities, other than liabilities to partners on account of their partnership interest and liabilities for which the recourse of creditors is limited to specified property of ours, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited will be included in our assets only to the extent that the fair value of that property exceeds that liability. Marshall Islands law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Marshall Islands law will be liable to the limited partnership for the distribution amount. Assignees who become substituted limited partners are liable for the obligations of the assignor to make contributions to the limited partnership that are known to the assignee at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

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The Series A preferred units represent perpetual equity interests.

The Series A preferred units represent perpetual equity interests in us, and unlike our indebtedness, we will not give rise to a claim for payment of a principal amount at a particular date. As a result, holders of the Series A preferred units may be required to bear the financial risks of an investment in the Series A preferred units for an indefinite period of time. In addition, the Series A preferred units rank junior to all our indebtedness and other liabilities, and any senior securities we may issue in future with respect to assets available to satisfy claims against us.

The Series A preferred units have not been rated.

We did not obtain a rating for the Series A preferred units, and they may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A preferred units or that we may elect to obtain a rating of our Series A preferred units in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are assigned to the Series A preferred units in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A preferred units. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A preferred units. Ratings do not reflect market prices or suitability of a security for a particular investor and any future rating of the Series A preferred units may not reflect all risks related to us and our business, or the structure or market value of the Series A preferred units.

We distribute all of our available cash to our limited partners and are not required to accumulate cash for the purpose of making distributions on units.

Subject to the limitations in our partnership agreement, we distribute all of our available cash each quarter to our limited partners. “Available cash” is defined in our partnership agreement, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own):

● less the amount of cash reserves established by our board of directors to:

o provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);

o comply with applicable law, any debt instruments, or other agreements;

o provide funds for payments to holders of Series A preferred units; or

o provide funds for distributions to our limited partners for any one or more of the next four quarters; and

o plus, all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit agreements and in all cases used solely for working capital purposes or to pay distributions to unitholders.

As a result, we do not expect to accumulate significant amount of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on our units.

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Our Series A preferred units are subordinated to our debt obligations, and the interests of holders of Series A preferred units could be diluted by the issuance of additional limited partner interests, including additional Series A preferred units, and by other transactions.

Our Series A preferred units are subordinated to all of our existing and future indebtedness. As of December 31, 2020, our total outstanding principal amount of debt was $439.9 million and we had the ability to borrow an additional $81.2 million under our revolving credit facilities, subject to limitations in the credit facilities. We may incur additional debt under these or future credit facilities. The payment of principal and interest on our debt reduces cash available for distribution to us and on our limited partner interests, including the Series A preferred units.

The issuance of additional limited partner interests on a parity with or senior to our Series A preferred units would dilute the interests of the holders of our Series A preferred units, and any issuance of Senior Securities (as defined) or Parity Securities or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on our Series A preferred units. No provisions relating to our Series A preferred units protect the holders of our Series A preferred units in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all our assets or business, which might adversely affect the holders of our Series A preferred units.

The Series A preferred units rank junior to any Senior Securities and pari passu with any Parity Securities.

Our Series A preferred units will rank junior to any class or series of limited partner interests or other equity securities expressly made senior to the Series A preferred units as to the payment of distributions and amounts payable upon liquidation, dissolution, or winding up, whether voluntary or involuntary (“Senior Securities”) and pari passu Parity Securities. If less than all distributions payable with respect to the Series A preferred units and any Parity Securities are paid, any partial payment shall be made pro rata with respect to Series A preferred units and any Parity Securities entitled to a distribution payment at such time in proportion to the aggregate amounts remaining due in respect of such units at such time.

The Series A preferred units do not have an established trading market, which may negatively affect their market value and ability of holders to transfer or sell Series A preferred units. In addition, the lack of a fixed redemption date for the Series A preferred units will increase unitholder reliance on the secondary market for liquidity purposes.

The Series A preferred units do not have a well-established trading market. In addition, since the Series A preferred units have no stated maturity date, investors seeking liquidity will be limited to selling their units in the secondary market absent redemption by us. The trading market for the Series A preferred units on the NYSE may not be active, in which case the trading price of the Series A preferred units could be adversely affected and the ability of holders to transfer such units will be limited. If an active trading market does develop on the NYSE, our Series A preferred units may trade at prices lower than the offering price. The trading price of the Series A preferred units depends on many factors, including:

● prevailing interest rates;

● the market for similar securities;

● general economic and financial conditions;

● our issuance of debt or preferred equity securities; and

● our financial condition, results of operations and prospects.

Market interest rates may adversely affect the value of our Series A preferred units.

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One of the factors that will influence the price of our Series A preferred units will be the distribution yield on the Series A preferred units (as a percentage of the price of our Series A preferred units) relative to market interest rates. An increase in market interest rates, may lead prospective purchasers of our Series A preferred units to expect a higher distribution yield, and higher interest rates would likely increase our borrowing costs and potentially decrease funds available for distribution. Accordingly, higher market interest rates could cause the market price of our Series A preferred units to decrease.

The Series A preferred units are redeemable at our option.

We may, at our option, redeem all or, from time to time, part of the Series A preferred units on or after October 5, 2022. If we redeem Series A preferred units, holders will be entitled to receive a redemption price equal to $25.00 per unit plus accumulated and unpaid distributions to the date of redemption. It is likely that we would choose to exercise our optional redemption right only when prevailing interest rates have declined, which would adversely affect the ability of holders to reinvest their proceeds from the redemption in a comparable investment with an equal or greater yield to the yield on the Series A preferred units had such units not been redeemed. We may elect to exercise our partial redemption right on multiple occasions.

Tax Risks

In addition to the following risk factors, you should read “Item 4.B. Business Overview—Taxation of Partnership” and “Item 10.E. Taxation” for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our common units.

We are subject to taxes, which reduces our cash available for distribution to you.

Some of our subsidiaries will be subject to tax in the jurisdictions in which they are organized or operate, reducing the amount of cash available for distribution. In computing our tax obligation in these jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions the applicable authorities will agree with our positions. A successful challenge by a tax authority could result in additional tax imposed on our subsidiaries, further reducing the cash available for distribution. In addition, changes in our operations could result in additional tax being imposed on us, our operating company or our or its subsidiaries in jurisdictions in which operations are conducted. Moreover, tax regulation and reporting requirements for value added taxes, withholding taxes, property taxes and corporate income taxes are complex in Indonesia, Colombia, and many of the countries where we operate. Tax regulations, guidance and interpretation in emerging markets may not always be clear and may be subject to alternative interpretations or changes in interpretation over time. In particular, Indonesia and Colombia have complex tax regulations and reporting requirements, which if not properly applied, could result in penalties that could be significant, which could also harm our business and ability to make cash distributions to our unitholders. Please read “Item 4.B. Business Overview—Taxation of the Partnership,” “Item 5.D. Operating and Financial Review and Prospects—Trend Information” and note 18 under Indonesian corporate income tax and Indonesian property tax to our consolidated financial statements.

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

Tax laws and regulations are highly complex and subject to interpretation. Consequently, we and our subsidiaries are subject to changing tax laws, treaties and regulations in and between 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, treaties or regulations, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings. As a result of new regulations related to property taxes in Indonesia for the fiscal year ended December 31, 2020, retroactive property tax and penalties were assessed for the years from 2015 to 2019. Such changes may also include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development.

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

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a “passive foreign investment company” (“PFIC”) for U.S. federal income tax purposes for any taxable year in which at least 75.0% of its gross income consists of “passive income” or at least 50.0% of the average value of its assets (based on the average of the values at the end of each quarter) produce, or are held for the production of, “passive income.” 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 that 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, certain distributions they receive from the PFIC, and the gain, if any, they derive from the sale or other disposition of their interests in the PFIC.

Based on our current and projected method of operation, we believe that we were not a PFIC for any prior taxable year, and we expect that we will not be treated as a PFIC for the current or any future taxable year. We believe that more than 25.0% of our gross income for each taxable year was or will be nonpassive income, and more than 50.0% of the average value of our assets for each such year was or will be held for the production of such nonpassive income. This belief is based on certain valuations and projections regarding our assets, income and charters, and its validity is conditioned on the accuracy of such valuations and projections. While we believe these valuations and projections to be accurate, the shipping market is volatile, and no assurance can be given that they will continue to be accurate at any time in the future.

Moreover, there are legal uncertainties involved in determining whether the income derived from time-chartering activities constitutes rental income or income derived from the performance of services. In Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. 2009), the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) held that income derived from certain time-chartering activities should be treated as rental income rather than services income for purposes of a provision of the Internal Revenue Code of 1986, as amended (the "Code"), relating to foreign sales corporations. 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, and we would likely be treated as a PFIC. In published guidance, the Internal Revenue Service (“IRS”) stated that it disagreed with the holding in Tidewater and specified that time charters similar to those at issue in the case should be treated as service contracts. We have not sought, and we do not expect to seek, an IRS ruling on the treatment of income generated from our time-chartering activities. As a result, the IRS or a court could disagree with our position. No assurance can be given that this result will not occur.

In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, we cannot assure you that the nature of our operations will not change in the future and that we will not become a PFIC in the future. If the IRS were to find that we are or have been a PFIC for any taxable year (and regardless of whether we remain a PFIC for subsequent taxable years), our U.S. unitholders would face adverse U.S. federal income tax consequences. Please read “Item 10.E Taxation—U.S. Federal Income Taxation of U.S. Holders—PFIC Status and Significant Tax Consequences” for a more detailed discussion of the U.S. federal income tax consequences to U.S. unitholders if we are treated as a PFIC.

We may have to pay tax on U.S. source income, which would reduce our cash flow.

Under the Code, U.S. source gross transportation income generally is subject to a 4.0% U.S. federal income tax without allowance for deduction of expenses unless an exemption from tax applies under Section 883 of the Code and the existing final and temporary regulations promulgated thereunder (the “Treasury Regulations”). U.S. source gross transportation consists of 50.0% of the gross shipping income that a non-U.S. vessel-owning or chartering corporation, such as ourselves, derives (either directly or through one or more subsidiaries that are classified as partnerships or disregarded as entities separate from such corporation for U.S. federal income tax purposes) and that is attributable to transportation that either begins or ends, but that does not both begin and end, in the United States.

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We believe that we and our vessel-owning subsidiaries currently qualify and we expect that we will continue to qualify for the foreseeable future, for an exemption from U.S. tax on any U.S. source gross transportation income under Section 883 of the Code, and we expect to take this position for U.S. federal income tax reporting purposes. Please read “Item 4.B— Business Overview—Taxation of the Partnership.” However, there are factual circumstances, including some that may be beyond our control, which could cause us to lose the benefit of this tax exemption. In addition, our position that we qualify for this exemption is based upon legal authorities that do not expressly contemplate an organizational structure such as ours; specifically, although we have elected to be treated as a corporation for U.S. federal income tax purposes, we are organized as a limited partnership under Marshall Islands law. Therefore, we can give no assurance that the IRS will not take a different position regarding our qualification for this tax exemption.

If we or our subsidiaries are not entitled to this exemption under Section 883 of the Code for any taxable year, we generally would be subject to a 4.0% U.S. federal gross income tax on our U.S. source gross transportation income for such year. Our failure to qualify for the exemption under Section 883 of the Code could have a negative effect on our business and would result in decreased earnings available for distribution to our unitholders.

The vessels in our fleet do not currently engage, and we do not expect that they will in the future engage, in transportation that begins and ends in the United States or in the provision of regasification or storage services in the United States. If, notwithstanding this expectation, our subsidiaries earn income in the future from transportation that begins and ends in the United States, or from regasification or storage activities in the United States, that income would not be exempt from U.S. federal income tax under Section 883 of the Code and would be subject to a 21.0% net income tax in the United States (and the after-tax earnings attributable to such income may be subject to an additional 30.0% branch profits tax). Please read “Item 4.B Business Overview—Taxation of the Partnership—United States Taxation—The Section 883 Exemption” for a more detailed discussion of the rules relating to qualification for the exemption under Section 883 of the Code and the consequences for failing to qualify for such an exemption.

You may be subject to income tax in one or more non-U.S. jurisdictions, including Norway, as a result of owning our common units if, under the laws of any such jurisdiction, we are considered to be carrying on business there. Such laws may require you to file a tax return with, and pay taxes to, those jurisdictions.

We conduct our affairs and cause or influence each of our subsidiaries to operate its business in a manner that minimizes income taxes imposed upon us and our subsidiaries and that may be imposed upon you as a result of owning our units. However, because we are organized as a limited partnership, there is a risk in some jurisdictions, including Norway, that our activities or the activities of our subsidiaries may be attributed to our unitholders for tax purposes if, under the laws of such jurisdiction, we are considered to be carrying on business there. If you are subject to tax in any such jurisdiction, you may be required to file a tax return with, and to pay tax in, that jurisdiction based on your allocable share of our income. We may be required to reduce distributions to you on account of any tax withholding obligations imposed upon us by that jurisdiction in respect of such allocation to you. The United States generally will not allow a tax credit for any foreign income taxes that you directly or indirectly incur by virtue of an investment in us.

We believe we can conduct our affairs in a manner that does not result in our unitholders being considered to be carrying on business in Norway solely as a consequence of the acquisition, ownership, disposition or redemption of our common units. However, the question of whether either we or any of our subsidiaries will be treated as carrying on business in any jurisdiction, including the Norway, will be largely a question of fact to be determined through an analysis of the decisions made and powers exercised by our board of directors, the limitation of the Chief Executive Officer or Chief Financial Officer's decisions making to day-to-day management for the purpose of implementing the decisions made by our board of directors, contractual arrangements, including the ship management agreements that our joint ventures and subsidiaries have entered into with Höegh LNG Management, the sub-technical support agreement that Höegh Norway has entered into with Höegh LNG Management, the administrative service agreement we and our operating company have entered into with Höegh Norway, as well as through an analysis of the manner in which we conduct business or operations, all of which may change over time. Furthermore, the laws of Norway or any other jurisdiction may also change, which could cause that jurisdiction’s taxing authorities to determine that we are carrying on business in such jurisdiction and that we or our unitholders are subject to its taxation laws. In addition to the potential for taxation of our unitholders, any additional taxes imposed on us or any of our subsidiaries will reduce our cash available for distribution.

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Item 4.Information on the Partnership

A.History and Development of the Partnership

Höegh LNG Partners LP is a publicly-traded limited partnership formed initially by Höegh LNG Holdings Ltd. (Oslo Børs symbol: HLNG), a leading floating LNG service provider, to own, operate and acquire floating storage and regasification units (“FSRUs”), LNG carriers and other LNG infrastructure assets under long-term charters, which we define as charters of five or more years.

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The Partnership also maintains an Internet site at www.hoeghlngpartners.com.

We were formed on April 28, 2014 as a Marshall Islands limited partnership and have our principal executive offices at Canon's Court, 22 Victoria Street, Hamilton, Bermuda (Telephone: +479-912-3443). At the closing of our initial public offering (“IPO”) in August 2014, Höegh LNG contributed interests in our initial fleet of three modern FSRUs to us.

On October 1, 2015, we acquired 100% of the shares of Höegh FSRU III, the entity that indirectly owned the FSRU Höegh Gallant. On January 3, 2017, we closed the acquisition of a 51% ownership interest in the Höegh Grace entities. On December 1, 2017, we closed the acquisition of the remaining 49% ownership interest in the Höegh Grace entities.

As of March 31, 2021, we had a fleet of five FSRUs. Our fleet consists of interests in the following vessels:

● a 50% interest in the Neptune, an FSRU built in 2009 that is currently operating under a time charter with Total Gas & Power a subsidiary of Total, a French publicly listed company, that produces and markets fuels, natural gas and low-carbon electricity, that expires in 2029, with an option to extend for up to two additional periods of five years each;

● a 50% interest in the Cape Ann, an FSRU built in 2010 that is currently operating under a time charter Total Gas & Power, that expires in 2030, with an option to extend for up to two additional periods of five years each;

● a 100% economic interest in the PGN FSRU Lampung, an FSRU built in 2014 that is currently operating under a time charter with PGN LNG, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk, a subsidiary of PT Pertamina, government-controlled, Indonesian oil and gas producer, natural gas transportation and distribution company. The time charter expires in 2034, with options to extend the time charter either for an additional 10 years or for up to two additional periods of five years each;

● a 100% interest in the Höegh Gallant, an FSRU built in 2014 that is currently operating under a time charter with CharterCo, a subsidiary of Höegh LNG. Previously, the Höegh Gallant operated under a long-term time charter which started in 2015 and expired in 2020 with EgyptCo, a subsidiary of Höegh LNG

● a 100% interest in Höegh Grace, an FSRU built in 2016 that is currently operating under a time charter with SPEC. SPEC is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. The non-cancellable charter period is 10 years. The initial term of the charter is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without a penalty. However, if SPEC waives its right to terminate in year 10 within a certain deadline, we will not be able to exercise our right to terminate in year 10.

Capital Expenditures

Our capital expenditures amounted to $8,000, $0.3 million and $0.7 million for the years ended December 31, 2020, 2019, and 2018 respectively.

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B.Business Overview

General

We own and operate FSRUs, under long-term charters, which we define as charters of five or more years. Our primary business objective is to increase quarterly distributions per unit over time by making accretive acquisitions of FSRUs, LNG carriers and other LNG infrastructure assets with long-term charters.

We intend to make accretive acquisitions of FSRUs, LNG carriers and other LNG infrastructure assets with long-term charters. We cannot assure you that we will make any particular acquisition or that as a consequence we will successfully grow the amount of our per unit distributions. Among other things, our ability to acquire additional FSRUs, LNG carriers and other LNG infrastructure assets will be dependent upon our ability to raise additional equity and debt financing.

Natural Gas and Liquefied Natural Gas

Natural gas is used to generate electric power, has residential and industrial use, and it is finding increasing application as a transportation fuel. The low carbon intensity and clean burning characteristics of natural gas contribute to the view that natural gas has the lowest environmental impact of hydrocarbon fuels.

The LNG trade developed from a need to transport natural gas over long distances with greater flexibility than is allowed by its movement via pipelines. Condensing natural gas into liquid form reduces its volume by a factor of over 600, making LNG an efficient means of transporting and storing natural gas in significant quantities. LNG is natural gas (predominantly methane (CH4)) that has been converted to liquid form by cooling it to -160 degrees centigrade under compression.

The processing of natural gas, transportation of LNG and regasification process requires specialized technologies, complex liquefaction processes and cryogenic materials. The specially built carriers in which LNG is transported have heavily insulated cargo tanks that maintain cryogenic temperatures by allowing a small portion of LNG to evaporate as boil-off gas.

LNG projects are capital intensive. LNG project sponsors are typically large international oil and gas companies often partnering with national oil and gas companies on the export side of the chain. The importers of LNG are typically large, regulated natural gas companies or power utilities. The diagram below shows the flow of natural gas and LNG from production to regasification and consumption:

Floating Regasification Vessels

Traditionally, the import of LNG and its regasification has been done in land based terminals. However, the interest in and use of floating import and regasification solutions is increasing.

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Floating regasification vessels may be called shuttle and regas vessels (“SRVs”) or LNG regas vessels (“LNGRVs”) but are more commonly referred to as FSRUs or Floating Storage and Regasification Units. FSRU technology represents a flexible, proven, expedient and cost effective means of allowing countries or regions to import LNG.

The underlying technology used in an FSRU is that of heat exchange between LNG and a warm fluid resulting in vaporization of the LNG into the gaseous state for delivery to shore. The fluid may either be seawater—often referred to as open loop vaporization—or recirculated water heated by a natural gas fired boiler on the FSRU itself—often referred to as closed loop vaporization. Vaporization capacity varies by vessel and is typically specified as a combination of continuous vaporization capacity (base capacity) and peak vaporization capacity (peak capacity). The vaporized LNG is replenished by delivery of LNG into the FSRU by LNG carriers serving as feeder vessels.

Key benefits of FSRU technology include:

● Speed. Planning, siting, permitting and constructing a traditional, land-based LNG terminal typically requires five to six years. In comparison, FSRU projects typically take less than 24 months to execute and have been implemented in as little as six months.

● Reduced Costs. FSRUs are considerably less capital intensive than a land-based LNG terminal, where even small terminals can cost upwards of $600 million. More importantly, the providers of FSRUs are prepared to retain ownership of their vessels and charter them to the importing company for a short, medium or long term period, avoiding the need for major capital outlays and corresponding financing requirements.

● Greater Cost Certainty. An importer has greater clarity on fees for regasification services and delivery of gas with an FSRU as compared to a land-based LNG terminal, which may be more likely to face construction cost overruns and uncertainty around terminal throughput fees.

● Operational Flexibility. FSRU operators have entered into agreements as short as three years, whereas land-based LNG terminals often require long term commitments of 15 years or more.

● Market Flexibility. Some FSRUs can also be operated as conventional LNG carriers and owners have been prepared to build such vessels on a speculative basis. FSRU technology has the flexibility to meet different market needs and terminal location challenges.

However, FSRUs are not without limitations and constraints. Land-based terminals typically have larger storage capacity and potentially larger gas send out capacities than FSRUs, especially FSRUs that are a result of LNG carrier conversions. This disadvantage could be partially mitigated by using multiple FSRUs. Greater storage capacity of land-based terminals facilitates faster cargo offload in a situation when storage tanks are partially full. The boil-off rate of an FSRU is higher than that of a land based terminal, and boil-off gas that cannot be used for fuel or regas purposes has to be flared in the gas combustion unit. The limitations on the physical size of an FSRU prevent it from having as much redundancy of vaporization equipment as a land-based terminal. As a result, an FSRU is more vulnerable to equipment outages, and thus requires the FSRU provider to hold very high standards regarding operations and maintenance. A technical problem with an FSRU could require a visit to drydock, which would result in a loss of service.

Our Relationship with Höegh LNG

We believe that one of our principal strengths is our relationship with Höegh LNG. With a track record dating back to the delivery of the world’s first Moss-type LNG carrier in 1973, we believe that Höegh LNG is one of the most experienced operators of LNG carriers, and one of only a few operators of FSRUs in the world, excluding FSRUs owned by companies dedicated to single projects, and has one of the largest FSRU fleets in operation. Our affiliation with Höegh LNG gives us access to Höegh LNG’s long-standing relationships with leading oil and gas companies, utility companies, shipbuilders, financing sources and suppliers, which we believe will allow us to compete more effectively when seeking additional long-term charters for FSRUs, LNG carriers and other LNG infrastructure assets. In addition, we believe Höegh LNG’s more than 40-year track record of providing LNG services and its technical, commercial and managerial expertise, including its leadership in the development of floating liquefaction solutions, will enable us to continue to maintain the high utilization of our fleet to preserve our stable cash flows. We cannot assure you that our relationship with Höegh LNG will lead to high fleet utilization rates or stable cash flows in the future.

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On March 8, 2021, Höegh LNG announced a recommended offer by Leif Höegh & Co. Ltd. (“LHC”) and funds managed by Morgan Stanley Infrastructure Partners (“MSIP”) through a 50/50 joint venture, Larus Holding Limited (“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates (the “Amalgamation”). Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange. The Amalgamation has been approved by Höegh LNG’s shareholders and bondholders and is anticipated to close in the first half of 2021. The Amalgamation is subject to waivers of specific change of control and delisting provisions in relation to certain of our and Höegh LNG's credit agreements, as well as the satisfaction of other customary closing conditions. Following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels (as defined in “Major Unitholders and Related Party Transactions – Related Party Transactions – Omnibus Agreement – Non Competition”), (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

Business Strategies

● Focus on FSRU Newbuilding Acquisitions. We intend to acquire newbuilding FSRUs on long-term charters, which we believe generally offer greater flexibility than FSRUs based on retrofitted, first generation LNG carriers. Newbuilding FSRUs have superior fuel efficiency, improved storage performance and larger capacity than retrofitted, first-generation LNG carriers. Their larger capacity allows for a full cargo from a comparably sized, modern-day LNG carrier to be offloaded in a single transfer, and this streamlines logistics. We may also acquire retrofitted LNG carriers if such vessels are converted from modern LNG carriers with comparable and logistical benefits. In addition, Höegh LNG has strong customer relationships deriving from its ability to work alongside customers on their vessel design and infrastructure needs. We believe that Höegh LNG’s ability to offer newbuild vessels promptly and its engineering expertise make it an operator of choice for projects that require rapid execution, complex engineering or unique specifications. This, in turn, enhances the growth opportunities available to us.

● Pursue Strategic Acquisitions of FSRUs, LNG Carriers and Other LNG Infrastructure Assets on Long-Term, Fixed-Rate Charters with Strong Counterparties. We will seek to leverage our relationship with Höegh LNG to make strategic acquisitions. We also intend to take advantage of business opportunities and market trends in the LNG transportation industry to grow our assets through third-party acquisitions of FSRUs, LNG carriers and other LNG infrastructure assets under long-term charters.

● Expand Global Operations in High-Growth Regions. We will seek to capitalize on opportunities emerging from the global expansion of LNG production activity and the need to provide flexible regasification solutions in areas which require natural gas imports. We believe that Höegh LNG’s position as one of a few FSRU owners and operators in the world, more than 40-year operational track record and strong customer relationships will enable us to have early access to new projects worldwide.

● Enhance and Diversify Customer Relationships Through Continued Operating Excellence and Technological Innovation. We intend to maintain and grow our cash flows by focusing on strong customer relationships and actively seeking the extension and renewal of existing charters, entering into new long-term charters with current customers, and identifying new business opportunities with other creditworthy charterers. We believe our customer relationships are enhanced by our ability to provide expert technical advice to our customers through Höegh LNG’s in-house engineering department, which in turn enables us to be directly involved in our customers’ project development processes. We will continue to incorporate safety, health, security and environmental stewardship into all aspects of vessel design and operation in order to satisfy our customers and comply with national and international rules and regulations. We believe that Höegh LNG’s operational expertise, recognized position, and track record in floating LNG infrastructure services will position us favorably to capture additional commercial opportunities in the FSRU and LNG sectors.

We can provide no assurance, however, that we will be able to implement our business strategies described above. For further discussion of the risks that we face, please read “Item 3.D. Risk Factors.”

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Our Fleet

Our Current Fleet

As of March 31, 2021, our fleet consists of interests in the following vessels:

● a 50% interest in the Neptune, an FSRU built in 2009 that is currently operating under a time charter with Total Gas & Power that expires in 2029, with an option to extend for up to two additional periods of five years each;

● a 50% interest in the Cape Ann, an FSRU built in 2010 that is currently operating under a time charter with Total Gas & Power that expires in 2030, with an option to extend for up to two additional periods of five years each;

● a 100% economic interest in the PGN FSRU Lampung, an FSRU built in 2014 that is currently operating under a time charter with PGN LNG that expires in 2034, with options to extend either for an additional 10 years or for up to two additional periods of five years each;

● a 100% interest in the Höegh Gallant, an FSRU built in 2014 that is currently operating under a time charter with CharterCo, a subsidiary of Höegh LNG. Previously, the Höegh Gallant operated under a long-term time charter which started in 2015 and expired in 2020 with EgyptCo, a subsidiary of Höegh LNG.

● a 100% interest in Höegh Grace, an FSRU built in 2016 that is currently operating under a time charter with SPEC. The non-cancellable charter period is 10 years. The initial term of the charter is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if SPEC waives its right to terminate in year 10 within a certain deadline, we will not be able to exercise our right to terminate in year 10.

Both the Neptune and the Cape Ann are owned in joint ventures with MOL and TLT, which own in the aggregate 50% of each joint venture. For a description of the joint venture agreements governing our joint ventures, please read “Item 4.B. Business Overview—Shareholder Agreements.” The PGN FSRU Lampung is 49% owned by one of our subsidiaries and 51% owned by PT Bahtera Daya Utama (“PT Bahtera”), an Indonesian subsidiary of PT Imeco Inter Sarana, which provides products and services for various energy and infrastructure projects. Due to local Indonesian regulations, we are required to have a local Indonesian joint venture partner (e.g., PT Bahtera). However, we have a 100% economic interest in the PGN FSRU Lampung. For a description of the agreements related to this arrangement, please read “—Shareholder Agreements—PT Höegh Shareholders’ Agreement.”

The following table provides information about our five FSRUs:

				Maximum					Charter
	Our			send out	Location				extension
	Economic		Capacity	capacity	of	Charter		Charter	option
FSRU	Interest		(cbm)	(MMscf/d)	operation	commencement	Charterer	Expiration	period
Neptune	50	%	145,000	750	Various	Nov 2009	Total Gas & Power	2029	Five years plus five years
Cape Ann	50	%	145,000	750	Various	Jun 2010	Total Gas & Power	2030	Five years plus five years
PGN FSRU Lampung	100	%	170,000	360	Indonesia	Jul 2014	PGN LNG	2034	Five or 10 years (1)
Höegh Gallant	100	%	170,000	500	Various	Apr 2015	CharterCo	2025	n/a
Höegh Grace	100	%	170,000	500	Colombia	Dec 2016	SPEC	2036	n/a (2)

(1) After the initial term, PGN LNG has the choice to extend the term by either five years or 10 years. If PGN LNG extends the term by five years, it subsequently may extend the term by another five years.

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(2) The non-cancellable term is 10 years. The initial term is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if SPEC waives its right to terminate in year 10 within a certain deadline, we will not be able to exercise our right to terminate in year 10.

As of December 31, 2020, the Neptune, the Cape Ann, the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace were approximately 11.2 years old, 10.6 years old, 6.8 years old, 6.2 years old and 4.8 years old, respectively. FSRUs are generally designed to have a lifespan of approximately 40 years.

From December 2016 until June 2019, the Neptune operated as the first FSRU in the Turkish market at the Etki Terminal near the port of Aliaga in Izmir province on the west coast of Turkey. Neptune has been trading as LNG Carrier since leaving Turkey. From October 2017 to March 2018, the Cape Ann was sub-chartered as an FSRU, located in Tianjin outside Beijing, China. Commencing in April 2018, the Cape Ann has served as an LNG carrier.

The PGN FSRU Lampung is located offshore in the Lampung province at the southeast coast of Sumatra, Indonesia. The vessel is moored at a purpose-built mooring system built by a subcontractor of Höegh LNG, subsequently sold to PGN LNG and located approximately 16 kilometers offshore.

In October 2018, the Höegh Gallant commenced operating as an LNG carrier for EgyptCo's charter with a third party with a term until April 2020. The FSRU Höegh Gallant operated as an LNG import terminal at Ain Sokhna port, located on the Red Sea in Egypt, until October 2018. On April 30, 2020, we entered into the Subsequent Charter with CharterCo, a subsidiary of Höegh LNG, which commenced on May 1, 2020 and expires July 31, 2025.

The Höegh Grace is operating as an LNG import terminal in the port of Cartagena on the Atlantic coast of Colombia. The Höegh Grace was delivered from the shipyard in March 2016 and employed as an LNG carrier by SPEC from June to October 2016.

Each of the Neptune, the Cape Ann, the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace has a reinforced membrane-type cargo containment system that facilitates offshore loading operations.

Technical Specifications

Each FSRU in our fleet has the following onboard equipment for the vaporization of LNG and delivery of high-pressure natural gas:

● High-Pressure Cryogenic Pumps. Each FSRU has, or will have upon delivery from the shipyard, high-pressure cryogenic pumps, which pressurize the LNG prior to vaporization.

● Vaporizers. Each FSRU has, or will have upon delivery from the shipyard, vaporizers, which convert the LNG back to vaporous natural gas using heat generated by either steam boilers or seawater.

● Dual-Fuel Diesel Electric Propulsion Plant. Each FSRU has, or will have upon delivery from the shipyard, a dual-fuel diesel electric propulsion plant, which provides the power for the vessel’s regasification, propulsion and utility systems.

● Mooring System. Each of the Neptune and the Cape Ann is equipped with a submerged turret loading (“STL”) offshore mooring system and can also be moored to a jetty. The PGN FSRU Lampung is equipped for mooring to a tower yoke. The Höegh Gallant and the Höegh Grace are equipped for quay-side mooring.

● Gas Export System. The PGN FSRU Lampung has an export pipeline on her bow, which is connected via jumper hoses to the tower yoke. The Höegh Gallant and the Höegh Grace have a high-pressure manifold on the side, to connect to the loading arms on the purpose-built jetties. The Neptune and the Cape Ann have an STL buoy system but have also been retrofitted with high-pressure gas manifold on the side, which can be connected to loading arms on a jetty.

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Each of the Neptune and the Cape Ann has a closed-loop regasification system, where heat for vaporization is generated by steam boilers. The PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace have open-loop regasification systems, where heat for vaporization is generated by pumping sea water.

Each of the Neptune, the Cape Ann, the Höegh Gallant and the Höegh Grace is capable of operating as a conventional LNG carrier.

Customers

For the years ended December 31, 2020, 2019 and 2018 the total revenues in the consolidated statements of income are from PGN LNG, EgyptCo and CharterCo, both subsidiaries of Höegh LNG, and SPEC. PGN LNG is a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk, a subsidiary of PT Pertamina, a government-controlled, Indonesian oil and gas producer, natural gas transportation and distribution company. SPEC is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. Total Gas & Power (formerly Global LNG Supply), accounted for 100% of our joint ventures’ time charter revenues for the years ended December 31, 2020, 2019 and 2018. During 2018, Global LNG Supply was acquired by Total, a French publicly listed company, that produces and markets fuels, natural gas and low-carbon electricity, from ENGIE. In February 2020, our joint ventures’ time charters were novated from Global LNG Supply to Total Gas & Power, a subsidiary of Total.

Vessel Time Charters

Our vessels are provided to the applicable charterer by our joint venture or us, as applicable (each, a “vessel owner”), under separate time charters.

A time charter is a contract for the use of a vessel for a fixed period of time at a specified hire rate. Under a time charter, the vessel owner provides the crew, technical and other services related to the vessel’s operation, the majority or all of the cost of which is included in the hire rate, and the charterer generally is responsible for substantially all of the vessel voyage costs (including fuel, port and canal fees and LNG boil-off).

Neptune Time Charter

Initial Term; Extensions

The Neptune time charter commenced upon acceptance of the vessel by the charterer in November 2009. The initial term of the Neptune time charter is 20 years. Total Gas & Power has the option to extend the time charter for up to two additional periods of five years each.

Performance Standards

Under the Neptune time charter, the vessel owner undertakes to ensure that the vessel meets specified performance standards at all times during the term of the time charter. The vessel must maintain a guaranteed speed, consume no more than a specified amount of fuel oil and not exceed a maximum average daily boil-off, all as specified in the time charter. On April 1, 2020, as part of the settlement of the boil-off claim with the charterer, the vessel owner and the charterer entered into an amendment to the Neptune time charter specifying a new procedure with respect to the calculation of excess boil-off under the time charter’s performance standards. In addition, the vessel owner undertakes that the vessel will be capable of discharging her cargo within a specified time and regasifying and discharging her cargo at not less than a specified rate.

Hire Rate

Under the Neptune time charter, hire is payable to the vessel owner monthly, in advance in U.S. Dollars. The hire rate under the Neptune time charter consists of three cost components:

● Fixed Element. The fixed element is a fixed per day fee providing for ownership costs and all remuneration due to the vessel owner for use of the vessel and the provision of time charter services.

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● Variable (Operating Cost) Element. The variable (operating cost) element is a fixed per day fee providing for the operating costs of the vessel, which consists of (i) a cost pass-through sub-element, which covers the crew (excluding the extra cost associated with a U.S. crew requirement, which is invoiced separately), insurance, consumables, miscellaneous services, spares and damage deductible costs and is subject to annual adjustment and (ii) an indexed sub-element, which covers management and is subject to annual adjustment for changes in labor costs and the size of the fleet under management.

● Optional (Capitalized Equipment Cost) Element. The optional (capitalized equipment cost) element consists of (i) costs associated with modifications to, changes in specifications of, structural changes in or new equipment for the vessel that become compulsory for the continued operation of the vessel by reason of new class requirements or national or international regulations coming into effect after the date of the time charter, subject to specified caps and (ii) costs associated with any new equipment or machinery that the owner and charterer have agreed should be capitalized. Such costs are distributed over the remaining term of the time charter.

While the hire rate under the Neptune time charter does not cover drydocking expenses or extra costs associated with a U.S. crew requirement, the charterer will reimburse the vessel owner on a cost pass-through basis.

If Total Gas & Power exercises its option to extend the Neptune time charter beyond its initial term, the hire rate will be determined as set forth above, provided that the fixed element will be reduced by approximately 30%.

The hire rate is subject to deduction by the charterer by, among other things, any sums due in respect of the vessel owner’s failure to satisfy the undertakings described under “—Performance Standards” and off-hire accruing during the period. The hire rate is also subject to deduction by the charterer if the vessel owner fails to maintain the vessel in compliance with the vessel’s specifications and contractual standards, provide the required crew, keep the vessel at the charterer’s disposal or comply with specified corporate organizational requirements and such failure increases the time taken by the vessel to perform her services or results in the charterer directly incurring costs.

Expenses

The vessel owner is responsible for providing certain items and services, which include the crew; drydocking, overhaul, maintenance and repairs; insurance; stores; necessary spare parts; water; inert gas and nitrogen; communication expenses and fees paid to the classification societies, regulatory authorities and consultants. The variable (operating cost) element of the hire rate is designed to cover these expenses. Except for when the vessel is off-hire, the charterer pays for bunker fuels, marine gas oil and boil-off if used or burned while steaming at a reduced rate. Additionally, except for when the vessel is off-hire, the charterer pays for boil-off used to provide power for discharge and regasification; and fuel for inert gas, nitrogen and diesel generators.

Off-hire

Under the Neptune time charter, the vessel generally will be deemed off-hire if the vessel is not available for the charterer’s use for a specified amount of time due to, among other things:

● failure of an inspection that prevents the vessel from performing normal commercial operations;

● scheduled drydocking that exceeds allowances;

● the vessel’s inability to discharge regasified LNG at normal performance;

● requisition of the vessel; or

● the vessel owner’s failure to maintain the vessel in compliance with her specifications and contractual standards or to provide the required crew.

In the event of off-hire, all hire will cease to be due or payable for the duration of off-hire. Notwithstanding the foregoing, hire is not reduced due to an event of off-hire if the event of off-hire does not exceed a specified number of days in any 12-month period.

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Ship Management and Maintenance

Under the Neptune time charter, the vessel owner is responsible for the technical management of the vessel, including engagement and provision of a qualified crew, maintaining the vessel, arranging supply of stores and equipment, periodic drydocking and ensuring compliance with applicable regulations, including licensing and certification requirements. These services are provided to the vessel owner by Höegh LNG Management pursuant to a ship management agreement.

Termination

Under the Neptune time charter, the vessel owner is entitled to terminate the time charter if the charterer fails to pay its debts, becomes insolvent or enters into bankruptcy or liquidation.

The charterer is entitled to terminate the time charter and, at its option, convert the time charter into a bareboat charter, if (i) either the vessel owner or any guarantor (a) fails to pay its debts or (b) becomes insolvent or enters into bankruptcy or liquidation or (ii) the vessel owner’s guarantee ceases to be in full force and effect. Furthermore, the charterer has the option to terminate the time charter without cause by providing notice at least two years in advance of the charterer’s election. On the date of such termination, the charterer will pay the vessel owner a specified termination fee, which declines over time and is based upon the year in which the time charter is terminated. Furthermore, the charterer may terminate the time charter if any period of off-hire due to (i) the vessel owner’s failure to maintain the vessel in compliance with her specifications and contractual standards or to provide the required crew exceeds a specified number of days, (ii) damage to the vessel’s cargo containment system as a result of the vessel owner’s failure to comply with cargo and filling level restrictions exceeds a specified number of months or (iii) any reason other than scheduled drydocking or damage to the vessel’s cargo containment system exceeds a specified number of months, unless such period of off-hire is due to the vessel owner’s failure to comply with cargo and filling level restrictions.

After attempting to take mitigating steps for a specified number of days, both the vessel owner and the charterer have the right to terminate the time charter if war is declared in any location that materially interrupts the performance of the time charter. The time charter will terminate automatically if the vessel is lost, missing or a constructive or compromised total loss.

Indemnification

No liability is imposed upon the vessel owner for the death or personal injury of the charterer, its representatives or their estates (collectively, the “Charterer’s Group”) while engaged in activities contemplated by the time charter unless such death or personal injury is by the gross negligence or willful misconduct of the vessel owner, its employees or its agents. Additionally, no liability is imposed upon the vessel owner if any personal property of the Charterer’s Group is damaged, lost or destroyed as a result of the gross negligence or willful misconduct of the vessel owner, its employees or its agents. Similar provisions apply to the charterer in both cases.

However, if any of the charterer’s representatives dies or is personally injured while engaged in activities contemplated by the time charter and as a result of the gross negligence or willful misconduct of the vessel owner, its employees or its agents, the vessel owner will indemnify the Charterer’s Group, as applicable. Additionally, if any personal property of the Charterer’s Group is damaged, lost or destroyed as a result of the gross negligence or willful misconduct of the vessel owner, its employees or its agents, the vessel owner will indemnify the Charterer’s Group, as applicable. Reciprocal obligations are imposed on the charterer in both cases.

The charterer will indemnify the vessel owner for losses associated with shipping documents to the extent they were signed as directed by the charterer or based upon information that it provided. In addition, the charterer will indemnify the vessel owner against taxes imposed on the vessel owner or the vessel in respect of hire by any country where loading or discharging of LNG takes place, where the vessel is located or through which the vessel travels, where the charterer is organized, does business or has a fixed place of business or where the charterer makes payments under the time charter, subject to certain exceptions.

The vessel owner will indemnify the charterer, its servants and agents against all losses, claims, responsibilities and liabilities arising from the employment of pilots, tugboats or stevedores, subject to certain exceptions.

The vessel owner will indemnify the charterer against any claim by a third party alleging that the construction or operation of the vessel infringes any right claimed by such third party, including but not limited to patent rights,

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copyrights, trade secrets, industrial property or trademarks. The charterer will indemnify the vessel owner for all amounts properly payable to the vessel builder if the charterer takes, or requires the vessel owner to take, any action that puts the vessel owner in breach of its intellectual property rights obligations under the vessel building contract.

Guarantee

Pursuant to the Neptune time charter, both Höegh LNG Ltd. and MOL guarantee the performance and payment obligations of the vessel owner under the time charter. Such guarantee is joint and several as to performance obligations and several as to payment obligations. If the guarantee is not maintained, the charterer may terminate the time charter.

Subcharter Provisions

The charterer entered into a subcharter to provide the Neptune as an FSRU for the Etki Terminal in Izmir province on the west coast of Turkey, pursuant to which Global LNG Supply and SRV Joint Gas Ltd. amended the Neptune time charter in December 2016 (the “Neptune charter amendments”). The subcharter terminated in June 2019. The Neptune charter amendments applied only during the term of the subcharter.

Cape Ann Time Charter

Initial Term; Extensions

The Cape Ann time charter commenced upon acceptance of the vessel by the charterer in June 2010. The initial term of the Cape Ann time charter is 20 years. Total Gas & Power has the option to extend the time charter for up to two additional periods of five years each. From October 2017 until March 2018, the Cape Ann operated as an FSRU pursuant to a subcharter between Global LNG Supply and CNOOC Tianjin LNG Limited Company (“CNOOC TLNG”). From November 2013 until January 3, 2017, the Cape Ann also operated as an FSRU pursuant to a similar subcharter with CNOOC TLNG.

On April 1, 2020, as part of the settlement of the boil-off claim with the charterer, the vessel owner and the charterer entered into an amendment to the Cape Ann time charter specifying a new procedure with respect to the calculation of excess boil-off under the time charter’s performance standards.

The terms of the Cape Ann time charter are substantially similar to those of the Neptune time charter unmodified by the Neptune charter amendments.

Guarantee

Pursuant to the Cape Ann time charter, both Höegh LNG Ltd. and MOL guarantee the performance and payment obligations of the vessel owner under the time charter. Such guarantee is joint and several as to performance obligations and several as to payment obligations. If the guarantee is not maintained, the charterer may terminate the time charter.

PGN FSRU Lampung Time Charter

Under a lease, operation and maintenance agreement, which we refer to as a time charter, we provide to PGN LNG the services of the PGN FSRU Lampung, which is moored at the Mooring owned by PGN LNG and located approximately 16 kilometers off the shore of Labuhan Maringgai at the southeast coast of Sumatra, Indonesia. Also, under the time charter, we operate and maintain the Mooring.

Initial Term; Extensions

The long-term time charter for the PGN FSRU Lampung with PGN LNG has an initial term of 20 years from the acceptance date of October 30, 2014. The time charter hire payments began July 21, 2014 when the project was ready to begin commissioning. At any time on or before 17 years and 183 days after acceptance, PGN LNG may exercise its option to extend the time charter for either five or 10 years. If the term is extended for five years pursuant to such option, at any time on or before the date that is 22 years and 183 days after acceptance, PGN LNG may exercise its option to extend the time charter for a subsequent five years.

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Performance Standards

Under the PGN FSRU Lampung time charter, the vessel owner makes certain performance warranties for the term of the time charter, excluding time during which the vessel is off-hire or in lay-up or a failure to satisfy any such warranty due to a “Lampung Charterer Risk Event” (which includes, among other things, any breach, act, interference or omission by the charterer that prevents or interferes with the vessel owner’s performance under the time charter) or an event of force majeure, including the following:

● the management warranties, which consist of the following:

o the vessel complies with specifications; is classed by Det Norske Veritas GL; is in good order and condition and fit for service; and has onboard all certificates, documents, approvals, permits, permissions and equipment required by Det Norske Veritas GL or any law necessary for the vessel to carry out required operations on the Mooring;

o the vessel owner provides shipboard personnel in accordance with specified terms;

o the vessel owner loads LNG in accordance with specified procedures; operates all equipment in a safe and proper manner and as required by Indonesian law; keeps up-to-date records and logs; uses reasonable endeavors to cooperate with the charterer to comply with and satisfy any requirements of any governmental authority; stows LNG properly and keeps a strict account of all LNG loaded, boil-off and regasified LNG discharged; and exercises due diligence and good industry practice to minimize venting of boil-off; and

o the vessel owner provides and pays for all provisions, wages and discharging fees and all other expenses related to the master, officers and crew; insurance; spare parts and other necessary stores, including lubricating oil; drydocking in emergency cases, maintenance and repairs; certificates; customs or import duties arising in connection with any of the foregoing; and consents, licenses and permits required by governmental authorities to be in the vessel owner’s name (collectively, the “Lampung Vessel Owner Expenses”);

● the vessel receives LNG in accordance with a specified nominating loading rate;

● the vessel consumes fuel at or below a specified amount;

● during a nomination period, the vessel delivers regasified LNG at a specified average rate;

● during a period in which there is no regasification send-out, no LNG transfer or cargo tank cool down ongoing and no LNG pump running in any cargo tank, the amount of boil-off does not exceed a specified percentage of cargo capacity per day;

● the boil-off recondenser is able to recondense boil-off gas for the days when the vessel is sending out regasified LNG; and

● the cargo capacity of the vessel does not exceed the aggregate volume of LNG that can be stored in the cargo tanks of the vessel.

Hire Rate

Under the PGN FSRU Lampung time charter, hire is payable to the vessel owner monthly, in arrears in U.S. Dollars. The hire rate under the PGN FSRU Lampung time charter consists of three cost components:

● Capital Element. The capital element is a fixed per day fee, which is intended to cover remuneration due to the vessel owner for use of the vessel and the provision of time charter services.

● Operating and Maintenance Element. The operating and maintenance element is a fixed per day fee, subject to annual adjustment, which is intended to cover the operating costs of the vessel, including manning costs,

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maintenance and repair costs, consumables and stores costs, insurance costs, management and operational costs, miscellaneous costs and alterations not required by Det Norske Veritas GL to maintain class or the IMO.

● Tax Element. The tax element is a fixed per day fee, equal to the vessel owner’s reasonable estimate of the tax liability for that charter year divided by the number of days in such charter year. If the vessel owner receives a tax refund or credit, the vessel owner will pay such amount to the charterer. Similarly, if any audit required by the time charter reveals that the vessel owner’s reasonable estimate of the tax liability varied from the actual tax liability, the vessel owner or the charterer, as applicable, will pay to the other party the difference in such amount.

If PGN LNG exercises an option to extend the PGN FSRU Lampung time charter beyond its initial term, the hire rate will be determined as set forth above, provided that the capital element will be increased by 50% and the operating and maintenance element will equal cost pass-through.

The hire rate is subject to adjustment if any change in Indonesian law or tax occurs that alters the vessel owner’s performance of the time charter or the charterer requires the vessel owner to lay-up the vessel.

Furthermore, the hire rate is subject to deduction by the charterer for sums due in respect of the vessel owner’s failure to satisfy the performance warranties or if, as a result of an event of force majeure and subject to specified exceptions, the regasification flow rate is less than that required to meet the quantity nominated. However, any deduction for the vessel owner’s failure to satisfy the performance warranties may not exceed the aggregate of the capital element and the operating and maintenance element for that day; provided, that such cap does not apply to the vessel owner’s failure to satisfy specified fuel consumption or boil-off warranties.

The charterer will pay the vessel owner the hire rate for time lost due to a Lampung Charterer Risk Event.

Expenses

The vessel owner is responsible for providing certain items and services, which include the Lampung Vessel Owner Expenses and the supply of all LNG required for gassing up and cooling of the vessel. The vessel owner pays for non-Indonesian taxes and alterations required by Det Norske Veritas GL to maintain class or the IMO. The vessel owner also will provide, at its expense, accommodation space for at least two of the charterer’s employees responsible for coordinating terminal operations onshore and offshore, provided that the charterer reimburses the vessel owner for the cost of provisions supplied to such employees.

The charterer pays for make-up of bunker fuels provided by the vessel owner and during tests; regasified LNG for use as fuel; port charges, pilotage, towing, mooring, agency fees or customs or import duties; duties, levies and taxes relating to unloading; costs and expenses relating to terminal security required by the International Ship and Port Facility Security Code (the “ISPS Code”); and mooring, periodic maintenance, repairs, insurance, inspections and surveys beyond daily inspections and capital spares. The charterer also pays for Indonesian taxes and alterations not required by Det Norske Veritas GL to maintain class or the IMO.

Off-hire

Under the PGN FSRU Lampung time charter, the vessel generally will be deemed off-hire if she is not available for the charterer’s use for a specified amount of time due to, among other things:

● drydocking that exceeds allowances;

● the vessel failing to satisfy specified operational minimum requirements, except as a result of a Lampung Charterer Risk Event or an event of force majeure; or

● the vessel owner’s failure to satisfy the management warranties described above under “—Performance Standards.”

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In the event of off-hire, all hire will cease to be due or payable for the duration of off-hire. Notwithstanding the foregoing, hire is not reduced due to an event of off-hire if the event of off-hire does not exceed a specified number of hours in any 12-month period.

Technical Support

Under the PGN FSRU Lampung time charter, the vessel owner is responsible for the technical support services with respect to the vessel, including engagement and provision of a qualified crew, maintaining the vessel, arranging supply of stores and equipment, periodic drydocking and ensuring compliance with applicable regulations, including licensing and certification requirements. These services are provided by Höegh LNG Management pursuant to the technical information and services agreement between the vessel owner and Höegh Norway and the sub-technical support agreement between Höegh Norway and Höegh LNG Management.

Termination

Under the PGN FSRU Lampung time charter, the charterer is entitled to terminate the time charter for the following reasons:

● if, due to one of several specified events of force majeure (“Lampung Nongovernmental Force Majeure”) that results in physical damage to the vessel or the Mooring in respect of which insurance proceeds are payable under the loss of hire insurance and hull and machinery insurance (“Lampung Vessel Force Majeure”), the vessel owner is unable to comply with nominations for a specified number of days;

● if, due to an event of force majeure that is not Lampung Nongovernmental Force Majeure or Lampung Vessel Force Majeure (“Lampung Other Force Majeure”), the vessel owner is unable to comply with nominations for a specified number of days; or

● if there has been an event of force majeure caused by the Indonesian government (“Lampung Governmental Force Majeure”) during a specified number of days.

If the charterer terminates for Lampung Other Force Majeure or Lampung Governmental Force Majeure, the charterer will pay the vessel owner a specified termination fee based upon the year in which the time charter is terminated.

Additionally, after the occurrence of an event of default by the vessel owner, and while such event of default continues, the charterer may terminate the time charter. If the charterer terminates the time charter for certain events of default that the vessel owner intentionally or deliberately committed for the purpose of terminating the time charter so that the vessel owner could employ the vessel with a third party, the vessel owner will transfer the vessel’s title to the charterer.

The vessel owner may terminate the time charter after the occurrence of an event of default by the charterer while such event of default continues. If the charterer fails to pay invoiced amounts when due and such failure continues for a specified number of days following notice from the vessel owner, the vessel owner may suspend its performance and remain on-hire until such failure is corrected.

If the time charter is terminated by the vessel owner for an event of default of the charterer, the charterer will pay the vessel owner a specified termination fee based upon the year in which the time charter is terminated. Under such circumstances, as well as if the time charter is terminated by the charterer for Lampung Governmental Force Majeure, the vessel owner may require that the parties begin negotiation of terms under which the vessel owner would be willing to sell to the charterer a 50% ownership interest in the vessel for a specified amount that declines over time and is based upon the year in which the time charter is terminated. If the charterer terminates the time charter for force majeure other than Lampung Governmental Force Majeure or an event of default of the vessel owner, the charterer may require the parties to begin such negotiation.

The time charter will terminate automatically if the vessel is lost or a constructive total loss.

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Indemnification

For losses arising out of claims for illness or injuries to or death of any employees of the vessel owner, the vessel owner’s affiliates, certain subcontractors of the vessel owner, persons contracting with the vessel owner under the building contract or the Mooring contract and representatives of each of the foregoing (collectively, the “Lampung Owner’s Group”), the vessel owner will indemnify the charterer, certain affiliates and subcontractors of the charterer, persons executing tug charters and terminal use agreements, persons receiving regasified LNG delivered by the vessel and representatives of each of the foregoing (collectively, the “Lampung Charterer’s Group”). Reciprocal obligations are imposed on the charterer.

For losses arising out of claims for damage to or loss of the vessel or property, equipment or materials owned or leased by any member of the Lampung Owner’s Group, the vessel owner will indemnify the Lampung Charterer’s Group. Similarly, the charterer will indemnify the Lampung Owner’s Group for losses arising out of claims for damage to or loss of property, equipment or materials owned or leased by any member of the Lampung Charterer’s Group or LNG stored on the vessel or the Mooring.

For losses arising from pollution or contamination created by the vessel or the operation thereof or the Mooring, the vessel owner will indemnify the Lampung Charterer’s Group; provided, that the vessel owner’s aggregate liability for each applicable accident will not exceed $150,000,000. For losses arising from pollution or contamination created by, or directly related to, the operation of the downstream pipeline, any LNG carrier or any vessel operating under a tug charter, the charterer will indemnify the Lampung Owner’s Group.

Purchase Option

PGN LNG was granted an option to purchase the PGN FSRU Lampung at specified prices based upon the year in which the option is exercised. Such option to purchase may be exercised commencing in June 2018; however, it may not be exercised if either of the charter extension options has expired without exercise. The option is exercisable upon PGN LNG giving us notice specifying the time and date of delivery, which must be after the third anniversary of the date of delivery. The option to purchase survives termination of the time charter. PGN LNG has discussed alternatives regarding the option, among other contractual provisions. However, no notice has been provided to indicate an intention of exercising this option as of March 31, 2021. Please read “Item 3.D. Risk Factors—Risks Inherent in Our Business—PGN LNG and SPEC have options to purchase the PGN FSRU Lampung and Höegh Grace, respectively. If either charterer exercises its option, it could have a material adverse effect on our operating cash flows and our ability to make cash distributions to our unitholders.”

Guarantee

Pursuant to the PGN FSRU Lampung time charter, Höegh LNG guarantees the due and proper performance by PT Höegh of all its obligations and liabilities under the time charter.

Höegh Gallant Time Charter

Previously, the Höegh Gallant operated under a long-term time charter which started in 2015 and expired in 2020 with EgyptCo, a subsidiary of Höegh LNG. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of the EgyptCo charter until July 2025. On April 30, 2020, the Partnership entered into a lease and maintenance agreement with CharterCo, another subsidiary of Höegh LNG, for the time charter of the Höegh Gallant (the “Subsequent Charter”).

Term

The Subsequent Charter (the “Höegh Gallant time charter”) commenced May 1, 2020 and expires July 31, 2025.

Performance Standards

Under the Höegh Gallant time charter, the vessel owner undertakes to exercise due diligence to maintain the vessel in accordance with international standards, provide a suitably qualified marine crew and comply with applicable laws, rules and regulation at all times during the term of the time charter.

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Hire Rate

Under the Höegh Gallant time charter, hire to the vessel owner is payable monthly, in arrears. The hire rate under the Höegh Gallant time charter has only one component, which is intended to cover remuneration due to the vessel owner for use of the vessel and the provision of time charter services as well as the operating and maintenance costs of the vessel, including manning costs, the cost of spare parts and any tax incurred. The hire rate under the Subsequent Charter is equal to 90% of the rate payable pursuant to the prior charter of the Höegh Gallant, subject to certain adjustments for i) avoided FSRU-related costs only when operating in LNG carrier mode and ii) higher incremental taxes or operating expenses when operating in FSRU mode.

The Höegh Gallant time charter does not have any pass-through provisions for drydocking expenses, except that if the vessel owner selects a special port for drydock instead of the one offered by the charterer, certain costs related to fuel and other costs associated with the voyage from the last discharge port and to the port used for gas-up or cool-down (if any) after drydock are passed through to the vessel owner.

A price review of the hire rate may be conducted after three years, but a revised rate can only be implemented upon written agreement by both parties.

Höegh LNG guarantees the performance by the charterer of all its obligations under the Höegh Gallant time charter.

Expenses

The vessel owner is responsible for providing certain items and services, which include the crew; drydocking, overhaul, maintenance and repairs; insurance; stores; necessary spare parts; communication expenses and fees paid to the classification societies, regulatory authorities and consultants. The hire rate is designed to cover these expenses except for when the vessel is off-hire. The charterer pays for port and light dues, towage and pilotage, loading and unloading expenses, port charges, canal fees and other similar expenses unless specifically payable by vessel owner. The vessel owner is responsible for providing bunker when the vessel is operating in FSRU mode, but charterer provides these when the vessel is operating in LNG carrier mode. Charterer is responsible for providing LNG as fuel gas when the vessel is operating in FSRU mode, not to exceed consumption guarantees set forth in the Höegh Gallant time charter. Unless otherwise agreed by the parties, the vessel owner must pay for the LNG Heel onboard the vessel at the time of redelivery.

Off-hire

Under the Höegh Gallant time charter, the vessel generally will be deemed off-hire if she is not available for the charterer’s use due to, among other things:

· drydocking or other repairs and maintenance;

· any damage, defect, breakdown or deficiency to the vessel;

● failure to maintain a minimum agreed speed (when operating in LNG carrier mode);

· any deficiency of crew, stores, repairs, surveys, or similar cause preventing the working of the vessel;

· any labor dispute, failure or inability of the officers or crew to perform the required services; or

· any failure to comply with laws, regulations or operational practices at the site of the vessel operations.

In the event of off-hire, all hire will cease to be due or payable for the duration of off-hire.

Ship Management and Maintenance

Under the Höegh Gallant time charter, the vessel owner is responsible for the technical management of the vessel, including engagement and provision of a qualified crew, maintaining the vessel, arranging supply of stores and equipment, periodic drydocking and ensuring compliance with applicable regulations, including licensing and

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certification requirements. The crew is provided to the vessel owner by Höegh Maritime Management pursuant to a secondment agreement. The remaining services are provided to the vessel owner by Höegh LNG Management pursuant to a ship management agreement.

Termination

Under the Höegh Gallant time charter, the vessel owner is entitled to terminate the time charter if charterer (a) fails to pay its hire or other amounts when due and such failure is not timely cured, (b) suspends payment of its debts, (c) becomes insolvent, (d) enters into bankruptcy or liquidation, or (e) otherwise materially breaches the terms of the charter.

The charterer is entitled to terminate the time charter if (i) there is a change in legal or disponent ownership of the vessel other than as permitted under the Höegh Gallant time charter; (ii) the vessel owner (a) fails to pay its debts or is otherwise insolvent, or (b) enters into bankruptcy or liquidation; (iii) without charterer’s consent (a) the vessel ceases to be registered under the laws of the agreed flag state and such default is not timely cured, (b) the vessel ceases to hold a classification certificate with the agreed classification society, (c) the vessel owner effects a lien or other mortgage over the vessel or any rights to payment in relation to the vessel, or (d) the vessel owner makes an assignment, transfer or novation of the charter; (iv) the vessel is arrested other than as permitted in the charter, (v) the vessel owner fails to maintain insurance or classification; (vi) the vessel owner is in material breach of the terms of the charter; (vii) prolonged off-hire for a specified period of days; or (viii ) the vessel owner fails to maintain required insurance. The time charter will terminate automatically if the vessel is lost, missing or a constructive or compromised total loss. While the vessel is operating in FSRU mode, either party may terminate the time charter if an event of force majeure lasts for a specified period of days.

Indemnification

The vessel owner will indemnify and hold the charterer harmless against all losses incurred by charterer resulting from the breach by vessel owner of vessel owner’s obligations to pay taxes for which it is obligated under the charter agreement.

The following indemnification provisions apply while the vessel is operating in FSRU mode:

● The charterer will indemnify the vessel owner for any damage or loss of property, death or personal injury of the charterer, its affiliates or their contractors (collectively, the “Charterer Indemnified Parties”) regardless of cause or whether or not the negligence, omission or default of the vessel owner, its affiliates or their contractors (collectively, the “Owner Indemnified Parties”) caused or contributed to the damages. The charterer will indemnify the vessel owner for any damage to or loss of property of any Person not being a Charterer Indemnified Party or an Owner Indemnified Party and any personal injury or death (including fatal injury, illness or disease) of any Person not being a Charterer Indemnified Party or an Owner Indemnified Party (or an employee or servant of a Charterer Indemnified Party or an Owner Indemnified Party), arising directly or indirectly from any negligent act, omission, error or breach of duty by any Charterer Indemnified Party, regardless of whether or not the negligence, act, omission, default, error or breach by any Owner Indemnified Party caused or contributed to such damages. The charterer will indemnify the vessel owner for all losses arising directly or indirectly from or incurred by reason of any failure by any Owner Indemnified Party to comply with, or for any contravention of, any applicable law (including laws related to Sanctions), including any claims or penalties imposed by any governmental authority.

● The vessel owner will indemnify the charterer for any damage or loss of the vessel and of its property and any cargo on board, and any death or personal injury of the Owner Indemnified Parties regardless of cause or whether or not the negligence, omission or default of the Charterer Indemnified Parties caused or contributed to the damages. The vessel owner will indemnify the Charterer Indemnified Parties for all damage and harm to the environment, including damages for control remediation and clean-up of all pollution arising from pollution, which originates from the vessel or the property of any Owner Indemnified Party used in connection with the operation of the vessel, regardless of fault or whether or not the negligence, omission or default of the Charterer Indemnified Parties caused or contributed to the damages. The vessel owner will indemnify charterer for any losses arising directly or indirectly from or incurred by reason of any failure by any Owner Indemnified Party to comply with, or for any contravention of, any applicable law (including laws related to sanctions), including

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any claims or penalties imposed by any governmental authority. The vessel owner will indemnify the charterer for any liquidated damages that the charterer is obligated to pay as a result of the vessel being off-hire, subject to an agreed maximum limit. The vessel owner shall indemnify the charterer for liquidated damages payable by charterer under a contract between charterer and a third party for services using the vessel as a result of the reduced performance of the vessel.

The following indemnification provisions apply while the vessel is operating in LNG carrier mode:

● The charterer will indemnify the vessel owner for any freight taxes imposed on the vessel owner as the result of the LNG vessel’s trading patterns.

Höegh Grace Charter

The Höegh Grace is subject to two material agreements with SPEC: an International Leasing Agreement, pursuant to which Höegh FSRU IV leases the vessel to SPEC (the “ILA”) and the FSRU Operation and Services Agreement, pursuant to which Höegh Colombia provides certain operational services to SPEC with respect to the vessel (the “OSA”). The ILA and the OSA are collectively referred to herein as the “Höegh Grace charter.”

Term and Termination

The Höegh Grace charter has a term of 20 years. Each party has an unconditional option to cancel the Höegh Grace charter after 10 and 15 years without a penalty. However, if the charterer waives its right to terminate in year 10 within a certain deadline, the vessel owner will not be able to exercise its right to terminate in year 10. Accordingly, the non-cancellable charter period is for 10 years.

There are certain conditions under which the Höegh Grace charter could terminate prior to its expiration date. The charter will terminate automatically upon the loss of the vessel. Either party may also terminate the charter for force majeure after a specified period. Additionally, either party may elect to terminate the charter upon the occurrence of specified events of default. The charterer also has the right to terminate the charter in the event of a prolonged off-hire period. If the ILA is terminated for any reason, the OSA will automatically terminate as well.

Performance Standards

Under the Höegh Grace charter, the vessel owner undertakes to ensure that the vessel meets specified performance standards at all times during the term of the charter. The vessel owner is required to pay liquidated damages in the event that the Höegh Grace is unable to accept all or part of a delivered LNG cargo, is unable to deliver the specified amount of regasified natural gas, exceeds a maximum average daily boil-off, consumes more than a specified amount of fuel or suffers other performance failures, which damages are subject to various caps per cargo, per year and in the aggregate for the term of the Höegh Grace charter.

Hire Rate

Under the Höegh Grace charter, hire is payable monthly, in arrears, in U.S. Dollars. The charterer pays a fixed daily rate of hire (with respect to the ILA) and operating fees (with respect to the OSA), as set forth in the Höegh Grace charter. Under the OSA, the operating fees are escalated yearly by a fixed percentage, and the OSA provides for a review and reasonable adjustment by the parties if the actual operating costs increase by more than such percentage over a period of three consecutive years.

Expenses

The vessel owner is responsible for providing certain items and services, which include the crew; bunker fuel, drydocking, overhaul, maintenance and repairs; insurance; stores; necessary spare parts; communication expenses and fees paid to the classification societies and regulatory authorities. The hire rate is designed to cover these expenses except for when the vessel is off-hire. The charterer pays for fuel oil and port expenses.

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Off-hire

Except for force majeure events and a specified maintenance allowance period, under the Höegh Grace charter the vessel generally will be deemed off-hire:

● if the vessel is not able to discharge regasified LNG at a specified rate;

● if the vessel owner breaches its warranties related to international sanctions; or

● if the vessel is not available for the charterer’s use due to, among other things:

o any damage, defect, breakdown or deficiency to the vessel;

o any deficiency of crew, stores, repairs, surveys, or similar cause preventing the working of the vessel;

o any labor dispute, failure or inability of the officers or crew to perform the required services; or

o any failure to comply with laws, regulations or operational practices at the site of the vessel operations.

In the event of off-hire, all hire will cease to be due or payable for the duration of off-hire.

Ship Management and Maintenance

Under the Höegh Grace charter, the vessel owner is responsible for the technical management of the vessel, including engagement and provision of a qualified crew, maintaining the vessel, arranging supply of stores and equipment, periodic drydocking and ensuring compliance with applicable regulations, including licensing and certification requirements. The vessel owner has entered into services agreements with affiliates of Höegh LNG and Höegh Autoliners Ltd. to provide certain of these services. See “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Support Agreement” and “— Höegh Grace Services Agreements.”

Indemnification

The charterer will indemnify the vessel owner for any damage or loss to the charterer’s vessel interconnection infrastructure, including the jetty and interconnection pipeline, or to any other property, death or personal injury of the charterer, its affiliates or their contractors (collectively, the “Charterer Indemnified Parties”) regardless of cause or whether or not the negligence, omission or default of the vessel owner, its affiliates or their contractors (collectively, the “Owner Indemnified Parties”) caused or contributed to the damages. The charter will indemnify the Owner Indemnified Parties for all damage and harm to the environment, including fines imposed by a governmental authority, including damages for control, remediation and clean-up of all pollution or contamination that originates from the charterer’s vessel interconnection infrastructure, including the jetty and interconnection pipeline, or any other property of any Charterer Indemnified Parties, regardless of fault.

The vessel owner will indemnify the charterer for any damage or loss of the vessel and of its property, and any death or personal injury of the Owner Indemnified Parties regardless of cause or whether or not the negligence, omission or default of the Charterer Indemnified Parties caused or contributed to the damages. The vessel owner will indemnify the Charterer Indemnified Parties for all damage and harm to the environment, including fines imposed by a governmental authority, including damages for control, remediation and cleanup of all pollution or contamination that originates from the vessel, regardless of fault.

Each of the vessel owner and the charterer will indemnify the other party for any loss, damage to any property or injury or death suffered by any third party, caused by the vessel owner or charterer, as applicable.

Purchase Option

Pursuant to the Höegh Grace charter, the charterer has the option to purchase the Höegh Grace in year 10, year 15 and year 20 at a price specified in the Höegh Grace charter. The option is exercisable upon the charterer giving notice at

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the end of the applicable term and survives any early termination of the charter in year 10 or year 15 thereof. Please read “Item 3.D. Risk Factors—Risks Inherent in Our Business—PGN LNG and SPEC have options to purchase the PGN FSRU Lampung and Höegh Grace, respectively. If either charterer exercises its option, it could have a material adverse effect on our operating cash flows and our ability to make cash distributions to our unitholders.”

Guarantee

The Partnership guarantees the performance of Höegh FSRU IV and Höegh Colombia under the Höegh Grace charter.

Shareholder Agreements

The following provides a summary of the governance, distribution and other significant terms of our shareholders’ agreements.

SRV Joint Gas Shareholders’ Agreement

We hold our interests in two vessels in our fleet through the following joint ventures (collectively, the “SRV Joint Gas joint ventures”):

● SRV Joint Gas Ltd. (owner of the Neptune), a limited liability company incorporated under the laws of the Cayman Islands, 50% of the equity interests of which are owned by our operating company, 48.5% of which are owned by MOL, and 1.5% of which are owned by TLT; and

● SRV Joint Gas Two Ltd. (owner of the Cape Ann), a limited liability company incorporated under the laws of the Cayman Islands, 50% of the equity interests of which are owned by our operating company, 48.5% of which are owned by MOL and 1.5% of which are owned by TLT.

The SRV Joint Gas joint ventures are governed by the SRV Joint Gas shareholders’ agreement. As a result, the terms and conditions for each of the SRV Joint Gas joint ventures are substantially the same.

The SRV Joint Gas shareholders’ agreement provides that the management of each of the SRV Joint Gas joint ventures will be carried out by a board of directors consisting of four members. We have the right to appoint two members to each board of directors, and MOL has the right to appoint the remaining two members. Additionally, as long as TLT holds at least 1.5% of the shares in an SRV Joint Gas joint venture, it may appoint an observer to attend any meeting of the board of directors of such joint venture.

Pursuant to the SRV Joint Gas shareholders’ agreement, neither we nor our joint venture partners exercise affirmative control over either of the SRV Joint Gas joint ventures. The approval of a majority of the members of the board of directors of an SRV Joint Gas joint venture is required to consent to any proposed action by such joint venture and, as a result, we are unable to cause such joint venture to act in our best interests over the objection of our joint venture partners. Moreover, a deadlocked dispute that cannot be resolved by the board of directors or the senior executives of the applicable joint venture may result in the transfer of our interest in such joint venture to our joint venture partners or a third party. Please read “Item 3.D. Risk Factors—Risks Inherent in Our Business—We are a holding entity that has historically derived a significant amount of our income from equity interests in our joint ventures. Neither we nor our joint venture partners exercise affirmative control over our joint ventures. Accordingly, we cannot require our joint ventures to act in our best interests. Furthermore, our joint venture partners may prevent our joint ventures from taking action that may otherwise be beneficial to us, including making cash distributions to us. A deadlock between us and our joint venture partners could result in our exchanging equity interests in one of our joint ventures for the equity interests in our other joint venture held by our joint venture counterparties or in us or our joint venture partner selling shares in a joint venture to a third party.”

Additionally, certain matters relating to our joint venture partners require the unanimous approval of the board of directors of the applicable SRV Joint Gas joint venture, including:

● agreement of any form of time charter to be entered into by such SRV Joint Gas joint venture and any material amendment to such time charter;

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● agreement of any form of ship management agreement to be entered into by such SRV Joint Gas joint venture;

● agreement of the terms of any financing of the Neptune or the Cape Ann, as applicable, or any other financing exceeding $5,000,000;

● investments exceeding $2,500,000 for a SRV Joint Gas joint venture or $5,000,000 for both SRV Joint Gas joint ventures;

● amendment or change of the articles of association, business or composition of the board of directors of such SRV Joint Gas joint venture;

● issuance of, or granting of options or rights to subscribe for, shares in such SRV Joint Gas joint venture, issuance of loan capital or convertible securities of such SRV Joint Gas joint venture, alteration of the share capital of such SRV Joint Gas joint venture or formation of any subsidiary;

● granting any security over shares of such SRV Joint Gas joint venture other than in accordance with the applicable security documents;

● acquisition of other companies;

● entering into joint ventures and other long-term cooperation with third parties;

● taking any action in respect of a significant contractual dispute, including commencement and defending any action or settling any dispute; and

● sale of the Neptune or the Cape Ann.

Höegh LNG, MOL and TLT made loans to each of the SRV Joint Gas joint ventures, in part to finance the operations of such joint ventures. In connection with the IPO, Höegh LNG’s shareholder loans to each of the joint ventures were transferred to our operating company. For a description of the shareholder loans, please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Loans Due to Owners (Shareholder Loans).”

Under the SRV Joint Gas shareholders’ agreement, the board of directors of an SRV Joint Gas joint venture is responsible for determining the amount of profits to be distributed each financial year. Distributions must first be used to repay the principal of the shareholder loans. Subsequent distributions are permitted but are subject to (i) preexisting financial agreements between such SRV Joint Gas joint venture and its lenders and (ii) prudent maintenance of reserve accounts.

Pursuant to the SRV Joint Gas shareholders’ agreement, in order for a party to transfer its shares, it must provide written notice and establish a fair price evaluation of the shares proposed to be transferred. Additionally, such party must permit the remaining parties (excluding TLT) to acquire such shares or sell their shares to the proposed transferor at the same price as the proposed transfer.

The SRV Joint Gas shareholders’ agreement also contemplates certain events that, upon occurrence and failure to cure, if a cure period is allowed, will give rise to a potential exchange of shares or a liquidation of such joint venture. These events include a party’s failure to make required payments, default in any material duties and/or obligations, insolvency and change of control, pursuant to which such party is acquired by a direct competitor. If one of these events occurs, we and our joint venture partners will attempt to exchange shares so that our operating company, on the one hand, will own 100% of one SRV Joint Gas joint venture, and MOL and TLT, on the other hand, will own 100% of the other SRV Joint Gas joint venture. If such an exchange cannot be agreed upon, then the party not in default, not insolvent or not undergoing a change of control may either purchase the shares and the shareholder loans from the other parties or demand termination of the SRV Joint Gas shareholders’ agreement and a liquidation of the applicable SRV Joint Gas joint venture.

Until the termination of the SRV Joint Gas shareholders’ agreement, Höegh LNG has agreed to continue to own common units representing a greater than 25% limited partner interest in us in the aggregate. In addition, Höegh LNG

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will be required to continue to directly or indirectly maintain the ability to control our general partner pursuant to an agreement with MOL.

The SRV Joint Gas shareholders’ agreement terminates when one party holds a 100% interest in the SRV Joint Gas joint ventures or a party not in default, not insolvent or not undergoing a change of control elects to terminate the agreement.

PT Höegh Shareholders’ Agreement

We own a 100% equity interest in Höegh Lampung, which owns a 49% equity interest in PT Höegh (the owner of the PGN FSRU Lampung). PT Bahtera, an Indonesian company established in February 2013, owns the remaining 51% equity interest in PT Höegh in order to comply with local Indonesian regulations. However, pursuant the Shareholders’ Agreement, dated March 13, 2013, between Höegh Lampung and PT Bahtera (“the PT Höegh shareholders’ agreement”) and the PT Höegh shareholder loan, we have a 100% economic interest in the PGN FSRU Lampung.

The board of directors of PT Höegh manages PT Höegh, whereas the board of commissioners of PT Höegh supervise the operation and management of PT Höegh. Both such board of directors and board of commissioners must consist of between three and five members. Furthermore, Höegh Lampung may appoint three members to each, whereas PT Bahtera may appoint one member. A majority of present members of the board of directors or the board of commissioners, respectively, is required to pass any resolution.

Höegh Lampung and PT Bahtera, in their capacity as shareholders, may also convene general meetings to consider resolutions. Resolutions concerning most matters require the approval of two-thirds of the issued shares for passage. However, resolutions concerning filing for bankruptcy, changes of control, disposal of certain assets or the creation of certain encumbrances require the approval of 75% of the issued shares for passage.

When deadlock (as defined below) occurs, Höegh Lampung has the right to provide notice to, and subsequently confer with, PT Bahtera to resolve the matters giving rise to deadlock. Deadlock occurs under the PT Höegh shareholders’ agreement if (i) a quorum is not present at a meeting of the board of directors of PT Höegh, the board of commissioners of PT Höegh or the shareholders as a result of the absence of PT Bahtera or (ii) any resolution proposed at a meeting of the board of directors of PT Höegh, the board of commissioners of PT Höegh and/or the shareholders of PT Höegh is approved by the directors appointed by Höegh Lampung, the commissioners appointed by Höegh Lampung or Höegh Lampung, as applicable, but is not passed.

The board of directors of PT Höegh is responsible for determining the amount of profits to be distributed each financial year. Once this determination is made, and prior to distributing net cash flow, the shares of Höegh Lampung are entitled to 65% of all dividends and distributions, and the shares of PT Bahtera are entitled to 35% of all dividends and distributions.

Höegh Lampung may transfer its shares in PT Höegh to anyone, subject only to the requirement that, upon the request of PT Bahtera, Höegh Lampung procures from the same transferee or an Indonesian entity an offer to purchase PT Bahtera’s shares. Conversely, PT Bahtera may transfer its shares only to an affiliate it wholly owns and only if both Höegh Lampung and any applicable lenders consent to the transfer.

At any time or in the event of a default, Höegh Lampung may require PT Bahtera to transfer its shares to Höegh Lampung or any other person it designates. Events of default only apply to PT Bahtera and occur if it fails to pay any amount due and payable under the shareholders’ agreement, becomes insolvent, materially breaches the shareholders’ agreement, becomes controlled by other people or breaches a financing requirement.

Additionally, in association with the PT Höegh shareholders’ agreement, PT Imeco Inter Sarana has guaranteed the performance and obligations of PT Bahtera. Furthermore, pursuant to the PT Höegh shareholders’ agreement, Höegh Lampung indemnifies PT Bahtera against liabilities it may suffer as a result of a breach of statutory duty or infringement of laws committed by PT Höegh, a failure by PT Höegh to pay tax, a dispute, litigation or arbitration relating to PT Höegh and all costs, losses, liabilities and claims relating to the PGN FSRU Lampung as a result of environmental damage.

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The PT Höegh shareholders’ agreement terminates when:

● all of the shareholders agree in writing that the agreement should be terminated;

● all of the issued shares in PT Höegh become directly or indirectly owned by the same person; or

● Höegh Lampung requires the other shareholders to dissolve PT Höegh. PT Imeco Inter Sarana has guaranteed the obligations of PT Bahtera under the equity loan agreement pursuant to a deed of guarantee and indemnity.

PT Höegh Shareholder Loan

PT Bahtera, as borrower, entered into an equity loan agreement with Höegh Lampung, as lender, the proceeds of which were used to purchase PT Bahtera’s 51% interest in PT Höegh. In connection with this loan, as security, PT Bahtera collaterally assigned its equity interest and any dividends it may receive from PT Höegh to Höegh Lampung for as long as amounts remain outstanding. As a result of the above and the PT Höegh shareholders’ agreement, we will be entitled to all of the net cash flows from PT Höegh, after the payment of management, agency and local representation fees.

Employees

Other than certain administrative staff in foreign subsidiaries, we do not have other direct employees and rely on the key employees of Höegh Norway who perform services for us pursuant to the administrative services agreement. Höegh Norway and Höegh LNG Management also provide commercial and technical management services to our fleet pursuant to ship management agreements, the Gallant management agreement, the Höegh Grace Services Agreements, a sub-technical support agreement and commercial and administration management agreements. Höegh Maritime Management also provides crew pursuant to a secondment agreement. Our crew may be employed by our or Höegh LNG’s subsidiaries. Please read “—Maritime Personnel and Competence Development” and “Item 6.A. Directors and Senior Management.”

Competition

The FSRU and LNG carrier industries are capital-intensive and operational expertise is critical, which create high barriers to entry. These industries are viewed as an integral part of the LNG industry. A company with a solid track record, knowledge of the market and an experienced, well-trained crew is preferred to a new entrant since the cost and impact of vessel downtime is significant for the customer. Our competitors in the FSRU sector include BW LNG, Dynagas Ltd, Excelerate Energy L.P., Golar LNG Limited, Golar LNG Partners LP, MOL and Maran Gas Maritime. Certain terminal operators have also ordered FSRUs directly from shipyards for specific projects. Our competitors in the LNG carrier universe is more diverse and, while we compete with this group when operating in LNG carrier mode, few have entered the FSRU market.

Classification, Inspection and Maintenance

Every large, commercial seagoing vessel must be “classed” by a classification society. The classification society certifies that the vessel is “in class,” signifying that the vessel has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of that particular class of vessel as laid down by that society and the applicable flag state. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake to conduct a survey on application or by official order, acting on behalf of the authorities concerned.

Our FSRUs are “classed” as LNG carriers with the additional class notation REGAS-2 signifying that the regasification installations are designed and approved for continuous operation. To ensure continuous compliance, regular and extraordinary surveys of hull and machinery, including the power plant and any special equipment classed, are required to be performed by a class surveyor. For inspection of the underwater parts and for repairs related to intermediate inspections, vessels generally are drydocked, pursuant to a drydock cycle determined by the classification society and the flag state concerned. However, with FSRUs, certain inspections can be done without drydocking, as special measures are available to inspect the underwater parts. If any defects are found, the class surveyor will issue a “recommendation” which must be rectified by the vessel owner within prescribed time limits. The classification society also undertakes

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other surveys on request of the flag state and checks that regulations and requirements of that flag state are complied with. These surveys are subject to agreements made for each individual survey and flag state concerned.

It is a condition for insurance coverage (i.e., the “seaworthiness” of the vessel) that the vessel is certified as “in class” with a member of the International Association of Classification Societies. Each of our vessels is certified by Det Norske Veritas GL, compliant with the ISM Code, and “in class.”

The ship manager carries out inspections of the ships on a regular basis; both at sea and while the vessels are in port, while the classification societies carry out inspections and ship audits to verify conformity with manager’s reports. The results of these inspections, which are conducted both in port and underway, are presented in a report containing recommendations for improvements to the overall condition of the vessel, maintenance, improvements to the safety and environmental protection system and to crew welfare. Among others, based on these evaluations, the ship manager creates and implements a program of continuous maintenance and improvement for its vessel and its systems.

Safety, Management of Ship Operations and Administration

Safety is a top priority. Our vessels are operated in a manner intended to protect the safety and health of employees, the general public and the environment. We actively manage the risks inherent in our business and are committed to eliminating incidents that threaten safety, such as groundings, collisions, loss of containment and fire. We are also committed to reducing emissions and waste generation. We have established key performance indicators to facilitate regular monitoring of our operational performance. We set targets on an annual basis to drive continuous improvement, and we review performance indicators monthly to determine if remedial action is necessary to reach our targets. Höegh LNG’s shore staff performs a full range of technical, commercial and business development services for us. This staff also provides administrative support to our operations in accounting, finance and cash management, legal, commercial insurance and general office administration and secretarial services.

Höegh LNG assists the vessel owners in managing ship operations and maintaining a technical department to monitor and audit ship manager operations. Höegh LNG hold its certifications for and works to the standards of ISO 9001 on Quality Management, ISO 14001 on Environmental Management and OHSAS 18001 Occupational Health and Safety Advisory Services. Additionally, Höegh LNG holds all compliance documents and permits needed to manage and operate LNG carriers and FSRUs. Through Det Norske Veritas GL, Höegh LNG Management has obtained approval of its safety management systems as being in compliance with the ISM Code, on behalf of the appropriate flag state for the vessels in our fleet, which are flagged in Norway or Indonesia. Our vessels’ safety management certificates are being maintained through ongoing internal audits performed by Höegh LNG Management and through intermediate audits performed by the flag states or recognized classification societies on its behalf. To supplement our operational experience, Höegh LNG provides expertise in various functions critical to our operations. This affords an efficient and cost-effective operation and, pursuant to commercial and administration management agreements with Höegh Norway and a technical information and services agreement with Höegh Norway, access to accounting, finance and cash management, legal, commercial insurance and general office administration and secretarial services. Critical ship management or technical support functions that will be provided by Höegh LNG Management through its various offices around the world include:

● technical management, maintenance and drydocking;

● crew management;

● procurement, purchasing and forwarding logistics;

● marine operations;

● oil major and terminal vetting compliance;

● shipyard supervision;

● insurance; and

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● financial services.

These functions are supported by onboard and onshore systems for maintenance, inventory, purchasing and budget management. In addition, Höegh LNG’s day-to-day focus on cost control will be applied to our operations. To some extent, the uniform design of some of our vessels and the adoption of common equipment standards should also result in operational efficiencies, including with respect to crew training and vessel management, equipment operation and repair and spare parts ordering.

Maritime Personnel and Competence Development

As of March 31, 2021, entities in the Höegh LNG group employed approximately 679 maritime personnel who serve on our and Höegh LNG’s vessels. The Scandinavian employees are employed by Höegh LNG Management. Non-Scandinavian employees, except for seafarers operating the PGN FSRU Lampung and the Höegh Grace, are employed by Höegh Maritime Management. The seafarers operating the PGN FSRU Lampung are employed by PT Höegh. The seafarers operating the Höegh Grace are employed by Höegh Colombia. Höegh LNG Management and Höegh Maritime Management will employ and train additional maritime personnel to assist us as we grow. Höegh LNG Management, the ISM-certified company, provides technical management services, including all necessary maritime personnel-related services, to the vessel owners pursuant to the ship management agreements. Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Support Agreement.”

We regard attracting and retaining competent and motivated seagoing personnel as a top priority. Like Höegh LNG, we offer our seafarers competitive employment packages and opportunities for personal and career development, which relates to a philosophy of promoting internally. The officers and crew operating our vessels are employed on individual employment contracts, which are based on International Transport Federation-Approved Collective Bargaining Agreements (CBAS) and include conditions determined both by the negotiating parties and the flag states. We believe our relationships with these labor unions are good. Höegh LNG currently is a member of the Norwegian Shipowners’ Association and is participating in some of the collective bargaining agreement negotiations with trade unions.

Our commitment to training is fundamental to the development of the highest caliber of seafarers for our marine operations. Höegh LNG Management’s cadet training approach is designed to balance academic learning with hands-on training at sea. Höegh LNG Management uses only recognized training institutions in Norway and other countries. Höegh LNG Management has cadets from Europe, Asia and the United States. We believe that high-quality crew and training policies will play an increasingly important role in distinguishing the preferred LNG-experienced independent shipping companies from those that are newcomers to LNG and lacking in-house experienced staff and established expertise on which to base their customer service and safety operations.

We will use in our operations Höegh LNG’s thorough risk management program that includes, among other things, computer-aided risk analysis tools, maintenance and assessment programs, a seafarers competence training program, seafarers workshops and membership in emergency response organizations. We expect to benefit from Höegh LNG’s commitment to safety and environmental protection as certain of its subsidiaries assist us in managing our vessel operations. Höegh LNG Management has been certified under the standards reflected in ISO 9001 for quality assurance and is certified in accordance with the International Marine Organization’s International Management Code for the Safe Operation of Ships and Pollution Prevention on a fully integrated basis.

Risk of Loss, Insurance and Risk Management

The operation of FSRUs, LNG carriers and other LNG infrastructure assets has inherent risks. These risks include mechanical failure, personal injury, collision, property loss, vessel or cargo loss or damage and business interruption due to political circumstances in foreign countries or hostilities. In addition, there is always an inherent possibility of marine disaster, including explosion, spills and other environmental mishaps, and the liabilities arising from owning and operating vessels in international trade. We believe that our present insurance coverage is adequate to protect us against the accident-related risks involved in the conduct of our business and that we maintain appropriate levels of environmental damage and pollution insurance coverage consistent with standard industry practice. However, not all risks can be insured, and there can be no guarantee that any specific claim will be paid, or that we will always be able to obtain adequate insurance coverage at reasonable rates.

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We have obtained hull and machinery insurance on all our vessels against marine risks, which include the risks of damage to our vessels, including claims arising from collisions with other vessels or contact with jetties or wharves, salvage or towing costs and also insure against actual or constructive total loss of any of our vessels. However, our insurance policies contain deductible amounts for which we will be responsible.

We have also obtained loss of hire insurance to protect us against loss of income in the event the vessel cannot be employed due to damage that is covered under the terms of our hull and machinery insurance. Under our loss of hire policy, our insurer will pay us the hire rate agreed in respect of each vessel for each day, in excess of 20 deductible days, for the time that the vessel is out of service as a result of damage, for a maximum of 180 days.

Protection and indemnity insurance, which covers our third-party legal liabilities in connection with our shipping activities, is provided by an approved P&I club. This includes third-party liability and other expenses related to the injury or death of crewmembers, passengers and other third-party persons, loss or damage to cargo and other damage to other third-party property, including pollution arising from oil or other substances, and other related costs, including wreck removal.

We have war risk insurance for all our vessels cover standard hull and machinery, protection and indemnity and loss of hire, if the event causing damage is a war peril. In addition, war risk insurance will also compensate the owner for loss of the ship caused by intervention of a foreign state power, or if the ship is prevented from leaving a port or similar limited area.

Our current protection and indemnity insurance coverage for all vessels is limited to $8.2 billion for all liabilities. For all vessels except PGN FSRU Lampung the limits set are $3 billion per incident. Limit for seafarers is $3 billion and limit for pollution is $1 billion per vessel per incident. For PGN FSRU Lampung each category of liability is limited to $500 million.

We are a member of the Gard P&I Club, which is among the 13 P&I clubs that comprise the International Group of P&I Clubs. Members of the International Group of P&I Clubs insure approximately 90% of the world’s commercial tonnage, and they have entered into a pooling agreement to reinsure each P&I club’s liabilities. Each P&I club provide the basic layer of insurance, which is currently $10 million. Members of the International Group of P&I Clubs provide the next layer of insurance, covering liability between $10 million and $100 million. For liabilities above $100 million, the International Group of P&I Clubs has one of the world’s largest reinsurance contracts, with the maximum liability per accident or occurrence currently set at $3 billion. As a member of the Gard P&I Club, we are subject to a call for additional premiums based on the club’s claims record, as well as the claims record of all other members of the P&I clubs comprising the International Group. However, our P&I club has reinsured the risk of additional premium calls to limit our additional exposure. This reinsurance is subject to a cap, and there is the risk that the full amount of the additional call would not be covered by this reinsurance

The insurers providing the covers for hull and machinery with interests and loss of hire have confirmed that they consider the FSRUs as conventional vessels for the purpose of providing insurance. For protection and indemnity insurance the same applies for all vessels except PNG FSRU Lampung which has a protection and indemnity insurance for mobile offshore units in order to incorporate the tower yoke mooring system.

Environmental and Other Regulation

General

Governmental and international agencies extensively regulate the carriage, handling, storage and regasification of LNG. These regulations include international conventions and national, state and local laws and regulations in the countries where our vessels now or, in the future, will operate or where our vessels are registered. We cannot predict the ultimate cost of complying with these regulations or the impact that these regulations will have on the resale value or useful lives of our vessels. Various governmental and quasi-governmental agencies require us to obtain permits, licenses and certificates for the operation of our vessels.

We believe that we are substantially in compliance with applicable environmental laws and regulations and have all permits, licenses and certificates required for our vessels. In many cases where permits are required from countries to whose jurisdictional waters our vessels have been deployed, the charter party or its customer is responsible for obtaining

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the permit. A variety of governmental and private entities inspect our vessels on both a scheduled and unscheduled basis. These entities, each of which may have unique requirements and each of which conducts frequent inspections, include classification societies, the flag state, or the administration of the country of registry, charterers, terminal operators, LNG producers and local port authorities, such as the U.S. Coast Guard, harbor master or equivalent. Our vessels are subject to inspections on an unscheduled basis and we expect, in the future, they will also be subject to inspection by the applicable governmental and private entities on a scheduled basis. However, future noncompliance or failure to maintain necessary permits or approvals could require us to incur substantial costs or temporarily suspend operation of one or more of our vessels.

Höegh LNG Management is operating in compliance with the ISO Environmental Standard for the management of the significant environmental aspects associated with the ownership and operation of a fleet of FSRUs and LNG carriers. Höegh Norway received its ISO 9001 certification (Quality Management Systems) in May 2008, which also includes certification of Höegh LNG Management. Höegh Norway also received its ISO 14001 Environmental Management Standard certification, which requires that we and Höegh LNG Management commit managerial resources to act on our environmental policy through an effective management system.

International Maritime Regulations of FSRUs and LNG Carriers

The IMO is the United Nations’ agency that provides international regulations governing shipping and international maritime trade. The requirements contained in the International Safety Management Code (“ISM Code”) promulgated by the IMO govern our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies. Höegh LNG hold a valid Document of Compliance (“DOC”) for each flag in the fleet; Norway (the Neptune, the Cape Ann and the Höegh Gallant), Marshall Islands (the Höegh Grace) and Indonesia (the PGN FRSU Lampung). Each DOC meets the requirements of the IMO.

Vessels that transport gas, including FSRUs and LNG carriers, are also subject to regulation under the International Gas Carrier Code (the “IGC Code”), published by the IMO. The IGC Code provides a standard for the safe carriage of LNG and certain other liquid gases by prescribing the design and construction standards of vessels involved in such carriage. Compliance with the IGC Code must be evidenced by a Certificate of Fitness for the Carriage of Liquefied Gases in Bulk. Each of our vessels is in compliance with the IGC Code, and each of our newbuildings contracts requires that the vessel receive certification of compliance with applicable regulations before she is delivered. Noncompliance with the IGC Code or other applicable IMO regulations may subject a vessel owner or a bareboat charterer to increased liability, 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.

The IMO also promulgates ongoing amendments to SOLAS. SOLAS 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 watchkeeping standard, afloat and at shore stations, and relates to the Treaty on the Standards of Training and Certification of Watchkeeping Officers (“STCW”), also promulgated by the IMO. Flag states that have ratified SOLAS and STCW generally employ the classification societies, which have incorporated SOLAS and STCW requirements into their class rules, to undertake surveys to confirm compliance.

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. Noncompliance with these types of IMO regulations may subject us 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. For example, the U.S. Coast Guard and European Union authorities have indicated that vessels not in compliance with the ISM Code are prohibited from trading in U.S. and European Union ports.

In 2017, the IMO's Maritime Safety Committee ("MSC") adopted Resolution MSC.428(98), Maritime Cyber Risk Management in Safety Management Systems, embracing guidelines on maritime cyber risk management approved by the MSC. This resolution affirmed the MSC's view that the ISM Code requires mitigation of cyber risk as part of the safety management system, and effectively provides that a vessel's safety management system must account for cyber

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risks in compliance with the ISM Code no later than the vessel's first annual compliance verification after January 1, 2021.

In the wake of increased worldwide security concerns, the IMO amended SOLAS and added the ISPS Code as a new chapter to that convention. The objective of the ISPS Code, which came into effect on July 1, 2004, is to detect security threats and take preventive measures against security incidents affecting ships or port facilities. Höegh LNG Management has developed Security Plans and appointed and trained Ship and Office Security Officers, and all of our vessels have been certified to meet the ISPS Code. Please read “—Vessel Security Regulations” for a more detailed discussion about these requirements.

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 regulations may have on our operations.

Air Emissions

The MARPOL Convention is the principal international convention negotiated by the IMO governing marine pollution prevention and response. The MARPOL Convention imposes environmental standards on the shipping industry relating to oil spills, management of garbage, the handling and disposal of noxious liquids, sewage and air emissions. MARPOL 73/78 Annex VI “Regulations for the Prevention of Air Pollution” (“Annex VI”) entered into force on May 19, 2005, and applies to all ships, fixed and floating drilling rigs and other floating platforms. Annex VI sets limits on sulfur oxide and nitrogen oxide emissions from ship exhausts, emissions of volatile compounds from cargo tanks and incineration of specific substances and prohibits deliberate emissions of ozone-depleting substances. Annex VI also includes a global cap on sulfur content of fuel oil and allows for special areas to be established in different regions of the world with more stringent controls on sulfur emissions. The certification requirements for Annex VI depend on size of the vessel and time of periodical classification survey. Ships weighing more than 400 gross tons and engaged in international voyages involving countries that have ratified the conventions, or ships flying the flag of those countries, are required to have an International Air Pollution Certificate (an “IAPP Certificate”). Annex VI came into force in the United States on January 8, 2009. All of our vessels currently have IAPP Certificates.

Annex I to the MARPOL Convention applies to various ships delivered on or after August 1, 2010. It includes requirements for the protected location of the fuel tanks, performance standards for accidental oil fuel outflow, a tank capacity limit and certain other maintenance, inspection and engineering standards. IMO regulations also require owners and operators of vessels to adopt Ship Oil Pollution Emergency Plans. Periodic training and drills for response personnel and for vessels and their crews are required.

On July 1, 2010, amendments to Annex VI took effect that impose progressively stricter limitations on sulfur oxide (SOx) emissions from ships. As of January 1, 2020, the ultimate limit of 0.5% sulfur content for fuel used to power ships outside of the the four designated Emission Control Areas (“ECAs”) for SOx took effect. Pursuant to Annex VI Regulation 14, for fuels used in the four ECAs, i.e., the Baltic Sea, North Sea, North America, and United States Caribbean Sea ECAs, the cap settled at 0.1% in January 2015. The 0.5% sulfur cap is generally referred to IMO 2020 and applies absent the installation of expensive sulfur scrubbers to meet reduced emission requirements for sulfur. The European Directive 2005/33/EU, which came into effect January 1, 2010, bans the use of fuel oils containing more than 0.1% sulfur by mass by any merchant vessel while at berth or anchored in any European Union country port. Our FSRUs have achieved compliance with applicable low sulfur fuel requirements through use of gas boil-off and low sulfur marine diesel oil in their diesel generators and boilers.

MARPOL Annex VI regulations also establish progressively more stringent standards for emissions of nitrogen oxides (NOx) from new and certain modified marine engines, depending on their date of installation or the date of ship construction. Engine standards required under Annex VI to limit NOx emissions in designated areas are referred to as "Tier III" controls. Pursuant to amendments adopted in April 2014, the Tier III Annex VI requirements for NOx apply to certain newbuild vessels with marine diesel engines constructed on or after January 1, 2016, and that operate in the North American or United States Caribbean Sea NOx Tier III ECAs. And, pursuant to amendments adopted in July 2017 and entered into force on January 1, 2019, the Baltic Sea and North Sea ECAs have been designated as NOx Tier III ECAs, with NOx Tier III Annex VI requirements applying to certain newbuild vessels with marine diesel engines constructed on or after January 1, 2021 that operate in the Baltic Sea or North Sea NOx Tier III ECAs.

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As discussed in “—U.S. Clean Air Act” below, U.S. air emissions standards are now equivalent to these amended Annex VI requirements. Additional or new conventions, laws and regulations may be adopted in the future and could require the installation of emission control systems. Because our vessels are largely powered by means other than fuel oil we do not anticipate that any emission limits that may be promulgated will require us to incur any material costs for the operation of our vessels but that possibility cannot be eliminated.

Ballast Water Management Convention

The IMO has negotiated international conventions that impose liability for oil pollution in international waters and the territorial waters of the signatory to such conventions. For example, the IMO adopted an International Convention for the Control and Management of Ships’ Ballast Water and Sediments (the “BWM Convention”) in February 2004. The BWM Convention’s implementing regulations call for a phased introduction of mandatory ballast water exchange requirements, which is being replaced with a requirement for treatment. The BWM Convention was ratified by a sufficient number of countries in September 2016 and the requirement to install ballast water management systems (“BWMS”) on new ships became effective in September 2017. As referenced below, the U.S. Coast Guard issued ballast water management rules on March 23, 2012, and the U.S. Environmental Protection Agency (the “EPA”) issued a five-year Vessel General Permit (VGP) in March 2013 that contains numeric technology-based ballast water effluent limitations that apply to certain commercial vessels with ballast water tanks. The VPG program is in the process of being phased out and replaced with National Standards of Performance (NSP) to be developed by EPA and implemented and enforced by the U.S. Coast Guard. From 2016 (or not later than the first intermediate or renewal survey after 2016), only ballast water treatment will be accepted by the BWM Convention. Because the convention has been ratified and entered into force, installation of approved ballast water treatment systems will be required on the Neptune and the Cape Ann in order to call on US ports. The Neptune would require retrofitting to meet the BWMS requirements no later than November 30, 2022 based on the drydock schedule. The Cape Ann was not retrofitted to meet the BWMS requirements during the drydock in 2018 and, therefore, cannot call on US ports. The charterer would cover the cost of complying with the rules and, therefore, makes the decision on whether retrofit to meet the BWMS requirements based upon their plans for the use of the vessels.

Bunkers Convention/CLC State Certificate

The International Convention on Civil Liability for Bunker Oil Pollution 2001 (the “Bunker Convention”) entered into force in signatory states to the Convention on November 21, 2008. The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. The Bunker Convention requires the vessel owner that is liable for pollution damage to pay compensation for such damage (including the cost of preventive measures) caused in the territory, including the territorial sea of a State Party, as well as its economic zone or equivalent area. Registered owners of any seagoing vessel and seaborne craft over 1,000 gross tonnage, of any type whatsoever, and registered in a State Party, or entering or leaving a port in the territory of a State Party, are required to maintain insurance that meets the requirements of the Bunker Convention and to obtain a certificate issued by a State Party attesting that such insurance is in force. The State Party-issued certificate must be carried onboard at all times. The Bunker Convention complements the international regime of liability, limitation and mandatory insurance in place with respect to spills of persistent oils from tankers under the International Convention on Civil Liability for Oil Pollution Damage, 1992 (CLC). The CLC and the Bunker Convention do not overlap; in circumstances where the CLC applies, the Bunker Convention does not apply.

P&I clubs in the International Group issue the required Bunkers Convention “Blue Cards” to enable signatory states to issue certificates. All of our vessels have received “Blue Cards” from their P&I club and are in possession of a CLC State-issued certificate attesting that the required insurance coverage is in force.

Anti-Fouling Requirements

In 2001, the IMO adopted the International Convention on the Control of Harmful Anti-fouling Systems on Ships (the “Anti-fouling Convention”). The Anti-fouling Convention, which entered into force on September 17, 2008, prohibits the use of organotin compounds in coatings applied to vessels to prevent the attachment of mollusks and other sea life to the hulls of vessels and establishes a mechanism to prevent the potential future use of other harmful substances in anti-fouling systems. Vessels of over 400 gross tons engaged in international voyages must obtain an International Anti-fouling System Certificate and undergo a survey before the vessel is put into service or when the anti-fouling systems are

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altered or replaced. We have obtained Anti-fouling System Certificates for all of our vessels, and we do not believe that actions required to maintain such certificates will have an adverse financial impact on the operation of our vessels.

Compliance Enforcement

The flag state, as defined by the United Nations Convention on Law of the Sea, has overall responsibility for the implementation and enforcement of international maritime regulations for all ships granted the right to fly its flag. The “Shipping Industry Guidelines on Flag State Performance” evaluates flag states based on factors such as sufficiency of infrastructure, ratification of international maritime treaties, implementation and enforcement of international maritime regulations, supervision of surveys, casualty investigations and participation at the IMO meetings.

As of January 2016, auditing of flag states that are parties to the SOLAS convention is mandatory and are conducted under the IMO Instruments Implementation Code (III Code), which provides guidance on implementation and enforcement of IMO policies by flag states. These audits may lead the various flag states to be more aggressive in their enforcement, which may in turn lead us to incur additional costs.

Criminal sanctions including fines and penalties and possible charges against company employees are possible under the laws of various countries. For instance, the European Union directive on ship source pollution imposes criminal sanctions for intentional, reckless or negligent pollution discharges by ships. Implementing laws in the EU could result in criminal liability for pollution from vessels in waters of European countries that adopt implementation legislation. Criminal liability for pollution may result in substantial penalties or fines and increased civil liability claims. Similar consequences are possible for spills in other countries that have enacted similar laws.

U.S. Environmental Regulation of FSRUs and LNG Carriers

Our vessels operating in U.S. waters now or, in the future, will be subject to various federal, state and local laws and regulations relating to protection of the environment. In some cases, these laws and regulations require governmental permits and authorizations before we may conduct certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution that occurs. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, increases our overall cost of business.

Oil Pollution Act and CERCLA

OPA 90 established an extensive regulatory and liability regime for environmental protection and clean-up of oil spills. OPA 90 affects all owners and operators whose vessels trade with the United States or its territories or possessions, or whose vessels operate in the waters of the United States, which include the U.S. territorial waters and the 200 nautical mile exclusive economic zone of the United States. CERCLA applies to the discharge of hazardous substances, rather than oil, whether on land or at sea. While OPA 90 and CERCLA would not apply to the discharge of LNG, they may affect us because we carry oil as fuel and lubricants for our engines, and the discharge of these could cause an environmental hazard and subject us to liability under these laws. Under OPA 90, vessel operators, including vessel owners, managers and bareboat or “demise” charterers, are “responsible parties” who are all liable regardless of fault, individually and as a group, for all containment and clean-up costs and other damages arising from oil spills from their vessels. These “responsible parties” would not be liable if the spill results solely from the act or omission of a third party, an act of God or an act of war. The other damages aside from clean-up and containment costs are defined broadly to include:

● natural resource damages and related assessment costs;

● real and personal property damages;

● net loss of taxes, royalties, rents, profits or earnings capacity;

● net cost of public services necessitated by a spill response, such as protection from fire, safety or health hazards; and

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● loss of subsistence use of natural resources.

Effective as of November 12, 2019, the U.S. Coast Guard adjusted the limits of OPA 90 liability to the greater of $2,300 per gross ton or $19,943,400 for any double-hull tanker that is over 3,000 gross tons (subject to possible adjustment for inflation) (relevant to our and Höegh LNG’s vessels). The liability limits are subject to possible further adjustment for inflation in the future. These limits of liability do not apply where the incident is caused by violation of applicable U.S. federal safety, construction or operating regulations, or by the responsible party’s gross negligence or willful misconduct. These limits likewise do not apply if the responsible party fails or refuses to report the incident or to cooperate and assist in connection with the substance removal activities. OPA 90 specifically permits individual states to impose their own liability regimes with regard to oil pollution incidents occurring within their boundaries, and some states have enacted legislation providing for unlimited liability for discharge of pollutants within their waters. In some cases, states, which have enacted their own legislation, have not yet issued implementing regulations defining vessel owners’ responsibilities under these laws.

CERCLA, which also applies to owners and operators of vessels, contains a liability regime similar to OPA 90 and provides for cleanup, removal and natural resource damages for releases of “hazardous substances.” Liability under CERCLA is limited to the greater of $300 per gross ton or $0.5 million for each release from vessels not carrying hazardous substances as cargo or residue, and $300 per gross ton or $5 million for each release from vessels carrying hazardous substances as cargo or residue. As with OPA 90, these limits of liability do not apply where the incident is caused by violation of applicable U.S. federal safety, construction or operating regulations, by the responsible party’s gross negligence or willful misconduct or if the responsible party fails or refuses to report the incident or to cooperate and assist in connection with the substance removal activities. OPA 90 and CERCLA each preserve the right to recover damages under existing law, including maritime tort law. We believe that we are in substantial compliance with OPA 90, CERCLA and all applicable state regulations in the ports where our vessels call.

OPA 90 requires owners and operators of vessels to establish and maintain with the U.S. Coast Guard evidence of financial responsibility sufficient to meet the limit of their potential strict liability under OPA 90/CERCLA. Under the regulations, evidence of financial responsibility may be demonstrated by insurance, surety bond, self-insurance or guaranty. Under OPA 90 regulations, an owner or operator of more than one vessel is required to demonstrate evidence of financial responsibility for the entire fleet in an amount equal only to the financial responsibility requirement of the vessel having the greatest maximum liability under OPA 90/CERCLA. We currently maintain U.S. Coast Guard National Pollution Funds Center-issued three-year Certificates of Financial Responsibility supported by guarantees that we purchased from an insurance-based provider for all of our vessels.

Compliance with any new requirements of OPA 90 or other laws and regulations relating to oil spill liability may substantially impact our cost of operations or require us to incur additional expenses to comply with any new regulatory initiatives or statutes. Additional legislation or regulation applicable to the operation of our vessels that may be implemented in the future could adversely affect our business and ability to make cash distributions to our unitholders.

U.S. Clean Water Act

The CWA prohibits the discharge of oil or hazardous substances in U.S. navigable waters unless authorized by a permit or exemption and imposes strict liability in the form of penalties for unauthorized discharges. The CWA also imposes substantial liability for the costs of removal, remediation and damages and complements the remedies available under OPA 90 and CERCLA. The EPA has enacted rules governing the regulation of ballast water discharges and other discharges incidental to the normal operation of vessels within U.S. waters. The rules historically have required commercial vessels 79 feet in length or longer (other than commercial fishing vessels) (“Regulated Vessels”) to obtain a CWA permit regulating and authorizing such normal discharges. This permit, which the EPA has designated as the Vessel General Permit for Discharges Incidental to the Normal Operation of Vessels (the “VGP”), incorporated the current U.S. Coast Guard requirements for ballast water management, as well as supplemental ballast water requirements including limits applicable to 26 specific discharge streams, such as deck runoff, bilge water and gray water. For each discharge type, among other things, the VGP establishes effluent limits pertaining to the constituents found in the effluent, including best management practices (the “BMPs”) designed to decrease the amount of constituents entering the waste stream. Unlike land-based discharges, which are deemed acceptable by meeting certain EPA-imposed numerical effluent limits, each of the 26 VGP discharge limits is deemed to be met when a Regulated Vessel carries out the BMPs pertinent to that specific discharge stream. The VGP imposes additional requirements on certain Regulated

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Vessel types that emit discharges unique to those vessels. Administrative provisions, such as inspection, monitoring, recordkeeping and reporting requirements, are also included for all Regulated Vessels.

In December 2018, the Vessel Incidental Discharge Act ("VIDA") was signed into law and restructured the EPA and the U.S. Coast Guard programs for regulating incidental discharges from vessels. Rather than requiring CWA permits, the discharges will be regulated under a new CWA Section 312(p) establishing Uniform National Standards for Discharges Incidental to Normal Operation of Vessels. Under VIDA, VGP provisions and existing U.S. Coast Guard regulations will be phased out over a period of approximately four years from December 2018 and replaced with National Standards of Performance (NSPs) to be developed by EPA and implemented and enforced by the U.S. Coast Guard. On October 26, 2020, EPA issued proposed regulations to establish NSPs, including general discharge standards of performance, covering general operation and maintenance, biofouling management, and oil management, and specific discharge standards applicable to specified pieces of equipment and systems. The scheduled expiration date of the 2013 VGP was December 18, 2018, but under VIDA the provisions of the VGP will remain in place until the new regulations are in place.

In addition to the requirements in the VGP (to be replaced by the NSPs established under VIDA), vessel owners and operators must potentially meet 25 sets of state-specific requirements under the CWA’s § 401 certification process. Because the CWA § 401 process allows tribes and states to impose their own requirements for vessels operating within their waters, vessels operating in multiple jurisdictions could face potentially conflicting conditions specific to each jurisdiction that they travel through.

U.S. Ballast Water Regulation

In the United States, two federal agencies regulate ballast water discharges, the EPA, currently through the VGP, and the U.S. Coast Guard, through approved BWMS. The 2013 VGP includes numeric effluent limits for ballast water expressed as the maximum concentration of living organisms in ballast water, as opposed to the current BMPs requirements. The 2013 VGP also imposes a variety of changes for non-ballast water discharges including more stringent BMPs for discharges of oil-to-sea interfaces in an effort to reduce the toxicity of oil leaked into U.S. waters. For certain existing vessels, the EPA adopted a staggered implementation schedule to require vessels to meet the ballast water effluent limitations by the first drydocking after January 1, 2014 or January 1, 2016, depending on the vessel size. Vessels that are constructed after December 1, 2013 became subject to the ballast water numeric effluent limitations immediately upon the 2013 VGP effective date.

On June 20, 2012, the final rule issued by the U.S. Coast Guard establishing standards for the allowable concentration of living organisms in ballast water discharged in U.S. waters and requiring the phase-in of U.S. Coast Guard-approved BWMS went into effect. The final rule adopts ballast water discharge standards for vessels calling on U.S. ports and intending to discharge ballast water equivalent to those set in the BWM Convention. The final rule requires that ballast water discharge have fewer than 10 living organisms per milliliter for organisms between 10 and 50 micrometers in size. For organisms larger than 50 micrometers, the discharge must have fewer than 10 living organisms per cbm of discharge. The rule requires installation of U.S. Coast-Guard approved BWMS by new vessels constructed on or after December 1, 2013 and existing vessels as of their first drydocking after January 1, 2016. The rule also provides for the use of an interim alternative management system ("AMS"), which is a BWMS approved pursuant to the BWM Convention standards by a foreign administration and determined by the U.S. Coast Guard to be at least as effective as ballast water exchange. AMSs can be used for up to five years following the compliance date for a vessel. Effective February 2016, the U.S. Coast Guard amended ballast water management recordkeeping requirements to require. Effective February 22, 2016, vessels with ballast tanks operating exclusively on voyages between ports or places within a single Captain of the Port zone to submit an annual report of their ballast water management practices.

As discussed above, under VIDA, existing U.S. Coast Guard ballast water management regulations will be phased out over a period of approximately four years from December 2018 and replaced with NSPs to be developed by EPA and implemented and enforced by the U.S. Coast Guard.

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U.S. Clean Air Act

The U.S. Clean Air Act of 1970, as amended, requires the EPA to promulgate standards applicable to emissions of volatile organic compounds and other air contaminants. Our vessels are subject to vapor control and recovery requirements for certain cargoes when loading, unloading, ballasting, cleaning and conducting other operations in regulated port areas and emission standards for so-called “Category 3” marine diesel engines operating in U.S. waters. The marine diesel engine emission standards are currently limited to new engines beginning with the 2004 model year. On April 30, 2010, the EPA promulgated final emission standards for Category 3 marine diesel engines equivalent to those adopted in the amendments to Annex VI. These emission standards require an 80% reduction in nitrogen dioxides for newly-built engines effective January 1, 2016. Aligned with the Annex VI Regulation 14 requirements, as of January 2015, the EPA emission standards also limit sulfur content in fuel used in Category 3 marine vessels operating in the North American ECA to 1,000 ppm (or 0.1% sulfur by mass). Compliance with EPA standards may cause us to incur costs to install control equipment on our vessels in the future.

Regulation of Greenhouse Gas Emissions

Pursuant to the Kyoto Protocol, which entered into force in 2005, adopting countries were required to implement national programs to reduce emissions of greenhouse gases. The emissions of greenhouse gases from international transport were not subject to the Kyoto Protocol. The Paris Agreement, which entered into force in November 2016 and replaces the Kyoto Protocol, similarly does not cover international shipping. However, to the extent that individual countries increase their regulation of domestic greenhouse gas emissions as a result of the Paris Agreement, we may experience increased regulation of greenhouse gas emissions resulting from regasification activities.

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The European Commission is pursuing a strategy to integrate maritime emissions into the overall European Union strategy to reduce greenhouse gas emissions. In accordance with this strategy, in April 2015 the European Parliament and Council adopted regulations requiring large vessels using European Union ports to monitor, report and verify their carbon dioxide emissions beginning in January 2018. On January 1, 2013, the IMO’s approved mandatory measures to reduce emissions of greenhouse gases from international shipping went into force. These include amendments to Annex VI for the prevention of air pollution from ships adding a new Chapter 4 to Annex VI on energy efficiency requiring the Energy Efficiency Design Index (the “EEDI”) for new ships, and the Ship Energy Efficiency Management Plan (the “SEEMP”) for all ships. Other amendments to Annex VI add new definitions and requirements for survey and certification, including the format for the International Energy Efficiency Certificate. The regulations apply to all ships of 400 gross tonnage and above. The IMO also adopted a mandatory requirement in October 2016 that ships of 5,000 gross tonnage and above record and report their fuel oil consumption. The requirement entered into force in March 2018. These rules will likely affect the operations of vessels that are registered in countries that are signatories to Annex VI or vessels that call upon ports located within such countries. In November 2020, the MEPC adopted further amendments to MARPOL Annex VI intended to significantly strengthen the EEDI “phase 3” requirements. These amendments accelerate the entry into effect date of phase 3 from 2025 to 2022 for several ship types, including gas carriers, general cargo ships and LNG carriers and require new ships built from that date to be significantly more energy efficient. The MEPC also is looking into the possible introduction of a phase 4 of EEDI requirements. The implementation of the EEDI and the SEEMP standards could cause us to incur additional compliance costs. The IMO has reaffirmed its strong commitment to work to address greenhouse gas emissions from ships engaged in international trade. At the October 2016 Marine Environmental Protection Committee (the "MEPC") session, the IMO adopted a roadmap for developing a comprehensive IMO strategy on reduction of GHG emissions. In April 2018, the MEPC adopted an initial strategy designed to reduce the emission of greenhouse gases from vessels, including short-term, mid-term and long-term candidate measures with a vision of reducing and phasing out greenhouse gas emissions from vessels as soon as possible in the 21^st Century. The mid-term measures under consideration by IMO include the development of a market-based mechanism for greenhouse gas emissions from ships, but it is impossible to predict the likelihood that such a standard might be adopted or the potential impact of this or other IMO measures under consideration on our future operations at this time. According to the “Roadmap” approved by IMO Member States in 2016, the initial strategy is due to be revised by 2023. In November 2020, the MEPC agreed to draft amendments to MARPOL Annex VI establishing an enforceable regulatory framework to reduce GHG emissions from international shipping, consisting of technical and operational carbon reduction measures. These measures include use of an Energy Efficiency Existing Ship Index ("EEXI"), an operational Carbon Intensity Indicator ("CII") and an enhanced SEEMP to drive carbon intensity reductions. A vessel's attained EEXI would be calculated in accordance with values established based on type and size category, which compares the vessels' energy efficiency to a baseline. A vessel would then be required to meet a specific EEXI based on a required reduction factor expressed as a percentage relative to the EEDI baseline. Under the draft MARPOL VI amendments, vessels with a gross tonnage of 5,000 or greater must determine their required annual operational CII and their annual carbon intensity reduction factor needed to ensure continuous improvement of the vessel's CII. On an annual basis, the actual annual operational CII achieved would be documented and verified against the vessel's required annual operational CII to determine the vessel's operational carbon intensity rating on a performance level scale of A (major superior) to E (inferior). The performance level would be required to be recorded in the vessel's SEEMP. A vessel with an E rating, or three consecutive years of a D (minor inferior) rating, would be required to submit a corrective action plan showing how the vessel would achieve a C (moderate) rating. This regulatory approach is consistent with the IMO GHG Strategy target of a 40% carbon intensity reduction for international shipping by 2030, as compared to 2008. The draft MARPOL Annex VI amendments will be proposed for formal adoption at the 2021MEPC session and, if adopted, are expected to enter into force on January 1, 2023. The EU has indicated that it intends to implement regulation in an effort to limit emissions of greenhouse gases from vessels if such emissions are not regulated through the IMO. On September 15, 2020, the European Parliament approved draft legislation, which has not yet been finalized, that would include GHG emissions from large vessels in the EU emissions trading system as of January 1, 2022 and include methane emissions in monitoring, reporting and verification requirements applicable to vessels. The European Parliament has also called for binding carbon dioxide reduction targets for shipping companies, which would require reduction of annual average carbon dioxide emissions of all ships during operation by at least 40% by 2030 as compared to 2018 levels.

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In the United States, the EPA issued a final finding that greenhouse gases threaten public health and safety and has promulgated regulations that regulate the emission of greenhouse gases, but not from ships. The EPA may decide in the future to regulate greenhouse gas emissions from ships and has already been petitioned by the California Attorney General to regulate greenhouse gas emissions from oceangoing vessels. Other federal and state regulations relating to the control of greenhouse gas emissions may follow, including climate change initiatives that have been considered from time to time by the U.S. Congress. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries where we operate, or any treaty adopted at the international level, that restrict emissions of greenhouse gases could require us to make significant financial expenditures that we cannot predict with certainty at this time. In addition, even without such regulation, our business may be indirectly affected to the extent that climate change results in sea level changes or more intense weather events.

Vessel Security Regulations

Since the terrorist attacks of September 11, 2001, there have been a variety of initiatives intended to enhance vessel security. On November 25, 2002, the Maritime Transportation Act of 2002 (the “MTSA”) came into effect. To implement certain portions of the MTSA, in July 2003, the U.S. Coast Guard issued regulations requiring the implementation of certain security requirements aboard vessels operating in waters subject to the jurisdiction of the United States. Similarly, in December 2002, amendments to SOLAS created a new chapter of the convention dealing specifically with maritime security. The new chapter became effective in July 2004 and imposed various detailed security obligations on vessels and port authorities, most of which are contained in the ISPS Code. The ISPS Code is designed to protect ports and international shipping against terrorism. Since July 1, 2004, to trade internationally, a vessel must obtain an International Ship Security Certificate (an “ISSC”) from a recognized security organization approved by the vessel’s flag state.

Among the various requirements are:

● onboard installation of automatic identification systems to provide a means for the automatic transmission of safety-related information from among similarly equipped ships and shore stations, including information on a ship’s identity, position, course, speed and navigational status;

● onboard installation of ship security alert systems, which do not sound on the vessel but only alert the authorities onshore;

● the development of vessel security plans;

● ship identification number to be permanently marked on a vessel’s hull;

● a continuous synopsis record kept onboard showing a vessel’s history, including the name of the ship, the state whose flag the ship is entitled to fly, the date on which the ship was registered with that state, the ship’s identification number, the port at which the ship is registered and the name of the registered owner(s) and their registered address; and

● compliance with flag state security certification requirements.

The U.S. Coast Guard regulations, intended to align with international maritime security standards, exempt non-U.S. vessels from obtaining U.S. Coast Guard-approved MTSA vessel security plans provided such vessels have onboard an ISSC that attests to the vessel’s compliance with SOLAS security requirements and the ISPS Code.

Our ship manager has developed Security Plans and appointed and trained Ship and Office Security Officers, and each of the vessels in our fleet complies with the requirements of the ISPS Code, SOLAS and the MTSA.

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Other Regulations

International Conventions

Our vessels may also become subject to the 2010 HNS Convention, if it is adopted by a sufficient number of countries. At least 12 states must ratify or accede to the 2010 HNS Protocol for it to enter into effect. In July 2019, South Africa became the 5th state to ratify the protocol. At least 7 more states must ratify or accede to the protocol for it to enter into effect. The Convention creates a regime of liability and compensation for damage from hazardous and noxious substances (“HNS”), including liquefied gases. The 2010 HNS Convention sets up a two-tier system of compensation composed of compulsory insurance taken out by vessel owners and an HNS Fund which comes into play when the insurance is insufficient to satisfy a claim or does not cover the incident. Under the 2010 HNS Convention, if damage is caused by bulk HNS, claims for compensation will first be sought from the vessel owner up to a maximum of 100 million from the supplementary foreign exchange reserve assets defined and maintained by the International Monetary Fund called Special Drawing Rights (“SDR”). If the damage is caused by packaged HNS or by both bulk and packaged HNS, the maximum liability is 115 million SDR. Once the limit is reached, compensation will be paid from the HNS Fund up to a maximum of 250 million SDR. The 2010 HNS Convention has not been ratified by a sufficient number of countries to enter into force, and we cannot estimate the costs that may be needed to comply with any such requirements that may be adopted with any certainty at this time.

Indonesia Environmental Regulation of FSRUs

In Indonesia, the environmental requirements of downstream business activity for the gas industry are regulated and supervised by the Government of Indonesia and controlled through business and technical licenses issued by the Minister of Energy and Mineral Resources and BPH Migas, the regulatory agency for downstream oil and gas activity. Under Law 22, the Government of Indonesia has the exclusive rights to gas exploitation and activities carried out by private entities based on government-issued licenses. Companies engaging in downstream activities must comply with environmental management and occupational health and safety provisions related to operations. This includes obtaining environmental licenses and conducting environmental monitoring and reporting for activities that may have an impact on the environment such as the environmental impact assessment required under Law No. 32 of 2009 regarding Environmental Protection and Management. Failure to comply with these laws and obtain the necessary business and technical licenses may subject us to sanctions including suspension and/or freezing of the business and responsibility for all damages arising from any violation. We believe we are currently in compliance with these laws and hold all applicable licenses. However, these laws are subject to change, and we cannot predict any future changes in the regulatory environment, which could result in increased costs to our business.

Colombia Environmental Regulation of FSRUs

While Colombia has a comprehensive suite of environmental regulations, there are currently no regulatory requirements specific to activities associated with the importation of LNG. In 2011, the Energy and Gas Regulatory Commission passed Resolution 106, which recognized that Colombia’s demand for natural gas could be met through LNG imports and proposed technical requirements for, among other things, the construction of LNG import plants. The Mines and Energy Ministry in 2015 subsequently proposed a resolution regarding those technical requirements, but it has not yet passed the resolution. In the meantime, we have obtained a port concession from the Colombian National Infrastructure Agency, as well as an environmental license from the National Authority for Environmental Licenses, each with respect to the FSRU Höegh Grace. Our operations in Colombia may also be subject to other permits to be issued by various entities, including the General Maritime Director of the Ministry of Defense.

We are unable to predict the impacts that any Colombian regulations will have on our business. The adoption of national and local laws or regulations and additional international treaties or conventions could materially increase our costs of operation and materially impact our ability to operate in Colombian waters.

In-House Inspections

Höegh LNG Management, our ship manager, regularly inspects our vessels for compliance with laws of host countries; both at sea and while in port. We also inspect and audit our vessels regularly to verify conformity with manager’s reports. These inspections result in a report containing recommendations for improvements to the overall condition of the vessel, maintenance, safety and crew welfare. Based in part on these evaluations, we create and implement a program of continual maintenance for our vessels and their systems.

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Taxation of the Partnership

The following are discussions of the material tax considerations applicable to us under U.S., Marshall Islands, Norway, Singapore, Indonesia, Cyprus, Egypt, and Columbia, respectively. These discussions are based upon provisions of the applicable tax law as in effect on the date of this Annual Report, regulations and current administrative rulings and court decisions, all of which are subject to change or differing interpretation, possibly with retroactive effect. Changes in these authorities or their interpretation may cause the tax consequences to vary substantially from the consequences described below.

United States Taxation

The following is a discussion of the material U.S. federal income tax considerations applicable to us. This discussion is based upon provisions of the Code as in effect on the date of this Annual Report, existing final and temporary Treasury Regulations thereunder, and current administrative rulings and court decisions, all of which are subject to change or differing interpretation, possibly with retroactive effect. Changes in these authorities or their interpretation may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the U.S. federal income tax considerations applicable to us.

Election to be Treated as a Corporation

We have elected to be treated as a corporation for U.S. federal income tax purposes. As such, we are subject to U.S. federal income tax to the extent we earn income from U.S. sources or income that is treated as effectively connected with the conduct of a trade or business in the United States, unless such income is exempt from tax under Section 883 of the Code or otherwise.

Taxation of Operating Income

Substantially all of our gross income is attributable, and we expect it will continue to be attributable, to the transportation, regasification and storage of LNG. Gross income generated from regasification and storage of LNG outside of the United States generally is not subject to U.S. federal income tax, and gross income generated from such activities in the United States generally is subject to U.S. federal income tax on a net basis plus a branch profits tax as described below. Gross income that is attributable to transportation that either begins or ends, but that does not both begin and end, in the United States (“U.S. Source International Transportation Income”) is considered to be 50.0% derived from sources within the United States and may be subject to U.S. federal income tax on a gross basis as described below. Gross income attributable to transportation that both begins and ends in the United States (“U.S. Source Domestic Transportation Income”) is considered to be 100.0% derived from sources within the United States and generally is subject to U.S. federal income tax on a net basis plus a branch profits tax as described below. Gross income attributable to transportation exclusively between non-U.S. destinations will be considered to be 100.0% derived from sources outside the United States and generally is not subject to U.S. federal income tax.

We are not permitted by law to engage in transportation that gives rise to U.S. Source Domestic Transportation Income, and we currently do not anticipate providing any regasification or storage services within the territorial seas of the United States. However, certain of our activities give rise to U.S. Source International Transportation Income, and future expansion of our operations could result in an increase in the amount of U.S. Source International Transportation Income, the U.S. source portion of which could be subject to U.S. federal income taxation unless an exemption from U.S. taxation applies under Section 883 of the Code (the “Section 883 Exemption”).

The Section 883 Exemption

In general, the Section 883 Exemption provides that if a non-U.S. corporation satisfies the requirements of Section 883 of the Code and Treasury Regulations thereunder (the “Section 883 Regulations”), it will not be subject to the net basis and branch profits taxes or the 4.0% gross basis tax described below on the U.S. source portion of its U.S. Source International Transportation Income. The Section 883 Exemption applies only to U.S. Source International Transportation Income and does not apply to U.S. Source Domestic Transportation Income. As discussed below, we believe that based on our current ownership structure, the Section 883 Exemption applies and we are not subject to U.S. federal income tax on our U.S. Source International Transportation Income.

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We qualify for the Section 883 Exemption for a particular taxable year if, among other things, we meet the following three requirements:

● we are organized in a jurisdiction outside the United States that grants an equivalent exemption from tax to corporations organized in the United States with respect to the types of U.S. Source International Transportation Income that we earn (an “Equivalent Exemption”);

● we satisfy the Publicly Traded Test (as described below) or the Qualified Shareholder Stock Ownership Test (as described below); and

● we meet certain substantiation, reporting and other requirements.

In order for a non-U.S. corporation to meet the Publicly Traded Test, its equity interests must be “primarily traded” and “regularly traded” on an established securities market either in the United States or in a jurisdiction outside the United States that grants an Equivalent Exemption. The Section 883 Regulations provide, in pertinent part, that equity interests in a non-U.S. corporation will be considered to be “primarily traded” on an established securities market in a given country if, with respect to the class or classes of equity relied upon to meet the “regularly traded” requirement described below, the number of units of each such class that are traded during any taxable year on all established securities markets in that country exceeds the number of units in such class that are traded during that year on established securities markets in any other single country.

Equity interests in a non-U.S. corporation will be considered to be “regularly traded” on an established securities market under the Section 883 Regulations if one or more classes of such equity interests that, in the aggregate, represent more than 50.0% of the combined vote and value of all outstanding equity interests in the non-U.S. corporation satisfy certain listing and trading volume requirements. These listing and trading volume requirements will be satisfied with respect to a class of equity interests if trades in such class are effected, other than in de minimis quantities, on an established securities market on at least 60 days during the taxable year and the aggregate number of units in such class that are traded on such established securities market during the taxable year is at least 10.0% of the average number of units outstanding in that class during the taxable year (with special rules for short taxable years). In addition, a class of equity interests will be considered to satisfy these listing and trading volume requirements if the equity interests in such class are traded during the taxable year on an established securities market in the United States and are “regularly quoted by dealers making a market” in such class (within the meaning of the Section 883 Regulations).

Even if a class of equity interests satisfies the foregoing requirements, and thus generally would be treated as “regularly traded” on an established securities market, an exception may apply to cause the class to fail the regularly traded test for a taxable year if, for more than half of the number of days during the taxable year, one or more 5.0% unitholders (i.e., unitholders owning, actually or constructively, at least 5.0% of the vote and value of that class) own in the aggregate 50.0% or more of the vote and value of the class (the “Closely Held Block Exception”). For purposes of identifying its 5.0% unitholders, a non-U.S. corporation is entitled to rely on Schedule 13D and Schedule 13G filings with the SEC. In addition, an investment company that is registered under the Investment Company Act of 1940, as amended, is not treated as a 5.0% unitholder. The Closely Held Block Exception does not apply to a class of units, however, in the event the corporation can establish that a sufficient proportion of such 5.0% unitholders are Qualified Shareholders (as defined below) so as to preclude other persons who are 5.0% unitholders from owning 50.0% or more of the value of that class for more than half the days during the taxable year.

As set forth above, as an alternative to satisfying the Publicly Traded Test, a non-U.S. corporation may qualify for the Section 883 Exemption by satisfying the Qualified Shareholder Stock Ownership Test. A corporation generally will satisfy the Qualified Shareholder Stock Ownership Test if more than 50.0% of the value of its outstanding equity interests is owned, or treated as owned after applying certain attribution rules, for at least half of the number of days in the taxable year by:

● individual residents of jurisdictions that grant an Equivalent Exemption;

● non-U.S. corporations organized in jurisdictions that grant an Equivalent Exemption and that meet the Publicly Traded Test; or

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● certain other qualified persons described in the Section 883 Regulations (which we refer to collectively as Qualified Shareholders).

We believe that we currently satisfy all of the requirement for the Section 883 Exemption, and we expect that we will continue to satisfy such requirements. First, we are organized under laws of the Republic of the Marshall Islands. The U.S Treasury Department has recognized the Republic of the Marshall Islands as a jurisdiction that grants an Equivalent Exemption with respect to the type of U.S. Source International Transportation Income we earn and expect to earn in the future. Consequently, our U.S. Source International Transportation Income (including for this purpose, any such income earned by our joint ventures and subsidiaries) should be exempt from U.S federal income taxation provided we meet wither the Publicly Traded Test or the Qualified Shareholder Stock Ownership Test and we satisfy certain substantiation, reporting and other requirements.

Our common units and our Series A preferred units are traded only on the New York Stock Exchange, which is considered to be an established securities market. Thus, the number of our common units and our Series A preferred units that is traded on the New York Stock Exchange exceeds the number of each class that is traded on any other securities market, and this is not expected to change. Therefore, we believe that our equity interests are “primarily traded” on an established securities market for purposes of the Publicly Traded Test. Although the matter is not free from doubt, based upon our analysis of our current and expected cash flow and distributions on our outstanding equity interests, we believe that (i) our common units and Series A preferred units represent more than 50.0% of the total value of all of our outstanding equity interests and (ii) our common units and our Series A preferred units represent more than 50.0% of the total combined voting power of our equity interests. In addition, we believe that our common units and our Series A preferred units each currently satisfy, and expect that our common units and our Series A preferred units each will continue to satisfy, the listing and trading volume requirements described previously. Therefore, we believe that our equity interests are “primarily traded” on an established securities market for purposes of the Publicly Traded Test.

Further, our partnership agreement provides that any person or group that beneficially owns more than 4.9% of any class of our units then outstanding generally will be treated as owning only 4.9% of such units for purposes of voting for directors. There can be no assurance that this limitation will be effective to eliminate the possibility that we will have any 5.0% unitholders for purposes of the Closely Held Block Exception. Nevertheless, we believe that our common units have not lost eligibility for the Section 883 Exemption as a result of the Closely Held Block Exception based upon the current ownership of our common units. Thus, although the matter is not free from doubt and is based upon our belief and expectations regarding our satisfaction of the factual requirements described above, we believe that we satisfied the Publicly Traded Test for 2020, and we expect that we will satisfy the Publicly Traded Test for the current and all future taxable years.

The legal conclusions described above are based upon legal authorities that do not expressly contemplate an organizational structure such as ours. In particular, although we have elected to be treated as a corporation for U.S. federal income tax purposes, we are organized as a limited partnership under Marshall Islands law. Accordingly, while we believe that, assuming the factual requirements described above are satisfied, our common units and Series A preferred units should be considered to be “regularly traded” on an established securities market and that we satisfy the requirements of the Section 883 Exemption, it is possible that the IRS would assert that our common units do not meet the “regularly traded” test. In addition, as described previously, our ability to satisfy the Publicly Traded Test depends upon factual matters that are subject to change. Should any of the factual requirements described above fail to be satisfied, we may not be able to satisfy the Publicly Traded Test. Furthermore, 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 satisfy the Publicly Traded Test in the future. Please read “—The Net Basis and Branch Profits Tax” and “—The 4.0% Gross Basis Tax” below for a discussion of the tax consequences in the event we do not qualify for the Section 883 Exemption.

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The Net Basis Tax and Branch Profits Tax

If we earn U.S. Source International Transportation Income and the Section 883 Exemption does not apply, the U.S. source portion of such income would be treated as effectively connected with the conduct of a trade or business in the United States (“Effectively Connected Income”) if we have a fixed place of business in the United States involved in the earning of U.S. Source International Transportation Income and substantially all of our U.S. Source International Transportation Income is attributable to regularly scheduled transportation or, in the case of vessel leasing income, is attributable to a fixed place of business in the United States. 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. Based on our current operations, substantially all of our potential U.S. Source International Transportation Income is not attributable to regularly scheduled transportation and is not received pursuant to vessel leasing, and none of our regasification or storage 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 or income earned from regasification or storage activities would be treated as Effectively Connected Income. However, there is no assurance that 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, in the future, which would result in such income being taxed as Effectively Connected Income if the Section 883 Exemption does not apply.

Any income we earn that is treated as Effectively Connected Income, net of applicable deductions, would be subject to U.S. federal corporate income tax (currently imposed at a rate of 21.0%). In addition, a 30.0% branch profits tax could be imposed on the after-tax amount of any income we earn that is treated as Effectively Connected Income, as determined after allowance for certain adjustments, and on certain interest paid or deemed paid by us in connection with the conduct of our U.S. trade or business.

Taxation of Gain from the Sale of a Vessel

On the sale of a vessel that has produced Effectively Connected Income, we could be subject to the net basis U.S. federal corporate income tax as well as branch profits tax with respect to the gain recognized up to the amount of certain prior deductions for depreciation that reduced Effectively Connected Income. Otherwise, we would not be subject to U.S. federal income tax with respect to gain realized on the sale of a vessel, provided the sale is considered to occur outside of the United States under U.S. federal income tax principles. In general, a sale of vessel will be considered to occur outside of the United States for this purpose if title to the vessel, and risk of loss with respect to the vessel, pass to the buyer outside the United States. It is expected that any sale of a vessel by us will be considered to occur outside of the United States.

The 4.0% Gross Basis Tax

If the Section 883 Exemption does not apply and the net basis tax does not apply, we would be subject to a 4.0% U.S. federal income tax on the U.S. source portion of our gross U.S. Source International Transportation Income, without benefit of deductions. Under the sourcing rules described above under “—Taxation of Operating Income,” 50.0% of our U.S. Source International Transportation Income would be treated as being derived from U.S. sources.

Marshall Islands Taxation

Because we, our operating subsidiary and our controlled affiliates do not, and do not expect to conduct business, transactions or operations in the Republic of the Marshall Islands, neither we nor our controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, other than taxes, fines or fees due to (i) the incorporation, dissolution, continued existence, merger, domestication (or similar concepts) of legal entities registered in the Republic of the Marshall Islands, (ii) filing certificates (such as certificates of incumbency, merger, or redomiciliation) with the Marshall Islands registrar, (iii) obtaining certificates of good standing from, or certified copies of documents filed with, the Marshall Islands registrar, (iv) compliance with Marshall Islands law concerning books and records and vessel ownership, such as tonnage tax, or (v) non-compliance with economic substance requirements or with requests made by the Marshall Islands Registrar of Corporations relating to our books and records and the books and records of our subsidiaries. As a result, distributions by our operating subsidiaries and our controlled affiliates to us will not be subject to Marshall Islands taxation.

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Norway Taxation

The following is a discussion of the material Norwegian tax consequences applicable to us. This discussion is based upon existing legislation and current tax authority practice as of the date of this Annual Report. Changes in this legislation and practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Norwegian tax considerations applicable to us.

As we do not have any Norwegian incorporated subsidiaries, there is no Norwegian taxation by virtue of being resident in Norway. We, our operating company, our joint ventures and our non-Norwegian incorporated subsidiaries do not contemplate to hold board meetings in Norway, to have a board consisting of a majority of Norwegian residents or to pass resolutions in any board with a majority of Norwegian resident directors.

Taxation of the Partnership and Non-Norwegian Incorporated Subsidiaries.

As we are a partnership and do not expect to be managed and controlled within Norway nor carrying out business in Norway, we do not expect to be subject to taxation in Norway. While certain of our joint ventures and non-Norwegian incorporated subsidiaries will enter into agreements with Höegh Norway and Höegh LNG Management, Norwegian incorporated and resident companies, for the provision of certain management and administrative services, we believe that the terms of these agreements will not result in us, our operating company or any of our non-Norwegian incorporated subsidiaries being treated as being resident in Norway or having a permanent establishment or carrying out business in Norway. As a consequence, we expect that neither our profits, the profits of our operating company or any of our joint ventures and non-Norwegian incorporated subsidiaries will be subject to Norwegian corporation tax. We do not currently anticipate that any of our joint ventures and non-Norwegian incorporated subsidiaries will be controlled or managed in Norway or have a permanent establishment or otherwise carry on business in Norway. Accordingly, we do not anticipate that any of our joint ventures and non-Norwegian incorporated subsidiaries will be subject to Norwegian corporation tax.

Singapore Taxation

The following is a discussion of the material Singapore tax consequences applicable to us. This discussion is based upon existing legislation and current Inland Revenue Authority of Singapore practice as of the date of this Annual Report. Changes in the existing legislation and current practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Singapore tax considerations applicable to us.

Taxation of the Partnership and non-Singapore Incorporated Subsidiaries.

As we are a limited partnership and do not expect to be managed and controlled within Singapore or carry on a trade or business in Singapore, we do not expect to be subject to taxation in Singapore. Similarly, as the non-Singapore incorporated subsidiaries are not managed and controlled within Singapore or carry on a trade or business in Singapore, the non-Singapore incorporated subsidiaries should not be subject to taxation in Singapore.

Taxation of the Singapore Incorporated Subsidiary.

Höegh Lampung is incorporated in Singapore, and we anticipate that it will be centrally managed and controlled in Singapore. As a result, Höegh Lampung will be regarded for the purposes of Singapore tax as being resident in Singapore and liable to Singapore corporate income tax on income accrued in or derived from Singapore or income received in Singapore from outside Singapore in respect of (i) gains or profits from any trade or business, (ii) income from investment such as dividends, interest and rental, (iii) royalties, premiums and any other profits from property and (iv) other gains of an income nature. The generally applicable rate of Singapore corporation tax is 17%. Höegh Lampung will generally be liable to tax at this rate on its income, profits and gains after deducting revenue expenses incurred wholly and exclusively for the purposes of the business being undertaken.

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Under Section 12(6) of the Income Tax Act, Chapter 134 of Singapore (“ITA”), the following payments are deemed to be derived from Singapore:

● any interest, commission, fee or any other payment in connection with any loan or indebtedness or with any arrangement, management, guarantee, or service relating to any loan or indebtedness which is:

● borne, directly or indirectly, by a person resident in Singapore or a permanent establishment in Singapore (except in respect of any business carried on outside Singapore through a permanent establishment outside Singapore or any immovable property situated outside Singapore); or

● deductible against any income accruing in or derived from Singapore; or

● any income derived from loans where the funds provided by such loans are brought into or used in Singapore.

Payments falling within the two bullet points above and made by Höegh Lampung, would fall within Section 12(6) of the ITA. Unless exempted, such payments, where made to a person not known to Höegh Lampung to be a tax resident in Singapore, are generally subject to withholding tax in Singapore.

Indonesian Taxation

The following is a discussion of the material Indonesia tax consequences applicable to us. This discussion is based upon existing legislation and current Directorate General of Taxes of Indonesia (“DGT”) practice as of the date of this Annual Report. Changes in the existing legislation and current practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Indonesia tax considerations applicable to us.

Taxation of the Partnership and non-Indonesian Incorporated Subsidiaries

As we are a limited partnership and do not expect to be managed and controlled or domiciled within Indonesia or conduct business or carry out activities through a permanent establishment in Indonesia, we do not expect to be subject to taxation in the Indonesia.

We do not currently anticipate that any of our other non-Indonesian incorporated subsidiaries will be controlled, managed or domiciled in Indonesia or conduct business or carry out activities through a permanent establishment in Indonesia. Accordingly, we do not anticipate that any of our non-Indonesian incorporated subsidiaries will be subject to Indonesian corporate income tax.

Taxation of Operating Income

PT Höegh’s main business activity in Indonesia is to provide the lease, operation, and maintenance of the PGN FSRU Lampung to PGN LNG. As PT Höegh was established in Indonesia, it is a resident taxpayer. Under Law No. 36 Year 2008 regarding Income Tax (“Income Tax Law” or “ITL”), PT Höegh is subject to Corporate Income Tax (“CIT”) of 25% on taxable profit derived from the business activities performed. However, due to the Covid-19 pandemic, the Indonesian Government issued the Law No. 2 Year 2020 which reduces the applicable CIT rate to be as follows:

● 22% for the Fiscal Year ("FY") 2020 and FY2021; and

● 20% for FY2022 onwards

Therefore, any income generated by PT Höegh from PGN LNG in regard to the lease, operation, and maintenance of the PGN FSRU Lampung is subject to the above applicable CIT rates (after deductions for allowable expenses in accordance with the ITL provisions).

Taxable income is calculated on the basis of accounting profits as modified by certain tax adjustments. Any tax loss can be carried forward for a maximum period of five years. Loss carry back is not permitted in Indonesia.

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For tax purposes, costs incurred in relation to the acquisition of fixed assets are deductible (through depreciation) over a useful life of four to 20 years depending on the type of the fixed assets. In this regard, although the commercial useful life of a fixed asset is more than 20 years, such asset shall only be depreciated for a maximum of 20 years for tax purposes.

Depreciation commences in the month when expenditures are incurred. The depreciation can be calculated either using the straight line method or double declining balance method.

The ITL taxes the world-wide income of Indonesian tax residents; however, we do not anticipate that PT Höegh will generate income outside of Indonesia.

Taxation of the Sale of the PGN FSRU Lampung to PGN LNG

PGN LNG was granted an option to purchase the PGN FSRU Lampung from PT Höegh at specified prices as set out in the time charter for PGN FSRU Lampung. Any gain arising from the sale of the FSRU (i.e. sales price less tax book value) will be subject to the applicable CIT rate to PT Höegh.

Withholding Taxes (“WHT”)

PT Höegh is required to withhold:

● WHT under Article 23/26 of the ITL at the following rates:

● 2% on payments for rent (other than land and/or building), fees for technical, management and other services to another resident taxpayer;

● 15% on payments of dividends, interest and royalties to another resident taxpayer;

● 20% (or a reduced tax treaty rate) on payments relating to services, dividends, interest and royalties to a non-resident taxpayer. The reduced tax treaty rate is also subject to the availability of the Certificate of Domicile of the counter party in the form prescribed by the Indonesian tax regulations and fulfilment of Indonesian Tax Treaty use requirements.

● WHT under Article 4(2) of the ITL at the rate of 10% for rent of land and/or buildings and at 3% to 6% on payments for construction services to another resident taxpayer;

● WHT under Article 15 of the ITL at the rate of 1.2% on payments related to domestic shipping services.

Salaries and wages paid to resident employees are subject to Employee Income Tax (“EIT”) under Article 21 of the ITL at progressive rates of maximum 30%. Salaries paid to non-resident employees are subject to EIT under Article 26 of the ITL at the rate of 20% from the gross salary amount. PT Höegh is required to withhold and remit EIT on monthly basis.

Value Added Tax (“VAT”)

Any fees charged by PT Höegh for services provided to PGN LNG are subject to VAT at 10%. Such VAT on revenue is called Output VAT. The Output VAT can be offset with the VAT that PT Höegh pays for the procurement of goods and/or services (“Input VAT”). If the Output VAT exceeds the Input VAT in a particular month, the balance is required to be settled by PT Höegh. However, if the Input VAT exceeds the Output VAT, the VAT overpayment can be carried forward to the following month or a refund can be requested at year end. A VAT refund request will automatically trigger a tax audit.

VAT of 10% would also be charged on the sale of the FSRU to PGN LNG, if applicable.

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Debt to Equity Ratio Requirement

Under Minister of Finance (“MoF”) Regulation No. 169/PMK.010/2015 (“MoF -169”) Indonesian corporate taxpayers are subject to a limit in claiming financing costs as tax deduction where their debt to equity ratio exceeds 4:1. PMK 169 was effective from fiscal year 2016 onwards.

MoF-169 stipulates that debt shall include long-term debt, short-term debt and trade payables which bear interest. Equity includes all items recorded under the equity section of the balance sheet based on the prevailing accounting standards and interest-free loans from related parties.

In case the balance of equity is zero or negative, no financing costs of the taxpayer can be deducted. In case the actual ratio of the debt and equity exceeds 4:1 the deductible financing costs must be adjusted to an allowable amount based on the 4:1 ratio.

Certain industries, including the infrastructure industry, are exempted from the debt to equity ratio requirements. The infrastructure industry is not defined in MoF-169, and there has been no further guidance issued by the DGT regarding this matter. The DGT issued Regulation No. PER-25/PJ/2017 (“PER-25”) in 2017 which provides information in relation to the implementation of MoF-169. PER-25 provides guidance that interest is not deductible on any debt for which the existence cannot be formally verified and specifies reporting requirements on the corporate income tax return to comply with the regulation.

Land and Building Tax (“Property tax”)

On December 10, 2019 the MoF issued regulation No. 186/PMK.03/2019 (“MoF-186”) regarding the following changes in relation to the application of Property tax. These changes are:

● an updated classification of “Tax Objects”; and

● new procedures to determine the Sale Value of these Tax Objects

The regulation is effective from January 1, 2020.

Under MoF-186, the definition of “building” extends to technical constructions planted or attached permanently on “land” within Indonesia’s territorial waters. This includes pipelines, cable networks, toll roads and, most importantly, industry-relevant storage and processing facilities (i.e. Floating storage and offloading vessels (“FSOs”), Floating production system (“FPS”), Floating storage unit (“FSUs”), Floating, production, storage and offloading vessels (“FPSOs”) and FSRUs).

In addition, while the DGT considers an FSRU as a building for Property tax purposes, it continues to be considered a non-building for CIT purposes. Therefore, the income from FSRU operations is still subject to CIT at the prevailing rate on taxable income, rather than a 10% income tax on rental income from a building.

Cyprus Taxation

The following is a discussion of the material Cyprus tax consequences applicable to us. This discussion is based upon existing legislation and current tax practice as of the date of this Annual Report. Changes in the existing legislation and current practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Cyprus tax considerations applicable to us.

Taxation of profits and deduction for losses

For the period up to April 29, 2020, Höegh Cyprus, acting through its Egypt Branch, provided a FSRU on a time charter to EgyptCo. The time charter activities were operated in the Egypt Branch.

Cyprus tax law exempts foreign branch profits from Cyprus corporate income tax, subject to certain exceptions. We have received a ruling from the Cyprus tax authorities confirming that this exemption applies for the profits in the Egypt Branch.

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Any tax losses incurred by the Egypt Branch can be used as a deduction against the taxable income of Höegh Cyprus for the same year. Any unutilized branch tax losses can be carried forward. A claw-back applies for previous losses utilized in the year in which the Egypt Branch becomes profitable. Losses clawed back through taxation of equal profits are restricted to losses offset with profits/losses being carried forward and exclude expired losses (i.e. exclude losses which were carried forward but not offset with profits due to the lapse of the five year carry forward period from the date the losses were incurred).

Höegh Cyprus may elect, but has not to date made the election, to be taxed on foreign permanent establishment’s (“PE”) profits. If Höegh Cyprus made this election, it could claim a foreign tax credit ("FTC") for taxes incurred on foreign PE profits, even when an applicable tax treaty is not in force.

Höegh Cyprus up until April 29, 2020, used the Höegh Gallant as a regasification terminal near Egypt's Red Sea coast. As a result, a Permanent Establishment was created in Egypt and taxed in accordance with the provision of the Income Tax Legislation (as explained above).

On April 30, 2020 the Subsequent Charter was signed where the Höegh Gallant is no longer used as a regasification terminal and is now used as an LNG carrier i.e. is involved in maritime transportation activities between ports or between ports and offshore installations.

The Vessel flies an EU/EEA flag (NIS).

In this respect, Höegh Cyprus is eligible to enter the Tonnage Tax system in Cyprus as from April 30, 2020 and thus following an application filed to the Deputy Ministry of Shipping (‘DMS’) a positive reply (confirmation) was received dated June 29, 2020.

Taxation method

(i) Cyprus Tonnage Tax Regime - General comments

The Merchant Shipping Law (‘MSL’) in Cyprus provides full exemption of qualifying shipowners from all profit from Corporate Income Tax (‘CIT’) and instead imposes tonnage tax (‘TT’) on the net tonnage of the vessels.

The exemption is granted provided that they carry out a qualifying activity, that is maritime transportation of goods and/or people using a qualifying vessel that is a sea-going vessel.

The EU Commission has recently approved the new Cyprus TT System for another 10 years (up to December 31, 2029). TT is calculated by reference to the net tonnage stated on the International Tonnage Certificate (not profits of the company).

● The tax exemption covers:

● Profits from the use of a qualifying vessel;

● Profits from the disposal of a qualifying vessel and/or share and/or interest in it;

● Profits from the disposal of shares in a shipowning company;

● Dividends paid out of the above profits at all levels of distribution;

● Interest income relating to the financing/maintenance/use of a qualifying vessel and the working capital; excluding interest on capital used for investments.

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(ii) Cyprus Tonnage Tax Regime - Specific comments

Höegh Cyprus is engaged into qualifying shipping activities as from April 30, 2020. On this basis, the company is taxed under TT in accordance with the net tonnage of the vessel owned and at the same time these results are exempt from CIT.

For tax year 2020, Höegh Cyprus has filed the relevant Declaration Form to the DMS and settle the relevant TT liability for tax year 2020 (Eur5.751,79).

(iii) Interaction of CIT and TT

The TT system allows for companies undertaking mixed activities to benefit from the TT regime, to this respect the MSL imposes an obligation to qualifying owner to " maintain such books and records so that it will be possible to determine the income subject to the tonnage tax system and the other income separately and prepare separate accounts".

Taking the above into consideration, for tax year 2020, Höegh Cyprus needs to maintain separate books and records for the two activities performed which have different tax treatment:

● Period from January 1, 2020 through April 29, 2020: Regasification terminal in Egypt (Egypt Branch) – Exempt from CIT as a foreign permanent establishment.

● Period from April 30, 2020 through December 31, 2020: LNG Carrier – Exempt from CIT and taxed under TT.

The above allocation will be reflected in the tax computation of Höegh Cyprus.

WHT

Cyprus does not levy any withholding taxes on interest and dividend payments to non-Cyprus tax residents (whether legal persons or individuals). As such, dividends and interest payments made by Höegh Cyprus should not be subject to WHT.

Exit Taxation

Exit tax provisions of the EU Anti-Tax Avoidance Directive have been transposed to Cyprus legislation and have an effect as from January 1, 2020. The expectation is that these provisions will not capture transactions that are anyway exempt from CIT (i.e. disposal of qualifying vessels). Having said that, this will only be clarified with the Circular to be published by the Cyprus Tax Authorities.

VAT

As per the ruling obtained with the Cyprus Tax Authority, Höegh Cyprus does not have an obligation to register for VAT purposes in Cyprus. Any income generated by Höegh Cyprus through the Egypt Branch from the time charter or any services (ship management, commercial management, crew management, etc.) received by the Egypt Branch will not trigger an obligation to account for Cypriot VAT.

Egyptian Taxation

The following is a discussion of the material Egypt tax consequences applicable to us. This discussion is based upon existing legislation and current practice as of the date of this Annual Report. Changes in the existing legislation and current practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Egypt tax considerations applicable to us.

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Taxation of Höegh Cyprus in Egypt – CIT and free zone

The Egypt Branch is registered as a legal entity in Egypt in the Suez Public Free Zone. The Egypt Branch is subject to a 1% free zone fee on the revenues from activities permitted under its free zone license (e.g., the time charter hire paid by EgyptCo), but is exempt from CIT on profits from the same activities.

WHT

Profit repatriation from the Egypt Branch is exempt from WHT.

The Egypt Branch has not drawn down debt with maturity less than three years and, as such, interest payments are not subject to WHT.

Payments for services made to recipients that are not tax resident in Egypt are subject to 20% WHT, subject to reduction or elimination under applicable tax treaties.

VAT

As a free zone entity, the Egypt Branch is not subject to VAT on the activities permitted under its free zone license and within the permitted location to operate (e.g., the time charter hire paid by EgyptCo and related acquired goods and services).

Exit taxation

The exit of the Höegh Gallant from Egypt after the end of the time charter may be considered a deemed sale of the Höegh Gallant for Egyptian tax purposes. The gains from the deemed sale would be subject to CIT (currently at 22.5%). The gain is calculated as the fair market value of the Höegh Gallant on the exit less the tax base value after deemed depreciation based on the assumption that it is considered as an asset of the branch.

Colombian Taxation

The following is a discussion of the material Colombian tax consequences applicable to us. This discussion is based upon existing legislation and current practice as of the date of this Annual Report. Changes in the existing legislation and current practice may cause the tax consequences to vary substantially from the consequences described below. The following discussion does not purport to be a comprehensive description of all of the Colombian tax considerations applicable to us.

Taxation of profits of Höegh FSRU IV

Höegh FSRU IV leases the Höegh Grace to a charterer in Colombia. The lease agreement is regarded as a financial lease for Colombian tax purposes. Höegh FSRU IV would not have a permanent establishment in Colombia and therefore would not be subject to Colombian corporate income tax (“CIT”), VAT or Industry and Trade Tax (“ITT”). The financial component of the financial lease paid to Höegh FSRU IV would be subject to 1% withholding tax in lieu of corporate income tax in Colombia.

Taxation of profits of Höegh Colombia

Höegh Colombia provides services to the charterer in Colombia. Höegh Colombia is subject to CIT levied on its worldwide income at a rate of 33% for fiscal year 2019, 32% for fiscal year 2020, 31% for fiscal year 2021 and 30% for fiscal year 2022 and onwards. The taxable basis will be the net taxable income (gross revenues less allocable cost and expenses).

In addition, to the ordinary taxation system, a presumptive tax system applies. Under the presumptive tax system, Colombian rules provide that net taxable income cannot be less than a cap calculated as 0.5% of the company’s net equity as of December 31 of the previous year. Accordingly, if net taxable income is lower than the cap, the ordinary taxation will be disregarded and the presumptive tax system considerations will apply. However, such system will not apply from fiscal year 2021 and onwards, since the percentage to determine the presumptive income will be set to 0%.

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WHT

Dividends paid out of profits that are subject to tax at the Colombian corporate level (CIT) have a 10.0% WHT rate (dividend tax), when distributed to foreign non-resident shareholders. Otherwise, a 38.8%, 37.9% and 37.0% WHT rate applies for the dividends on profits not subject to CIT for the years ended December 31, 2020, 2021 and 2022 onwards, respectively. Höegh Colombia expects to pay dividends from retained profits that were subject to Colombian CIT.

VAT

The services rendered by Höegh Colombia are subject to 19% VAT.

Financial Transaction Tax

Financial Transaction Tax is levied on the transfers from Colombian bank accounts at a rate of 0.4% of the amount transferred. A 50% share of the Financial Transaction Tax is deductible for CIT purposes.

ITT

ITT will be applicable in Cartagena for the services provided through the Cartagena office and services provided on-shore or within the boundaries of the Cartagena District. Up to 50% of the ITT paid by the Company will be a tax credit for CIT purposes, or alternatively, 100% of the ITT paid can be treated as a deduction for CIT purposes. In 2022, the tax credit will increase to 100% for CIT purposes.

Capital gains taxation

Starting in 2019, the sale of Colombian assets (i.e. shares) by a foreign non-resident is subject to a 10% capital gains tax provided the seller possessed the assets for two years or longer. If the assets are held for less than two years, the gain is subject to the ordinary corporate income tax rate at a rate of 32% for taxable year 2020 (31% on 2021 and 30% from 2022 onwards).

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C.Organizational Structure

We are a publicly traded limited partnership formed on April 28, 2014. The diagram below depicts our simplified organizational structure as of March 31, 2021. As of March 31, 2021, we have issued and outstanding 33,361,042 common units, 7,089,325 Series A preferred units and incentive distribution rights, and as of March 31, 2021 Höegh LNG owns 15,257,498 of our common units and incentive distribution rights issued and outstanding.

We listed our common units on the New York Stock Exchange (“NYSE”) in August 2014 under the ticker symbol “HMLP.” Our preferred units are listed on the NYSE under the ticker symbol “HMLP-A.”

We were formed under the law of the Marshall Islands and maintain our principal executive headquarters at Canon's Court, 22 Victoria Street, Hamilton HM12, Bermuda.

A full list of our significant operating and vessel-owning subsidiaries is included in Exhibit 8.1.

D.Property, Plant and Equipment

Other than the vessels in our fleet, we do not have any material property.

Item 4A.Unresolved Staff Comment

Not applicable.

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Item 5.Operating and Financial Review and Prospects

You should read the following discussion of our financial condition and results of operations in conjunction with “Item 3.A. Selected Financial Data” and “Item 4. Information on the Partnership” and the consolidated financial statements and related notes of Höegh LNG Partners LP, included elsewhere in this Annual Report. Such financial statements, including related notes thereto, have been prepared in accordance with US GAAP and are presented in U.S. Dollars.

Prior to the closing of the IPO on August 12, 2014, Höegh LNG contributed to us all of its equity interests in and promissory notes due to it from Höegh Lampung, PT Höegh (the owner of the PGN FSRU Lampung) and our joint ventures, SRV Joint Gas Ltd. (the owner of the Neptune) and SRV Joint Gas Two Ltd. (the owner the Cape Ann) (the “initial fleet”).

Overview

We were formed on April 28, 2014 as a growth-oriented limited partnership by Höegh LNG, to own, operate and acquire FSRUs, LNG carriers and other LNG infrastructure assets under long-term charters, which we define as charters of five or more years.

On August 12, 2014, we completed our IPO. At the closing of the IPO, we sold 11,040,000 common units to the public for net proceeds, after deduction of underwriters’ discount and offering expenses, of $203.5 million. We also issued 2,116,060 common units and 13,156,060 subordinated units, representing approximately 58.0% of the limited partner interest in the Partnership, and 100% of the incentive distribution rights (“IDRs”) to Höegh LNG. A wholly owned subsidiary of Höegh LNG owns a non-economic general partner interest in us.

On October 1, 2015, we purchased 100% of the shares of Höegh FSRU III, the entity that indirectly owned the FSRU Höegh Gallant, which we accounted for as the acquisition of a business. Accordingly, the results of this acquisition are included in our earnings from October 1, 2015.

In December 2016, we completed a 6,588,389 common unit offering raising approximately $111.5 million in net proceeds, after deduction of underwriters’ discount and offering expenses to be used primarily to fund the purchase price of the acquisition of a 51% ownership interest in Höegh Colombia Holding, the owner of Höegh FSRU IV and Höegh Colombia, the entities that own and operate the Höegh Grace (the "Höegh Grace entities").

On January 3, 2017, we closed the acquisition of a 51% ownership interest in the Höegh Grace entities for cash consideration of $91.8 million, excluding the working capital adjustment. On January 1, 2017, we entered into an agreement with Höegh LNG, under which Höegh LNG granted us the authority to make decisions about operations of Höegh Colombia Holding from January 1, 2017 to the closing date of the acquisition. Accordingly, the results of the Höegh Grace are included in our earnings from January 1, 2017.

On October 5, 2017, we issued to the public 4,600,000 8.75% Series A cumulative redeemable preferred units (the “Series A preferred units”) for proceeds, net of underwriting discounts and expenses, of $110.9 million. A portion of the net proceeds was used to repay outstanding debt under the seller’s credit note related to the Höegh Gallant acquisition and outstanding debt under the revolving credit facility and the remainder of the net proceeds were used to fund the acquisition of the remaining 49% ownership interest in the Höegh Grace entities.

On December 1, 2017, we closed the acquisition of the remaining 49% ownership interest in the Höegh Grace entities. From January 1, 2017 until November 30, 2017, the results of the Höegh Grace entities were reduced by non-controlling interest and until December 1, 2017 total equity was split between partners’ capital and the non-controlling interest.

On January 26, 2018, the Partnership entered into sales agreement with B. Riley FBR Inc. (the “Agent”). Under the terms of the sales agreement, the Partnership could offer and sell up to $120 million aggregate offering amount of common units and 8.75% Series A cumulative redeemable preferred units (“Series A preferred units”) through the Agent, acting as agent for the Partnership (the “Prior ATM Program”).

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On October 18, 2019, the Partnership entered into a sales agreement with the Agent for a new ATM program and terminated the Prior ATM Program. Under the terms of the new sales agreement, the Partnership may offer and sell up to $120 million aggregate offering amount of common units and Series A preferred units, from time to time, through the Agent, acting as an agent for the Partnership. Sales of such units may be made in negotiated transactions that are deemed to be "at the market" offerings, including sales made directly on the New York Stock Exchange or through a market maker other than on an exchange.

On January 31, 2019, Höegh FSRU III transferred its ownership in Höegh Cyprus to our operating company and Höegh LNG III was formally dissolved on May 4, 2020.

Our Fleet

Our fleet consisted of interests in the following vessels as of December 31, 2020:

● a 50% interest in the Neptune, an FSRU built in 2009 that is currently operating under a time charter with Total Gas & Power, a subsidiary of Total, that expires in 2029, with an option to extend for up to two additional periods of five years each;

● a 50% interest in the Cape Ann, an FSRU built in 2010 that is currently operating under a time charter with Total Gas & Power that expires in 2030, with an option to extend for up to two additional periods of five years each;

● a 100% economic interest in the PGN FSRU Lampung, an FSRU built in 2014 that is currently operating under a time charter with PGN LNG, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk, a subsidiary of PT Pertamina, a government controlled Indonesian oil and gas producer, natural gas transportation and distribution company, that expires in 2034, with options to extend either for an additional 10 years or for up to two additional periods of five years each;

● a 100% interest in the Höegh Gallant, an FSRU built in 2014 that operated under a time charter with EgyptCo, a subsidiary of Höegh LNG, that expired in April 2020. EgyptCo had a time charter agreement with EGAS until October 2018. EgyptCo had an LNG carrier time charter to a third party from October 2018 until April 2020. In addition, pursuant to an option agreement we had the right to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of the EgyptCo charter until July 2025. On February 27, 2020, we exercised the option and on April 30, 2020, we entered into the Subsequent Charter with CharterCo, another subsidiary of Höegh LNG, which commenced on May 1, 2020 and expires July 31, 2025; and

● a 100% interest in the Höegh Grace, an FSRU built in 2016 that is currently operating under a time charter with SPEC. SPEC is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. The non-cancellable charter period of 10 years ends in December 2026. The initial term of the charter is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if SPEC waives its right to terminate in year 10 within a certain deadline, we will not be able to exercise our right to terminate in year 10.

For a description of our joint ventures and our shareholder agreements, please read “Item 4.B. Business Overview—Shareholder Agreements.”

Our Charters

We and our joint ventures generate revenues by chartering our vessels under long-term time charters. As of March 31, 2021, the average remaining term of the time charters for the vessels in our fleet was approximately 8.3 years, excluding the exercise of any customer options, and 15.3 years, assuming the exercise of all customer options.

Under our time charters for the Neptune and the Cape Ann, the rate charged for the services of each vessel, which we call the “hire rate,” is paid monthly in advance. Under our time charters for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace, the hire rate is paid monthly in arrears. Under certain time charters, hire payments may be reduced and /or liquidated damages may be incurred if the vessel does not perform to certain of her specifications.

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Moreover, when a vessel is “off-hire”—or not available for service—the customer generally is not required to pay any hire rate, and the vessel owner is responsible for all costs. Prolonged off-hire may lead to termination of the time charter.

Under the time charters for the Neptune and the Cape Ann, the hire rate includes the following three cost components:

● Fixed Element. The fixed element is a fixed per day fee providing for ownership costs and all remuneration due to the vessel owner for use of the vessel and the provision of time charter services.

● Variable (Operating Cost) Element. The variable (operating cost) element is a fixed per day fee providing for the operating costs of the vessel, which consists of (i) a cost pass-through sub-element, which covers the crew, insurance, consumables, miscellaneous services, spares and damage deductible costs and is subject to annual adjustment and (ii) an indexed sub-element, which covers management and is subject to annual adjustment for changes in labor costs and the size of the fleet under management.

● Optional (Capitalized Equipment Cost) Element. The optional (capitalized equipment cost) element is a revenue for the reimbursement of costs incurred that consists of (i) costs associated with modifications to, changes in specifications of, structural changes in or new equipment for the vessel that become compulsory for the continued operation of the vessel by reason of new class requirements or national or international regulations coming into effect after the date of the time charter, subject to specified caps and (ii) costs associated with any new equipment or machinery that the owner and charterer have agreed should be capitalized. Such revenues for these reimbursements are amortized over the shorter of the life of the capital improvement or the remaining term of the time charter.

Under the Neptune and Cape Ann time charters, a vessel generally will be deemed off-hire if the vessel is not available for the charterer’s use for a specific amount of time due to, among other things:

● failure of an inspection that prevents the vessel from performing normal commercial operations;

● scheduled drydocking that exceeds allowances;

● the vessel’s inability to discharge regasified LNG at normal performance;

● requisition of the vessel; or

● the vessel owner’s failure to maintain the vessel in compliance with her specifications and contractual standards or to provide the required crew.

The hire rate under the PGN FSRU Lampung time charter consists of the following three cost components:

● Fixed Element. The fixed element is a fixed per day fee, which is intended to cover remuneration due to the vessel owner for use of the vessel and the provision of time charter services.

● Operating and Maintenance Element. The operating and maintenance element is a fixed per day fee, subject to annual adjustment, which is intended to cover the operating costs of the vessel, including manning costs, maintenance and repair costs, consumables and stores costs, insurance costs, management and operational costs, miscellaneous costs and alterations not required by Det Norske Veritas GL to maintain class or the IMO.

● Tax Element. The tax element is a fixed per day fee, equal to the vessel owner’s reasonable estimate of the tax liability for that charter year divided by the number of days in such charter year. If the vessel owner receives a tax refund or credit, the vessel owner will pay such amount to the charterer. The tax liability includes Indonesian corporate income taxes, defined withholding taxes and all Indonesian taxes associated with the Mooring. The time charter requires an annual audit to determine the difference between the invoiced estimate of the tax liability and the actual tax liability. If the vessel owner’s reasonable estimate of the tax liability varied from the actual tax liability, the vessel owner or the charterer, as applicable, will pay to the other party the difference in such amount.

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Under the PGN FSRU Lampung time charter, the vessel generally will be deemed off-hire if the vessel is not available for the charterer’s use for a specified amount of time due to, among other things:

● drydocking that exceeds allowances;

● the vessel failing to satisfy specified operational minimum requirements, except as a result of a Lampung Charterer Risk Event (as defined under “Item 4.B. Business Overview—Vessel Time Charters— PGN FSRU Lampung Time Charter—Performance Standards”) or an event of force majeure; or

● the vessel owner’s failure to satisfy the management warranties described under “Item 4.B. Business Overview—Vessel Time Charters— PGN FSRU Lampung Time Charter—Performance Standards.”

The hire rate under the Höegh Gallant time charter is a fixed per day fee (subject to certain adjustments for i) avoided FSRU related costs only when operating in LNG carrier mode and ii) higher incremental taxes or operating expenses when operating in FSRU mode) which is intended to cover remuneration due to the vessel owner for use of the vessel and the provision of time charter services as well as the operating and maintenance costs of the vessel, including manning costs, the cost of spare parts, and any tax incurred.

Under the Höegh Gallant time charter, the vessel generally will be deemed off-hire if the vessel is not available for the charterer’s use for a specified amount of time due to, among other things:

● drydocking or other repairs and maintenance;

● any force majeure event acting on the vessel; and

● every other occasion the vessel ceases to be at the disposal of the charterer, including due to damage, defect, deficiency of crew or spare parts, labor disputes, time in and waiting to enter dry dock for repairs or because of a failure to comply with laws, regulations, physical requirements or operational practices at the site of vessel operations.

Additionally, we have agreed to indemnify CharterCo under certain circumstances. Please read “Item 4.B. Business Overview-Vessel Time Charters- Höegh Gallant Time Charter-Indemnification.”

Under the Höegh Grace charter, hire is payable monthly, in arrears, in U.S. Dollars. The charterer pays a fixed daily rate of hire for use of the vessel and the provision of time charter services and operating fees, as set forth in the Höegh Grace charter. The operating fees are escalated yearly by a fixed percentage, and the charter provides for a review and reasonable adjustment by the parties if the actual operating costs increase by more than such percentage over a period of three consecutive years.

Except for force majeure events and a specified maintenance allowance period, under the Höegh Grace charter the vessel generally will be deemed off-hire:

● if the vessel is not able to discharge regasified LNG at a specified rate;

● if the vessel owner breaches its warranties related to international sanctions; or

● if the vessel is not available for the charterer’s use due to, among other things:

o any damage, defect, breakdown or deficiency to the vessel;

o any deficiency of crew, stores, repairs, surveys, or similar cause preventing the working of the vessel;

o any labor dispute, failure or inability of the officers or crew to perform the required services; or

o any failure to comply with laws, regulations or operational practices at the site of the vessel operations.

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In the event of off-hire, all hire will cease to be due or payable for the duration of off-hire.

Additionally, we have agreed to pay liquidated damages in the event that the Höegh Grace is unable to meet specified performance standards, which are subject to various caps per cargo, per year and in the aggregate for the term of the Höegh Grace charter.

As further discussed in note 2 of our consolidated financial statements; Significant accounting policies—Time charter revenue, related contract balances and related expenses;—Performance obligations; and Contract terms, determination of transaction price and allocation to performance obligations, the performance warranties included in all of our time charters are an important element in determining variable consideration for time charter services for revenue recognition purposes.

We have obtained loss of hire insurance to protect us against loss of income in the event one of our vessels cannot be employed due to damage that is covered under the terms of our hull and machinery insurance. Please read “—Insurance and Indemnifications.”

For more information on our time charters, please read “Item 4.B. Business Overview—Vessel Time Charters.”

Impact of Our Interests in Joint Ventures on Our Financial Information

Two of the five vessels in our fleet as of December 31, 2020 are owned by our joint ventures, each of which is owned 50% by us. Please read “Item 4.B. Business Overview—Shareholder Agreements.” Under applicable accounting guidance, we do not consolidate the financial results of our joint ventures into our financial results, but we record our joint venture results using the equity method of accounting. The following provides a description of the impact of our interests in our joint ventures on selected components of our statements of income in our consolidated financial statements.

● Equity in Earnings (Losses) of Joint Ventures. Consists of our 50% share of the combined net income of our joint ventures. The net income of our joint ventures gives effect to interest expense associated with payments on the shareholder loans to the owners of our joint ventures as described below. Equity in earnings (losses) of joint ventures also includes the unrealized gains or losses on adjusting the interest rate swap contracts to fair value in each period, which can result in significant volatility between years. For the years ended December 31, 2020, 2019, and 2018 there was no income tax expense for our joint ventures. The equity in earnings (losses) of joint ventures is a “one line” consolidation of the results of our joint ventures. Therefore, our joint venture’s revenues and expenses are not included in other lines of the consolidated income statement.

● Interest Income. Interest income represents our share of interest income accrued on the advances to our joint ventures (shareholder loans). The shareholder loans were originally issued by Höegh LNG to our joint ventures and were transferred to our operating company in connection with the IPO. For a description of the shareholder loans, please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Loans Due to Owners (Shareholder Loans).”

The following provides a description of the impact of our interests in our joint ventures on selected components of our balance sheets in the consolidated financial statements.

● Advances to Joint Ventures. Represents our share of the advances to our joint ventures (shareholder loans). Please read note 9 of our consolidated financial statements.

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● Accumulated Earnings (Losses) of Joint Ventures. Accumulated earnings of joint ventures represent our share of the net assets of our joint ventures. Accumulated losses of joint ventures represent our share of the net liabilities of our joint ventures. Our joint ventures entered into interest rate swap contracts, which historically have had unrealized mark-to-market losses on the interest rate swap contracts recorded as derivative instrument liabilities on the combined balance sheets. As a result, for the periods up to and including December 31, 2018, the liabilities exceeded the assets for our joint ventures’ combined balance sheets and result in us having a net liability balance for our investment in our joint ventures. For the years ended December 31, 2020 and 2019, the assets exceeded the liabilities for our joint ventures' combined balance sheet and resulted in us having a net asset for our investment in joint ventures. Please read note 8 of our consolidated financial statements. The investment in accumulated earnings or (accumulated losses) of our joint ventures is a “one line” consolidation of the balance sheet of our joint ventures. Therefore, our joint ventures’ assets and liabilities are not included in other lines of the consolidated balance sheet.

We derive cash flows from the operations of our joint ventures from interest payments related to accrued interest on our share of the shareholder loans issued to such joint ventures. Under the terms of the shareholders’ agreement, the payments are prioritized over any dividend payment to the owners. Our joint ventures have not paid any dividends to date. The payments of interest are made based upon available cash after servicing our joint ventures’ long-term bank debt. Therefore, the payments of interest have historically been less than interest income accrued for the period. The joint ventures repaid the original principal of all shareholder loans during 2016 and all of the payments for the year ended December 31, 2017 represented payments of interest, including accrued interest to be repaid at the end of the loans. The shareholder loans are subordinated to long-term bank debt and the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt and meeting a 1.20 historical and projected debt service coverage ratio. As of September 30, 2017, the joint ventures suspended payments on the shareholder loans pending the outcome of the boil-off claim. Accordingly, the outstanding balance on the shareholder loans was classified as long-term as of December 31, 2017, 2018 and 2019. In February 2020, each of the joint ventures and the charterer reached a commercial settlement addressing all the past and future claims related to boil-off with respect to the Neptune and the Cape Ann. The final settlement and release agreements were signed on and had an effective date of April 1, 2020. The settlement amount was in line with the accrual made by the joint ventures. The first installment of the settlement was paid in April 2020 and the second and final installment of the settlement was paid in December 2020. Refer to note 17 of our consolidated financial statements under “Joint ventures boil-off settlement.” As of December 31, 2020, both the 1.20 historical and projected debt service coverage ratios were met by SRV Joint Gas Ltd. As a result, SRV Joint Gas Ltd. qualifies to make payments on the shareholder loans or other distributions. As of December 31, 2020, SRV Joint Gas Two Ltd. did not meet the 1.20 historical debt service coverage ratio but did meet the projected debt service coverage ratio. As a result, no payments on the shareholder loans or other distributions can be made by SRV Joint Gas Two Ltd. until the debt service coverage ratio is met in future periods. Refer to note 9 of our consolidated financial statements.

The following provides a description of the impacts of our interests in our joint ventures on our statement of cash flows in our consolidated financial statements:

● Cash Flows Provided by (Used in) Operating Activities. Receipt of cash payments for interest income on the shareholder loans, including accrued interest repaid from prior periods, is reflected in cash flows provided by (used in) operating activities. Such payments amounted to zero for the years ended December 31, 2020, 2019 and 2018. All other cash flows provided by (used in) operating activities relate to our other activities.

Please read our consolidated financial statements included elsewhere in this Annual Report for more detailed information.

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Historical Employment of Our Fleet

The following table describes the operations of the vessels in our fleet as of December 31, 2020.

Vessel	Description of Historical Operations
Neptune	Delivered in November 2009. Has operated under a long-term time charter with Global LNG Supply, as novated to Total Gas & Power in February 2020, which commenced on delivery.
Cape Ann	Delivered in June 2010. Has operated under a long-term time charter with Global LNG Supply, as novated to Total Gas & Power in February 2020, which commenced on delivery.
PGN FSRU Lampung	Delivered in April 2014. Has operated under a long-term time charter with PGN LNG, which commenced on July 21, 2014.
Höegh Gallant	Delivered in November 2014. Acquired on October 1, 2015. Has operated under a time charter with EgyptCo since the acquisition date until April 2020. Afterwards the vessel has operated under the Subsequent Charter with a subsidiary of Höegh LNG, which commenced on May 1, 2020.
Höegh Grace	Delivered in March 2016. Acquired 51% ownership interest on January 3, 2017 and acquired the remaining 49% ownership interest on December 1, 2017. Has operated under a long-term time charter with SPEC since acquisition date.

Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects

You should consider the following facts when evaluating our historical results of operations and assessing our future prospects:

● The size of our fleet has changed. Our historical results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries. The PGN FSRU Lampung was delivered from the shipyard in April 2014 and commenced operations in July 2014 and, as such, has had historical operations for each of the years ended December 31, 2015 to December 31, 2020. As of October 1, 2015, we increased our fleet with the acquisition of the Höegh Gallant which contributed to our results of operations starting in the fourth quarter of 2015. Commencing on January 1, 2017, the Höegh Grace has contributed to our earnings due to our acquisition of a 51% ownership interest in the Höegh Grace entities. On December 1, 2017, we acquired the remaining 49% ownership interest in the Höegh Grace entities. From January 1, 2017 until November 30, 2017, our net income was reduced with a non-controlling interest to arrive at the limited partners’ interest in net income. As of December 1, 2017, the Höegh Grace has contributed 100% to our earnings without a reduction of non-controlling interest as such, the operations of the Höegh Grace have contributed 100% to our earnings during 2020, 2019 and 2018. Furthermore, we may grow through the acquisition in the future of additional vessels as part of our growth strategy.

● Preferred unitholders have an interest in net income. The Series A preferred units represent perpetual equity interests in us. The Series A preferred units rank senior to our common units as to the payment of distributions and amounts payable upon liquidation, dissolution or winding up. The distribution rate on the Series A preferred units is 8.75% per annum. The distributions accrue and are cumulative. Distributions are payable quarterly, when, and if declared by the Partnership’s board of directors out of legally available funds for such purpose. The preferred unitholders’ interest in net income is equivalent to the amount of preferred unitholders’ distribution for the given quarter or annual period and reduces the net income attributable to the limited partners’ interest in net income.

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● Our historical results of operations are affected by significant gains and losses relating to derivative transactions. Our historical results of operations reflect significant gains and losses relating to the joint ventures’ interest rate swap contracts that impact our equity in earnings (losses) for our joint ventures. The joint ventures’ interest rate swap contracts are not designated as hedges for accounting purposes. As a result, there is volatility in earnings for the unrealized exchange gains and losses on the interest rate swap contracts. On March 17, 2014, we entered into interest rate swap contracts related to the Lampung facility (as defined below). On October 1, 2015, we assumed the interest rate swap contracts related to the Gallant facility (as defined below) as part of the acquisition of the Höegh Gallant. On January 1, 2017, we assumed the interest rate swap contracts related to the Grace facility (as defined below) as part of the acquisition of 51% ownership interest in the Höegh Grace entities. The interest rate swaps related to the Lampung facility, the Gallant facility and the Grace facility were designated as cash flow hedges for accounting purposes, however, certain amortization and the ineffective portion of the hedge for the years up to and including December 31, 2018, impacts the results of operations. Starting January 1, 2019, under the revised accounting guidance for hedge accounting, the impact of the ineffective portion of the hedge is recorded as a component of other comprehensive income and does not impact the results of operations. Hedge accounting was discontinued for interest rate swaps related to the Gallant and Grace facilities in the fourth quarter of 2018 as a result of firm commitment for the refinancing of the facilities which occurred on January 29, 2019. On January 31, 2019, the interest rate swaps related to the Gallant and Grace facilities were settled. In December 2018 and February 2019, the Partnership entered into interest rate swaps for the commercial tranches of a new $385 million facility to refinance the debt facility for the Höegh Gallant and the Höegh Grace, which were designed as cash flow hedges. Refer to note 16 of our consolidated financial statements. We may enter into (i) additional interest rate swap contracts to economically hedge all or a portion of our exposure to floating interest rates and (ii) foreign currency swap contracts to economically hedge risk from foreign currency fluctuations.

● Our historical results of operations are impacted by management and service fees for vessel operating and administrative expenses provided by Höegh LNG’s affiliates. Our operating entities entered into a variety of management, technical service and consulting agreements with affiliates of Höegh LNG related to the operations of the vessels. In addition, we and our operating company entered into administrative services agreements with affiliates of Höegh LNG. Refer to "Item 7. B. Related Party Transactions" for information on the management and service fees for these agreements.

● Our results of operations are affected by accounting for the PGN FSRU Lampung time charter as a financing lease. When the PGN FSRU Lampung began operating under her charter, we recorded a receivable (net investment in financing lease) and removed the PGN FSRU Lampung from our balance sheet. The lease element of time charter payments under the PGN FSRU Lampung time charter is split between revenues and the repayment of part of the receivable. The revenues are recorded using the effective interest method, which provides for a constant rate of return on the net investment. As a result, the revenues will decline over time as more of the time charter payments are treated as a repayment of the receivable. However, the cash flows from the PGN FSRU Lampung are not impacted by the accounting treatment. In addition, since there is no vessel  on the balance sheet, there is no charge for depreciation expense. In our consolidated statements of cash flows for the year ended December 31, 2020 and 2019, the time charter payments reflected as revenues and for repayment of the receivable are included under net cash provided by (used in) operating activities. In our consolidated statements of cash flows for the year ended December 31, 2018, the time charter payments reflected as revenues are included under net cash provided by (used in) operating activities while the repayment of the receivable are included under net cash provided by (used in) investing activities. The change in classification in cash flows for 2019 and onwards related to the cash flows from the repayment of the lease receivable is a result of adopting the revised guidance for leases on January 1, 2019.

● Outbreaks of epidemic and pandemic diseases and governmental responses thereto could adversely affect our business. Our operations are subject to risks related to outbreaks of infectious diseases. For example, the recent COVID-19 outbreak has negatively affected economic conditions and may otherwise impact our operations, including availability of crew, and the operations of our customers and suppliers. Although our operations have not been materially affected by the COVID-19 outbreak to date, the ultimate length and severity of the COVID-19 outbreak is uncertain at this time.

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● Our future business and prospects may be impacted by the Amalgamation. Following the Amalgamation, unless otherwise agreed by the parties, some provisions of the omnibus agreement that we entered into with Höegh LNG in connection with the IPO will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels, (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

Factors Affecting Our Results of Operations

We believe the principal factors that will affect our future results of operations include:

● the number of vessels in our fleet;

● our ability to successfully employ our vessels at economically attractive hire rates as long-term charters expire or are otherwise terminated;

● our ability to maintain strong relationships with our existing customers and to increase the number of customer relationships;

● the operating performance of our vessels and any related performance warranty claims by customers;

● our ability to acquire additional vessels, including Höegh LNG’s other vessels and any effect the Amalgamation may have on such ability;

● our ability to raise capital to fund acquisitions;

● the levels of demand for FSRU and LNG carrier services and other LNG infrastructure;

● the supply and capacities of FSRUs;

● the hire rate earned by our vessels, unscheduled off-hire days and the level of our vessel operating expenses;

● the effective and efficient technical and maritime management and crewing of our vessels;

● economic, regulatory, political and governmental conditions that affect the floating LNG industry;

● interest rate changes;

● mark-to-market changes in interest rate swap contracts;

● foreign currency exchange gains and losses;

● our access to capital required to acquire additional vessels and/or to implement our business strategy;

● variations in crewing and insurance costs;

● the level of our debt and the related interest expense; and

● the amount of distributions on our common and preferred units.

Please read “Item 3.D. Risk Factors” for a discussion of certain risks inherent in our business.

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Customers

For the years ended December 31, 2020, 2019 and 2018 time charter revenues in the consolidated statement of income are from PGN LNG, a subsidiary of PGN, a subsidiary of PT Pertamina, a government controlled Indonesian oil and gas producer, natural gas transportation and distribution company; EgyptCo, a subsidiary of Höegh LNG; CharterCo, a subsidiary of Höegh LNG; and SPEC, which is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. Revenues included as a component of equity in earnings (losses) of joint ventures are from Total Gas & Power and accounted for 100% of our joint ventures’ time charter revenues for all periods presented. Total Gas & Power is a subsidiary of Total, a French publicly listed company.

Inflation and Cost Increases

Inflation has not had a significant impact on operating expenses, including crewing costs, for the Neptune and the Cape Ann. FSRUs are specialized vessels, and there has been demand for experienced crew, which has led to higher crew costs. The Neptune and the Cape Ann time charters provide for operating cost pass-through, which means that we will be able to pass on the cost increases to the charterer.

A portion of the operating cost for the PGN FSRU Lampung will increase for inflation in Indonesia, including part of the crew cost and certain supplies. Indonesian inflation has ranged from approximately 2.0% to approximately 4.0% in recent years. The PGN FSRU Lampung time charter provides that the operating cost component of the hire rate, established at the beginning of the time charter, will increase by a fixed percentage per year for the first five years and be reset each fifth year based on the average increase over the previous five years, which is expected to somewhat mitigate cost increases.

The Höegh Gallant has operated as an LNG carrier during 2020 and 2019. Inflation has not had a significant impact on operating expenses during both 2020 and 2019.

The Höegh Grace operates in Colombia and inflation in Colombia has ranged from approximately 2.0% to over 7.0% in recent years. All revenues under the Höegh Grace charter are received in U.S. dollars. A limited amount of operating expenses related to the Höegh Grace is denominated in Colombian Pesos, and as such, we bear a limited risk of cost increase due to inflation or exchange rates.

Insurance and indemnifications

Please read “Item 4.B. Business Overview—Risk of Loss, Insurance and Risk Management” for information on the insurance coverage of certain risks inherent in our business.

Environmental indemnifications. Under the omnibus agreement, Höegh LNG agreed to indemnify the Partnership until August 12, 2019 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to the Partnership to the extent arising prior to the time they were contributed or sold to the Partnership. No indemnification claims were filed for environmental liabilities under the agreement prior to its expiration.

Other indemnifications. Under the omnibus agreement, Höegh LNG also agreed to indemnify the Partnership for losses:

● related to certain defects in title to the assets contributed or sold to the Partnership and any failure to obtain, prior to the time they were contributed to the Partnership, certain consents and permits necessary to conduct the business, which liabilities arose within three years after the closing of the IPO;

● related to certain tax liabilities attributable to the operation of the assets contributed or sold to the Partnership prior to the time they were contributed or sold;

● in the event that the Partnership does not receive hire rate payments under the PGN FSRU Lampung time charter for the period commencing on August 12, 2014 through the earlier of (i) the date of acceptance of the PGN FSRU Lampung or (ii) the termination of such time charter. The Partnership was indemnified by Höegh LNG for the September 2014 and October 2014 invoices not paid by PGN LNG (refer to notes 14 and 17 of our consolidated financial statements);

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● with respect to any obligation to pay liquidated damages to PGN LNG under the PGN FSRU Lampung time charter for failure to deliver the PGN FSRU Lampung by the scheduled delivery date set forth in the PGN FSRU Lampung time charter;

● with respect to any non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project (including the construction of the Mooring) occurring prior to the date of acceptance of the PGN FSRU Lampung pursuant to the time charter; and

● pursuant to a letter agreement dated August 12, 2015, Höegh LNG confirmed that the indemnification provisions of the omnibus agreement include indemnification for all non-budgeted, non-creditable Indonesian value added taxes and non-budgeted Indonesian withholding taxes, including any related impact on cash flow from PT Höegh and interest and penalties associated with any non-timely Indonesian tax filings related to the ownership or operation of the PGN FSRU Lampung and the Mooring whether incurred (i) prior to the closing date of the IPO, (ii) after the closing date of the IPO to the extent such taxes, interest, penalties or related impact on cash flows relate to periods of ownership or operation of the PGN FSRU Lampung and the Mooring and are not subject to prior indemnification payments or deemed reimbursable by the charterer under its audit of the taxes related to the PGN FSRU Lampung time charter for periods up to and including June 30, 2015, or (iii) after June 30, 2015 to the extent withholding taxes exceed the minimum amount of withholding tax due under Indonesian tax regulations due to lack of documentation or untimely withholding tax filings.

For the year ended December 31, 2018, the Partnership received indemnification payments from Höegh LNG for non-budgeted expenses (including warranty provisions, other non-budgeted expenses and replacement capital expenditure) of $0.9 million, which was recorded as a contribution to equity. Indemnification payments received from Höegh LNG are subject to repayment to the extent the amounts are subsequently recovered from insurance or deemed reimbursable by the charterer.

For the years ended December 31, 2019 and 2018, the Partnership refunded to Höegh LNG approximately $0.1 million and $2.4 million, respectively, related to insurance proceeds received related to the warranty provision and costs for previous years determined to be reimbursable by the charterer. No indemnification was filed or received for the year ended December 31, 2020. Refer to notes 14 and 17 to our consolidated financial statements.

Under the contribution, purchase and sale agreement entered into with respect to the purchase of the entity that indirectly owns the Höegh Gallant, Höegh LNG will indemnify the Partnership for:

● losses from breach of warranty;

● losses related to certain environmental and tax liabilities attributable to the operation of the Höegh Gallant prior to the closing date;

● all capital gains tax or other export duty incurred in connection with the transfer of the Höegh Gallant outside of Höegh Cyprus’s permanent establishment in a Public Free Zone in Egypt;

● any recurring non-budgeted costs owed to Höegh LNG Management with respect to payroll taxes;

● any non-budgeted losses suffered or incurred in connection with the commencement of services under the time charter with EgyptCo or EgyptCo’s time charter with EGAS; and

● liabilities under the Gallant/Grace facility not attributable to the Höegh Gallant.

Additionally, Höegh LNG has guaranteed the payment of hire pursuant to the time charter for the Höegh Gallant.

For the year ended December 31, 2018, the Partnership received indemnification payment from Höegh LNG for losses incurred in connection with the time charter of $0.5 million, which was recorded as a contribution to equity. Refer to notes 14 and 17 to our consolidated financial statements.

Under the contribution, purchase and sale agreement entered into with respect to the acquisition of the 51% and 49% ownership interest in the Höegh Grace entities, Höegh LNG will indemnify the Partnership for:

● losses from breach of warranty;

● losses related to certain environmental liabilities, damages or repair costs and tax liabilities attributable to the operation of the Höegh Grace prior to the closing date;

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● any recurring non-budgeted costs owed to tax authorities with respect to payroll taxes, taxes related to social security payments, corporate income taxes (including income tax for equality and surcharge on income tax for equality), withholding tax, port associations, local Cartagena tax, and financial transaction tax, including any penalties associated with taxes to the extent not reimbursed by the charterer; and

● any non-budgeted losses suffered or incurred in connection with the commencement of services under the Höegh Grace charter with SPEC.

No indemnification claims were filed or received for the years ended December 31, 2020, 2019 and 2018.

On September 27, 2017, the Partnership entered into an indemnification agreement with Höegh LNG with respect to the boil-off claims under the Neptune and the Cape Ann time charters, pursuant to which Höegh LNG will, among other things, indemnify the Partnership for its share of any losses and expenses related to or arising from the failure of either Neptune or Cape Ann to meet the performance standards related to the daily boil-off of LNG under their respective time charters (including any cash impact that may result from any settlement with respect to such claims.) For the year ended December 31, 2018 the Partnership received indemnification payments of $0.3 million from Höegh LNG. For the year ended December 31, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures boil-off settlement payments to its charterer by a reduction of $11.9 million on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. Indemnification payments and the non-cash settlements were recorded as a contribution to equity and increase to equity, respectively. Refer to notes 14 and 17 to our consolidated financial statements.

A.Operating Results

The following table summarizes our operating results for the years ended December 31, 2020, 2019 and 2018:

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019		2018
Statement of Income Data:
Time charter revenues	$	143,095	$	145,321	$	144,952
Other revenue		—		115		1,609
Total revenues		143,095		145,436		146,561
Vessel operating expenses		(24,072)		(30,870)		(24,195)
Administrative expenses		(9,740)		(9,861)		(8,916)
Depreciation and amortization		(20,937)		(21,477)		(21,146)
Total operating expenses		(54,749)		(62,208)		(54,257)
Equity in earnings (losses) of joint ventures		6,420		6,078		17,938
Operating income (loss)		94,766		89,306		110,242
Interest income		605		947		725
Interest expense		(24,430)		(27,692)		(26,814)
Gain (loss) on debt extinguishment		—		1,030		—
Gain (loss) on derivative instruments		—		—		4,681
Other items, net		(2,232)		(3,575)		(2,907)
Total financial income (expense), net		(26,057)		(29,290)		(24,315)
Income (loss) before tax		68,709		60,016		85,927
Income tax expense		(5,564)		(7,275)		(8,305)
Net income (loss)	$	63,145	$	52,741	$	77,622
Preferred unitholders' interest in net income		14,802		13,850		12,303
Limited partners' interest in net income (loss)	$	48,343	$	38,891	$	65,319

Financial Highlights in 2020

The following sets forth our significant developments for the year ended December 31, 2020:

● Reported time charter revenues were $143.1 million for the year ended December 31, 2020 compared to $145.3 million for the year ended December 31, 2019;

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● Operating income was $94.8 million for the year ended December 31, 2020 compared to $89.3 million for the year ended December 31, 2019; operating income was impacted by unrealized losses on derivative instruments for the years ended December 31, 2020 and 2019 on the Partnership's share of equity in earnings (losses) of joint ventures;

● Unrealized loss on derivative instruments was $6.1 million on the Partnership’s share of equity in earnings of joint ventures for the year ended December 31, 2020, compared to unrealized loss on derivative instruments of $5.2 million on the Partnership’s share of equity in earnings of joint ventures for the year ended December 31, 2019;

● Excluding the impact of the unrealized losses on derivatives, the increase in operating income was primarily due to lower vessel operating expenses largely as a result of maintenance performed for the PGN FSRU Lampung and the Höegh Gallant in 2019 and Indonesian property tax and penalties in 2019;

● Net income was $63.1 million for the year ended December 31, 2020 compared to $52.7 million for the year ended December 31, 2019.

Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019

Time Charter Revenues. The following table sets forth details of our time charter revenues for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Time charter revenues	$	143,095	$	145,321	$	(2,226)

Time charter revenues for the year ended December 31, 2020 were $143.1 million, a decrease of $2.2 million from $145.3 million for the year ended December 31, 2019. The decrease was mainly due to lower time charter revenues for the Höegh Gallant and for the PGN FSRU Lampung. On May 1, 2020, the Höegh Gallant commenced the Subsequent Charter (as described below) with a subsidiary of Höegh LNG. The hire rate under the Subsequent Charter is lower than under the prior time charter, resulting in lower time charter revenues for the Höegh Gallant for the year ended December 31, 2020 compared with the year ended December 31, 2019. The Höegh Gallant had no off-hire days for the year ended December 31, 2020 compared with reduced hire equivalent to 16 days of off-hire in relation to a scheduled drydock during the year ended December 31, 2019. The impact from being on-hire for the year ended December 31, 2020 was more than offset by the impact of lower revenues under the terms of the Subsequent Charter that commenced on May 1, 2020. Time charter revenues for the PGN FSRU Lampung were impacted in the year ended December 31, 2019 by the conclusion of audits by the charterer of the final amounts that would be reimbursed for prior year expenses which resulted in the recognition of revenue that was previously considered constrained variable consideration. Time charter revenues for the Höegh Grace were at the same level for both the year ended December 31, 2020 and 2019. The PGN FSRU Lampung and the Höegh Grace were both on-hire for the full periods ended December 31, 2020 and 2019.

Time charter revenues for the PGN FSRU Lampung consisted of the lease element of the time charter, accounted for as a financing lease using the effective interest rate method, as well as fees for providing time charter services, reimbursement for vessel operating expenses, performance warranties, if any, and withholding and current income taxes borne by the charterer. Time charter revenues for the Höegh Gallant consisted of the fixed daily hire rate which covers the operating lease and the provision of time charter services including the costs incurred to operate the vessel and performance warranties, if any. The time charter revenues for the Höegh Grace consisted of a lease element accounted for as an operating lease, as well as variable consideration for providing time charter services, reimbursement of vessel operating expenses, performance warranties, if any, and certain taxes incurred.

On April 30, 2020, the Partnership entered into the Subsequent Charter with CharterCo, a subsidiary of Höegh LNG for the time charter of the Höegh Gallant. The hire rate under the Subsequent Charter is equal to 90% of the rate payable pursuant to the prior charter of the Höegh Gallant, subject to certain adjustments for i) avoided FSRU related costs only when operating in LNG carrier mode and ii) higher incremental taxes or operating expenses when operating in FSRU mode. The Subsequent Charter commenced on May 1, 2020 and expires on July 31, 2025.

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Other revenue. The following table sets forth details of our vessel operating expenses for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Other revenue	$	—	$	115	$	(115)

Other revenue for the year ended December 31, 2019 consists of insurance proceeds received for a claim related to the PGN FSRU Lampung's warranty work from prior periods.

Vessel Operating Expenses. The following table sets forth details of our vessel operating expenses for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Vessel operating expenses	$	(24,072)	$	(30,870)	$	6,798

Vessel operating expenses for the year ended December 31, 2020 were $24.1 million, a decrease of $6.8 million from $30.9 million for the year ended December 31, 2019. The lower expenses were mainly due to maintenance expenses of approximately $4.1 million for the year ended December 31, 2019, principally for the Höegh Gallant but also for the PGN FSRU Lampung. During the scheduled drydock of the Höegh Gallant and the on-water survey of the PGN FSRU Lampung, the opportunity was utilized to complete as many maintenance procedures as possible. In addition, vessel operating expenses for the year ended December 31, 2019 included $3.0 million of Indonesian property tax and penalties that was assessed on the PGN FSRU Lampung for the years 2015 through 2019. The retroactive assessment was as a result of the issuance of a new regulation in 2019 defining FSRUs as subject to the existing Indonesian property tax law.

Administrative Expenses. The following table sets forth details of our administrative expenses for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Administrative expenses	$	(9,740)	$	(9,861)	$	121

Administrative expenses for the year ended December 31, 2020 were $9.7 million, a decrease of $0.2 million from $9.9 million for the year ended December 31, 2019. The decrease reflects lower administrative expenses for partnership expenses for the year ended December 31, 2020 compared to the year ended December 31, 2019.

Depreciation and Amortization. The following table sets forth details of our depreciation and amortization for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Depreciation and amortization	$	(20,937)	$	(21,477)	$	540

Depreciation and amortization for the year ended December 31, 2020 were $20.9 million, a decrease of $0.6 million from $21.5 million for the year ended December 31, 2019. In 2019, a drydock was completed for the Höegh Gallant. As a result, the remaining depreciation for the drydock component was expensed. In addition, onshore assets in the Egypt Branch were fully depreciated at the end of April 2020.

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Total Operating Expenses. The following table sets forth details of our total operating expenses for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Total operating expenses	$	(54,749)	$	(62,208)	$	7,459

Total operating expenses for the year ended December 31, 2020 were $54.7 million, a decrease of $7.5 million from $62.2 million for the year ended December 31, 2019. The decrease is a result of the lower vessel operating expenses and depreciation principally due to maintenance performed during the drydock for the Höegh Gallant and the on-the water class renewal survey for the PGN FSRU Lampung during 2019 and the retroactively assessed property tax in 2019.

Equity in Earnings (Losses) of Joint Ventures. The following table sets forth details of our equity in earnings (losses) of joint ventures for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Equity in earnings (losses) of joint ventures	$	6,420	$	6,078	$	342

Equity in earnings of joint ventures for the year ended December 31, 2020 was $6.4 million, an increase of $0.3 million from equity in earnings of $6.1 million for the year ended December 31, 2019. Equity in earnings of joint ventures was impacted by unrealized losses on derivative instruments of $6.1 million for the year ended December 31, 2020 compared with unrealized losses on derivative instruments of $5.2 million for the year ended December 31, 2019.

Our share of our joint ventures’ operating income was $24.2 million for the year ended December 31, 2020, an increase of $0.8 million compared with $23.4 million for the year ended December 31, 2019. The increase was primarily due to higher time charter revenues and lower administrative expenses, which were partly offset by higher vessel operating expenses and higher losses on derivative instruments for the year ended December 31, 2020 compared to the year ended December 31, 2019.

Our share of other income (expense), net, principally consisting of interest expense, was $11.7 million for the year ended December 31, 2020, a decrease of $0.4 million from $12.1 million for the year ended December 31, 2019. The reduction in interest expense was principally due to the repayment of outstanding loan balances for bank financing during the year ended December 31, 2020.

Our share of unrealized losses on derivative instruments was $6.1 million for the year ended December 31, 2020, an increase of $0.9 million compared to our share of unrealized losses on derivative instruments of $5.2 million for the year ended December 31, 2019. The joint ventures utilize interest rate swap contracts to exchange floating interest rate payments for fixed interest rate payments to reduce the exposure to interest rate variability on their outstanding floating-rate debt. The interest rate swap contracts are not designated as hedges for accounting purposes. As a result, there is volatility in earnings for the unrealized exchange gains and losses on the interest rate swap contracts.

There was no accrued income tax expense for the years ended December 31, 2020 and 2019. Our joint ventures did not pay any dividends for the years ended December 31, 2020 and 2019.

Operating Income. The following table sets forth details of our operating income for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Operating income (loss)	$	94,766	$	89,306	$	5,460

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Operating income for the year ended December 31, 2020 was $94.8 million, an increase of $5.5 million from $89.3 million for the year ended December 31, 2019. Excluding the unrealized losses on derivatives for the year ended December 31, 2020 and 2019 impacting the equity in earnings of joint ventures, operating income for the year ended December 31, 2020 would have been $100.8 million, an increase of $6.3 million from $94.5 million for the year ended December 31, 2019. Excluding the impact of the unrealized losses on derivatives, the increase for the year ended December 31, 2020 is primarily due to lower vessel operating expenses, largely as a result of the higher maintenance expense and property tax and penalties during 2019 and higher equity in earnings of joint ventures for the year ended December 31, 2020. This was partially offset by the impact of lower time charter revenues as a result of reduced hire rate in the Subsequent Charter that commenced on May 1, 2020.

Interest Income. The following table sets forth details of our interest income for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Interest income	$	605	$	947	$	(342)

Interest income for the year ended December 31, 2020 was $0.6 million, a decrease of $0.3 million from $0.9 million for the year ended December 31, 2019. Interest income is mainly related to cash balances and interest accrued on the advances to our joint ventures for the years ended December 31, 2020 and 2019. The interest rate under the shareholder loans to our joint ventures is a fixed rate of 8.0% per year.

Interest Expense. The following table sets forth details of our interest expense for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Interest expense	$	(21,830)	$	(25,128)	$	3,298
Amortization and gain (loss) on cash flow hedge		(173)		178		(351)
Commitment fees		(138)		(381)		243
Amortization of debt issuance cost and fair value of debt assumed		(2,289)		(2,361)		72
Total interest expense	$	(24,430)	$	(27,692)	$	3,262

Total interest expense for the year ended December 31, 2020 was $24.4 million, a decrease of $3.3 million from $27.7 million for the year ended December 31, 2019. Interest expense consists of the interest incurred, amortization and gain (loss) on cash flow hedge, commitment fees and amortization of debt issuance cost and fair value of debt assumed.

The interest incurred of $21.8 million for the year ended December 31, 2020 decreased by $3.3 million compared to $25.1 million for the year ended December 31, 2019. The decrease was principally due to repayment of outstanding loan balances for the loan facilities related to the PGN FSRU Lampung (the "Lampung facility") and the commercial and export tranches of the $385 million facility financing the Höegh Gallant, the Höegh Grace and the Partnership’s liquidity needs (the “$385 million facility”).

Amortization and gain (loss) on cash flow hedge was a loss of $0.2 million for the year ended December 31, 2020 compared to a gain of $0.2 million for the year ended December 31, 2019. For the year ended December 31, 2020, the loss solely related to amortization of amounts excluded from hedge effectiveness for discontinued hedges and the initial fair values of interest rate swaps. For the year ended December 31, 2019, the gain was mainly due to the inclusion of a gain on the settlement of the interest rate swaps terminated when the Gallant/Grace facility was extinguished.

Commitment fees were $0.14 million for the year ended December 31, 2020, a decrease of $0.24 million from $0.38 million for the year ended December 31, 2019. For the year ended December 31, 2020 and 2019, the commitment fees relate to the undrawn portion of the $63 million revolving credit tranche of the $385 million facility.

Amortization of debt issuance cost and fair value of debt assumed for the year ended December 31, 2020 was $2.3 million compared to $2.4 million for the year ended December 31, 2019. The decrease in amortization of debt issuance cost and fair value in of debt assumed is a result of the effective interest rate used for amortization.

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Gain (Loss) on Debt Extinguishment. The following table sets forth details of our gain (loss) on debt extinguishment for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Gain (loss) on debt extinguishment	$	—	$	1,030	$	(1,030)

Gain on debt extinguishment for the year ended December 31, 2019 of $1.0 million related to the repayment of the Gallant/Grace facility on January 31, 2019. The unamortized amounts related to the fair value of debt assumed, or premium, recognized in relation to the acquisitions of the entities owning the Höegh Gallant on October 1, 2015 and the entities owning the Höegh Grace on January 1, 2017, of approximately $1.0 million, which was recognized as a gain on January 31, 2019 due to the extinguishment of the Gallant/Grace facility.

Other Items, Net. The following table sets forth details of our other items for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Foreign exchange gain (loss)	$	444	$	(396)	$	840
Bank charges, fees and other		(276)		(297)		21
Withholding tax on interest expense and other		(2,400)		(2,882)		482
Total other items, net	$	(2,232)	$	(3,575)	$	1,343

Other items, net for the year ended December 31, 2020 were $2.2 million, a decrease of $1.4 million from $3.6 million for the year ended December 31, 2019. The decrease is mainly due to foreign exchange gains of $0.4 million for the year ended December 31, 2020 compared to foreign exchange losses of $0.4 million for the year ended December 31, 2019 and lower withholding tax on interest expense for the year ended December 31, 2020, compared to the year ended December 31, 2019. Withholding tax is primarily payable on interest expense to parties outside of Singapore and Indonesia.

Income (Loss) Before Tax. The following table sets forth details of our income before tax for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Income (loss) before tax	$	68,709	$	60,016	$	8,693

Income before tax for the year ended December 31, 2020 was $68.7 million, an increase of $8.7 million from $60.0 million for the year ended December 31, 2019. Excluding all the unrealized gains (losses) on derivative instruments, income before tax for the year ended December 31, 2020 would have been $75.0 million, an increase of $9.8 million from $65.2 million for the year ended December 31, 2019. Excluding the unrealized gains (losses) on derivative instruments, the increase is primarily due to lower vessel operating expenses, administration expenses, depreciation and higher results from equity in earnings of joint ventures, partially offset by reduced time charter revenues during 2020 and no gain on debt extinguishment in 2020.

Income Tax Expense. The following table sets forth details of our income tax expense for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Income tax expense	$	(5,564)	$	(7,275)	$	1,711

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Income tax expense was $5.6 million for the year ended December 31, 2020, a decrease of $1.7 million compared to $7.3 million for the year ended December 31, 2019. The main reason for the decrease was the reduction of the tax rate in Indonesia which was enacted on March 31, 2020. The tax rate decreased from 25% for 2019 to 22% for 2020 and 2021, with further reduction to occur thereafter. The effect of changes in tax rates on deferred tax assets and liabilities is recognized at the date of enactment.

We are not subject to Marshall Islands corporate income taxes. However, we are subject to tax for earnings of our subsidiaries incorporated in Singapore, Indonesia, Cyprus and the UK and for certain Colombian source income. For the years ended December 31, 2020 and 2019, the tax expense principally related to subsidiaries in Indonesia, Singapore and Colombia. The Singapore subsidiary’s taxable income mainly arises from internal interest income. The charterer in Colombia pays certain taxes directly to the Colombian tax authorities on behalf of the Partnership’s subsidiaries that own and operate the Höegh Grace. The tax payments are a mechanism for advance collection of part of the income taxes for the Colombian subsidiary and a final income tax on Colombian source income for the non-Colombian subsidiary. We concluded these third-party payments to the tax authorities represent income taxes that must be accounted for under the guidance for income taxes. The amount of non-cash income tax expense was $0.9 million for the years ended December 31, 2020 and 2019.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. For the year ended December 31, 2020, there was an increase to the uncertain tax position of $0.4 million for a tax position to be taken in the 2020 tax return which is not more-likely-than-not to be sustained. As of December 31, 2020, the unrecognized tax benefits were $2.7 million. Refer to note 6 of our consolidated financial statements for additional information.

Net Income (Loss). The following table sets forth details of our net income for the years ended December 31, 2020 and 2019:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2019		2019		variance
Net income (loss)	$	63,145	$	52,741	$	10,404
Preferred unitholders' interest in net income		14,802		13,850		952
Limited partners' interest in net income (loss)	$	48,343	$	38,891	$	9,452

As a result of the foregoing, net income for the year ended December 31, 2020 was $63.1 million, an increase of $10.4 million compared with net income of $52.7 million for the year ended December 31, 2019.

For the years ended December 31, 2020 and 2019, net income of $14.8 million and $13.8 million, respectively, was attributable to the holders of the Series A preferred units, an increase of $1.0 million due to additional preferred units issued as part of our at-the-market offering program. Our limited partners' interest in net income, for the year ended December 31, 2020 was $48.3 million, an increase of $9.4 million compared to $38.9 million for the year ended December 31, 2019.

Segments

There are two operating segments. The segment profit measure is Segment EBITDA, which is defined as earnings before interest, taxes, depreciation, amortization and impairment and other financial items (gain (loss) on debt extinguishment, gain (loss) on derivative instruments and other items, net). Segment EBITDA is reconciled to operating income and net income in the segment presentation below. Please read “Item 3.A. Selected Financial Data—Non-GAAP Financial Measures” for a definition of Segment EBITDA and a reconciliation of Segment EBITDA to net income. The two segments are “Majority held FSRUs” and “Joint venture FSRUs.” In addition, unallocated corporate costs, interest income from advances to joint ventures, and interest expense related to the outstanding balances on the $85 million revolving credit facility and the $385 million facility are included in “Other.”

For the years ended December 31, 2020 and 2019, Majority held FSRUs includes the financing lease related to the PGN FSRU Lampung and the operating leases related to the Höegh Gallant and the Höegh Grace.

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For the years ended December 31, 2020 and 2019, Joint venture FSRUs include the operating leases related to two 50% owned FSRUs, the Neptune and the Cape Ann, that operate under long term time charters with one charterer.

The accounting policies applied to the segments are the same as those applied in the consolidated financial statements, except that i) Joint venture FSRUs are presented under the proportional consolidation method for the segment note and under equity accounting for the consolidated financial statements and ii) internal interest income and interest expense between the Partnership's subsidiaries that eliminate in consolidation are not included in the segment columns for the other financial income (expense), net line. Under the proportional consolidation method, 50% of the Joint venture FSRUs’ revenues, expenses and assets are reflected in the segment note. Management monitors the results of operations of joint ventures under the proportional consolidation method and not the equity method of accounting.

Majority Held FSRUs. The following table sets forth details of segment results for the Majority held FSRUs for the years ended December 31, 2020 and 2019:

	Year ended				Positive
Majority Held FSRUs	December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Time charter revenues	$	143,095	$	145,321	$	(2,226)
Other revenue		—		115		(115)
Total revenues		143,095		145,436		(2,341)
Vessel operating expenses		(24,072)		(30,870)		6,798
Administrative expenses		(3,390)		(3,396)		6
Segment EBITDA		115,633		111,170		4,463
Depreciation, amortization and impairment		(20,937)		(21,477)		540
Operating income (loss)		94,696		89,693		5,003
Gain (loss) on debt extinguishment		—		1,030		(1,030)
Other financial income (expense), net		(9,072)		(12,511)		3,439
Income (loss) before tax		85,654		78,212		7,412
Income tax expense		(5,564)		(7,278)		1,714
Net income (loss)	$	80,060	$	70,934	$	9,126
Limited partners' and preferred unitholders' interest in net income (loss)	$	80,060	$	70,934	$	9,126

Time charter revenues for the year ended December 31, 2020 were $143.1 million, a decrease of $2.2 million from $145.3 million for the year ended December 31, 2019. As discussed above, the decrease was mainly due to lower time charter revenues for the Höegh Grace and for the PGN FSRU Lampung. The decrease in revenues for the Höegh Gallant related to the Subsequent Charter that commenced on May 1, 2020 and which has lower daily rates. Time charter revenues for the PGN FSRU Lampung were impacted in the year ended December 31, 2019 by the conclusion of audits by the charterer of the final amounts that would be reimbursed for prior year expenses which resulted in the recognition of revenue that was previously considered constrained variable consideration. Time charter revenues for the Höegh Grace were at the same level for both the year ended December 31, 2020 and 2019. The PGN FSRU Lampung and the Höegh Grace were both on-hire for the full periods ended December 31, 2020 and 2019.

Other revenue for the years ended December 31, 2019 consists of insurance proceeds received for a claim related to the PGN FSRU Lampung's warranty work from prior periods.

Vessel operating expenses for the year ended December 31, 2020 were $24.1 million compared to $30.9 million for the year ended December 31, 2019. The lower expenses were mainly due to maintenance expenses of approximately $4.1 million for the year ended December 31, 2019, principally for the Höegh Gallant but also for the PGN FSRU Lampung. During the scheduled drydock of the Höegh Gallant and the on-water survey of the PGN FSRU Lampung, the opportunity was utilized to complete as many maintenance procedures as possible. In addition, vessel operating expenses for the year ended December 31, 2019 included $3.0 million of Indonesian property tax and penalties that was assessed on the PGN FSRU Lampung for the years 2015 through 2019. The retroactive assessment was as a result of the issuance of a new regulation in 2019, defining FSRUs as subject to the existing Indonesian property tax law.

Administrative expenses for both the year ended December 31, 2020 and 2019 were $3.4 million.

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Segment EBITDA for the year ended December 31, 2020 was $115.7 million, an increase of $4.5 million from $111.2 million for the year ended December 31, 2019. The increase was mainly due to decreased maintenance expenses and the retroactively assessed property tax which was partially offset by lower time charter revenues due to commencement of the Subsequent Charter for the Höegh Gallant on May 1, 2020.

Joint Venture FSRUs. The following table sets forth details of segment results for the Joint venture FSRUs for the years ended December 31, 2020 and 2019:

	Year ended				Positive
Joint Venture FSRUs	December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Time charter revenues	$	43,572	$	42,433	$	1,139
Vessel operating expenses		(8,576)		(7,698)		(878)
Administrative expenses		(876)		(1,346)		470
Segment EBITDA		34,120		33,389		731
Depreciation, amortization and impairment		(9,965)		(10,030)		65
Operating income (loss)		24,155		23,359		796
Gain (loss) on derivative instruments		(6,073)		(5,209)		(864)
Other income (expense), net		(11,662)		(12,072)		410
Income (loss) before tax		6,420		6,078		342
Income tax expense		—		—		—
Net income (loss) and limited partners' and preferred unitholders' interest in net income (loss)	$	6,420	$	6,078	$	342

Time charter revenues for the year ended December 31, 2020 were $43.6 million, an increase of $1.2 million compared to $42.4 million for the year ended December 31, 2019. Higher time charter revenues mainly reflect higher reimbursement of costs incurred for maintenance and projects for the charterer.

As further discussed in note 17 under " Joint ventures boil-off settlement" of our consolidated financial statements, in 2017 the joint ventures recorded accruals for the probable liability for boil-off claims under the Neptune and the Cape Ann time charters. Our 50% share of the accrual was estimated at approximately $11.9 million which was recorded as a reduction of time charter revenues as of September 30, 2017. In February 2020, each of the joint ventures and the charterer reached a commercial settlement addressing all the past and future claims related to boil-off with respect to the Neptune and the Cape Ann. The final settlement and release agreements were effective on April 1, 2020. The settlement amount is in line with the accrual made by the joint ventures. Accordingly, the accrual was unchanged as of December 31, 2019. The settlement was paid in two installments, the first in April 2020 and the second and final in December 2020.

Vessel operating expenses for the year ended December 31, 2020 were $8.6 million, an increase of $0.9 million compared to $7.7 million for the year ended December 31, 2019. The increase in vessel operating expenses was mainly due to higher maintenance expenses for the Cape Ann for the year ended December 31, 2020 compared to the year ended December 31, 2019. In addition, there were higher expenses due to one of the charterer’s projects. For the year ended December 31, 2019, the Neptune completed an on-water class renewal survey. As a result, vessel operating expenses were somewhat higher reflecting routine maintenance completed during the survey. The Neptune was on-hire during the class renewal period.

Administrative expenses for the year ended December 31, 2020 were $0.9 million, a decrease of $0.5 million compared to $1.3 million for the year ended December 31, 2019. The lower administrative expenses during the year ended December 31, 2020 were mainly due to the administrative procedures for the drydock and modifications work related to the Neptune during 2019.

Segment EBITDA was $34.1 million for the year ended December 31, 2020, an increase of $0.7 million compared with $33.4 million for the year ended December 31, 2019. Segment EBITDA was positively impacted by higher revenues that more than offset higher vessel operating expenses.

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Other. The following table sets forth details of other results of Other for the years ended December 31, 2020 and 2019:

	Year ended				Positive
Other	December 31,				(negative)
(in thousands of U.S. dollars)	2020		2019		variance
Administrative expenses	$	(6,350)	$	(6,465)	$	115
Segment EBITDA		(6,350)		(6,465)		115
Operating income (loss)		(6,350)		(6,465)		115
Other financial income (expense), net		(16,985)		(17,809)		824
Income (loss) before tax		(23,335)		(24,274)		939
Income tax benefit (expense)		—		3		(3)
Net income (loss)	$	(23,335)	$	(24,271)	$	936

Administrative expenses and Segment EBITDA for the year ended December 31, 2020 were each $6.4 million, a decrease of $0.1 million from $6.5 million for the year ended December 31, 2019.

The decrease in administrative expenses of $0.1 million for the year ended December 31, 2020 was principally related to lower audit and legal fees. For the year ended December 31, 2019, the higher audit fees primarily related to the first audit of our internal control over financial reporting. As a result of our status as an “emerging growth company,” as defined in the JOBS Act, we had an initial exemption from having an audit performed on our internal control over financial reporting.

Other financial income (expense), net, which is not part of the segment measure of profits, includes interest incurred, commitment fees and amortization of debt issuance costs, related to the $385 million facility. In addition, other financial income (expense), net also includes interest income accrued on the advances to our joint ventures and interest expenses related to the $85 million revolving credit facility from Höegh LNG.

Other financial income (expense), net for the year ended December 31, 2020 was an expense of $17.0 million, a decrease of $0.8 million from an expense of $17.8 million for the year ended December 31, 2019 principally due to repayments made of the $385 million facility.

For both the years ended December 31, 2020 and 2019, the drawn balance on the revolving credit tranche under the $385 million facility was $48.3 million. Refer to "Liquidity and Capital Resources" below as well as note 12 of our consolidated financial statements for more information on the refinancing of the Gallant/Grace facility and the new $385 million facility.

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018

See "Item 5. Operating and Financial Review and Prospects – Operating Results – Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018" in our Annual Report on Form 20-F for the year ended December 31, 2019 (our "2019 20-F") for a discussion of our results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 and other financial information related to the year ended December 31, 2018.

B.Liquidity and Capital Resources

Liquidity and Cash Needs

We operate in a capital-intensive industry, and we expect to finance the purchase of additional vessels and other capital expenditures through a combination of cash from operations, the utilization of borrowings from commercial banks and debt and equity financings. Our liquidity requirements relate to paying our unitholder distributions, servicing interest and quarterly repayments on our debt (“debt amortization”), funding working capital, funding on-water surveys or drydocking and maintaining cash reserves against fluctuations in operating cash flows. The liquidity requirements of our joint ventures relate to the servicing of debt, including repayment of shareholder loans, funding the settlement of the boil-off claim, funding working capital, including drydocking and on-water surveys, and maintaining cash reserves against fluctuations in operating cash flows.

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Our sources of liquidity include cash balances, cash flows from our operations, interest payments from our advances to our joint ventures, our undrawn balance of $66.8 million under the $85 million revolving credit facility from Höegh LNG and our undrawn balance of $14.7 million under the $63 million revolving credit tranche of our $385 million facility as of March 31, 2021, as further described below. In addition, liquidity can also be supplemented, from time to time, by net proceeds of the ATM program, depending on market conditions. Cash and cash equivalents are denominated primarily in U.S. dollars. We do not currently use derivative instruments for other purposes than managing interest rate risks. The advances to our joint ventures (accrued interest from prior periods on repaid shareholder loans) are subordinated to the joint ventures’ long-term bank debt, consisting of the Neptune facility and the Cape Ann facility. Under terms of the shareholder loan agreements, the repayments shall be prioritized over any dividend payment to the owners of the joint ventures. As discussed in note 17 under "Joint ventures boil-off settlement " to our consolidated financial statements and further below, the joint ventures recorded accruals for the probable liability for the boil-off claim under the time charters. As a precaution, the joint ventures suspended payments on the shareholder loans as of September 30, 2017 pending the outcome of the boil-off claim since the amounts and timing of a potential settlement were not clear. The suspension of the payments on the shareholder loans reduces cash flows available to us. Dividend distributions from our joint ventures require a) agreement of the other joint venture owners; b) fulfilment of requirements of the long-term bank loans (refer to note 9 of our consolidated financial statements); and c) under Cayman Islands law may be paid out of profits or capital reserves subject to the joint venture being solvent after the distribution. Dividends from Höegh Lampung may only be paid out of profits under Singapore law. Dividends from PT Höegh may only be paid if its retained earnings are positive under Indonesian law and requirements are fulfilled under the Lampung facility. In addition, PT Höegh, as an Indonesian incorporated company, is required to establish a statutory reserve equal to 20% of its paid in capital. The dividend can only be distributed if PT Höegh’s retained earnings are positive after deducting the statutory reserve. As of December 31, 2020, PT Höegh is in the process of establishing the required statutory reserves and therefore is currently unable to make dividend payments under Indonesia law. Under the Lampung facility, there are limitations on cash dividends and loan distributions that can be made to us. Subject to meeting a debt service coverage ratio of 1.20 to 1.00, PT Höegh can distribute cash from its cash flow from operations to us as payment of intercompany accrued interest and/or intercompany debt, after quarterly payments of the Lampung facility and fulfilment of the “waterfall” provisions to meet operating requirements as defined by the Lampung facility. Under Cayman Islands law, Höegh FSRU IV and Höegh Colombia Holding may only pay distributions out of profits or capital reserves if the entity is solvent after the distribution. Dividends from Höegh Cyprus may only be distributed out of profits and not from the share capital of the company. Dividends and other distributions from Höegh Cyprus, Höegh Colombia and Höegh FSRU IV may only be distributed if after the dividend payment, the Partnership would remain in compliance with the financial covenants under the $385 million facility.

For the year ended December 31, 2020, we sold 126,743 Series A preferred units under our ATM program at an average gross sales price of $25.50 per unit and received net proceeds, after sales commissions, of $3.2 million. For the year ended December 31, 2020, we did not sell any common units under our ATM program. We have paid an aggregate of $0.1 million in sales commissions to the Agent in connection with such sales for the year ended December 31, 2020. From the commencement of the Prior ATM program in January 2018 through December 31, 2020, we sold 2,152,333 Series A preferred units and 306,266 common units under the ATM programs and received net proceeds of $54.9 million and $5.6 million, respectively. The compensation paid to the Agent for such sales was $1.1 million.

For the period from January 1, 2021 to March 31, 2021, we sold 336,992 Series A preferred units under our ATM program at an average gross sales price of $25.12 per unit and received net proceeds, after sales commissions, of $8.3 million and 52,603 common units under the ATM program at an average gross sales price of $15.75 per unit and received net proceeds, after sales commissions, of $0.8 million.

As of December 31, 2020, we did not have material commitments for capital expenditures for our current business. However, procedures for the on-water class renewal survey for the Höegh Grace were performed during the fourth quarter of 2020 and are expected to be completed in the first half of 2021. Incurred expenditures of approximately $0.6 million have been recorded as deferred asset as of December 31, 2020 in connection with the survey.

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The Partnership is indemnified by Höegh LNG for its share of the cash impact of the settlement agreements, effective April 1, 2020, related to the boil-off claims against the joint ventures, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreement. On April 8, 2020 and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. Refer to note 17 under " Joint ventures boil-off settlement " in our consolidated financial statements.

As discussed in “—Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019—Time Charter Revenues” above, we exercised the right on February 27, 2020 to cause Höegh LNG to charter the Höegh Gallant from the expiration of the initial charter in April 2020 until July 2025. We entered into a Subsequent Charter with Höegh LNG for the Höegh Gallant, the final terms of which were approved by our conflicts committee and board of directors.

Höegh LNG’s ability to make payments to us under the Subsequent Charter may be affected by events beyond either of the control of Höegh LNG or us, including opportunities to obtain new employment for the Höegh Gallant and prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Höegh LNG’s ability to meet its obligations to us may be impaired. If Höegh LNG is unable to meet its obligations to us the Subsequent Charter, our financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected.

The outbreak of COVID-19 has negatively affected economic conditions in many parts of the world which may impact our operations and the operations of our customers and suppliers. Although our operations have not been materially affected by the COVID-19 outbreak to date, the ultimate length and severity of the COVID-19 outbreak and its potential impact on our operations and financial condition is uncertain at this time. We believe our primary risk and exposure related to uncertainty of cash flows from our long-term time charter contracts is due to the credit risk associated with the individual charterers. Payments are due under time charter contracts regardless of the demand for the charterers’ gas output or the utilization of the FSRU. It is therefore possible that charterers may not make payments for time charter invoices in times of reduced demand. As of March 31, 2021, we have not experienced any reduced or non-payments for obligations under our time charter contracts. In addition, we have not provided concessions or made changes to the terms of payments for our customers. Furthermore, should there be an outbreak of the COVID-19 on board one of our FSRUs or an inability to replace critical supplies or replacement parts due to disruptions to third-party suppliers, adequate crewing or supplies may not be available to fulfill our obligations under our time charter contracts. This could result in off-hire or warranty payments under performance guarantees which would reduce revenues for the impacted period. To date, we have mitigated the risk of an outbreak of the COVID-19 on board our FSRUs by extending time between crew rotations on the FSRUs and developing mitigating actions for crew rotations. As a result, we expect that we will incur somewhat higher crewing expenses to ensure appropriate mitigating actions are in place to minimize risks of outbreaks.

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To date, we have not had service interruptions on our FSRUs. Management and administrative staffs have largely transitioned to working remotely from home to address the specific COVID-19 situation in the applicable geographic location. We have supported staffs by supplying needed internet boosters and office equipment to facilitate an effective work environment. In addition, if financial institutions providing our interest rate swaps or lenders under our revolving credit facility are unable to meet their obligations, we could experience higher interest expense or be unable to obtain funding. From the commencement of the Prior ATM program in January 2018 through March 31, 2021, we have sold Series A preferred units and common units for total net proceeds of $69.6 million which has supplemented our liquidity. In current market conditions with lower unit prices, sales under the ATM program are a less viable and more expensive option for accessing liquidity. If our charterers or lenders are unable to meet their obligations to us under their respective contracts or if we are unable to fulfill our obligations under our time charter contracts, our financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected. We have long-term debt maturing in October 2021 when the commercial tranche of the Lampung facility becomes due and the export tranche can be called if the commercial tranche is not refinanced. The Partnership is at an advanced stage of the process to refinance the Lampung facility. As of April 9, 2021, a group of lending banks have provided a credit approved term sheet for the refinancing of both the commercial tranche and the export credit tranche. The refinancing is subject to completion of the loan documentation and satisfaction of customary closing conditions before drawdown. The refinancing is expected to be completed before the due date of the commercial tranche in October 2021. Should we be unable to complete the refinancing for the Lampung facility in 2021, we may not have sufficient funds or other assets to satisfy all of our obligations, which would have a material adverse effect on our business, results of operations and financial condition. In addition, planning has commenced in relation to the refinancing of the Neptune facility which matures and becomes payable by our Joint Ventures in November 2021.

As discussed in note 17 under "Indonesian property tax" of our consolidated financial statements, the Partnership's Indonesian subsidiary was assessed a property tax and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The retroactive assessment was due to the issuance of new Indonesian regulations which define an FSRU as a “Building” subject to the existing property tax law. The property tax and penalties were paid in February 2020 from our cash flows from operations. The annual property tax for the year ended December 31, 2020 was approximately $0.5 million and is expected to be similar for the years to come.

As of December 31, 2020, the total outstanding principal on our long-term debt was $439.9 million related to the Lampung facility, the $385 million facility, including the associated $63 million revolving credit tranche, and the $85 million revolving credit facility. The book value of our total long-term debt was $433.1 million as of December 31, 2020. Refer to “—Borrowing Activities—Long-term Debt” for a description of the facilities and notes 12 and 14 of our consolidated financial statements.

As of December 31, 2020, we had outstanding interest rate swap agreements for a total notional amount of $325.1 million to hedge against the interest rate risks of our long-term debt under the Lampung facility and the $385 million facility. We apply hedge accounting for derivative instruments related to those facilities. We receive interest based on three-month US dollar LIBOR and pay a fixed rate of 2.8% for the Lampung facility. We receive interest based on the three-month US dollar LIBOR and pay a fixed rate ranging from 2.650% to 2.941% for the $385 million facility. The carrying value of the liability for derivative instruments was a net liability of $26.5 million as of December 31, 2020. Refer to “Item 5.F. Tabular Disclosure of Contractual Obligations” and note 16 of our consolidated financial statements. In addition, our joint ventures have utilized interest rate swap contracts that are not designated as hedges for accounting purposes. Refer to note 8 of our consolidated financial statements for the carrying value of the liabilities for derivative instruments of our joint ventures.

As of December 31, 2020, we had cash and cash equivalents of $31.8 million. Current restricted cash for operating obligations of the PGN FSRU Lampung was $7.2 million and long-term restricted cash required under the Lampung facility was $12.1 million as of December 31, 2020. As of March 31, 2021, we had undrawn balances of $66.8 million and $14.7 million on the $85 million revolving credit facility and $63 million revolving credit tranche, respectively.

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As of December 31, 2020, our total current liabilities exceeded total current assets by $22.7 million. This is partly a result of the current portion of long-term debt of $59.1 million being classified as current while restricted cash of $12.1 million associated with the Lampung facility is classified as long-term. The current portion of long-term debt reflects principal payments for the next twelve months which will be funded, for the most part, by future cash flows from operations, and the balloon payment on the commercial tranche of the Lampung facility that is due in October 2021. As described above, we are expecting to successfully refinance the Lampung facility before the maturity date. The Partnership does not intend to maintain a cash balance to fund the next twelve months' net liabilities.

We believe our cash flows from operations, including distributions to us from PT Höegh, Höegh Cyprus, and Höegh FSRU IV as payment of intercompany interest and/or intercompany debt or dividends, will be sufficient to meet our debt amortization and working capital needs and maintain cash reserves against fluctuations in operating cash flows. In addition, we require liquidity to pay distributions to our unitholders. We believe the available balance on the $85 million revolving credit facility and the $63 million revolving credit tranche will provide us with adequate liquidity reserves to fund our distributions and other general liquidity needs. We believe our current resources, including the undrawn balances on the $85 million revolving credit facility and the $63 million revolving credit tranche, are sufficient to meet our working capital requirements for our current business for the next twelve months.

Generally, our long-term source of funds will be cash from operations, long-term bank borrowings and other debt and equity financings. Because we will distribute all of our available cash, we expect that we will rely principally upon external financing sources, including bank borrowings and the issuance of debt and equity securities, to fund acquisitions and other expansion capital expenditures.

For information regarding estimated maintenance and replacement capital expenditures impacting our cash distributions, refer to “Item 8.A. Consolidated Statements and Other Financial Information—The Partnership’s Cash Distribution Policy—Estimated Maintenance and Replacement Capital Expenditures.”

Cash Flows

The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the years presented:

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019		2018
Net cash provided by (used in) operating activities	$	85,825	$	85,252	$	91,681
Net cash provided by (used in) investing activities		(8)		(269)		3,067
Net cash provided by (used in) financing activities		(94,622)		(70,625)		(92,478)
Increase (decrease) in cash, cash equivalents and restricted cash		(8,805)		14,358		2,270
Effect of exchange rate changes on cash, cash equivalents and restricted cash		49		7		(97)
Cash, cash equivalents and restricted cash, beginning of period		59,819		45,454		43,281
Cash, cash equivalents and restricted cash, end of period	$	51,063	$	59,819	$	45,454

Cash Flows for the Years ended December 31, 2020 and 2019

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $85.8 million for the year ended December 31, 2020 compared with $85.3 million for the year ended December 31, 2019. Before changes in working capital, net cash flows from operating activities were $89.0 million and $82.1 million for the years ended December 31, 2020 and 2019, respectively. The increase of $6.9 million was primarily due to lower maintenance expenses in the Majority held FSRU segment and the capitalized expenditure for drydocking related to the Höegh Gallant for the year ended December 31, 2019, while there were no similar expenditures for the year ended December 31, 2020.

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Changes in working capital decreased net cash provided by operating activities by $3.2 million for the year ended December 31, 2020 compared with an increase of $3.1 million for the year ended December 31, 2019. For the year ended December 31, 2020, the negative contribution of changes in working capital was largely due to cash used in funding higher balances for prepaid expenses, other receivables and other accrued liabilities. For the year ended December 31, 2019, the positive contribution of changes in working capital was largely due to cash provided by increased value added and withholding tax liability.

Net Cash Provided by (Used in) Investing Activities

Net cash used in investing activities decreased by $0.3 million for the year ended December 31, 2020 compared with net cash used in investing activities of $0.3 million for the year ended December 31, 2019, which was comprised of expenditures for vessel and other equipment.

Net Cash Provided by (Used in) Financing Activities

Net cash used in financing activities was $94.6 million and $70.6 million for the years ended December 31, 2020 and 2019, respectively.

Net cash used in financing activities for the year ended December 31, 2020 was mainly due to the repayment of long-term debt of $44.7 million, which includes repayment of $19.1 million on the Lampung facility and repayment of $25.6 million on the $385 million facility and our payment of cash distributions to our common unit holders of $60.2 million and our payment of cash distributions to the holders of our Series A preferred units of $14.7 million. This was partially offset by the proceeds of $21.8 million under the $85 million revolving credit facility, and proceeds of $3.2 million for the issuance of Series A preferred units under our ATM program.

Net cash used in financing activities for the year ended December 31, 2019 was mainly due to the repayment of long-term debt of $342.4 million, which includes repayment of $19.1 million on the Lampung facility, repayment of $19.2 million on the $385 million facility, repayment of $0.9 million on the export credit tranche of the Gallant facility on January 29, 2019, and a settlement of $303.2 million of the remaining outstanding balance on the Gallant/Grace facility on January 31, 2019, payment of $5.8 million in debt issuance costs under the $385 million facility, repayment of $34.0 million on the $85 million revolving credit facility, our payment of cash distributions to our common and subordinated unitholders of $60.1 million and our payment of cash distributions to the holders of our Series A preferred units of $13.7 million. This was partially offset by receipt of $368.3 million in proceeds from long-term debt, including $320.0 million under the $385 million facility and $48.3 million on the revolving credit tranche under the $385 million facility, proceeds of $3.5 million under the $85 million revolving credit facility, and proceeds of $1.0 million and $13.1 million for the issuance of common and Series A preferred units, respectively, under our ATM program.

Cash Flows for the Years ended December 31, 2019 and 2018

See "Item 5. Operating and Financial Review and Prospects – Liquidity and Capital Resources – Cash Flows – Cash Flows for the Years Ended December 31, 2019 and 2018" in our Annual Report on Form 20-F for the year ended December 31, 2019 (our "2019 20-F") for a discussion of changes in our cash flows from 2018 to 2019 and other financial information related to the year ended December 31, 2018.

Borrowing Activities

Revolving Credit Facility Due to Owners and Affiliates

The following table sets forth the revolving credit facility due to owners and affiliates as of December 31, 2020 and 2019:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Revolving credit facility due to owners and affiliates	$	18,465	$	8,792

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Revolving Credit Facility with Höegh LNG

In connection with the IPO, we entered into an $85 million revolving credit facility with Höegh LNG.

On February 28, 2016, the maturity date of the $85 million revolving credit facility with Höegh LNG was extended to January 1, 2020, unless otherwise terminated due to an event of default. Interest on drawn amounts is payable quarterly at a rate equal to LIBOR plus a margin of 4.0%. Originally, we were required to pay a 1.4% annual commitment fee, payable quarterly, to Höegh LNG on undrawn available amounts under the revolving credit facility. On January 29, 2018, the revolving credit facility was amended eliminating the requirement to pay a commitment fee on the undrawn balance of the facility. On May 28, 2019, the repayment date on the $85 million revolving credit facility was extended to January 1, 2023 and the terms amended for the interest rate to be LIBOR plus a margin of 1.4% in 2019, 3.0% in 2020 and 4.0% thereafter. On April 8, 2020 and December 11, 2020, we were indemnified by Höegh LNG for our share of the joint ventures' boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on the outstanding balance on the $85 million revolving credit facility. On April 24, 2020, August 7, 2020 and October 23, 2020, we drew $4.5 million, $6.6 million and $10.7 million, respectively, on the $85 million revolving credit facility. Drawings on the revolving credit facility are subject to customary conditions precedent, including absence of a default or event of default and accuracy of representations and warranties in all material respects.

The revolving credit facility identifies various events of default that may trigger acceleration and cancellation of the facility, such as:

● failure to repay principal and interest;

● inaccuracy of representations and warranties;

● cross-default to other indebtedness held by us or our subsidiaries; and

● bankruptcy and certain other insolvency events.

Long-term Debt

The following table sets forth our long-term debt as of December 31, 2020 and 2019:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Lampung facility:
Export credit tranche	$	79,324	$	94,210
FSRU tranche		18,635		22,812
$385 million facility:
Commercial tranche		230,705		249,635
Export credit tranche		44,500		51,167
Revolving credit tranche		48,300		48,300
Outstanding principal		421,464		466,124
Lampung facility unamortized debt issuance cost		(2,999)		(4,309)
$385 million facility unamortized debt issuance cost		(3,876)		(4,854)
Total debt		414,589		456,961
Less: Current portion of long-term debt		(59,119)		(44,660)
Long-term debt	$	355,470	$	412,301

Refer to “Item 5.F. Tabular Disclosure of Contractual Obligations” and note 12 of our consolidated financial statements for the maturity profile of the debt.

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Lampung facility

In September 2013, PT Höegh (the “Borrower”) entered into a secured $299 million term loan facility (the “Lampung facility”) with a syndicate of banks and an export credit agency for the purpose of financing a portion of the construction of the PGN FSRU Lampung and the Mooring. Höegh LNG is the guarantor for the Lampung facility. The facility was drawn in installments as construction was completed. The term loan facility includes two commercial tranches, the FSRU tranche and the Mooring tranche, and the export credit tranche. The interest rates vary by tranche. The full principal amount on the Mooring tranche and accrued interest was repaid in 2014.

The FSRU tranche has an interest rate of LIBOR plus a margin of 3.4%. The interest rate for the export credit tranche is LIBOR plus a margin of 2.3%. The FSRU tranche is repayable quarterly over 7 years with a final balloon payment of $15.5 million due on October 30, 2021. The export credit tranche is repayable in quarterly installments over 12 years assuming the balloon payment of the FSRU tranche is refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the outstanding balance upon maturity of the FSRU tranche. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 4.7% and 6.2% respectively.

The primary financial covenants under the Lampung facility are as follows:

● Borrower must maintain a minimum debt service coverage ratio of 1.10 to 1.00 for the preceding nine-month period tested on each quarterly repayment date;

● Höegh LNG’s book equity must be greater than the higher of (i) $200 million and (ii) 25% of total assets; and

● Höegh LNG’s free liquid assets (cash and cash equivalents or available draws on credit facilities) must be greater than $20 million.

As of December 31, 2020 and 2019, the Borrower and the guarantor were in compliance with the financial covenants.

Höegh LNG, as guarantor, has issued the following guarantees related to the Lampung facility that remain in effect as of December 31, 2020: (a) an unconditional and irrevocable on-demand guarantee for the repayment of the balloon repayment installment of the FSRU tranche callable only at final maturity of the FSRU tranche; (b) an unconditional and irrevocable on-demand guarantee for all amounts due in respect of the export credit agent in the event that the export credit agent exercises its prepayment right for the export credit tranche if the FSRU tranche is not refinanced; and (c) an undertaking that, if the time charter is terminated for an event of vessel force majeure, that under certain conditions, a guarantee will be provided for the outstanding debt, less insurance proceeds for vessel force majeure. In addition, all project agreements and guarantees are assigned to the bank syndicate and the export credit agent, all cash accounts and the shares in PT Höegh and Höegh Lampung are pledged in favor of the bank syndicate and the export credit agent.

The Lampung facility requires cash reserves that are held for specifically designated uses, including working capital, operations and maintenance and debt service reserves. Distributions are subject to “waterfall” provisions that allocate revenues to specified priorities of use (such as operating expenses, scheduled debt service, targeted debt service reserves and any other reserves) with the remaining cash being distributable only on certain dates and subject to satisfaction of certain conditions, including meeting a 1.20 historical debt service coverage ratio, no default or event of default then continuing or resulting from such distribution and the guarantor not being in breach of the financial covenants applicable to it. The Lampung facility limits, among other things, the ability of the Borrower to change its business, sell or grant liens on its property including the PGN FSRU Lampung, incur additional indebtedness or guarantee other indebtedness, make investments or acquisitions, enter into intercompany transactions and make distributions.

The Lampung facility identifies various events that may trigger mandatory reduction, prepayment and cancellation of the facility, including total loss or sale of the PGN FSRU Lampung. The Lampung facility contains customary events of default such as:

● change of ownership;

● inaccuracy of representations and warranties;

● failure to repay principal and interest;

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● failure to comply with the financial or insurance covenants;

● cross-default to other indebtedness held by Höegh LNG or PT Höegh;

● bankruptcy and other insolvency events at Höegh LNG or PT Höegh;

● occurrence of certain litigation events at Höegh LNG or PT Höegh;

● the occurrence of a material adverse effect in respect of Höegh LNG, PT Höegh or the charterer;

● breach by the contractor of any technical services agreement, master maintenance agreement or a master parts agreement pertaining to the vessel;

● termination or breach of the charter; and

● cross-default to certain material project contracts.

Gallant/Grace Facility

On October 1, 2015, the Partnership acquired Höegh FSRU III, the entity that owned Höegh Cyprus, which owns the Höegh Gallant. Höegh Cyprus, together with Höegh FSRU IV, the owner of the Höegh Grace, were borrowers (the “Borrowers”) under a term loan facility (the “Gallant/Grace facility”) with a syndicate of banks and an export credit agency for the purpose of financing a portion of the Höegh Gallant and the Höegh Grace. The facility was secured by, among other things, a first priority mortgage of the Höegh Gallant and the Höegh Grace, an assignment of the Höegh Cyprus’s, EgyptCo’s, Höegh FSRU IV’s and Höegh Colombia’s rights under their respective time charters, the assignment of a bank guarantee for the performance of EGAS under the time charter and a pledge of the Borrowers’ and EgyptCo’s cash accounts. The Partnership provided a pledge of its shares in Höegh FSRU III, Höegh Cyprus and Höegh LNG Colombia Holding Ltd., and Höegh LNG provided a pledge of its shares in EgyptCo as security for the facility. Höegh Colombia Holding provided a pledge of its shares in Höegh FSRU IV as security for the facility. Höegh LNG, Höegh Colombia Holding, Höegh FSRU III and the Partnership were guarantors for the facility.

On January 31, 2019, the outstanding balance and the accrued interest of $303.2 million and $1.6 million, respectively, on the Gallant/Grace facility was repaid from the proceeds of the $385 million facility. The unamortized balance of the fair value of debt assumed, or premium, was recorded as a gain when the debt was extinguished.

$385 million Facility

On January 29, 2019, the Partnership entered into a loan agreement with a syndicate of banks to refinance the outstanding balances of the Gallant/Grace facility. The Partnership is the borrower (the “Borrower”) for the senior secured term loan and revolving credit facility (the “$385 million facility”). The aggregate borrowing capacity is $320 million on the senior secured term loan and $63 million on the revolving credit tranche. Höegh Cyprus, which owns the Höegh Gallant, Höegh FSRU IV, the owner of the Höegh Grace, (collectively, the "Vessel Owners"), and Höegh Colombia, are guarantors for the facility (collectively, the "guarantors"). The facility is secured by, among other things, a first priority mortgage of the Höegh Gallant and the Höegh Grace, an assignment of the Höegh LNG Cyprus’, Höegh FSRU IV’s, Höegh Colombia’s rights under their respective time charters and earnings and a pledge of the Borrower’s and Guarantor’s cash accounts. The Partnership and its subsidiaries have provided a pledge of shares in Höegh Cyprus, Höegh FSRU IV and Höegh Colombia.

The senior secured term loan related to the $385 million facility includes a commercial tranche and the export credit tranche. Each tranche is divided into two term loans for each of the Höegh Gallant and the Höegh Grace.

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On January 31, 2019, the Partnership drew $320 million under the commercial and the export credit tranches on the $385 million facility to settle $303.2 million and $1.6 million of the outstanding balance and accrued interest, respectively, on the Gallant/Grace facility and used proceeds of $5.5 million to pay arrangement fees due under the $385 million facility. The remaining proceeds of $9.6 million were used for general partnership purposes. On August 12, 2019, the Partnership drew $48.3 million under the revolving credit tranche of the $385 million facility, of which $34.0 million was used to repay part of the outstanding balance on the $85 million revolving credit facility due to Höegh LNG.

The commercial tranche and the revolving credit tranche related to the $385 million facility have an interest rate of LIBOR plus a margin of 2.30%. The commitment fee on the undrawn portion of the revolving credit tranche is approximately 1.6%. The interest rate for the export credit tranche related to the $385 million facility have fixed interest rates and guarantee commissions of 3.98% and 3.88% on the term loans related to the Höegh Gallant and the Höegh Grace, respectively. The commercial tranche is repayable quarterly with a final balloon payment of $136.1 million due in January 2026. The term loans for export credit tranche related to the Höegh Gallant and the Höegh Grace are repayable in quarterly installments with the final payments in October 2026 and April 2028, respectively, assuming the balloon payments of the commercial tranches are refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the total outstanding balance on both the terms loans of the export credit tranche of $9.5 million upon maturity of the commercial tranche. Any outstanding balance on the revolving credit facility is due in full in January 2026. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 3.4% and 4.7%, respectively.

The primary financial covenants under the $385 million facility are as follows:

● The Partnership must maintain

o Consolidated book equity (excluding hedge reserves and mark to market value of derivatives) equal to the greater of

◾ 25% of total assets, and

◾ $150 million

o Consolidated working capital (current assets, excluding intercompany receivables and marked-to-market value of any financial derivative, less current liabilities, excluding intercompany payables, marked-to-market value of any financial derivative and the current portion of long-term debt) shall at all times be greater than zero

o Minimum liquidity (cash and cash equivalents and available draws under a bank credit facility for a term of more than 12 months) equal to the greater of

◾ $15 million, and

◾ $2.5 million multiplied by the number of vessels owned or leased by the Partnership (prorated for partial ownership), subject to a cap of $20 million

o A ratio of combined EBITDA for the Vessel Owners to debt service (principal repayments, guarantee commission, commitment fees and interest expense) for the preceding twelve months of a minimum of 115%

As of December 31, 2020 and 2019, the Borrower and the Vessel Owners were in compliance with the financial covenants.

In addition, a security maintenance ratio based on the aggregate market value of the Höegh Gallant, the Höegh Grace and any additional security must be at least 125% of the aggregate outstanding loan balance.

If the security maintenance ratio is not maintained, the relevant Borrower has 30 days to provide more security or to repay part of the loan to be in compliance with the ratio no later than 30 days after notice from the lenders.

Under the $385 million facility, cash accounts are freely available for the use of the Borrower and the guarantors, unless there is an event of default. Cash can be distributed as dividends or to service loans of owners and affiliates provided that after the distribution the Borrower and guarantors would remain in compliance with the financial covenants. The $385 million facility limits, among other things, the ability of the Borrower and the guarantors to change their business, grant liens on the Höegh Gallant or the Höegh Grace, incur additional indebtedness that is not pari passu with the $385 million facility, enter into intercompany debt that is not subordinated to the $385 million facility and for the Vessel Owners to make investments or acquisitions.

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The $385 million facility identifies various events that may trigger mandatory reduction, prepayment and cancellation of the facility, including total loss or sale of the Höegh Gallant or the Höegh Grace. The facility contains events of default such as:

● failure to repay principal and interest;

● failure to comply with the financial or insurance covenants;

● inaccuracy of representations;

● cross-default to other indebtedness held by the Partnership or any its subsidiaries;

● bankruptcy and other insolvency events for the Partnership or the Guarantors;

● occurrence of certain litigation events for the Partnership or the Guarantors;

● expiration or termination of time charter contracts without replacement contracts meeting certain criteria; and

● change of control of Höegh LNG or the Partnership due to the failure of Höegh LNG to own at least 25% of our common units.

Joint Ventures Debt

The debt of our joint ventures is not consolidated on our consolidated financial statements, but it is included as a component in “Investment in and advances to joint ventures” on our consolidated balance sheet in accordance with the equity method of accounting.

Loans Due to Owners (Shareholder Loans)

The loans due to owners consist of shareholder loans where the principal amounts, including accrued interest, are repaid based on available cash after servicing of long-term bank debt. As of December 31, 2020, our 50.0% share of the outstanding balance was $4.2 million. The shareholder loans are due not later than the 12th anniversary of the delivery date of each FSRU. The Neptune and the Cape Ann were delivered November 30, 2009 and June 1, 2010, respectively. The shareholder loans are subordinated to the long-term bank debt, consisting of the Neptune facility and the Cape Ann facility (described below). Under terms of the shareholder loan agreements, the repayments shall be prioritized over any dividend payment to the owners of our joint ventures. The shareholder loans bear interest at a fixed rate of 8.0% per year. The Partnership is due 50.0% of the outstanding balance and the other joint venture partners have, on a combined basis, an equal amount of shareholder loans outstanding at the same terms to each of our joint ventures.

The shareholder loans financed part of the construction of the vessels and operating expenses until the delivery and commencement of operations of the Neptune and the Cape Ann. In 2011, our joint ventures began repaying principal and a portion of the interest expense based on available cash after servicing of the external debt. The quarterly payments included a payment of interest for the first month of the quarter and a repayment of principal. Interest was accrued for the last two months of the quarter for repayment after the full principal is repaid at the end of the loans. The joint ventures repaid the original principal of all shareholder loans during 2016 and all of the payments after such time represent payments of interest, including accrued interest to be repaid at the end of the loans.

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As of September 30, 2017, the joint ventures suspended payments on the shareholder loans pending the outcome of the boil-off claim. Accordingly, the outstanding balance on the shareholder loans was classified as long-term as of December 31, 2019. As of April 1, 2020, the joint ventures reached an agreement on the boil-off claim requiring full settlement during 2020. The first instalment of the settlement was paid by the joint ventures in April 2020 and the second and final instalment of the settlement was paid by the joint ventures in December 2020. Refer to note 17 of our consolidated financial statements under “Joint ventures boil-off settlement.” The shareholder loans are subordinated to long-term bank debt and the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt and meeting a 1.20 historical and projected debt service coverage ratio. As of December 31, 2020, both the 1.20 historical and projected debt service coverage ratios were met by SRV Joint Gas Ltd. As a result, SRV Joint Gas Ltd. qualifies to make payments on the shareholder loans or other distributions. Accordingly, the outstanding balance on the shareholder loans from SRV Joint Gas Ltd. is classified as current portion of advances to joint ventures in our consolidated financial statements as of December 31, 2020. As of December 31, 2020, the 1.20 historical debt service coverage ratio was not met by SRV Joint Gas Two Ltd., however, the projected debt service coverage ratio was met. As a result, no payments on the shareholder loans or other distributions can be made by SRV Joint Gas Two Ltd. until the debt service coverage ratio is met in future periods. Accordingly, the outstanding balance on the shareholder loans from SRV Joint Gas Two Ltd. is classified as non-current portion of advances to joint ventures in our consolidated financial statements as of December 31, 2020. Refer to note 9 of our consolidated financial statements.

Neptune Facility

In December 2007, our joint venture owning the Neptune, as the borrower, entered into a $300 million secured facility with a syndicate of banks as long-term financing of the construction of the Neptune (the “Neptune facility”). As of December 31, 2020, our 50.0% share of the outstanding balance, excluding deferred debt issuance cost, was $92.0 million. The Neptune facility is secured with a first priority mortgage of the Neptune, an assignment of its rights under the time charter and a pledge of the borrower’s cash accounts. We and the other owners of the borrower have provided a negative pledge of shares in the borrower as security for the facility. In addition, Höegh LNG and MOL guarantee funding of drydocking costs and remarketing efforts in the event of an early termination of the charter.

The Neptune facility is repayable in quarterly installments over 12 years with a final balloon payment of $169 million, of which $84.5 million is our share, due in November 2021. The Neptune facility bears interest at a rate equal to three months LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swap contracts to the borrower covering the period to 2029, which are not reflected in the LIBOR rate for the facility. The fair value of the swaps as of December 31, 2020 was negative $40.3 million. These interest rate swap contracts might also have to be restructured and potentially settled upon maturity of the Neptune facility in 2021. Planning has commenced in relation to the refinancing of the Neptune facility and the related interest rate swap contracts.

There are no financial covenants in the Neptune facility, but certain other covenants and restrictions apply. The borrower is required to maintain insurance coverage for damage to the FSRU equivalent to 120.0% of the aggregate outstanding loan balance and loss of hire insurance. The borrower must maintain cash accounts with the syndicate of banks for its operating account and restricted cash for debt service for the next 6 months, including interest payments on the facility and associated interest rate swap contracts and certain distribution accounts. Cash in the operating account from hire rates will be applied for the following purposes in the following order; first, to pay operating costs, insurance, taxes and technical management fees; second, to transfer to the debt service retention account on each debt service retention date all or part of the debt service retention amount for such debt service retention date; third, to transfer funds to the restricted cash account for debt service until reserve requirements are met; finally, to transfer funds to certain distribution accounts. Certain conditions apply to making distributions from the distribution accounts, including meeting a 1.20 historical and projected debt service coverage ratio, no event of default then continuing, and debt service reserve and retention accounts are fully funded. The facility agreement limits the borrower’s ability to raise additional debt, enter into certain material transactions and make guarantees.

The Neptune facility identifies various events that may trigger mandatory reduction, prepayment and cancellation of the facility, including total loss or sale of the Neptune. The Neptune facility contains customary events of default such as:

● change of ownership;

● inaccuracy of representations and warranties;

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● failure to repay principal and interest;

● cross-default to other indebtedness held by the borrower;

● bankruptcy and other insolvency events related to the borrower; and

● termination or breach of the charter.

Cape Ann Facility

In December 2007, our joint venture owning the Cape Ann, as the borrower, entered into a $300 million secured facility with a syndicate of banks as long-term financing of the construction of the Cape Ann (the “Cape Ann facility”). As of December 31, 2020, our 50.0% share of the outstanding balance, excluding deferred debt issuance cost, was $95.9 million. The Cape Ann facility is secured with a first priority mortgage of the Cape Ann, an assignment of its rights under the time charter and a pledge of the borrower’s cash accounts. We and the other owners of the borrower have provided a negative pledge of shares in the borrower as security for the facility. In addition, Höegh LNG and MOL guarantee funding of drydocking costs and remarketing efforts in the event of an early termination of the charter.

The Cape Ann facility is repayable in quarterly installments over 12 years with a final balloon payment of $169 million, of which $84.5 million is our share, due in June 2022. The Cape Ann facility bears interest at a rate equal to three months LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swap contracts to the borrower covering the period until 2030, which are not reflected in the LIBOR rate for the facility. The fair value of the swaps as of December 31, 2020 was negative $44.0 million. These interest rate swap contracts might also have to be restructured and potentially settled upon maturity of the Cape Ann facility in 2022. Planning has commenced in relation to the refinancing of the Cape Ann facility, in conjunction with the planning of the refinancing of the Cape Ann facility and the related interest rate swap contracts.

There are no financial covenants in the Cape Ann facility, but certain other covenants and restrictions apply. The borrower is required to maintain insurance coverage for damage to the FSRU equivalent to 120.0% of the aggregate outstanding loan balance and loss of hire insurance. The borrower must maintain cash accounts with the syndicate of banks for its operating account and restricted cash for debt service for the next 6 months, including interest payments on the facility and associated interest rate swap contracts and certain distribution accounts. Cash in the operating account from hire rates will be applied for the following purposes in the following order; first, to pay operating costs, insurance, taxes and technical management fees; second, to transfer to the debt service retention account on each debt service retention date all or part of the debt service retention amount for such debt service retention date; third, to transfer funds to the restricted cash account for debt service until reserve requirements are met; finally, to transfer funds to certain distribution accounts. Certain conditions apply to making distributions from the distribution accounts, including meeting a 1.20 historical and projected debt service coverage ratio, no event of default then continuing, and debt service reserve and retention accounts are fully funded. The facility agreement limits the borrower’s ability to raise additional debt, enter into certain material transactions and make guarantees.

The Cape Ann facility identifies various events that may trigger mandatory reduction, prepayment and cancellation of the facility, including total loss or sale of the Cape Ann. The Cape Ann facility contains customary events of default such as:

● change of ownership;

● inaccuracy of representations and warranties;

● failure to repay principal and interest;

● cross-default to other indebtedness held by the borrower;

● bankruptcy and other insolvency events related to the borrower; and

● termination or breach of the charter.

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Critical Accounting Estimates

The preparation of our consolidated financial statements in accordance with US 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. Please read note 2 of our consolidated financial statements.

Time Charter Revenue Recognition

Lease revenue recognition:

In February 2016, the Financial Accounting Standards Board ("FASB") issued revised guidance for leasing, Leases, that amends the accounting guidance on leases for both lessors and lessees. On January 1, 2019, we adopted the new standard using the optional transition method to apply the new standard at the transition date of January 1, 2019 with no retrospective adjustments to prior periods. We are the lessor for time charters for our FSRUs. There were no changes to the timing or amount of revenue recognized and, therefore, no cumulative effect adjustment to retained earnings of initially applying the standard related to the lessor accounting.

Leases are classified based upon defined criteria either as sale-type/direct financing leases (“financing leases”) or operating leases. A lease that transfers substantially all of the benefits and risks of the FSRU to the charterer is accounted for as a financing lease by the lessor. All other leases that do not meet the criteria are classified as operating leases. On January 1, 2019, when adopting the revised leasing guidance, we elected the package of practical expedients and did not reassess conclusions under the previous standard about whether any existing contracts are, or contain leases, lease classification, and initial direct costs for any existing leases. Accordingly, outstanding leases on January 1, 2019, continue to be classified in accordance with the prior lease guidance.

The lease component of time charters that are accounted for as operating leases is recognized on a straight-line basis over the term of the charter. The Höegh Gallant’s time charter, which had a five-year lease term at inception, and the Subsequent Charter that commenced on May 1, 2020 and which expires on July 31, 2025, are accounted for as an operating lease. The Höegh Grace’s time charter contracts, which have a non-cancellable charter period of ten years, are accounted for as an operating lease. Under one of the time charter contracts, the contract provides for additional variable payments, including a finance component, over the initial term depending upon the actual commencement date of the contract within a defined window of potential commencement dates. The variable payments are considered directly related to the lease performance obligation. The revenue, excluding the financing component, is recognized over the initial 10-year term. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for final income tax directly related to the provision of the lease is recorded as a component of lease revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

The lease component of time charters that are accounted for as financing leases is recognized over the lease term using the effective interest rate method and is included in time charter revenues. Origination costs related to the time charter are a component of the net investment in financing lease and amortized over the lease term using the effective interest method. Financing leases are reflected on the consolidated balance sheets as net investments in financing leases. The PGN FSRU Lampung time charter, which had a 20-year lease term at inception, meets the criteria of transferring substantially all of the benefits and risks to the charterer and is accounted for as a financing lease.

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Time charter services revenue recognition:

Variable consideration for the time charter services performance obligation, including amounts allocated to time charter services, estimated reimbursements for vessel operating expenses and estimated reimbursements of certain types of costs and taxes, are recognized as revenues as the performance obligation for the 24-hour interval is fulfilled, subject to adjustment for off-hire and performance warranties. Constrained variable consideration is recognized as revenue on a cumulative catch-up basis when the significant uncertainty related to that amount of variable consideration to be received is resolved. Estimates for variable consideration, including constrained variable consideration, are reassessed at the end of each period. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes directly related to the provision of the time charter services are recorded as a component of time charter service revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

Joint venture FSRUs lease and time charter services revenue recognition:

Our interest in the Joint venture FSRUs’ net income is included in the consolidated financial statements under the equity method of accounting, however, the Joint venture FSRUs’ results are presented under the proportional consolidation method for the segment note and the time charter revenue note (notes 3 and 4, respectively, of our consolidated financial statements). The Neptune’s and the Cape Ann’s time charters, which had a twenty-year lease term at inception, are accounted for as operating leases. The joint ventures’ time charters include provisions for the charterer to make upfront payments to compensate for variable cost for certain vessel modifications, drydocking costs, other additions to equipment or spare parts. The expenditures are considered costs required to fulfill the lease component of the contract. Payments for modifications are deferred and amortized over the shorter of the remaining charter period or the useful life of the additions. Payments for reimbursement of drydocking costs are deferred and recognized on a straight-line basis over the period to the next drydocking.

The accounting policy for time charter services for the joint ventures is the same as described above.

Significant judgments in revenue recognition:

We do not provide stand-alone bareboat leases or time charter services for FSRUs. As a result, observable stand-alone transaction prices for the performance obligations are not available. The estimation of the transaction price for the lease and the time charter service performance obligation is complex, subject to a number of input factors, such as market conditions when the contract is entered into, internal return objectives and pricing policies, and requires substantial judgment. Significant changes in the transaction price between the two performance obligations could impact conclusions on the accounting for leases as financing or operating leases. In addition, variable consideration is estimated at the most likely amount that we expect to be entitled to. Variable consideration is reassessed at the end of the reporting period taking into account performance warranties. The time charter contracts include provisions for performance guarantees that can result in off-hire, reduced hire, liquidated damages, or other payments for performance warranties. Measurement of some of the performance warranties can be complex and require properly calibrated equipment on the vessel, complex conversions and computations based on substantial judgment in the interpretation of the contractual provisions. Conclusions on compliance with performance warranties impact the amount of variable consideration recognized for time charter services.

Evaluation of whether a time charter should be accounted for as an operating or financing lease requires use of judgment. In addition to estimating the transaction price for the lease element, our evaluations of each time charter require that we estimate the fair value of our FSRUs, the estimated useful lives of those vessels, whether the option price, if any, represents a bargain purchase option, whether options to extend the time charter are reasonably assured and other factors. The impact of the change in such estimates could impact our evaluation of the accounting for the time charters as financing leases, if the criteria are met, or operating leases.

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Trade receivables and allowance for expected credit losses

In June 2016, FASB issued a revised guidance on Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments. The new standard replaces the incurred loss methodology with a current expected credit loss ("CECL") methodology that requires consideration of a broader range of reasonable and supportable information to estimate credit losses. The new standard is applicable to financial assets measured at amortized cost, including trade receivables, contract assets and net investment financing leases. On January 1, 2020, we adopted the new standard using a modified retrospective method. We recorded a net decrease to retained earnings of $0.16 million as of January 1, 2020 for the cumulative effect of adopting the new standard. The cumulative effect includes allowances for expected credit losses recognized of $0.1 million (related to the net investment in financing lease) and $0.06 million (related to trade receivables).

Trade receivables are recorded at the invoiced amount and do not bear interest. Trade receivables, contract assets and the net investment in financing lease are initially recorded by including the current expected credit loss of the asset over the life of the contract. The allowance for expected credit losses is a valuation account that is deducted from the amortized cost of the asset to present the net amount expected to be collected. At each period, the allowance for expected credit losses is evaluated and adjusted through earnings to reflect the revised expected credit losses over the remaining lives of the assets. Expected credit losses are estimated using historical credit loss experience, relevant available information, from internal and external sources, relating to current conditions and reasonable and supportable forecasts of economic conditions impacting the collectability of the assets. Receivable amounts are written off against the allowance when the asset is confirmed uncollectible.

Estimated Useful Lives

The estimated economic life of our FSRUs is 40 years. Depreciation of FSRUs is calculated on a straight-line basis using our estimated useful life, less the estimated residual value. Our estimated useful life represents our best estimate of the period we will use the vessel, while the estimated economic life may involve periods an asset will be used by others. Our business model is to provide time charters of five years or more. Charterers tend to prefer newer vessels for long-term charters. Accordingly, we have estimated that the estimated useful life, or depreciable life, to us is 35 years.

Valuation of Derivative Instruments

Under our risk management policies, we currently use derivative instruments to manage interest rate risk. On January 1, 2019, the Partnership adopted Derivatives and Hedging, Targeted Improvements to Accounting for Hedging Activities on a prospective basis. For interest rate swaps qualifying as cash flow hedges, the entire change in fair value of the cash flow hedge included in the assessment of hedge effectiveness is included in other comprehensive income (OCI) with the result that the hedge ineffectiveness is no longer recognized in earnings. Those amounts are reclassified to earnings in the same income statement line as the hedged item when hedged item affects earnings. In order to designate a derivative as a cash flow hedge, formal documentation of the relationship between the derivative and the hedged item is required. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge.

For the year ended December 31, 2018, changes in the fair value of the effective portion of the derivative instruments qualifying as cash flow hedges were initially recorded in other comprehensive income as a component of total equity. Any hedge ineffectiveness was recognized immediately in earnings, as were any gains and losses or amortization on the portion of the derivative instruments that are excluded from the assessment of hedge effectiveness. In the periods when the hedged items affect earnings, those amounts were transferred from accumulated other comprehensive income to the gain (loss) on derivative instruments line in the consolidated statement of income.

The fair values of the interest rates swaps are estimated based on the present value of cash flows over the term of the instruments based on the relevant LIBOR interest rate curves, adjusted for our credit worthiness and the credit worthiness of the counterparty to the derivative. Determining credit worthiness is highly subjective and requires significant judgment.

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Goodwill and intangible assets

We allocate the cost of acquired companies to the identifiable tangible and intangible assets and liabilities acquired, with the remaining amount being classified as goodwill. Certain intangible assets, such as above-market contracts, are being amortized over the term of the charter. In addition, we entered into an option agreement with Höegh LNG pursuant to which we had the right to cause Höegh LNG to charter Höegh Gallant from the expiration or termination of the existing charter until July 2025. On February 27, 2020, we exercised our right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of its initial charter and on April 30, 2020 we entered into the Subsequent Charter which commenced on May 1, 2020 and expires July 31, 2025. The intangible for the option for the time charter extension is amortized on a straight-line basis over the extension period starting on May 1, 2020, subsequent to impairment testing for recoverability in the preceding periods. Our future operating performance will be affected by the amortization of intangible assets and potential impairment charges related to goodwill or intangible assets. Accordingly, the allocation of the purchase price to intangible assets and goodwill may significantly affect our future operating results.

The allocation of the purchase price requires management to make significant estimates and assumptions, including estimates of future cash flows expected to be generated by the acquired assets and the appropriate discount rate to value these cash flows. In addition, the process of evaluating the potential impairment of goodwill and intangible assets is highly subjective and requires significant judgment at many points during the analysis. The estimates and assumptions regarding expected future cash flows and appropriate discount rates are in part based upon existing contracts, anticipated future FSRU charter rates, historical experience, financial forecasts and industry trends and conditions.

On January 1, 2020, we adopted FASB's revised guidance: Intangibles - Goodwill and Other: Simplifying the test for Goodwill Impairment. The revised standard simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total goodwill allocated to that reporting unit. The adoption of the standard did not have an impact on the consolidated financial statements.

Loss contingencies

Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. Significant judgment is required to determine the probability and the estimated amount of loss. Such assessments involve complex judgments about future events and estimates and assumptions that are deemed reasonable by management. Accruals are reviewed quarterly and adjusted to reflect the impact of additional information such as the impact of negotiations, advice of legal counsel or settlements.

As discussed in note 17 under " Joint ventures boil-off settlement" to our consolidated financial statements, the joint ventures had as of December 31, 2019 recorded accruals for the probable liability for boil-off claim related to performance standards as specified in the time charters which has been settled in full during 2020. Significant judgment is required to assess the interpretation of the contractual provisions related to performance standards, warranties, associated exclusions, the interaction of the contractual provisions, advice of legal counsel, the arbitration determination of key contractual interpretations and the application of the performance data and technical input associated with quantification of potential ranges of outcomes which might occur as a result of future events, such as a final arbitration award or a negotiated settlement, for the claim. In February 2020, each of the joint ventures and the charterer reached a commercial settlement addressing all the past and future claims related to boil-off with respect to the Neptune and the Cape Ann. The settlement amount is in line with the accrual made by the joint ventures. Accordingly, the accrual was unchanged as of December 31, 2019. The final settlement and release agreements were signed on and had an effective date of April 1, 2020 and the boil-off claim has been fully settled and paid in two instalments during 2020.

Recent Accounting Pronouncements

Recently adopted accounting pronouncements

Refer to note 2, under "Recently adopted accounting pronouncements," of our consolidated financial statements for a complete discussion of recent accounting pronouncements.

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C.Research and Development, Patents and Licenses, Etc.

Not applicable.

D.Trend Information

Outlook

The Partnership believes its primary risk and exposure related to uncertainty of cash flows from its long-term time charter contracts is due to the credit risk associated with the individual charterers. Payments are due under time charter contracts regardless of the demand for the charterer’s gas output or the utilization of the FSRU. It is therefore possible that charterers may not make payments for time charter services in times of reduced demand. As of March 31, 2021, the Partnership has not experienced any reduced or non-payments for obligations under the Partnership’s time charter contracts. In addition, the Partnership has not provided concessions or made changes to the terms of payment for its customers. Höegh LNG has indemnified the Partnership for the joint ventures’ boil-off settlement, leased the Höegh Gallant under the Subsequent Charter and provided the Partnership the $85 million revolving credit facility. Höegh LNG’s ability to make payments to the Partnership under the indemnification for the Subsequent Charter and funding requests under the $85 million revolving credit facility may be affected by events beyond the control of Höegh LNG or the Partnership, including opportunities to obtain new employment for the Höegh Gallant and prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Höegh LNG’s ability to meet its obligations to the Partnership may be impaired. If Höegh LNG is unable to meet its obligations to the Partnership under the indemnification for the Subsequent Charter or meet funding requests, the Partnership’s financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected.

If financial institutions providing the Partnership’s interest rate swaps or lenders under the revolving credit facility are unable to meet their obligations, the Partnership could experience a higher interest expense or be unable to obtain funding. If the Partnership’s charterers or lenders are unable to meet their obligations under their respective contracts or if the Partnership is unable to fulfill its obligations under time charters, its financial condition, results of operations and ability to make cash distributions to unitholders could be materially adversely affected.

Since implementing its prior ATM program in January 2018 until March 31, 2021, the Partnership has sold preferred units and common units for total net proceeds of $69.6 million which have supplemented the Partnership’s liquidity. In current market conditions with lower unit prices, sales under the new ATM program are a less viable and more expensive option for accessing liquidity.

The Partnership has long term debt maturing in October 2021 when the commercial tranche of the Lampung facility becomes due and export credit tranche can be called if the commercial tranche is not refinanced. The Partnership is at an advanced stage of the process to refinance the Lampung facility. As of April 9, 2021, a group of lending banks have provided a credit approved term sheet for the refinancing of both the commercial tranche and the export credit tranche. The refinancing is subject to completion of the loan documentation and satisfaction of customary closing conditions before drawdown. The refinancing is expected to be completed before the due date of the commercial tranche in October 2021.The Joint venture FSRUs’ debt facilities are also approaching maturity dates towards the end of 2021 and in 2022 respectively, and the Partnership has commenced the planning of the refinancing of these facilities together with its joint venture partners. Should the Partnership be unable to obtain the refinancing for the debt maturities, it may not have sufficient funds or other assets to satisfy all its obligations, which would have a material adverse effect on its business, results of operations and financial condition.

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The outbreak of COVID-19 has negatively affected economic conditions in many parts of the world which may impact the Partnership’s operations and the operations of its customers and suppliers. Although the Partnership’s operations have not been materially affected by the COVID-19 outbreak to date, the ultimate length and severity of the COVID-19 outbreak and its potential impact on the Partnership’s operations and financial condition is uncertain at this time. Furthermore, should there be an outbreak of COVID-19 on board one of the Partnership’s FSRUs or an inability to replace critical supplies or replacement parts due to disruptions to third-party suppliers, adequate crewing or supplies may not be available to fulfill the Partnership’s obligations under its time charter contracts. This could result in off-hire or warranty payments under performance guarantees which would reduce revenues for the impacted period. To date, the Partnership has mitigated the risk of an outbreak of COVID-19 on board its vessels by extending time between crew rotations on the vessels and developing mitigating actions for crew rotations. As a result, the Partnership expects that it may incur somewhat higher crewing expenses to ensure appropriate mitigation actions are in place to minimize risks of outbreaks. To date, the Partnership has not had service interruptions on the Partnership’s vessels. Management and administrative staffs have largely transitioned to working remotely from home to address the specific COVID-19 situation in the applicable geographic location. The Partnership has supported staffs by supplying needed internet boosters and office equipment to facilitate an effective work environment.

Pursuant to the omnibus agreement that the Partnership entered into with Höegh LNG at the time of the initial public offering, Höegh LNG is obligated to offer to the Partnership any FSRU or LNG carrier operating under a charter of five or more years.

Following the Amalgamation, unless otherwise agreed by the parties, some provisions of the omnibus agreement will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels, (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

The statements in this section are forward-looking statements based on management's current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance and outcomes to differ materially from those expressed herein. Please also see “Item 3. Key Information – Risk Factors” and “Item 5. Operating and Financial Review and Prospects – Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects.”

E.Off-Balance Sheet Arrangements

As of December 31, 2020, there were no off-balance sheet arrangements.

F.Tabular Disclosure of Contractual Obligations

The following table sets forth our contractual obligations as of December 31:

	Payments Due by Period
			Less				More
			than 1	1-3		4-5	than 5
(in thousands of U.S. dollars)	Total		Year	Years		Years	Years
Long term debt and revolving credit facility due to owners and affiliates	$	439,929	123,557	69,659	(4)	51,194	195,519
Interest commitments on long-term debt and interest rate swaps (1)		66,698	20,410	25,087		19,022	2,179
Operating lease obligations (2)		60	39	21		—	—
Other long-term liabilities (3)		103	—	103		—	—
Total	$	506,790	144,006	94,870		70,216	197,698

(1) Our interest commitments on long-term debt and interest rate swaps are calculated based upon the varying margins by tranche of the Lampung facility and the $385 million facility and the fixed interest rate of the interest rate swaps since we are fully hedged. We swap a floating LIBOR interest rate on our long-term debt for a fixed interest rate on our swaps.

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(2) Operating lease obligations, please refer to Notes 2 and 11 to our Audited Consolidated Financial Statements included herein.

(3) Our consolidated balance sheet includes other long-term liabilities for an advance provided by the charterer to fund refundable value added tax on the import of the FSRU.

(4) The repayment profile for the years 2021 and 2022 includes the maturity of the FSRU tranche of the Lampung facility in 2021 and assumes the exercise of the prepayment right for the export credit tranche of the Lampung facility in the same period.

G.Safe Harbor

Please read “Forward-Looking Statements.”

Item 6.Directors, Senior Management and Employees

Management of Höegh LNG Partners LP

Our partnership agreement provides that our general partner will irrevocably delegate to our board of directors the authority to oversee and direct our operations, management and policies on an exclusive basis, and such delegation will be binding on any successor general partner of the Partnership. Our general partner, Höegh LNG GP LLC, is wholly owned by Höegh LNG. Our officers will manage our day-to-day activities consistent with the policies and procedures adopted by our board of directors.

Employees of affiliates of Höegh LNG provide services to us under the administrative services Agreement. Please read “Item 7.B. Related Party Transactions—Administrative Services Agreements.”

A.Directors and Senior Management

The following table provides information about our directors and executive officer. The business address for each of our directors and executive officer is Canon’s Court, 5th Floor, 22 Victoria Street, Hamilton, HM12, Bermuda

Name	Age	Position
Andrew Jamieson	73	Chairman of the Board of Directors and Member of the Audit Committee
Sveinung J. S. Støhle	62	Director and Chief Executive Officer
Steven Rees Davies	47	Director
Morten W. Høegh	47	Director
Kathleen McAllister	56	Director, Member of the Audit Committee, Member of the Conflicts Committee
Robert Shaw	65	Director, Member of the Audit Committee, Chairman of the Conflicts Committee
David Spivak	53	Director, Chairman of the Audit Committee, Member of the Conflicts Committee
Håvard Furu	46	Chief Financial Officer

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Andrew Jamieson has served as our director since April 2014 and was appointed as chairman of our board of directors in September 2020. He has extensive experience in the energy industry, in general, and in LNG, in particular. Since 2009, Mr. Jamieson has served as a director of Höegh LNG. From 1974 to 2009, Mr. Jamieson held various positions with Royal Dutch Shell plc in the United Kingdom, the Netherlands, Denmark, Australia and Nigeria. Specifically, from 2005 to 2009, he served as Executive Vice President Gas & Projects and Member of the Gas & Power Executive Committee. From 1999 to 2004, he was Managing Director of Nigeria LNG Limited and Vice President of Bonny Gas Transport Limited. While at Royal Dutch Shell plc, Mr. Jamieson also was in charge of the North West Shelf Project in Australia and served as a director on various Royal Dutch Shell plc companies. In 2006, he was made an Officer of the Order of the British Empire (OBE) for “services to British business and sustainable development in Nigeria.” Mr. Jamieson serves on the boards of GTT (Gaztransport & Technigaz) and Kerogen Capital Hong Kong. Previously, Mr. Jamieson also served on the boards of Woodside Petroleum Ltd., Seven Energy Limited, Chrysaor Holdings Ltd and Velocys PLC. Mr. Jamieson holds a Ph.D. degree from Glasgow University, is the Past President of the Institute of Chemical Engineers and a Fellow of the Royal Academy of Engineering.

Sveinung J. S. Støhle has served as our Chief Executive Officer since August 2020. He has served as our director and chairman of our board of directors since April 2014 but stepped down as a chairman when assuming the role as Chief Executive Officer. Since 2005, Mr. Støhle has served as the President and Chief Executive Officer of Höegh LNG through his employment with Höegh LNG AS. He is also a member of the board of directors for Avenir LNG Limited. Mr. Støhle has more than 25 years of experience from the LNG industry with both shipping and oil and gas companies. Prior to his employment with Höegh LNG, Mr. Støhle held positions as President of Total LNG USA, Inc., Executive Vice President and Chief Operating Officer of Golar LNG Limited, General Manager Commercial of Nigeria LNG Limited and various positions with Elf Aquitaine. Mr. Støhle has a Master of Business Administration from the University of San Francisco and a Bachelor of Science in Finance from California State University.

Steven Rees Davies has served as our director since June 2019 and as a director of Höegh LNG since May 2017. He is also a director of Höegh LNG Partners Operating LLC, Höegh LNG GP LLC and Höegh LNG Galleon Limited. Mr. Rees Davies is a partner within the Corporate department of Appleby (Bermuda) Limited, Höegh LNG’s Bermuda counsel, where he practices in the areas of corporate finance, capital markets, regulation, corporate governance and intellectual property. He also advises on cross jurisdictional corporate transactions and restructurings as well as private and public offerings, placements and introductions to the Bermuda, London and New York stock exchanges, in addition to multinational joint ventures and private equity projects. Mr. Rees Davies graduated from Oxford Brookes University with a Bachelor of Laws and from the College of Law, England, with a Postgraduate Diploma in Legal Practice. Mr. Rees Davies qualified as an attorney and member of the bar of New York (US Southern District) in 2002 and as a solicitor in England and Wales in 2003 (non-practicing). He was called to the Bermuda Bar in 2008. Mr. Rees Davies is a British citizen and resides in Bermuda.

Morten W. Høegh has served as our director since April 2014. Since 2006, Mr. Høegh has served as the Chairman of Höegh LNG, and he also serves as chairman of Leif Höegh (U.K.) Limited. Since 2003, he has been a director of Höegh Autoliners Holdings AS (and its predecessors Leif Höegh & Co. ASA, Leif Höegh & Co. Ltd. and Höegh Autoliners Ltd.). Mr. Høegh is a director of Höegh Eiendom Holdings AS. He is a director and Chairman of Gard P&I (Bermuda) Ltd. and Chairman of its Risk and Election and Governance Committees and a director and Chairman of certain of its subsidiaries. He also serves as the Chairman of the Western Europe committee of DNV GL. From 1998 to 2000, Mr. Høegh worked as an investment banker with Morgan Stanley. He has a Master’s in Business Administration from Harvard Business School with High Distinction (Baker Scholar) and a Master of Science in Ocean Systems Management and a Bachelor of Science in Ocean Engineering from the Massachusetts Institute of Technology.

Kathleen McAllister has served as our director since July 2017. Ms. McAllister served as President, Chief Executive Officer, and Director of Transocean Partners LLC from 2014 and as Chief Financial Officer in 2016. From 2011 to 2014 Ms. McAllister served as Vice President and Treasurer of Transocean Ltd. and led the initial public offering of Transocean Partners in 2014 after holding roles of increasing responsibility in corporate and operations, finance, treasury, accounting and tax with Transocean. Ms. McAllister began her career at Deloitte and served in various finance, treasury, accounting and tax roles at Baker Hughes, Helix Energy Solutions Group and Veritas DGC Inc. prior to joining Transocean. Ms. McAllister serves as an independent non-executive director of Black Hills Corporation (since 2019) and served as an independent non-executive board member of Maersk Drilling (2019 to 2021) where she chaired the Audit and Risk Committee. Ms. McAllister holds a Bachelor of Science degree in Accounting (with Honors) from the University of Houston-Clear Lake and is a National Association Corporate Directors Board Leadership Fellow and a Certified Public Accountant.

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Robert Shaw has served as our director since April 2014. Since 2008, Mr. Shaw has been an owner and a managing director of Mystras Ventures LLC, which makes dry bulk shipping industry-related investments. He is a managing director of Sea Trade Holdings Inc., that owns and operates dry bulk carriers. He is a director of The Steamship Mutual Underwriting Association (Bermuda) Limited, which is a mutual insurance association that insures its members against various risks arising out of the operations of ships. From 2001 to 2007, Mr. Shaw held various positions at Navios Maritime Holdings Inc., including board member, Executive Vice President, General Counsel and President. From 1985 to 2000, Mr. Shaw was a partner at Healy & Baillie LLP, a law firm specializing in shipping and international commercial law. Mr. Shaw also was the chairman and is a member and the secretary of the board of the Carnegie Council for Ethics in International Affairs and has served as a board member and the President of the Society of Maritime Arbitrators, Inc. Mr. Shaw was admitted to the Law Society of England and Wales in 1980 and the New York bar in 1981 and holds a Bachelor of Arts in Jurisprudence from St John’s College, Oxford University.

David Spivak has served as our director since April 2014. Since 2018, Mr. Spivak has been the Group Chief Financial Officer and Senior Vice President, Corporate Development of Persis Holdings Ltd. From 2016 to 2018, Mr. Spivak served as the Chief Financial Officer of Seaspan Corporation and, prior to that, he was the President and Founder of Brockstreet Consulting. From 1995 to 2012, Mr. Spivak worked at Citigroup as a capital markets professional and investment banker. He held a variety of positions at Citigroup, including Managing Director in the Investment Banking and US Equity Capital Markets Groups and Canadian Head of Global Capital Structuring. From 2005 to 2009, Mr. Spivak was based in New York and led Citigroup’s equity capital markets business in the aircraft leasing, maritime and SPAC sectors. Earlier in his career, Mr. Spivak worked at Coopers & Lybrand in the Financial Advisory Services Group. Mr. Spivak has a Master of Business Administration from the University of Chicago and a Bachelor of Commerce from the University of Manitoba. He is a Certified Public Accountant (inactive).

Håvard Furu has served as our Chief Financial Officer since August 2020. Since 2019, Mr. Furu has served as Chief Financial Officer for Höegh LNG through his employment with Höegh LNG AS. From 2017 until February 2019, Mr. Furu served as the chief financial officer of the law firm Wikborg Rein. From 2009 to 2017, he was the chief financial officer of Western Bulk, a drybulk carrier operator. From 2005 to 2009, Mr. Furu was employed by BW Gas in various positions within the finance area, including Assistant Director Strategy and Finance. From 1997 until 2005 he held various positions within auditing with PriceWaterhouse Coopers. Mr. Furu holds a BSc Economics and Business Administration as well as being a Chartered Accountant from the Norwegian School of Business Administration (NHH) in Bergen, Norway. He is a Norwegian citizen.

B.Compensation

Reimbursement of Expenses of Our General Partner

Our general partner does not receive compensation from us for any services it provides on our behalf, although it is entitled to reimbursement for expenses incurred on our behalf. In addition, PT Höegh, the owner of the PGN FSRU Lampung, reimburses Höegh Norway pursuant to the technical information and services agreement for expenses Höegh Norway incurs pursuant to a sub-technical support agreement with Höegh LNG Management. Höegh Cyprus, the entity that owns the Höegh Gallant, reimburses Höegh LNG Management for expenses incurred pursuant to a ship management agreement with Höegh LNG Management, Höegh Norway for expenses incurred pursuant to the Gallant management agreement and Höegh Maritime Management for expenses incurred pursuant to a secondment agreement for crew with Höegh Maritime Management. Our joint ventures reimburse Höegh LNG Management for expenses incurred pursuant to ship management agreements with Höegh LNG Management. Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Support Agreement.”

Executive Compensation

Pursuant to the Höegh Norway Administrative Services Agreement (as defined below), Sveinung J. S. Støhle provides chief executive officer functions and Håvard Furu provides chief financial officer functions for our benefit. Mr. Støhle and Mr. Furu are responsible for our day-to-day management subject to the direction of our board of directors. Our officers and employees and officers and employees of our subsidiaries and affiliates of Höegh LNG and our general partner may participate in employee benefit plans and arrangements sponsored by Höegh LNG, our general partner or their affiliates, including plans that may be established in the future. Under the Höegh Norway Administrative Services Agreement, we paid $2.7 million to Höegh Norway for the year ended December 31, 2020.

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Höegh LNG compensates Mr. Støhle and Mr. Furu in accordance with its own compensation policies and procedures.

Compensation of Directors

Directors receive compensation for attending meetings of our board of directors, as well as committee meetings. During the year ended December 31, 2020, directors each received a director fee of $81,200 per year (paid half in cash and half in equity-based amounts). Chairpersons of the audit and conflicts committees each received a committee fee of $21,900 per year, and other committee members received a committee fee of $11,000 per year. One director voluntarily waived the board compensation payable in 2020. In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of our board of directors or committees. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

2014 Long-Term Incentive Plan

In connection with our initial public offering, we adopted the Höegh LNG Partners LP 2014 Long-Term Incentive Plan, or the “LTIP,” for our employees, officers, consultants and directors who perform services for us and our subsidiaries. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance.

On September 14, 2018, we granted 14,584 phantom units to Richard Tyrrell (previously our Chief Executive Officer and Chief Financial Officer) under the LTIP, one third of which vested as of each of November 30, 2019 and 2020, respectively, and one third of which will vest on November 30, 2021, so long as Mr. Tyrrell continues to provide services to the Partnership or an affiliate. Effective March 21, 2019, we granted 10,917 phantom units to Steffen Føreid, who served as our Chief Executive Officer and Chief Financial Officer until the announcement of his resignation as Chief Executive Officer and Chief Financial Officer on August 6, 2020. One-third of such phantom units vested as of November 30, 2019, and one third of which would have vested on November 30, 2020 and 2021, respectively. Effective March 26, 2020, we granted 8,100 phantom units to Steffen Føreid under the LTIP, one-third of which would have vested on each of November 30, 2021, 2022 and 2023, respectively. Due to Steffen Føreid’s resignation, all unvested units at the time of resignation were forfeited. Additionally, effective September 4, 2020, we awarded a total of 15,528 common units to non-employee directors under the LTIP as compensation for directors’ fees, with an aggregate grant date fair value of $0.2 million, based on our closing unit price on the grant date.

Administration

The LTIP is administered by our board of directors, or an alternative committee appointed by our board of directors, which we refer to together as the “committee” for purposes of this summary. The committee administers the LTIP pursuant to its terms and all applicable state, federal or other rules or laws. The committee has the power to determine to whom and when awards will be granted, determine the type and amount of awards (measured in cash or in common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.

Securities to Be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 658,000 common units, subject to adjustment due to recapitalization or reorganization as provided under the LTIP. In addition, if any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under the LTIP may be newly issued common units or common units acquired in the open market, from any person, or any combination of the foregoing.

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Awards

Unit Options. We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for a unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option. Unit options may be exercised in the manner and at such times as the committee determines for each unit option. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

Unit Appreciation Rights. A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee may make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right.

Restricted Units. A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. Cash distributions paid with respect to our common units will be paid to the holder of restricted units without restriction at the same time as such distributions are paid to unitholders generally, unless otherwise specified in the applicable award agreement governing the restricted units.

Unit Awards. The committee may grant common units that are not subject to restrictions to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units. Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times and under such circumstances as determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof as determined by the committee. Distribution equivalent rights may be granted in tandem with a phantom unit award, which may provide that cash distribution equivalents will be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights. The committee may grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Cash Awards. The committee may grant awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards. The committee may condition the right to exercise or receive an award, or the settlement or vesting of an award, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

Other Unit-Based Awards. The committee may grant other unit-based awards under the LTIP, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

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Substitute Awards. The committee may grant awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation or acquisition by or involving us, an affiliate of another entity or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with applicable laws and exchange rules.

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, tax withholding obligations with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Anti-Dilution Adjustments and Change in Control

In the event of any “equity restructuring” event (such as a unit dividend, unit split, reverse unit split or similar event) with respect to the common units that may result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”) if adjustments to awards in such event were discretionary, the committee will adjust the number and type of units covered by each outstanding award, the terms and conditions of each such award, the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP, in each case, to equitably reflect the restructuring event. With respect to any similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustments to awards were discretionary (such as certain recapitalizations, reclassifications, reorganizations, mergers, combinations, exchanges or other relevant changes in capitalization), adjustment will be made by the committee in its discretion in accordance with the terms of the LTIP with respect to, as appropriate, the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events. Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

Termination of Employment or Service

The consequences on outstanding awards under the LTIP of the termination of a participant’s employment, consulting arrangement or membership on our board of directors will be determined by the committee in the terms of the relevant award agreement.

C.Board Practices

General

Our partnership agreement provides that our general partner irrevocably delegates to our board of directors the authority to oversee and direct our operations, management and policies on an exclusive basis, and such delegation is binding on any successor general partner of the Partnership. Our general partner, Höegh LNG GP LLC, is wholly owned by Höegh LNG. Our officers manage our day-to-day activities consistent with the policies and procedures adopted by our board of directors.

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Our current board of directors consists of seven members, three of whom were appointed by our general partner and four of whom were elected by our common unitholders. Sveinung J. S. Støhle, Steven Rees Davies and Kathleen McAllister were appointed by our general partner and will serve for terms as determined by our general partner. The directors elected by our common unitholders, Morten W. Høegh, Andrew Jamieson, David Spivak and Robert Shaw, are divided into four classes serving staggered terms. Mr. Jamieson is designated as our Class I elected director and will serve until our annual meeting of unitholders in 2023, Mr. Shaw is designated as our Class II elected director and will serve until our annual meeting of unitholders in 2024, Mr. Spivak is designated as our Class III elected director and will serve until our annual meeting of unitholders in 2021 and Mr. Høegh is designated as our Class IV elected director and will serve until our annual meeting of unitholders in 2022. At each subsequent annual meeting of unitholders, directors will be elected to succeed the class of director whose term has expired by a plurality of the votes of the common unitholders. Directors elected by our common unitholders may be nominated by our board of directors or by any limited partner or group of limited partners that holds at least 10% of the outstanding common units.

Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, to preserve our ability to claim an exemption from U.S. federal income tax under Section 883 of the Code, if at any time, any person or group owns beneficially more than 4.9% of any class of units then outstanding, any such units owned by that person or group in excess of 4.9% may not be voted (except for purposes of nominating a person for election to our board of directors). The voting rights of any such unitholders in excess of 4.9% will effectively be redistributed pro rata among the other common unitholders holding less than 4.9% of the voting power of such class of units. Our general partner, its affiliates and persons who acquired common units with the prior approval of our board of directors will not be subject to this 4.9% limitation except with respect to voting their common units in the election of the elected directors.

The Series A preferred units generally have no voting rights except (i) with respect to amendments to the partnership agreement that would have a material adverse effect on the existing terms of the Series A preferred units, (ii) or in the event the Partnership proposes to issue Parity Securities, if the cumulative dividends payable on outstanding Series A preferred units are in arrears, or Senior Securities. However, if and whenever distributions payable on the Series A preferred units are in arrears for six or more quarterly periods, whether or not consecutive, holders of Series A preferred units (voting together as a class with all other classes of Parity Securities upon which like voting rights have been conferred and are exercisable) will be entitled to replace one of the members of our board of directors appointed by our general partner with a person nominated by such holders (unless the holders of Series A preferred units, voting together as a class with all other classes of Parity Securities upon which like voting rights have been conferred and are exercisable, voting as a class, have previously elected a member of our board of directors, and such director continues then to serve on the board of directors).

Committees

We have an audit committee that, among other things, reviews our external financial reporting, engages our external auditors and oversees our internal audit activities and procedures, if any, and the adequacy of our internal accounting controls. Our audit committee is comprised of four directors, Ms. McAllister, Mr. Jamieson, Mr. Shaw and Mr. Spivak. Each of Ms. McAllister, Mr. Jamieson, Mr. Shaw and Mr. Spivak satisfies the independence standards required for audit committee members of the SEC and the NYSE. Ms. McAllister and Mr. Spivak qualify as “audit committee financial experts” for purposes of SEC rules and regulations.

We also have a conflicts committee comprised of three members of our board of directors. The conflicts committee will be available at our board of directors’ discretion to review specific matters that our board of directors believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of us or directors, officers or employees of our general partner or its affiliates, and must meet the independence standards established by the NYSE to serve on an audit committee of a board of directors and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our directors, our general partner or its affiliates of any duties any of them may owe us or our unitholders. Our conflicts committee is comprised of Ms. McAllister, Mr. Shaw and Mr. Spivak.

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Exemptions from Corporate Governance Rules

Because we qualify as a foreign private issuer under SEC rules, we are permitted to follow the corporate governance practices of the Marshall Islands (the jurisdiction in which we are organized) in lieu of certain of the corporate governance requirements that would otherwise be applicable to us. The NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is comprised of a majority of independent directors. Under Marshall Islands law, we are not required to have a board of directors comprised of a majority of directors meeting the independence standards described in the NYSE rules. In addition, the NYSE rules do not require limited partnerships like us to have boards of directors comprised of a majority of independent directors.

NYSE rules do not require foreign private issuers or limited partnerships like us to establish a compensation committee or a nominating/corporate governance committee. Similarly, under Marshall Islands law, we are not required to have a compensation committee or a nominating/corporate governance committee. Accordingly, we do not have a compensation committee or a nominating/corporate governance committee. For a listing and further discussion of how our corporate governance practices differ from those required of U.S. companies listed on the NYSE, please read “Item 16G. Corporate Governance.”

D.Employees

Employees of Höegh LNG’s affiliates provide administrative services to us pursuant to the administrative services agreement. Our board of directors has the authority to hire other employees as deemed necessary. Certain affiliates of Höegh LNG also provide commercial and technical management services to our fleet pursuant to ship management agreements, the Gallant management agreement, a sub-technical support agreement, commercial and administration management agreements and other service agreements. Crew are employed directly by our or by Höegh LNG’s subsidiaries to operate our FSRUs. As of December 31, 2020, our or Höegh LNG's subsidiaries employed approximately 647 seagoing staff to serve on our FSRUs.

E.Unit Ownership

Please read “Item 7.A. Major Unitholders.”

Item 7.Major Unitholders and Related Party Transactions

A.Major Unitholders

The following table sets forth the beneficial ownership of our common units as of March 31, 2021, by each of our directors and executive officers and each person that we know to beneficially own more than 5% of our outstanding common units:

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Major Unitholders

	Common Units
	Beneficially Owned
Name of Beneficial Owner	Number	Percent
Höegh LNG Holding Ltd.(1)	15,257,498	45.7	%
FMR LLC(2)	2,145,613	6.4	%
Invesco Ltd(3)	2,002,122	6.0	%
Andrew Jamieson (Chairman of the Board of Directors)	*	*
Steven Mathew Rees Davies (Director)	*	*
Morten W. Høegh (Director)(4)	441,037	1.3	%
Kathleen McAllister (Director)	*	*
Robert Shaw (Director)	*	*
David Spivak (Director)	*	*
Sveinung J. S. Støhle (Director and Chief Executive Officer)	*	*
Håvard Furu (Chief Financial Officer)	*	*
All directors and executive officers as a group (8 persons)	517,504	1.6	%

* Less than 1%

(1) Höegh LNG Holdings Ltd. is a public company listed on the Oslo Børs stock exchange. Leif Höegh & Co. Ltd. is the largest shareholder of Höegh LNG Holdings Ltd., holding an 48.88% ownership interest. Leif Höegh & Co. Ltd. is indirectly controlled by Leif O. Høegh and a family trust under which Morten W. Høegh, one of our directors, is the primary beneficiary.

(2) FMR LLC and Abigail P. Johnson (collectively, “FMR LLC”) each have sole dispositive power as to 2,145,613 common units. This information is based on the Schedule 13G/A filed by FMR LLC on February 8, 2021.

(3) Invesco Ltd. (“Invesco Ltd”) has a sole dispositive power as to 2,002,122 common units. This information is based on Schedule 13G filed by Invesco Ltd on February 16, 2021.

(4) Morten W. Høegh may be deemed to have shared beneficial ownership of 441,037 common units through direct and indirect ownership interests in Leif Höegh & Co Ltd. and Brompton Cross VII Limited.

On March 8, 2021, Höegh LNG announced a recommended offer by LHC and funds managed by MSIP through a 50/50 joint venture, Larus Holding Limited (“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates. Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange.

Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, to preserve our ability to claim an exemption from U.S. federal income tax under Section 883 of the Code, if at any time any person or group owns beneficially more than 4.9% of any class of units then outstanding, any units beneficially owned by that person or group in excess of 4.9% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to our board of directors), determining the presence of a quorum or for other similar purposes under our partnership agreement, unless otherwise required by law. The voting rights of any such unitholders in excess of 4.9% will effectively be redistributed pro rata among the other common unitholders holding less than 4.9% of the voting power of all classes of units entitled to vote. Our general partner, its affiliates and persons who acquired common units with the prior approval of our board of directors will not be subject to this 4.9% limitation except with respect to voting their common units in the election of the elected directors.

Höegh LNG exercises influence over the Partnership through our general partner, a wholly owned subsidiary of Höegh LNG, which in its sole discretion appoints three directors to our board of directors. Please read “Item 6. Directors, Senior Management and Employees—Management of Höegh LNG Partners LP.”

B.Related Party Transactions

As a result of our relationships with Höegh LNG and its affiliates, we and our subsidiaries have entered into various agreements that were not the result of arm’s length negotiations. A number of agreements were entered into in connection with our IPO. In addition, we may enter into new agreements in the future. We have established a conflicts

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committee that may review future related party transactions. Please refer to “Item 6.C. Board Practices—Committees.” The related party agreements that we have entered in to or were party to since January 1, 2018 are discussed below.

Our partnership agreement sets forth procedures by which future related party transactions may be approved or resolved by our board of directors. Pursuant to our partnership agreement, our board of directors may, but is not required to, seek the approval of a related party transaction from the conflicts committee of our board of directors or from the common unitholders. Affiliated transactions that are not approved by the conflicts committee of our board of directors and that do not involve a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our board of directors may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us. If the above procedures are followed, it will be presumed that, in making its decision, our board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. When our partnership agreement requires someone to act in good faith, it requires that person to believe that he is acting in the best interests of the Partnership, unless the context otherwise requires.

Our conflicts committee is comprised of at least two members of our board of directors. The conflicts committee is available at our board of directors’ discretion to review specific matters that our board of directors believes may involve conflicts of interest. The conflicts committee may determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of us or directors, officers or employees of our general partner or its affiliates, and must meet the independence standards established by the NYSE to serve on an audit committee of a board of directors and certain other requirements.

Omnibus Agreement

Upon completion of the IPO, we entered into an omnibus agreement with Höegh LNG, our general partner and certain of our other subsidiaries. The following discussion describes certain provisions of the omnibus agreement.

Noncompetition

Under the omnibus agreement, Höegh LNG agrees, and causes its controlled affiliates (other than us, our general partner and our subsidiaries) to agree, not to acquire, own, operate or charter any FSRU or LNG carrier operating under a charter for five or more years. For purposes of this section, we refer to these vessels, together with any related charters and ancillary installations or equipment covered by such charters, as “Five-Year Vessels” and to all other FSRUs and LNG carriers as “Non-Five-Year Vessels.” The restrictions in this paragraph will not prevent Höegh LNG or any of its controlled affiliates (other than us and our subsidiaries) from:

(1) acquiring, owning, operating or chartering any Non-Five-Year Vessel;

(2) acquiring one or more Five-Year Vessels if Höegh LNG promptly offers to sell the vessel to us for the acquisition price plus any administrative costs (including re-flagging and reasonable legal costs) associated with the transfer to us at the time of the acquisition;

(3) delivering a Non-Five-Year Vessel under charter for five or more years if Höegh LNG offers to sell the vessel to us for fair market value (x) promptly after the time she becomes a Five-Year Vessel and (y) at each renewal or extension of that charter for five or more years;

(4) acquiring one or more Five-Year Vessels as part of the acquisition of a controlling interest in a business or package of assets and owning, operating or chartering those vessels; provided, however, that:

(a) if less than a majority of the value of the business or assets acquired is attributable to Five-Year Vessels, as determined in good faith by Höegh LNG’s board of directors, Höegh LNG must offer to sell such Five-Year Vessels to us for their fair market value plus any additional tax or other similar costs Höegh LNG incurs in connection with the acquisition and the transfer of such vessels to us separate from the acquired business; and

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(b) if a majority or more of the value of the business or assets acquired is attributable to Five-Year Vessels, as determined in good faith by Höegh LNG’s board of directors, Höegh LNG must notify us of the proposed acquisition in advance. Not later than 10 days following receipt of such notice, we will notify Höegh LNG if we wish to acquire any of such vessels in cooperation and simultaneously with Höegh LNG acquiring the Non-Five-Year Vessels. If we do not notify Höegh LNG of our intent to pursue the acquisition within 10 days, Höegh LNG may proceed with the acquisition and then offer to sell such vessels to us as provided in clause (a) above;

(5) acquiring a non-controlling interest in any company, business or pool of assets;

(6) acquiring, owning, operating or chartering any Five-Year Vessel if we do not fulfill our obligation to purchase such vessel in accordance with the terms of any existing or future agreement;

(7) acquiring, owning, operating or chartering a Five-Year Vessel subject to the offers to us described in clauses (2), (3) and (4) above pending our determination whether to accept such offers and pending the closing of any offers we accept;

(8) providing ship management services relating to any vessel;

(9) owning or operating any Five-Year Vessel that Höegh LNG owned on the closing date of our IPO and that was not part of our initial fleet; or

(10) acquiring, owning, operating or chartering a Five-Year Vessel if we have previously advised Höegh LNG that we consent to such acquisition, ownership, operation or charter.

If Höegh LNG or any of its controlled affiliates (other than us or our subsidiaries) acquires, owns, operates or charters Five-Year Vessels pursuant to any of the exceptions described above, it may not subsequently expand that portion of its business other than pursuant to those exceptions. However, such Five-Year Vessels could eventually compete with our vessels upon their re-chartering.

In addition, under the omnibus agreement we agree, and cause our subsidiaries to agree, to acquire, own, operate or charter Five-Year Vessels only. The restrictions in this paragraph will not prevent us or any of our subsidiaries from:

(1) owning, operating or chartering any Non-Five-Year Vessel that was previously a Five-Year Vessel while owned by us;

(2) acquiring Non-Five-Year Vessels as part of the acquisition of a controlling interest in a business or package of assets and owning, operating or chartering those vessels; provided, however, that:

(a) if less than a majority of the value of the business or assets acquired is attributable to Non-Five-Year Vessels, as determined in good faith by us, we must offer to sell such vessels to Höegh LNG for their fair market value plus any additional tax or other similar costs that we incur in connection with the acquisition and the transfer of such vessels to Höegh LNG separate from the acquired business; and

(b) if a majority or more of the value of the business or assets acquired is attributable to Non-Five-Year Vessels, as determined in good faith by us, we must notify Höegh LNG of the proposed acquisition in advance. Not later than 10 days following receipt of such notice, Höegh LNG must notify us if it wishes to acquire the Non-Five-Year Vessels in cooperation and simultaneously with us acquiring the Five-Year Vessels. If Höegh LNG does not notify us of its intent to pursue the acquisition within 10 days, we may proceed with the acquisition and then offer to sell such vessels to Höegh LNG as provided in clause (a) above;

(3) acquiring, owning, operating or chartering any Non-Five-Year Vessels subject to the offer to Höegh LNG described in clause (2) above, pending its determination whether to accept such offer and pending the closing of any offer it accepts; or

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(4) acquiring, owning, operating or chartering Non-Five-Year Vessels if Höegh LNG has previously advised us that it consents to such acquisition, ownership, operation or charter.

If we or any of our subsidiaries acquires, owns, operates or charters Non-Five-Year Vessels pursuant to any of the exceptions described above, neither we nor such subsidiary may subsequently expand that portion of our business other than pursuant to those exceptions.

Upon a change of control of us or our general partner, the noncompetition provisions of the omnibus agreement will terminate immediately. Upon a change of control of Höegh LNG, the noncompetition provisions of the omnibus agreement applicable to Höegh LNG will terminate at the date of the change of control. On the date on which a majority of our directors ceases to consist of directors that were (i) appointed by our general partner prior to our first annual meeting of unitholders and (ii) recommended for election by a majority of our appointed directors, the noncompetition provisions applicable to Höegh LNG shall terminate immediately. See “—The Amalgamation”.

In the event that Höegh LNG is required to make an offer to sell to us a Five-Year Vessel, or we are required to make an offer to sell to Höegh LNG a Non-Five-Year Vessel, and we and Höegh LNG are unable to agree upon the fair market value of such vessel, the fair market value will be determined by a mutually acceptable investment banking firm, ship broker or other expert advisor, and we or Höegh LNG, as the case may be, will have the right, but not the obligation, to purchase the vessel at such price.

Rights of First Offer on FSRUs and LNG Carriers

Under the omnibus agreement, we and our subsidiaries grant to Höegh LNG a right of first offer on any proposed sale, transfer or other disposition of any Five-Year Vessels or Non-Five-Year Vessels owned by us. Under the omnibus agreement, Höegh LNG agrees (and will cause its subsidiaries to agree) to grant a similar right of first offer to us for any Five-Year Vessels they might own. These rights of first offer will not apply to a (i) sale, transfer or other disposition of vessels between any affiliated subsidiaries or pursuant to the terms of any current or future charter or other agreement with a charter party or (ii) merger with or into, or sale of substantially all of the assets to, an unaffiliated third party.

Prior to engaging in any negotiation regarding any vessel disposition with respect to a Five-Year Vessel with an unaffiliated third party or any Non-Five-Year Vessel, we or Höegh LNG, as the case may be, will deliver a written notice to the other relevant party setting forth the material terms and conditions of the proposed transaction. During the 30-day period after the delivery of such notice, we and Höegh LNG, as the case may be, will negotiate in good faith to reach an agreement on the transaction. If we do not reach an agreement within such 30-day period, we or Höegh LNG, as the case may be, will be able within the next 180 calendar days to sell, transfer, dispose or re-charter the vessel to a third party (or to agree in writing to undertake such transaction with a third party) on terms generally no less favorable to us or Höegh LNG, as the case may be, than those offered pursuant to the written notice.

Upon a change of control of us or our general partner, the right of first offer provisions of the omnibus agreement will terminate immediately. Upon a change of control of Höegh LNG, the right of first offer provisions applicable to Höegh LNG under the omnibus agreement will terminate at the date of the change of control. On the date on which a majority of our directors ceases to consist of directors that were (i) appointed by our general partner prior to our first annual meeting of unitholders and (ii) recommended for election by a majority of our appointed directors, the provisions related to the rights of first offer granted to us by Höegh LNG shall terminate immediately.

Indemnification

Under the omnibus agreement, Höegh LNG agreed to indemnify us until August 12, 2019 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us. No indemnification claims were filed for environmental liabilities under the agreement prior to its expiration.

Höegh LNG also indemnifies us for losses:

● related to certain tax liabilities attributable to the operation of the assets contributed or sold to us prior to the time they were contributed or sold;

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● with respect to any non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project (including the construction of the related tower yoke mooring system) occurring prior to the date of acceptance of the PGN FSRU Lampung pursuant to the time charter; and

● pursuant to a letter agreement dated August 12, 2015, Höegh LNG confirmed that the indemnification provisions of the omnibus agreement include indemnification for all non-budgeted, non-creditable Indonesian value added taxes and non-budgeted Indonesian withholding taxes, including any related impact on cash flow from PT Höegh and interest and penalties associated with any non-timely Indonesian tax filings related to the ownership or operation of the PGN FSRU Lampung and the Mooring whether incurred (i) prior to the closing date of the IPO, (ii) after the closing date of the IPO to the extent such taxes, interest, penalties or related impact on cash flows relate to periods of ownership or operation of the PGN FSRU Lampung and the Mooring and are not subject to prior indemnification payments or deemed reimbursable by the charterer under its audit of the taxes related to the PGN FSRU Lampung time charter for periods up to and including June 30, 2015, or (iii) after June 30, 2015 to the extent withholding taxes exceed the minimum amount of withholding tax due under Indonesian tax regulations due to lack of documentation or untimely withholding tax filings.

Amendments

The omnibus agreement may not be amended without the prior approval of the conflicts committee of our board of directors if the proposed amendment will, in the reasonable discretion of our board of directors, adversely affect holders of our common units.

Pursuant to our partnership agreement, our general partner, our board of directors and our conflicts committee are entitled to make decisions in “good faith” if they believe that the decision is in our best interests. Our partnership agreement permits our general partner, our board of directors and our conflicts committee to consult with advisors and consultants, such as, among others, appraisers and investment bankers, selected by either of them to assist them with, among other things, the determination of the fair market value of a vessel. Any act taken or omitted to be taken in reliance upon the advice or opinion such advisors as to matters that our general partner, our board of directors and our conflicts committee reasonably believes to be within such advisor’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice.

The Amalgamation

On March 8, 2021, Höegh LNG announced a recommended offer by LHC and funds managed by MSIP through a 50/50 joint venture, Larus Holding Limited (“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates (the “Amalgamation”). Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange. The Amalgamation has been approved by Höegh LNG’s shareholders and bondholders and is anticipated to close in the first half of 2021. The Amalgamation is subject to waivers of specific change of control and delisting provisions in relation to certain of our and Höegh LNG's credit agreements, as well as the satisfaction of other customary closing conditions.

Following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels, (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

Indemnification Agreement

On September 27, 2017, we entered into an indemnification agreement with Höegh LNG with respect to the boil-off claims under the Neptune and Cape Ann time charters, pursuant to which Höegh LNG will, among other things, indemnify us for our share of any losses and expenses related to or arising from the failure of either Neptune or Cape Ann to meet the performance standards related to the daily boil-off of LNG under their respective time charters (including any cash impact that may result from any settlement with respect to such claims, including any reduction in

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the hire rate under either time charter). Please read note 17 “Commitments and Contingencies” of our consolidated financial statements.

Administrative Services Agreements

Höegh Norway Administrative Services Agreement

In December 2019, the Partnership and the operating company entered an administrative services agreement with Höegh Norway, pursuant to which Höegh Norway provides certain administrative services to us (the “administrative services agreement”). The administrative services agreement replaced the Prior Höegh UK Administrative Services Agreement and the Prior Höegh Norway Administrative Services Agreement, each as defined below. We reimbursed Höegh Norway approximately $2.7 million and $2.9 million under the administrative services agreement for the years ended December 31, 2020 and 2019, respectively.

Each month, we and our operating company reimburse Höegh Norway for its reasonable costs and expenses incurred in connection with the provision of the services under the administrative services agreement. Höegh Norway receives a service fee in U.S. Dollars equal to 3.0% of the costs and expenses incurred by it in connection with providing services. The services provided under the administrative services agreement will be provided in a diligent manner, as we or our operating company may reasonably direct.

The administrative services agreement may be terminated by us and our operating company upon 90 days’ written notice for any reason in the sole discretion of our and our operating company’s boards of directors. The administrative services agreement may be terminated by Höegh Norway at any time on or after December 31, 2024 upon 90 days’ written notice for any reason in the sole discretion of Höegh Norway. The administrative services agreement may also be terminated solely by Höegh Norway upon 90 days’ written notice if:

● there is a change of control of us or our general partner;

● a receiver is appointed for all or substantially all of our property or our operating company’s property;

● an order is made to wind up the Partnership or our operating company;

● a final judgment, order or decree that materially and adversely affects our or our operating company’s ability to perform the agreement is obtained or entered and not vacated, discharged or stayed; or

● we make a general assignment for the benefit of our creditors, file a petition in bankruptcy or for liquidation or commence any reorganization proceedings.

On April 9, 2021, the parties amended the administrative services agreement to provide that it would continue in full force and effect following the consummation of the Amalgamation and that Höegh Norway would not enforce any rights to terminate the administrative services agreement as a result of the consummation of the Amalgamation.

The administrative services provided by Höegh Norway to the Partnership and our operating company include:

● bookkeeping, audit and accounting services: assisting with the maintenance of our corporate books and records, assisting with the preparation of our tax returns and arranging for the provision of audit and accounting services;

● legal and insurance services: arranging for the provision of legal, insurance and other professional services and maintaining our existence and good standing in necessary jurisdictions;

● administrative and clerical services: assisting with office space and arranging the provision of IT services;

● advisory services: assisting in complying with U.S. and other applicable securities laws;

● assisting with the integration of any acquired businesses.

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Under the administrative services agreement, Sveinung J. S. Støhle and Håvard Furu, as officers of Höegh Norway, provide executive officers functions for our benefit.

Under the administrative services agreement, we and the operating company will indemnify Höegh Norway and its subcontractors against all actions that may be brought against them as a result of their performance of the administrative services including, without limitation, all actions brought under the environmental laws of any jurisdiction, and against and in respect of all costs and expenses they may suffer or incur due to defending or settling such actions; provided, however, that such indemnity excludes any or all losses to the extent that they are caused by or due to the fraud, gross negligence or willful misconduct of Höegh Norway or such subcontractor or its officers, employees and agents.

Prior Administrative Services Agreements

In connection with the IPO, we and our operating company entered into an administrative services agreement with Höegh UK (the “Prior Höegh UK Administrative Services Agreement”), pursuant to which Höegh UK provided us and our operating company certain administrative services. The agreement had an initial term of five years and expired during 2019. Höegh UK received a service fee in U.S. Dollars equal to 5.0% of the costs and expenses incurred by it in connection with providing services. We reimbursed Höegh UK approximately $2.9 million and $2.7 million in total under the Prior Höegh UK Administrative Services Agreement for the years ended December 31, 2019 and 2018, respectively.

Under the Prior Höegh UK Administrative Services Agreement, Höegh UK was permitted to subcontract to Höegh Norway certain of the administrative services provided to us pursuant to an administrative services agreement with Höegh Norway (the “Prior Höegh Norway Administrative Services Agreement”). This agreement had an initial term of five years and expired during 2019. Höegh Norway received a service fee in U.S. Dollars equal to 3.0% of the costs and expenses incurred by it in connection with providing services. Höegh UK reimbursed Höegh Norway approximately $2.9 million and $2.1 million in total under the Prior Höegh Norway Administrative Services Agreement for the years ended December 31, 2019 and 2018, respectively.

Our operating company and Höegh UK entered into administrative services agreements with Leif Höegh UK (the “Prior Leif Höegh UK Administrative Services Agreements”), pursuant to which Leif Höegh UK provided certain administrative services. Each of the Prior Leif Höegh UK Administrative Services Agreements were terminated by mutual agreement during 2019.

Our operating company and Höegh UK reimbursed Leif Höegh UK for its reasonable costs and expenses incurred in connection with the Prior Leif Höegh UK Administrative Services Agreements. In addition, Leif Höegh UK received a services fee equal to 5% of the costs and expenses of secretarial services under the agreement with Höegh UK. For the year ended December 31, 2019 there were no expenses incurred under the Prior Leif Höegh UK Administrative Services Agreements. Höegh UK reimbursed Leif Höegh UK approximately $0.2 million in total under the Prior Leif Höegh UK Administrative Services Agreements for the year ended December 31, 2018.

Commercial and Administration Management Agreements

Each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. has entered into a commercial and administration management agreement with Höegh Norway. Pursuant to each agreement, Höegh Norway provides the following services to SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., as applicable:

● accounting, including budgeting, reporting and annual audited reports;

● finance and cash management;

● in-house legal;

● commercial;

● insurance; and

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● general office administration and secretary functions.

Each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. pays Höegh Norway an annual management fee equal to costs incurred plus 3%. Höegh Norway was paid management fees of approximately $0.7 million under the commercial and administration management agreements with both SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd, for the year ended December 31, 2020. For the year ended December 31, 2019 management fees of approximately $0.6 million and $0.7 million were paid under the commercial and administration management agreements by each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., respectively. For the year ended December 31, 2018, management fees of approximately $0.9 million and $0.8 million were paid under the commercial and administration management agreements by each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., respectively.

Each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. also will indemnify Höegh Norway and its employees and agents against claims brought against them under the applicable commercial and administration management agreement. The agreements may be terminated by either party upon 90 days’ written notice.

Ship Management Agreements and Sub-Technical Support Agreement

In order to assist with the technical and maritime management of the vessels, each of SRV Joint Gas Ltd., SRV Joint Gas Two Ltd., Höegh Cyprus and Höegh Colombia has entered into a ship management agreement with Höegh LNG Management, and Höegh Norway has entered into a sub-technical support agreement with Höegh LNG Management for the technical management of the PGN FSRU Lampung. Each of the ship management agreements and the sub-technical support agreement provides that Höegh LNG Management must use its best endeavors to provide technical services, including but not limited to the following:

· crew management: except with respect to the ship management agreements with Höegh Cyprus and Höegh Colombia, providing suitably qualified crew for each vessel, arranging for all transportation of the crew, ensuring the crew meets all medical requirements of the flag state, training the crew and conducting union negotiations;

● technical management: supervise the maintenance and efficiency of the vessel, arranging and supervising drydockings, repairs, alterations and maintenance of the vessel and arranging and supplying the necessary stores, spares and lubricating oils;

● provisions: arranging for the supply of provisions; and

● accounting: establishing an accounting system that keeps true and correct accounts with respect to ship management services and maintains the records of all costs and expenditures incurred.

Each of the ship management agreements may be terminated by Höegh LNG Management if the vessel owner fails to pay any amount due under the agreement or employs the vessel in a hazardous or illegal manner. Each of these agreements also may be terminated by the vessel owner if Höegh LNG Management is in material breach of its obligations. If the vessel is sold, becomes a total loss or is requisitioned, or if an order or resolution is passed for the winding up, dissolution, liquidation or bankruptcy of either party or if a receiver is appointed for either party, the agreement terminates. With respect to the ship management agreements or sub-technical support agreement with each of SRV Joint Gas Ltd., SRV Joint Gas Two Ltd., Höegh Norway and Höegh Cyprus, either party may terminate the ship management agreements and the sub-technical support agreement upon 30 days’ notice (with respect to the ship management agreement with Höegh Cyprus) or 90 days’ notice (with respect to the other agreements).

For each of the respective years ended December 31, 2020, 2019 and 2018, annual management fees of approximately $3.6 million, in the aggregate, were paid under the ship management agreements or sub-technical support agreement. In addition, the vessel owner must indemnify Höegh LNG Management and its employees, agents and subcontractors against all actions, proceedings, claims, demands or liabilities arising in connection with the performance of the ship management agreements or the sub-technical support agreement, unless the same resulted solely from the negligence, gross negligence or willful default of Höegh LNG Management or its employees, agents and subcontractors, in which case Höegh LNG Management will be liable in an amount up to 10 times the annual management fee.

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Gallant Management Agreement

Höegh Cyprus is party to a management agreement with Höegh Norway, pursuant to which Höegh Norway provides administrative, commercial and technical management services, each as instructed from time to time by Höegh Cyprus. The services performed under the Gallant management agreement may include, but are not limited to:

● administrative management services, including:

o provision of a person to be appointed as president or managing director of Höegh Cyprus;

o services relating to the day-to-day running of the business of Höegh Cyprus;

o management and provision of controller functions for financial matters;

o arranging entry into loan agreements, currency exchange agreements, interest hedging agreements, financial swap agreements, and other agreements in respect of futures and derivative instruments, each subject to the authorization of Höegh Cyprus’s board of directors;

o provision of budgets and financial statements, including long- and short-term budgets, long term financial forecasts, status reports and projections, annual reports and quarterly reports;

o handling and settling minor claims by third parties; and

o bringing or defending actions, suits and proceedings;

● commercial management services, including;

o chartering services, including seeking and negotiating employment for the Höegh Gallant, appointment of brokers and agents, and concluding charter contracts, subject to the authorization of Höegh Cyprus’ board of directors;

o arranging the provision of bunker fuel for the Höegh Gallant;

o operation of the Höegh Gallant, including the provision of compatibility/interface studies, FSRU approval and vetting processes and voyage estimates and accounts and calculation of hire, freights, demurrage and dispatch moneys due from or due to the charterer, and the issuance of voyage instructions, appointing agents and stevedores and to arrange survey of cargoes; and

o freight management, including provision of freight estimates and accounts and calculation of hire and freights and/or demurrage and dispatch money due from or due to charterers and arranging proper payment of all hire and freight revenues; and

● technical management services, including arranging insurance and handling and settling all insurance, salvage and other claims.

The Gallant management agreement’s term was concurrent with the term of the Höegh Gallant time charter with EgyptCo but continues thereafter until either party terminates the agreement upon six months’ notice. Additionally, Höegh Norway may terminate or suspend performance under the agreement if Höegh Cyprus fails to pay any amount due under the agreement. If an order or resolution is passed for the winding up, dissolution, liquidation or bankruptcy of either party or if a receiver is appointed for either party, the agreement terminates.

Höegh Cyprus pays Höegh Norway an annual management fee in NOK of Höegh Norway’s documented costs plus 3%. An estimate of the annual management fee forms the basis of an amount payable by equal monthly installments in arrears. Settlement of the discrepancy between the estimated management fee and the actual management fee takes place at the end of each calendar year. Höegh Cyprus paid Höegh Norway approximately $0.1 million, $0.1 million and $0.2 million under the Gallant management agreement for the years ended December 31, 2020, 2019 and 2018, respectively.

Höegh Cyprus must indemnify Höegh Norway and its employees, agents and subcontractors against all actions, proceedings, claims, demands or liabilities arising in connection with the performance of the Gallant management agreement, unless the same resulted solely from the negligence, gross negligence or willful default of Höegh Norway or its employees, agents and subcontractors. If a claim is the sole result of the negligence, gross negligence or willful default of Höegh Norway or its employees, agents and subcontractors, then Höegh Norway is liable in an amount up to NOK 500,000 per incident.

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Technical Information and Services Agreement

PT Höegh entered into a technical information and services agreement with Höegh Norway, pursuant to which Höegh Norway provides PT Höegh certain technical information and services. The technical information and services agreement’s term is concurrent with the term of the PGN FSRU Lampung time charter, including any exercised extension options.

The technical information and services agreement may be terminated with immediate effect prior to the end of its term if either PT Höegh or Höegh Norway (i) fails to pay any amount due under the technical information and services agreement and such failure continues for more than 14 days after notice of such failure was given to the failing party, (ii) commits a material breach of the technical information and services agreement that remains unremedied for more than 30 days after the breaching party was notified of such material breach or (iii) suffers an insolvency event. The technical information and services agreement may also be terminated by PT Höegh or Höegh Norway upon 30 days’ written notice.

Pursuant to the technical information and services agreement, Höegh Norway provides technical information, consisting of data, commercial information and technical information, to PT Höegh relating to the design, construction, operation and maintenance of the PGN FSRU Lampung and the Mooring. During the period of the PGN FSRU Lampung time charter, including any exercised extension options, Höegh Norway also provides PT Höegh non-transferrable and non-exclusive intellectual property rights in respect of the technical information, along with the safety management system and certain databases, technology and software.

The services provided by Höegh Norway to PT Höegh include:

● commercial support, including:

o assisting in identifying suppliers, liaising with off-shore suppliers of goods and services, assisting in identifying insurance providers;

o assisting in identifying insurance providers; and

o assisting in negotiations and reviewing contracts and insurance policies;

● technical support and advice, including in relation to:

o identification, assessment and resolution of technical issues;

o information technology;

o health, safety and the environment; and

o maintaining, developing and improving a quality assurance system to ensure compliance with relevant mandatory international rules, regulations and standards;

● financial and cash management support, including budgeting, reporting and preparation of annual audited reports;

● in-house legal support;

● general administrative and back-office support;

● research and development; and

● training for employees.

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Each month, PT Höegh pays Höegh Norway a fee for the provision of the technical information, including the intellectual property rights, and the services. The monthly fee consists of (i) a license fee and (ii) a service fee consisting of a pro rata payment of the estimated annual costs incurred by Höegh Norway under the technical information and services agreement and a 5.0% fee on such payment. The service fee is reconciled annually with the actual costs incurred by Höegh Norway during the prior calendar year. Any amounts payable after such reconciliation must be paid by the owing party no later than 44 days after the end of each such calendar year. Höegh Norway has never invoiced any amounts for the license fee. PT Höegh paid Höegh Norway approximately $0.04 million, $0.04 million and $0.03 million for the service fee under the technical information and services agreement for the years ended December 31, 2020, 2019 and 2018, respectively.

Under the technical information and services agreement, PT Höegh indemnifies Höegh Norway against all losses arising under the technical information and services agreement in connection with (i) losses suffered by third parties, (ii) the personal injury, sickness or death of any person that itself or together with its affiliates holds more than half of PT Höegh’s issued share capital or any of PT Höegh’s officers, directors, employees, agents, representatives, advisors and contractors and (iii) loss of or damage to property owned or under the custody of PT Höegh or any party listed above in section (ii) of this paragraph.

Master Spare Parts Supply Agreement

PT Höegh and Höegh Asia entered into a master spare parts supply agreement, pursuant to which Höegh Asia supplies certain spare parts and supplies for the PGN FSRU Lampung and the Mooring to PT Höegh. PT Höegh, from time to time, submits an order, which may be freely accepted or declined, to Höegh Asia for the supply of spare parts, lubricating oils and other provisions. In respect of each accepted order, Höegh Asia submits an invoice to PT Höegh consisting of the actual cost of the supplied services and a 5.0% fee on the cost of such supplied services, which must be paid by PT Höegh no more than 14 days after receipt of such invoice.

Master Maintenance Agreement

PT Höegh and Höegh Shipping entered into a master maintenance agreement, pursuant to which Höegh Shipping provides certain maintenance services to PT Höegh. PT Höegh, from time to time, submits an order, which may be freely accepted or declined, to Höegh Shipping for the supply of services, including maintenance of the PGN FSRU Lampung, its systems and equipment and the Mooring. In respect of each accepted order, Höegh Shipping submits an invoice to PT Höegh consisting of the actual cost of the supplied services and a 5.0% fee on the cost of such supplied services, which must be paid by PT Höegh no more than 14 days after receipt of such invoice.

Secondment Agreement

Höegh Cyprus has entered into a secondment agreement with Höegh Maritime Management pursuant to which Höegh Maritime Management provides crew to the Höegh Gallant. During their period of service, the crew members remain employees of Höegh Maritime Management, but are seconded to, and operate under the instruction and supervision of, Höegh Cyprus. Either party may terminate the secondment agreement upon six months’ written notice to the other party or upon a material breach by the other party (not cured within 10 days). Höegh Cyprus reimburses Höegh Maritime Management for the salaries and other expenses of the seconded employees. Höegh Cyprus also reimburses Höegh Maritime Management for any amount paid to manning agents used for hiring crew, plus a service fee equal to 5.0% of such amount and an administration fee of up to $5,000, with all payments made in U.S. Dollars. During the years ended December 31, 2020, 2019 and 2018, respectively, Höegh Maritime Management charged approximately $2.7 million, $2.6 million and $2.9 million to Höegh Cyprus pursuant to the secondment agreement.

Höegh Grace Services Agreements

Höegh Colombia and Höegh FSRU IV have entered into several agreements with affiliates of Höegh LNG and Höegh Autoliners Ltd. to provide services related to the Höegh Grace (the “Höegh Grace Services Agreements”):

● a manning agreement with Höegh Fleet Services Philippines Inc. (an affiliate of Höegh Autoliners Ltd.) to recruit and engage crew for the vessel, including planning the crew rotation schedule, processing employment contracts and arranging visas and travel to the vessel; in exchange for reimbursement of costs, plus a service fee equal to 5.0%;

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● a technical services agreement with Höegh Norway to provide technical services for the vessel, including arranging for the provision of bunker fuel, operational support, providing access to the information technology systems of Höegh LNG and providing technical information and supporting documentation as requested by Höegh Colombia; in exchange for specified hourly rates, plus a service fee equal to 3.0% and an additional fee calculated based on the scope of use of Höegh LNG’s information technology systems;

● a management consulting agreement with Höegh Norway to provide support related to certain management activities, including support and advice to the management of Höegh Colombia regarding operational and financial matters, assistance with the preparation of budgets and the provision of controller functions for financial matters; in exchange for specified hourly rates, plus a service fee equal to 3.0%;

● a crew recruitment consulting services agreement with Höegh Maritime Management to provide professional consulting services in connection with recruitment of crew and other employees, including evaluating and recommending to Höegh Colombia individuals that meet its hiring specifications, executing employment contracts with individuals approved by Höegh Colombia and arranging visas and travel to the vessel; in exchange for reimbursement of costs, plus a 5.0% fee charged on certain administrative costs and on any amount paid to manning agents used for hiring crew;

● an agreement for provision of professional payment services with Höegh Maritime Management to provide services in connection with the payment of monthly salaries to the crew and employees working on the vessel; in exchange for reimbursement of costs, plus a service fee equal to 5.0%; and

● a spare parts procurement and insurance services agreement with Höegh LNG Management to arrange for the supply of spare parts and the insurance coverage for the vessel; in exchange for an annual fee plus reimbursement of certain expenses.

Höegh Colombia and Höegh FSRU IV paid an aggregate of approximately $0.6 million, $0.5 million and $0.5 million to the service providers under the Höegh Grace Services Agreements for the years ended December 31, 2020, 2019 and 2018, respectively.

Revolving Credit Facility with Höegh LNG

In connection with the closing of the IPO, we entered into an unsecured $85 million revolving credit facility with Höegh LNG, to be used to fund acquisitions and our working capital requirements. The revolving credit facility’s original maturity date was January 1, 2020. Interest on drawn amounts was payable quarterly at an original rate equal to LIBOR plus a margin of 4.0%. On May 28, 2019, the repayment date on the $85 million revolving credit facility was extended to January 1, 2023 and the terms amended for the interest rate to be LIBOR plus a margin of 1.4% in 2019, 3.0% in 2020 and 4.0% thereafter.

Originally, we were required to pay a 1.4% annual commitment fee to Höegh LNG on undrawn available amounts under the revolving credit facility. On January 29, 2018, the revolving credit facility was amended eliminating the requirement to pay a commitment fee on the undrawn balance of the facility. Drawings on the revolving credit facility are subject to customary conditions precedent, including absence of a default or event of default and accuracy of representations and warranties in all material respects.

For a more detailed description of this credit facility, please read “Item 5.B—Liquidity and Capital Resources—Borrowing Activities—Revolving Credit Facility Due to Owners and Affiliates.”

License Agreement

At the closing of the IPO, we entered into a license agreement with Leif Höegh & Co. Ltd., pursuant to which Leif Höegh & Co. Ltd. granted to us a worldwide, nonexclusive, royalty-free license to use the name and unregistered trademark “Höegh LNG” and a flag and funnel mark. The license agreement will terminate, upon the election of Leif Höegh & Co. Ltd., if Höegh LNG ceases to control our general partner or Leif Höegh & Co. Ltd. beneficially owns less than 34% of the issued shares of Höegh LNG.

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Time Charter and Option for the Höegh Gallant

The Höegh Gallant was operating under a time charter with EgyptCo, a subsidiary of Höegh LNG, that expired in 2020. In addition, we had entered into an option agreement with Höegh LNG pursuant to which we had the right to cause Höegh LNG to charter the Höegh Gallant from the expiration or termination of the EgyptCo charter until July 2025 at a rate equal to 90% of the rate payable pursuant to the current charter with EgyptCo, plus any incremental taxes or operating expenses as a result of the new charter. On February 27, 2020, the Partnership exercised its right pursuant to the option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of the EgyptCo charter until July 2025. On April 30, 2020, the Partnership entered into a lease and maintenance agreement with another subsidiary of Höegh LNG for the time charter of the Höegh Gallant (the “Subsequent Charter”). The Subsequent Charter commenced on May 1, 2020 and expires July 31, 2025. Please read “Item 4.B. Business Overview—Vessel Time Charters— Höegh Gallant Time Charter.”

Other Related Party Transactions

Our activities were an integrated part of Höegh LNG until the closing of the IPO on August 12, 2014. We entered into several agreements with Höegh LNG (and certain of its subsidiaries) for the provision of services. As such, Höegh LNG has provided general and corporate management services to us. A subsidiary of Höegh LNG provides ship management for PGN FSRU Lampung, Höegh Gallant and Höegh Grace. Refer to note 14 of our consolidated financial statements for additional information.

Amounts for related party transactions included in the consolidated statements of income for the years ended December 31, 2020, 2019 and 2018 or capitalized or recorded in the consolidated balance sheets as of December 31, 2020 and 2019 are as follows:

	Year ended
Statement of income:	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Time charter revenue Höegh Gallant	$	45,274	47,173	$	47,108
Vessel operating and administrative expenses		(25,681)	(28,408)		(25,191)
Interest income from joint ventures		321	295		273
Interest expense and commitment fees to Höegh LNG		(64)	(1,882)		(2,938)
Total	$	19,850	17,178	$	19,252

Balance sheet:	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Equity:
Contribution from Höegh LNG	$	11,850	$	—
Repayment of indemnification received from Höegh LNG		—		(64)
Issuance of units for board of directors' fees		181		194
Other and contribution from owner		109		485
Total	$	12,140	$	615

Our trade liabilities and revolving credit facility to Höegh LNG and affiliates were $21.1 million and $11.3 million for the years ended December 31, 2020 and 2019, respectively. The outstanding revolving credit facility had a weighted average interest rate of 3.6% and 6.6% for the years ended December 31, 2020 and 2019, respectively.

Distributions to Höegh LNG

For the years ended December 31, 2020, 2019 and 2018, we paid quarterly distributions totaling $74.8 million, $73.8 million and $72.5 million of which $28.5 million, $28.4 million and $28.2 million were paid to Höegh LNG, respectively.

C.Interests of Experts and Counsel

Not applicable.

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Item 8.Financial Information

A.Consolidated Statements and Other Financial Information

Please read “Item 18—Financial Statements” below for additional information required to be disclosed under this item.

Legal Proceedings

From time to time we have been, and expect to continue to be, subject to legal proceedings and claims in the ordinary course of our business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. Refer to note 17 “Commitments and contingencies” to our consolidated financial statements for a description of certain claims made against us.

The Partnership’s Cash Distribution Policy

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing our available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves) rather than retaining it. Because we believe we will generally finance any expansion capital expenditures from external financing sources, we believe that our unitholders are best served by our distributing all of our available cash. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves).

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

● Our unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to the broad discretion of our board of directors to establish reserves and other limitations.

● We will be subject to restrictions on distributions under our financing agreements. Our financing agreements contain material financial tests and covenants that must be satisfied in order to pay distributions. If we are unable to satisfy the restrictions included in any of our financing agreements or are otherwise in default under any of those agreements, as a result of our debt levels or otherwise, we will not be able to make cash distributions to unitholders, notwithstanding our stated cash distribution policy. These financial tests and covenants are described in this Annual Report in “Item 5.B. Liquidity and Capital Resources.”

● A part of our business is currently conducted through our joint ventures. Under the joint venture agreement that governs our joint ventures that own the Neptune and the Cape Ann, our joint ventures are prohibited from making distributions under certain circumstances, including when they have outstanding shareholder loans. In addition, we are unable to cause our joint ventures to make distributions without the agreement of our joint venture partners. Under the joint ventures’ bank debt facilities certain covenants and restrictions apply to making distributions. In order to make distributions for the shareholder loans or dividends, a 1.20 historical and projected debt service coverage ratio must be met. As of December 31, 2020, both the 1.20 historical and projected debt service coverage ratios were met by SRV Joint Gas Ltd. As a result, SRV Joint Gas Ltd. qualifies to make payments on the shareholder loans or other distributions. As of December 31, 2020, SRV Joint Gas Two Ltd. met the 1.20 historical debt service coverage ratio but did not meet the projected debt service coverage ratio. As a result, no payments on the shareholder loans or other distributions can be made by SRV Joint Gas Two Ltd. until the debt service coverage ratio is met in future periods. Further, our joint ventures suspended payments on the shareholder loans pending the outcome of the boil-off claim, which was finally settled in 2020. Refer to note 9 “Advances to joint ventures” and note 17 “Commitments and contingencies” of our consolidated financial statements and “Item 5.B. Liquidity and Capital Resources” for additional information. If our joint ventures are unable to make distributions to us, it could have a material

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adverse effect on our ability to pay cash distributions to unitholders in accordance with our stated cash distribution policy.

● We are required to make substantial capital expenditures to maintain and replace our fleet. These expenditures may fluctuate significantly over time, particularly as our vessels near the end of their useful lives. In order to minimize these fluctuations, our partnership agreement requires us to deduct estimated, as opposed to actual, maintenance and replacement capital expenditures from the amount of cash that we would otherwise have available for distribution to our unitholders. In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance and replacement capital expenditures were deducted.

● Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended. Our partnership agreement can be amended with the approval of a majority of the outstanding common units. Höegh LNG owns approximately 45.7% of our common units as of March 31, 2021.

● Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our partnership agreement.

● The Series A preferred units rank senior to our common units as to payments of distributions. Therefore, we will not be able to pay distributions to our common unitholders if we have failed to pay distributions to our Series A preferred units.

● Under Section 51 of the Marshall Islands Act, we may not make a distribution to unitholders if, after giving effect to the distribution, our liabilities, other than liabilities to partners on account of their partnership interest and liabilities for which the recourse of creditors is limited to specified property of ours, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of that property exceeds that liability.

● PT Höegh is subject to restrictions on distributions under Indonesian laws due to its formation under the laws of Indonesia. Under Article 71.3 of the Indonesian Company Law (Law No. 40 of 2007), dividend distributions may be made only if PT Höegh has positive retained earnings. In addition, PT Höegh as an Indonesian incorporated company is required to establish a statutory reserve equal to 20% of its paid-up capital. The dividend can only be distributed if PT Höegh’s retained earnings are positive after deduction of the statutory reserve. PT Hoegh LNG Lampung is working to establish the required statutory reserves as of December 31, 2020. Therefore, PT Hoegh LNG Lampung cannot make dividend payments under Indonesian law. However, subject to meeting a debt service ratio of 1.20 to1.00, PT Höegh can distribute cash from its cash flow from operations to us as payment of intercompany accrued interest and / or intercompany debt, after quarterly payments of the Lampung facility and fulfilment of the “waterfall” provisions to meet operating requirements as defined by the Lampung facility. Höegh Lampung, our subsidiary holding the ownership interest in PT Höegh, is subject to restrictions under Singapore law due to its formation under Singapore law. Under Section 403(1) of the Companies Act (Cap. 50) of Singapore, no dividends shall be payable to the shareholders of any company except out of profits.

● Under Cayman Islands law, Höegh Colombia Holding and Höegh FSRU IV may only pay dividends distributions out of profits or capital reserves if the entity is solvent after the distribution. Dividends from Höegh Cyprus may only be distributed out of profits and not from the share capital of the company.

● Our joint ventures for the Neptune and the Cape Ann are subject to restrictions on distributions under the laws of the Cayman Islands due to their formation under the laws of the Cayman Islands. Under such laws, a dividend distribution may only be paid out of profits or capital reserves if the entity is solvent after the distribution.

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● We may lack sufficient cash to pay distributions to our unitholders due to decreases in total operating revenues, decreases in hire rates, the loss of a vessel, increases in operating or general and administrative expenses, principal and interest payments on outstanding debt, taxes, working capital requirements, maintenance and replacement capital expenditures or anticipated cash needs. Please read “Item 3.D. Risk Factors” for a discussion of these factors.

Estimated Maintenance and Replacement Capital Expenditures

Our partnership agreement requires our board of directors to deduct from operating surplus each quarter estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures. To the extent that our charterers reimburse our joint ventures or us, as applicable, for anticipated drydocking expenses, these are excluded from maintenance capital expenditures.

For the year ended December 31, 2020, our estimated maintenance and replacement capital expenditures for us and our joint ventures was $21.4 million per year for future vessel replacement and drydocking. Changes to our estimated maintenance and replacement capital expenditures for us and our joint ventures are assessed by our board of directors, with the approval of the conflicts committee. Estimated maintenance and replacement capital expenditures are based on assumptions regarding the remaining useful life of the vessels in our fleet, a net investment rate equivalent to our current expected long-term borrowing costs, vessel replacement values based on current market conditions, the residual value of the vessels at the end of their useful lives based on current steel prices, estimated expenditures for drydocking not reimbursable under time charters and an assumed level of inflation. The actual cost of replacing the vessels in our fleet will depend on a number of factors, including prevailing market conditions, hire rates and the availability and cost of financing at the time of replacement.

Our board of directors, with the approval of the conflicts committee, may from time to time determine that one or more of our assumptions should be revised, which could cause our board of directors to adjust the amount of estimated maintenance and replacement capital expenditures. Furthermore, we may elect to finance some or all of our maintenance and replacement capital expenditures through the issuance of additional common units, which could be dilutive to existing unitholders.

Please read “Item 3.D. Risk Factors—Risks Inherent in Our Business—We must make substantial capital expenditures to maintain and replace the operating capacity of our fleet, which will reduce our cash available for distribution. In addition, each quarter we will be required, pursuant to our partnership agreement, to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.”

Minimum Quarterly Distribution

Common unitholders are entitled under our partnership agreement to receive a quarterly distribution of $0.3375 per unit to the extent we have sufficient cash on hand to pay the distribution, after establishment of cash reserves, distribution payments on the Series A preferred units and payment of fees and expenses. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our partnership agreement. We are prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is then existing, under our financing arrangements. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities” for a discussion of the restrictions contained in our credit facilities.

Subordination Period

The subordination period, as defined in our partnership agreement, for the subordinated units ended on August 16, 2019. All of the 13,156,060 subordinated units, which were owned by Höegh LNG, converted to common units on a one-for-one basis and have the same rights as other common units.

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Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Höegh LNG currently holds the incentive distribution rights. The incentive distribution rights may be transferred separately from any other interest, subject to restrictions in our partnership agreement. Any transfer by Höegh LNG of the incentive distribution rights would not change the percentage allocations of quarterly distributions with respect to such rights.

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of the incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders			Holders of IDRs
First Target Distribution	up to $0.388125		100	%		0	%
	above $0.388125
Second Target Distribution	up to $0.421875		85	%		15	%
	above $0.421875
Third Target Distribution	up to $0.50625		75	%		25	%
Thereafter	above $0.50625		50	%		50	%

B. Significant changes

Not applicable.

Item 9.The Offer and Listing

A.Offer and Listing Details

Not applicable.

B.Plan of Distribution

Not applicable.

C.Markets

Our common units started trading on the NYSE under the symbol “HMLP” on August 8, 2014.

Our Series A preferred units began trading on the NYSE under the symbol “HMLP PRA” on October 9, 2017.

D.Selling Unitholders

Not applicable.

E.Dilution

Not applicable.

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F.Expenses of the Issue

Not applicable.

Item 10.Additional Information

A.Share Capital

Not applicable.

B.Memorandum and Articles of Association

The information required to be disclosed under Item 10B is incorporated by reference to Exhibit 2.1 to this Annual Report.

C.Material Contracts

The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which we or any of our subsidiaries is a party, for the two years immediately preceding the date of this Annual Report:

(1) Omnibus Agreement, dated August 12, 2014, among Höegh LNG Holdings Ltd., Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC, as supplemented by a letter agreement dated August 12, 2015. Please read “Item 7.B. Related Party Transactions—Omnibus Agreement.”

(2) 2014 Höegh LNG Partners LP Long-Term Incentive Plan. Please read “Item 6.B. Compensation.”

(3) Höegh LNG Partners LP Amended and Restated Non-Employee Director Compensation Plan. Please read “Item 6.B. Compensation.”

(4) Administrative Services Agreement, dated December 20, 2019, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG AS, as amended by Addendum No. 1, dated August 21, 2020 and Addendum No. 2, dated April 9, 2021. Please read “Item 7.B. Related Party Transactions—Administrative Services Agreements—Höegh Norway Administrative Services Agreement.”

(5) Commercial and Administration Management Agreement, dated November 24, 2009, between SRV Joint Gas Ltd. and Höegh LNG AS (Neptune). Please read "Item 7.B. Related Party Transactions-Commercial and Administration Management Agreements."

(6) Commercial and Administration Management Agreement, dated May 19, 2010, between SRV Joint Gas Two Ltd. and Höegh LNG AS (Cape Ann). Please read “Item 7.B. Related Party Transactions—Commercial and Administration Management Agreements.”

(7) Commercial and Administration Management Agreement, dated May 31, 2010, between Höegh LNG FSRU III Ltd. (as successor to HöeghStream LNG Ltd.) and Höegh LNG AS (Höegh Gallant).

(8) Management Agreement, dated March 27, 2015, between Höegh Cyprus and Höegh LNG AS (Höegh Gallant). Please read “Item 7.B. Related Party Transactions—Gallant Management Agreement.”

(9) Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Ltd. and Höegh LNG Fleet Management AS (Neptune). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(10) Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Two Ltd. and Höegh LNG Fleet Management AS (Cape Ann). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

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(11) Baltic and International Maritime Council Standard Ship Management Agreement, dated March 24, 2015, between Höegh LNG Cyprus and Höegh LNG Fleet Management AS (Höegh Gallant). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(12) Baltic and International Maritime Council Standard Ship Management Agreement, dated October 17, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Fleet Management AS (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(13) Technical Information and Services Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG AS (PGN FSRU Lampung). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(14) Master Spare Parts Supply Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG Asia Pte. Ltd. (PGN FSRU Lampung). Please read “Item 7.B. Related Party Transactions—Master Spare Parts Supply Agreement.”

(15) Master Maintenance Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG Shipping Services Pte Ltd (PGN FSRU Lampung). Please read “Item 7.B. Related Party Transactions—Master Maintenance Agreement.”

(16) Sub-Technical Support Agreement, dated April 11, 2014, between Höegh LNG AS and Höegh LNG Fleet Management AS. Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(17) Intercompany Agreement Regarding Secondment of Employees, dated March 31, 2015, between Höegh LNG Maritime Management Pte. Ltd. and Höegh Cyprus, as amended by Addendum No.1, dated November 17, 2015. Please read “Item 7.B. Related Party Transactions—Secondment Agreement.”

(18) Manning Agreement, dated September 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh Fleet Services Philippines Inc. (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(19) Management Consulting Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG AS (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(20) Agreement for the Provision of Professional Payment Services, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Maritime Management Pte. Ltd. (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(21) Crew Recruitment Consulting Services Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Maritime Management Pte. Ltd. (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(22) Spare Parts Procurement and Insurance Services Agreement, dated October 25, 2016, between Höegh LNG FSRU IV Ltd. and Höegh LNG Fleet Management AS (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(23) Technical Services Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG AS (Höegh Grace). Please read “Item 7.B. Related Party Transactions—Höegh Grace Services Agreements.”

(24) SRV LNG Carrier Time Charterparty, dated March 20, 2007, between SRV Joint Gas Ltd. and Suez LNG Trading SA, as novated by the Novation Agreement, dated March 25, 2010, among SRV Joint Gas Ltd., GDF Suez LNG Trading SA (formerly known as Suez LNG Trading SA) and GDF Suez Global LNG Supply SA, as amended by Amendment No. 1, dated February 23, 2015, between SRV Joint Gas Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 2, dated February 23, 2015, between SRV Joint Gas Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 3, dated April 23, 2014, between SRV Joint Gas Ltd.

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and GDF Suez LNG Supply SA, as amended by the Deed of Novation and Amendment, dated December 20, 2019, among SRV Joint Gas Ltd., Global LNG SAS and Total Gas & Power Limited, as amended by Amendment No. 5, dated April 1, 2020, between SRV Joint Gas Ltd. and Total Gas & Power Limited (Neptune). Please read “Item 4.B. Business Overview—Vessel Time Charters— Neptune Time Charter.”

(25) SRV LNG Carrier Time Charterparty, dated March 20, 2007, between SRV Joint Gas Ltd. and Suez LNG Trading SA, as novated by the Novation Agreement, dated December 20, 2007, among SRV Joint Gas Ltd., Suez LNG Trading SA and SRV Joint Gas Two Ltd., as novated by the Novation Agreement, dated March 25, 2010, among SRV Joint Gas Two Ltd., GDF Suez LNG Trading SA (formerly known as Suez LNG Trading SA) and GDF Suez Global LNG Supply SA, as amended by Amendment No. 1, dated June 20, 2012, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 2, dated June 20, 2012, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as supplemented by the Side Letter, dated November 17, 2013, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 3, dated April 23, 2014, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 4, dated October 23, 2017, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as supplemented by the Side Letter, dated October 27, 2017, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as amended by the Deed of Novation and Amendment, dated December 20, 2019, among SRV Joint Gas Two Ltd., Global LNG SAS and Total Gas & Power Limited, as amended by Amendment No. 5, dated February 20, 2020, between SRV Joint Gas Two Ltd. and Total Gas & Power Limited, as amended by Amendment No. 6, dated April 1, 2020, between SRV Joint Gas Two Ltd. and Total Gas & Power Limited (Cape Ann). Please read “Item 4.B. Business Overview—Vessel Time Charters.”

(26) Amendment and Restatement Agreement of the Original Lease, Operation and Maintenance Agreement, dated January 25, 2012, between Höegh LNG Ltd. and PT Perusahaan Gas Negara (Persero) Tbk, as novated by the Novation Agreement for Amended & Restated Lease, Operation & Maintenance Agreement, dated September 18, 2013, among PT Perusahaan Gas Negara (Persero) Tbk, Höegh LNG Ltd. and PT Höegh LNG Lampung, as novated by the Novation Agreement for Amended & Restated Lease, Operation & Maintenance Agreement, dated February 21, 2014, among PT Perusahaan Gas Negara (Persero) Tbk, PT PGN LNG Indonesia and PT Höegh LNG Lampung (PGN FSRU Lampung). Please read “Item 4.B. Business Overview—Vessel Time Charters— PGN FSRU Lampung Time Charter.”

(27) Lease and Maintenance Agreement, dated April 15, 2015, between Höegh Cyprus, acting through its Egypt Branch, and Höegh LNG Egypt LLC (Höegh Gallant). Please read “Item 4.B. Business Overview—Vessel Time Charters— Höegh Gallant Time Charter.”

(28) Lease and Maintenance Agreement, dated April 30, 2020, between Hoegh LNG Cyprus Limited and Hoegh LNG Chartering LLC (Höegh Gallant). Please read "Item 4.B. Business Overview-Vessel Time Charters- Höegh Gallant Time Charter."

(29) International Leasing Agreement, dated November 1, 2014, between Höegh LNG FSRU IV Ltd. and Sociedad Portuaria El Cayao S.A. E.S.P., as amended by Amendment No. 1 thereto dated September 24, 2015 (Höegh Grace). “Item 4.B. Business Overview—Vessel Time Charters— Höegh Grace Charter.”

(30) FSRU Operation and Services Agreement, dated November 1, 2014, between Höegh LNG Holdings Ltd. and Sociedad Portuaria El Cayao S.A. E.S.P., as amended by Amendment No. 1 thereto, dated September 24, 2015, as novated by the Deed of Novation, dated October 18, 2016, among Höegh LNG Holdings Ltd., Höegh LNG Colombia S.A.S. and Sociedad Portuaria El Cayao S.A. E.S.P. (Höegh Grace). “Item 4.B. Business Overview—Vessel Time Charters— Höegh Grace Charter.”

(31) Second Amended and Restated Shareholders’ Agreement, dated July 18, 2014, among Mitsui O.S.K Lines, Ltd., Höegh LNG Partners Operating LLC and Tokyo LNG Tanker Co., Ltd. Please read “Item 4.B. Business Overview—Shareholder Agreements.”

(32) Shareholders’ Agreement, dated March 13, 2013, between Höegh LNG Lampung Pte Ltd. and PT Bahtera Daya Utama. Please read Item 4.B. Business Overview—Shareholder Agreements.”

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(33) Novation Deed, dated August 31, 2010, among Mitsui O.S.K. Lines, Ltd., Tokyo LNG Tanker Co., Ltd., Höegh LNG Ltd. and SRV Joint Gas Ltd.

(34) Novation Deed, dated August 31, 2010, among Mitsui O.S.K. Lines, Ltd., Tokyo LNG Tanker Co., Ltd., Höegh LNG Ltd. and SRV Joint Gas Two Ltd.

(35) Amendment and Restatement Agreement, dated October 9, 2013, among Höegh LNG Lampung Pte Ltd., PT Bahtera Daya Utama and PT Imeco Inter Sarana.

(36) Revolving Loan Agreement, dated August 12, 2014, between Höegh LNG Partners LP and Höegh LNG Holdings Ltd. in the amount of $85,000,000, as amended by Amendment No. 1, dated February 28, 2016, Amendment No. 2, dated January 29, 2018 and Amendment No. 3, dated May 28, 2019. Please read “Item 7.B. Related Party Transactions—Revolving Credit Facility with Höegh LNG.”

(37) Neptune Facility Agreement, dated December 20, 2007, among SRV Joint Gas Ltd. and the other parties thereto, as amended by the Amendment Agreement, dated March 25, 2010, the Letter from the Agent for the Lenders, dated August 26, 2010, the Letter from the Agent for the Lenders, dated July 25, 2014, the Amendment Agreement, dated February 24, 2015, the Amendment Agreement dated December 7, 2016 and the Amendment Agreement dated December 20, 2019. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Neptune Facility.”

(38) Cape Ann Facility Agreement, dated December 20, 2007, among SRV Joint Gas Two Ltd. and the other parties thereto, as amended by the Amendment Agreement, dated March 25, 2010, the Letter from the Agent for the Lenders, dated August 26, 2010, the Amendment Agreement, dated June 29, 2012, the Letter from the Agent for the Lenders, dated July 25, 2014 and the Amendment Agreement dated December 20, 2019. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Cape Ann Facility.”

(39) $299 Million Lampung Facility Agreement, dated September 12, 2013, between PT Höegh LNG Lampung and the other parties thereto, as amended by the Second Side Letter, dated December 18, 2014. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Lampung Facility.”

(40) $412 Million Amended and Restated Facilities Agreement, dated March 17, 2016, between Höegh LNG Cyprus and Höegh LNG FSRU IV Ltd., as borrowers, and the other parties thereto, as amended by the Amendment Letter, dated December 23, 2016. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Gallant/Grace Facility.”

(41) $385 Million Senior Secured Term Loan and Revolving Credit Facility Agreement, dated January 29, 2019, among Höegh LNG Partners LP, as borrower, and the other parties thereto. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—$385 Million Facility.”

(42) License Agreement, between Leif Höegh & Co. Ltd. and Höegh LNG Partners LP. Please read “Item 7.B. Related Party Transactions—License Agreement.”

(43) Contribution, Purchase and Sale Agreement, dated August 12, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC. Please read note 14 "Related party transactions" of our consolidated financial statements.

(44) Letter Agreement, dated October 1, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Egypt LLC, Höegh LNG Partners LP and Höegh LNG Partners Operating LLC. Please read note 14 "Related party transactions" of our consolidated financial statements.

(45) Option Agreement, dated October 1, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd. and Höegh LNG Partners LP. Please read “Item 7.B. Related Party Transactions—Time Charter and Option for of the Höegh Gallant.”

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(46) Contribution, Purchase and Sale Agreement, dated December 1, 2016, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC. Please read note 14 “Related party transactions” of our consolidated financial statements.

(47) Contribution, Purchase and Sale Agreement, dated November 16, 2017, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC. Please read note 14 “Related party transactions” of our consolidated financial statements.

(48) Indemnification Agreement, dated September 27, 2017, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG Holdings Ltd. Please read “Item 7.B. Related Party Transactions—Indemnification Agreement.”

(49) At-the-Market Issuance Sales Agreement, dated October 18, 2019, among Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC and B. Riley FBR, Inc. Please read “Item 5.B. Liquidity and Capital Resources—Liquidity and Cash Needs.”

D.Exchange Controls

We are not aware of any governmental laws, decrees, regulations or other legislation, including foreign exchange controls, in the Republic of the Marshall Islands that may affect the import or export of capital, including the availability of cash and cash equivalents for use by the Partnership, or the remittance of dividends, interest or other payments to non-resident and non-citizen holders of our securities.

E.Taxation

Material U.S. Federal Income Tax Consequences

The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders.

This discussion is based upon provisions of the Code, Treasury Regulations and current administrative rulings and court decisions, all as in effect or existence on the date of this Annual Report and all of which are subject to change or differing interpretation, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership to vary substantially from the consequences described below. The following discussion applies only to beneficial owners of common units or Series A preferred units that own such units as “capital assets” within the meaning of Section 1221 of the Code (i.e., generally, for investment purposes) and is not intended to be applicable to all categories of investors, such as unitholders subject to special tax rules (e.g., financial institutions, insurance companies, broker dealers, tax-exempt 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, or former citizens or long-term residents of the United States), persons who hold the units as part of a straddle, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes, or persons that have a functional currency other than the U.S. Dollar, each of whom may be subject to tax rules that differ significantly from those summarized below. If a partnership or other entity or arrangement classified as a partnership for U.S. federal income tax purposes holds our common units or Series A preferred units, the tax treatment of its partners generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding our common units or Series A preferred units, you should consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of such units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or our unitholders. The statements made herein may be challenged by the IRS and, if so challenged, may not be sustained upon review in a court. This discussion does not contain information regarding any U.S. state or local, estate, gift or alternative minimum tax considerations concerning the ownership or disposition of common units or Series A preferred units. This discussion does not comment on all aspects of U.S. federal income taxation that may be important to particular unitholders in light of their individual circumstances, and each prospective unitholder is urged to consult its own tax advisor regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of common units or Series A preferred units.

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Election to be Treated as a Corporation

We have elected to be treated as a corporation for U.S. federal income tax purposes. Consequently, among other things, U.S. Holders (as defined below) will not be directly subject to U.S. federal income tax on our income, but rather will be subject to U.S. federal income tax on distributions received from us and dispositions of units as described below.

U.S. Federal Income Taxation of U.S. Holders

As used herein, the term “U.S. Holder” means a beneficial owner of our common units or Series A preferred units that is:

● an individual U.S. citizen or resident (as determined for U.S. federal income tax purposes),

● a corporation (or other entity that is classified as a corporation for U.S. federal income tax purposes) organized under the laws of the United States or any of its political subdivisions,

● an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

● a trust if (i) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in effect to be treated as a U.S. person for U.S. federal income tax purposes.

U.S. Federal Taxation of Distributions

Subject to the discussion below of the rules applicable to PFICs, any distributions to a U.S. Holder made by us with respect to our Series A preferred units generally will constitute dividends to the extent of our current and accumulated earnings and profits, as determined under U.S. federal income tax principles, allocated to our Series A preferred units, and any distributions to a U.S. Holder made by us with respect to our common units generally will constitute dividends to the extent of our current and accumulated earnings and profits, as determined under U.S. federal income tax principles, allocable to our common units. Distributions in excess of our earnings and profits allocable to our Series A preferred units or common units, as applicable, will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in its Series A preferred units or common units and, thereafter, as capital gain. U.S. Holders that are corporations generally will not be entitled to claim a dividend received deduction with respect to distributions they receive from us because we are not a U.S. corporation. Dividends received with respect to our common units and Series A preferred units generally will be treated as “passive category income” for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes.

Dividends received with respect to our common units or Series A preferred units by a U.S. Holder that is an individual, trust or estate (a “U.S. Individual Holder”) generally will be treated as “qualified dividend income,” which is currently taxable to such U.S. Individual Holder at preferential capital gain tax rates provided that: (i) our common units or Series A preferred units, as applicable, are readily tradable on an established securities market in the United States (such as the NYSE, on which our common units and our Series A preferred units are listed); (ii) we are not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (which we do not believe we are, have been or will be, as discussed below under “—PFIC Status and Significant Tax Consequences”); (iii) the U.S. Individual Holder has owned the common units or Series A preferred units for more than 60 days during the 121-day period beginning 60 days before the date on which the common units or Series A preferred units, as applicable, become ex-dividend (and has not entered into certain risk limiting transactions with respect to such units); and (iv) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property. There is no assurance that any dividends paid on our common units or Series A preferred units will be eligible for these preferential rates in the hands of a U.S. Individual Holder, and any dividends paid on our common units or Series A preferred units that are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.

Special rules may apply to any amounts received in respect of our common units or Series A preferred units that are treated as “extraordinary dividends.” In general, an extraordinary dividend is a dividend with respect to a common unit that is equal to or in excess of 10.0% of the unitholder’s adjusted tax basis (or fair market value upon the unitholder’s election) in such common unit , and a dividend with respect to a Series A preferred unit that is equal to or in excess of

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5.0% of a unitholder’s adjusted tax basis (or fair market value upon the unitholder’s election) in such Series A preferred unit. In addition, extraordinary dividends include dividends received within a one-year period that, in the aggregate, equal or exceed 20.0% of a unitholder’s adjusted tax basis (or fair market value). If we pay an “extraordinary dividend” on our common units or Series A preferred units that is treated as “qualified dividend income,” then any loss recognized by a U.S. Individual Holder from the sale or exchange of such common units or Series A preferred units will be treated as long-term capital loss to the extent of the amount of such dividend.

Sale, Exchange or Other Disposition of Common Units and Series A Preferred Units

Subject to the discussion of PFIC status below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of our common units or Series A preferred units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s adjusted tax basis in such units. The U.S. Holder’s initial tax basis in its common units or Series A preferred units generally will be the U.S. Holder’s purchase price for the units and that tax basis will be reduced (but not below zero) by the amount of any distributions on such units that are treated as non-taxable returns of capital (as discussed above under “—U.S. Federal Taxation of Distributions”). Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Certain U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder’s ability to deduct capital losses is subject to limitations. Such capital gain or loss generally will be treated as U.S. source income or loss, as applicable, for U.S. foreign tax credit purposes.

Medicare Tax on Net Investment Income

Certain U.S. Holders, including individuals, estates and trusts, will be subject to an additional 3.8% Medicare tax on, among other things, dividends and capital gains from the sale or other disposition of equity interests. For individuals, the additional Medicare tax applies to the lesser of (i) “net investment income” or (ii) the excess of “modified adjusted gross income” over $200,000 ($250,000 if married and filing jointly or $125,000 if married and filing separately). “Net investment income” generally equals the taxpayer’s gross investment income reduced by deductions that are allocable to such income. Unitholders should consult their tax advisors regarding the implications of the additional Medicare tax resulting from their ownership and disposition of our common units or Series A preferred units.

PFIC Status and Significant Tax Consequences

Adverse U.S. federal income tax rules apply to a U.S. Holder that owns an equity interest in a non-U.S. corporation that is classified as a PFIC for U.S. federal income tax purposes. In general, we will be treated as a PFIC with respect to a U.S. Holder if, for any taxable year in which the holder held our common units or Series A preferred units, either:

● at least 75.0% of our gross income (including our pro rata share of the gross income of our vessel-owning joint ventures and subsidiaries) for such taxable year consists of passive income (e.g., dividends, interest, capital gains from the sale or exchange of investment property and rents derived other than in the active conduct of a rental business); or

● at least 50.0% of the average of the values of the assets held by us (including our pro rata share of the assets of our vessel-owning joint ventures and subsidiaries) during such taxable year produce, or are held for the production of, passive income.

Income earned or treated as earned (for U.S. federal income tax purposes) by us in connection with the performance of services would not constitute passive income for PFIC purposes. By contrast, rental income generally would constitute “passive income” unless we were treated as deriving that rental income in the active conduct of a trade or business under the applicable rules.

Based on our current and projected methods of operation, we believe that we were not a PFIC for any prior taxable year, and we expect that we will not be treated as a PFIC for the current or any future taxable year. We believe that more than 25.0% of our gross income for each taxable year was or will be nonpassive income, and more than 50.0% of the average value of our assets for each such year was or will be held for the production of such nonpassive income. This belief is based on valuations and projections regarding our assets, income and charters, and its validity is conditioned on the

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accuracy of such valuations and projections. While we believe these valuations and projections are accurate, the shipping market is volatile, and no assurance can be given that they will continue to be accurate at any time in the future.

Moreover, there are legal uncertainties in determining whether the income derived from our time-chartering activities constitutes rental income or income derived from the performance of services. While there is legal authority supporting our conclusions, including IRS pronouncements concerning the characterization of income derived from time charters as services income, 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, and we would likely be treated as a PFIC. The IRS has announced its nonacquiescence 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.

Distinguishing between arrangements treated as generating rental income and those treated as generating services income involves weighing and balancing competing factual considerations, and there is no legal authority under the PFIC rules addressing our specific method of operation. Conclusions in this area therefore remain matters of interpretation. 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. In addition, although we intend to conduct our affairs in a manner to avoid being classified as a PFIC with respect to any taxable year, we cannot assure you that the nature of our operations will not change in the future and that we will not become a PFIC in any future taxable year.

As discussed more fully below, if we were to be treated as a PFIC for any taxable year (and regardless of whether we remain a PFIC for subsequent taxable years), a U.S. 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 U.S. Holder should be able to make a “mark-to-market” election with respect to our common units or Series A preferred units, as discussed below. If we are a PFIC, a U.S. 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 U.S. Holder owns our common units or Series A preferred units during any taxable year that we are a PFIC, such holder must file an annual report with the IRS.

Taxation of U.S. Holders Making a Timely QEF Election

If a U.S. Holder makes a timely QEF election (an “Electing Holder”), then, for U.S. federal income tax purposes, the Electing Holder must report as income for its taxable year its pro rata share of our ordinary earnings and net capital gain, if any, for our taxable years that end with or within the taxable year for which that holder is reporting, regardless of whether or not the Electing Holder received distributions from us in that year. The Electing Holder’s adjusted tax basis in the common units or Series A preferred units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in the common units or Series A preferred units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our common units or Series A preferred units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with its U.S. federal income tax return. If contrary to our expectations, we determine that we are treated as a PFIC for any taxable year, we intend to provide each U.S. Holder with the information necessary to make the QEF election described above.

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Taxation of U.S. Holders Making a “Mark-to-Market” Election

If we were to be treated as a PFIC for any taxable year in which a U.S. Holder holds our common units or Series A preferred units and, as we anticipate, our common units or Series A preferred units were treated as “marketable stock,” then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common units or Series A preferred units, as applicable, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the U.S. Holder’s common units or Series A preferred units, as applicable, at the end of the taxable year over the holder’s adjusted tax basis in such units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common units or Series A preferred units over the fair market value thereof 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 U.S. Holder’s tax basis in its common units or Series A preferred units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our common units or Series A preferred units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units or Series A preferred units , as applicable, would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were determined to be PFICs.

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election

If we were to be treated as a PFIC for any taxable year in which a U.S. Holder holds our common units or Series A preferred units, a U.S. Holder that does not make either a QEF election or a “mark-to-market” election for that year (a “Non-Electing Holder”) would be subject to special rules resulting in increased tax liability with respect to (i) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common units or Series A preferred units in a taxable year in excess of 125.0% 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 such units) and (ii) any gain realized on the sale, exchange or other disposition of the units. 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 units or Series A preferred units;

● the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder 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 on ordinary income in effect for the applicable class of taxpayers for that year, and an interest charge for the deemed tax deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

These adverse tax consequences would not apply to a qualified pension, profit sharing or other retirement trust or other tax-exempt organization that did not borrow money or otherwise utilize leverage in connection with its acquisition of our common units or Series A preferred units. If we were treated as a PFIC for any taxable year and a Non-Electing Holder who is an individual dies while owning our common units or Series A preferred units, such holder’s successor generally would not receive a step-up in tax basis with respect to such units.

U.S. Federal Income Taxation of Non-U.S. Holders

A beneficial owner of our common units or Series A preferred units (other than a partnership or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is referred to as a Non-U.S. Holder. If you are a partner in a partnership (or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holding our common units or Series A preferred units, you should consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of such units.

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Distributions

Distributions we pay to a Non-U.S. Holder 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, our distributions will be subject to U.S. federal income tax in the same manner as a U.S. Holder to the extent they constitute income effectively connected with the Non-U.S. Holder’s U.S. trade or business (provided, in the case of a Non-U.S. Holder entitled to the benefits of an income tax treaty with the United States, such distributions also are attributable to a U.S. permanent establishment). The after-tax amount of any effectively connected dividends received by a corporate Non-U.S. Holder may also be subject to an additional U.S. branch profits tax at a 30.0% rate (or, if applicable, a lower treaty rate).

Disposition of Units

In general, a Non-U.S. Holder is not subject to U.S. federal income tax or withholding tax on any gain resulting from the disposition of our common units or Series A preferred units provided the Non-U.S. Holder is not engaged in a U.S. trade or business. A Non-U.S. Holder that is engaged in a U.S. trade or business will be subject to U.S. federal income tax in the same manner as a U.S. Holder in the event the gain from the disposition of units is effectively connected with the conduct of such U.S. trade or business (provided, in the case of a Non-U.S. Holder entitled to the benefits of an income tax treaty with the United States, such gain also is attributable to a U.S. permanent establishment). The after-tax amount of any effectively connected gain of a Non-U.S. Holder that is a corporation for U.S. federal income tax purposes may also be subject to an additional U.S. branch profits tax at a rate of 30.0% (or, if applicable, a lower treaty rate). However, even if not engaged in a U.S. trade or business, individual Non-U.S. Holders may be subject to tax on gain resulting from the disposition of our common units or Series A preferred units if they are present in the United States for 183 days or more during the taxable year in which those units are disposed and meet certain other requirements.

Backup Withholding and Information Reporting

In general, payments to a non-corporate U.S. Holder of distributions or the proceeds of a disposition of common units or Series A preferred units will be subject to information reporting. These payments to a non-corporate U.S. Holder also may be subject to backup withholding if the non-corporate U.S. 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, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by timely filing a U.S. federal income tax return with the IRS.

In addition, individual citizens or residents of the United States holding certain “foreign financial assets” (which generally includes stock and other securities issued by a foreign person unless held in an account maintained by a financial institution) that exceed certain thresholds (the lowest being holding foreign financial assets with an aggregate 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 these reporting obligations. U.S. Holders should consult their tax advisors regarding their reporting obligations, if any, that would result from their purchase, ownership or disposition of our units.

177

Non-United States Tax Consequences

The following is a discussion of the material non-U.S. tax considerations that may be relevant to prospective unitholders. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Höegh LNG Partners LP.

Marshall Islands Tax Consequences

The following discussion is based on the current laws of the Republic of the Marshall Islands applicable to persons who are not citizens of the Republic of the Marshall Islands and do not reside in, maintain offices in or engage in business, transactions or operations in the Republic of the Marshall Islands.

Because we and our subsidiaries do not and do not expect to conduct business, transactions or operations in the Republic of the Marshall Islands, under current Marshall Islands law you will not be subject to Marshall Islands taxation or withholding on distributions, including upon distribution treated as a return of capital, we make to you as a unitholder. In addition, you will not be subject to Marshall Islands stamp, capital gains or other taxes on the purchase, ownership or disposition of common units or Series A preferred units, and you will not be required by the Republic of the Marshall Islands to file a tax return relating to your ownership of units.

Norway Tax Consequences

The following is a discussion of the material Norwegian tax consequences that may be relevant to prospective unitholders who are persons not resident in Norway for taxation purposes, which we refer to as “Non-Norwegian Holders.” Prospective unitholders who are resident in Norway for taxation purposes are urged to consult their own tax advisors regarding the potential Norwegian tax consequences to them of an investment in our common units. For this purpose, a company incorporated outside of Norway will be treated as resident in Norway in the event its central management and control is carried out in Norway.

Under the Tax Act on Income and Wealth, Non-Norwegian Holders will not be subject to any taxes in Norway on income or profits in respect of the acquisition, holding, disposition or redemption of the common units or Series A preferred units, provided that we are not treated as carrying on business in Norway, and the Non-Norwegian Holder is not engaged in a Norwegian trade or business to which the common units or Series A preferred units are effectively connected, or if the Non-Norwegian Holder is resident in a country that has an income tax treaty with Norway, such holder does not have a permanent establishment in Norway to which the common units are effectively connected.

We believe that we will be able to conduct our affairs so that Non-Norwegian Holders should not be subject to Norwegian tax on the acquisition, holding, disposition or redemption of the common units or Series A preferred units. However, this determination is dependent upon the facts existing at such time, including (but not limited to) the place where our board of directors meets and the place where our management makes decisions or takes certain actions affecting our business. We intend to conduct our affairs in a manner consistent with our Norwegian tax practice so that our business should not be treated as managed from or carried on in Norway for taxation purposes, and consequently, Non-Norwegian Holders should not be subject to tax in Norway solely by reason of the acquisition, holding, disposition or redemption of their common units or Series A preferred units. Nonetheless, there is no legal authority addressing our specific circumstances, and conclusions in this area remain matters of interpretation. Thus, it is possible that the Norwegian taxation authority could challenge, or a court could disagree with, our position.

While we do not expect it to be the case, if the arrangements we propose to enter into result in our being considered to carry on business in Norway for the purposes of the Tax Act on Income and Wealth, unitholders would be considered to be carrying on business in Norway and would be required to file tax returns with the Norwegian Tax Administration and, subject to any relief provided in any relevant double taxation treaty (including, in the case of holders resident in the United States, the U.S.-Norway Tax Treaty), would be subject to taxation in Norway on any income considered to be attributable to the business carried on in Norway.

F.Dividends and Paying Agents

Not applicable.

178

G.Statement by Experts

Not applicable.

H.Documents on Display

Documents concerning us that are referred to in this Annual Report may be inspected at our offices at Cannon's Court, 22 Victoria Street, Hamilton, HM12, Bermuda and may also be obtained from our website at www.hoeghlngpartners.com. Those documents electronically filed via the SEC’s Electronic Data Gathering, Analysis, and Retrieval system may also be obtained from the SEC’s website at www.sec.gov.

I.Subsidiary Information

Not applicable.

Item 11.Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including interest rate and foreign currency exchange risks.

Interest Rate Risk

Interest rate swap contracts can be utilized to exchange a receipt of floating interest for a payment of fixed interest to reduce the exposure to interest rate variability on our outstanding floating rate debt. As of December 31, 2020, there are interest rate swap agreements on the Lampung and the $385 million facilities’ floating rate debt that are designated as cash flow hedges for accounting purposes. Please read notes 15 and 16 of our consolidated financial statements.

As of December 31, 2020, the following interest rate swap agreements were outstanding:

				Fair
				Value			Fixed
	Interest			Carrying			interest
	rate	Notional		Amount			rate
(in thousands of U.S. dollars)	index	amount		Liability		Term	(1)
LIBOR-based debt
Lampung interest rate swaps (2)	LIBOR	$	97,960	$	(5,680)	Sep 2026	2.800	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,560)	Jan 2026	2.941	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,197)	Oct 2025	2.838	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,111)	Jan 2026	2.735	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(4,927)	Jan 2026	2.650	%

(1) Excludes the margins paid on the floating-rate debt.

(2) All interest rate swaps are U.S. dollar denominated and principal amount reduces quarterly.

The table below provides information about our financial instruments that are sensitive to interest rates:

(In thousands of U.S. dollars)
Liabilities	2021		2022	2023	2024	2025	Thereafter	Total	Fair value		Rate(1)
Long-term Debt
Fixed rate	$	6,667	6,667	6,667	6,667	6,667	11,166	44,501	$	45,829	3.9	%
Variable rate		116,890	18,930	18,930	18,930	18,930	184,353	376,963		376,808	2.6	%
Interest Rate Swaps
Variable to fixed	$	6,945	5,708	5,715	4,431	3,196	480	26,475	$	26,475	2.8	%

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(1) Rate refers to the weighted-average interest rate for our variable long-term debt, including the margin we pay on our floating-rate debt. The average variable to fixed rate for our interest rate swaps excludes the margin we pay on our drawn floating-rate debt. Please read note 12 of our consolidated financial statements.

Foreign Currency Risk

All financing, interest expenses from financing and most of the Partnership’s revenue and expenditures for vessel improvements are denominated in U.S. dollars. Certain operating expenses can be denominated in currencies other than U.S. dollars. For the years ended December 31, 2020, 2019 and 2018, no derivative instruments have been used to manage foreign exchange risk.

Credit risk

Credit risk is the exposure to credit loss in the event of non-performance by the counterparties related to cash and cash equivalents, restricted cash, trade receivables, amounts due from affiliates and interest rate swap agreements. Further, the Partnership has future exposure for Höegh LNG’s ability to make payments to the Partnership for the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the boil-off settlement agreement. Refer to note 17 of our consolidated financial statements. In order to minimize counterparty risk, bank relationships are established with counterparties with acceptable credit ratings at the time of the transactions. Credit risk related to receivables is limited by performing ongoing credit evaluations of the customers’ or counterparty’s financial condition. PGN guarantees PGN LNG's obligations under the PGN FSRU Lampung time charter. Höegh LNG provides a guarantee for its subsidiary’s payment obligations under the Subsequent Charter for the Höegh Gallant. Refer to note 16 of our consolidated financial statements.

Concentration of Risk

Financial instruments, which potentially subject the Partnership to significant concentrations of credit risk, consist principally of cash and cash equivalents, restricted cash, trade receivables, amounts due from affiliates and derivative contracts (interest rate swaps). The maximum exposure to loss due to credit risk is the book value at the balance sheet date. We do not have a policy of requiring collateral or security. Cash and cash equivalents and restricted cash are placed with qualified financial institutions. Periodic evaluations are performed of the relative credit standing of those financial institutions. In addition, exposure is limited by diversifying among counterparties. There are three charterers so there is a concentration of risk related to trade receivables. Credit risk related to trade receivables is limited by performing ongoing credit evaluations of the customer’s financial condition. Refer to note 2 of our consolidated financial statements for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There were no impairment losses for lease or time charter services or contract assets for the year ended December 31, 2019. While the maximum exposure to loss due to credit risk is the book value of trade receivables at the balance sheet date, should the time charters for the PGN FSRU Lampung or the Höegh Grace terminate prematurely, or Höegh LNG prematurely terminate the future time charter under the option exercised for the Höegh Gallant, or the option to acquire the PGN FSRU Lampung be exercised, there could be delays in obtaining new time charters and the hire rates could be lower depending upon the prevailing market conditions.

Item 12.Description of Securities Other than Equity Securities

Not applicable.

180

PART II

Item 13.Defaults, Dividend Arrearages and Delinquencies

As of December 31, 2020, we were in compliance with all applicable covenants under our debt agreements.

Item 14.Material Modifications to the Rights of Securities Holders and Use of Proceeds

Not applicable.

Item 15.Controls and Procedures

Disclosure Controls and Procedures

Under the direction of our Chief Executive Officer ("CEO") and Chief Financial Officer “CFO”), we evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of December 31, 2020. Disclosure controls and procedures are designed to ensure that (i) information required to be disclosed in our reports that are filed or submitted under the Exchange Act, are recorded, processed, summarized, and reported within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms, and (ii) information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our system of controls is designed to provide reasonable, not absolute, assurance regarding the reliability and integrity of accounting and financial reporting. Because of inherent limitations in any such control system (e.g. faulty judgments, human error, information technology system error, or intentional circumvention), there can be no assurance that the objectives of a control system will be met under all circumstances. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of a control system also must be considered relative to the costs of the system and our judgment regarding the likelihood of potential events. In addition, expectations related to any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as (defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act). Internal controls are designed to provide reasonable assurance regarding the reliability of the financial reporting and the preparation and presentation of the financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes those policies and procedures that:

i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

181

In connection with the preparation of this Annual Report, management, under the supervision and with the participation of our CEO and CFO, conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020, based on the criteria described in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). This evaluation included review of the documentation of controls, evaluation of the design of the Partnership’s internal control over financial reporting, testing of the operating effectiveness of such controls and a conclusion on this evaluation.

Based on this evaluation, management believes that our internal control over financial reporting was effective as of December 31, 2020.

Attestation Report of the Registered Public Accounting Firm

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2020 has been audited by Ernst & Young AS, an independent registered public accounting firm, as stated in their report which appears on page F-4 of our consolidated financial statements.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the period covered by this Annual Report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16A.Audit Committee Financial Expert

Our board of directors has determined that Kathleen McAllister and David Spivak qualify as audit committee financial experts and are independent under applicable NYSE and SEC standards.

Item 16B.Code of Ethics

We have adopted the Höegh LNG Partners LP Code of Business Conduct and Ethics that applies to all of our employees, officers and directors. This document is available under the “Governance” section of our website (www.hoeghlngpartners.com). We intend to disclose, under this section of our website, any waivers to or amendments of the Höegh LNG Partners LP Corporate Code of Business Ethics and Conduct for the benefit of any of our directors and executive officers.

Item 16C.Principal Accountant Fees and Services

Our principal accountant for 2020 was Ernst & Young AS.

The audit committee of our board of directors has the authority to pre-approve permissible audit-related and non-audit services not prohibited by SEC and PCAOB standards to be performed by our independent auditors and associated fees. Engagements for proposed services either may be separately pre-approved by the audit committee or entered into pursuant to detailed pre-approval policies and procedures established by the audit committee, as long as the audit committee is informed on a timely basis of any engagement entered into on that basis. The audit committee separately pre-approved all engagements and fees paid to our principal accountant in 2020.

Fees Incurred by the Partnership for Ernst & Young AS’ Services

(In thousands of U.S. dollars)	2020		2019
Audit Fees	$	1,066	$	1,226
Total Fees	$	1,066	$	1,226

Audit Fees

Audit fees for 2020 and 2019 are the aggregate fees billed for professional services rendered by the principal accountant for the audit of the Partnership’s annual financial statements and services normally provided by the principal accountant in connection with statutory and regulatory filings or engagements for the two most recent fiscal years.

182

Audit-Related Fees

There were no audit-related fees for 2020 and 2019.

Item 16D.Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E.Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not applicable.

Item 16F.Change in Registrants’ Certifying Accountant

Not applicable.

Item 16G.Corporate Governance

Overview

Pursuant to an exemption under the NYSE listing standards for foreign private issuers, the Partnership is not required to comply with the corporate governance practices followed by U.S. companies under the NYSE listing standards. However, pursuant to Section 303A.11 of the New York Stock Exchange Listed Company Manual, we are required to state any significant differences between our corporate governance practices and the practices required by the NYSE for U.S. companies. We believe that our established practices in the area of corporate governance are in line with the spirit of the NYSE standards and provide adequate protection to our unitholders. The significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies are set forth below.

Independence of Directors

The NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is comprised of a majority of independent directors. Under Marshall Islands law, we are not required to have a board of directors comprised of a majority of directors meeting the independence standards described in the NYSE rules. In addition, the NYSE rules do not require limited partnerships like us to have boards of directors comprised of a majority of independent directors. However, our board of directors has determined that each of Ms. McAllister, Mr. Jamieson, Mr. Shaw and Mr. Spivak satisfies the independence standards established by the NYSE as applicable to us.

Executive Sessions

The NYSE requires that non-management directors of a listed U.S. company meet regularly in executive sessions without management. The NYSE also requires that all independent directors of a listed U.S. company meet in an executive session at least once a year. As permitted under Marshall Islands law and our partnership agreement, our non-management directors do not regularly hold executive sessions without management, and we do not expect them to do so in the future.

Nominating/Corporate Governance Committee

The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and our partnership agreement, we do not currently have a nominating or corporate governance committee.

183

Compensation Committee

The NYSE requires that a listed U.S. company have a compensation committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and our partnership agreement, we do not currently have a compensation committee.

Unitholder Approval

We are not required to obtain unitholder approval prior to the adoption of equity compensation plans or certain equity issuances, including, among others, issuing 20% or more of our outstanding common units or voting power in a transaction.

Corporate Governance Guidelines

The NYSE requires U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Marshall Islands law, and we have not adopted such guidelines.

We make available a statement of significant differences on our website (www.hoeghlngpartners.com) in the governance section.

We believe that our established corporate governance practices satisfy the NYSE listing standards.

Item 16H.Mine Safety Disclosure

Not applicable.

184

PART III

Item 17.Financial Statements

Not applicable.

Item 18.Financial Statements

The consolidated financial statements of Höegh LNG Partners LP and schedule set forth on pages F-1 through F-63 and Exhibit 15.1, together with the related reports of Ernst & Young AS, Independent Registered Public Accounting Firm thereon, are filed as part of this Annual Report.

All other schedules for which provision is made in the applicable accounting regulations of the SEC are not required, are inapplicable or have been disclosed in the notes to the financial statements and therefore have been omitted.

Item 19.Exhibits

The following exhibits are filed as part of this Annual Report:

Exhibit
Number	Description
1.1	Certificate of Limited Partnership of Höegh LNG Partners LP (incorporated by reference to Exhibit 3.1 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
1.2	Second Amended and Restated Agreement of Limited Partnership of Höegh LNG Partners LP, dated October 5, 2017, between Höegh LNG GP LLC and Höegh LNG Holdings Ltd. (incorporated by reference to Exhibit 4.1 to the registrant’s Report on Form 6-K, filed on October 5, 2017)
2.1	Description of Securities Registered under Section 12 of the Exchange Act (incorporated by reference to Exhibit 2.1 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.1	Omnibus Agreement, dated August 12, 2014, among Höegh LNG Holdings Ltd., Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.2 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.1.1	Letter Agreement, dated August 12, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.32 to the registrant’s Annual Report on Form 20-F/A, filed on November 30, 2015)
4.2	2014 Höegh LNG Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.3*	Höegh LNG Partners LP Amended and Restated Non-Employee Director Compensation Plan (as amended September 11, 2020)
4.4	Administrative Services Agreement, dated December 20, 2019, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG AS (incorporated by reference to Exhibit 4.6 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.4.1*	Addendum No 1. to the Administrative Services Agreement, dated August 21, 2020, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG AS.
4.4.2*	Addendum No 2. to the Administrative Services Agreement, dated April 9, 2021, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG AS.

185

Exhibit
Number	Description
4.5	Commercial and Administration Management Agreement, dated November 24, 2009, between SRV Joint Gas Ltd. and Höegh LNG AS ( Neptune ) (incorporated by reference to Exhibit 10.8 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.6	Commercial and Administration Management Agreement, dated May 19, 2010, between SRV Joint Gas Two Ltd. and Höegh LNG AS ( Cape Ann ) (incorporated by reference to Exhibit 10.9 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.7	Management Agreement, dated March 27, 2015, between Hoegh LNG Cyprus Limited and Höegh LNG AS ( Höegh Gallant ) (incorporated by reference to Exhibit 4.14 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.8	Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Ltd. and Höegh LNG Fleet Management AS ( Neptune ) (incorporated by reference to Exhibit 10.10 to Amendment No. 4 to the registrant’s Form F-1 Registration Statement (333-197228), filed on August 6, 2014)
4.9	Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Two Ltd. and Höegh LNG Fleet Management AS ( Cape Ann ) (incorporated by reference to Exhibit 10.11 to Amendment No. 4 to the registrant’s Form F-1 Registration Statement (333-197228), filed on August 6, 2014)
4.10	Baltic and International Maritime Council Standard Ship Management Agreement, dated March 24, 2015, between Hoegh LNG Cyprus Limited and Höegh LNG Fleet Management AS ( Höegh Gallant ) (incorporated by reference to Exhibit 4.17 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.11	Baltic and International Maritime Council Standard Ship Management Agreement, dated October 17, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Fleet Management AS ( Höegh Grace ) (incorporated by reference to Exhibit 4.17 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.12	Technical Information and Services Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG AS ( PGN FSRU Lampung ) (incorporated by reference to Exhibit 10.12 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.13	Master Spare Parts Supply Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG Asia Pte. Ltd. ( PGN FSRU Lampung ) (incorporated by reference to Exhibit 10.13 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.14	Master Maintenance Agreement, dated April 2, 2014, between PT Höegh LNG Lampung and Höegh LNG Shipping Services Pte Ltd ( PGN FSRU Lampung ) (incorporated by reference to Exhibit 10.14 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.15	Sub-Technical Support Agreement, dated April 11, 2014, between Höegh LNG AS and Höegh LNG Fleet Management AS ( PGN FSRU Lampung ) (incorporated by reference to Exhibit 10.15 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.16	Intercompany Agreement Regarding Secondment of Employees, dated March 31, 2015, between Höegh LNG Maritime Management Pte. Ltd. and Hoegh LNG Cyprus Limited, as amended by Addendum No. 1 dated November 17, 2015 (incorporated by reference to Exhibit 4.22 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)

186

Exhibit
Number	Description
4.17	Manning Agreement, dated September 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh Fleet Services Philippines Inc. ( Höegh Grace ) (incorporated by reference to Exhibit 4.23 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.18	Management Consulting Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG AS ( Höegh Grace ) (incorporated by reference to Exhibit 4.24 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.19	Agreement for the Provision of Professional Payment Services, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Maritime Management Pte. Ltd. ( Höegh Grace ) (incorporated by reference to Exhibit 4.25 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.20	Crew Recruitment Consulting Services Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG Maritime Management Pte. Ltd. ( Höegh Grace ) (incorporated by reference to Exhibit 4.26 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.21	Spare Parts Procurement and Insurance Services Agreement, dated October 25, 2016, between Höegh LNG FSRU IV Ltd. and Höegh LNG Fleet Management AS ( Höegh Grace ) (incorporated by reference to Exhibit 4.27 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.22	Technical Services Agreement, dated October 1, 2016, between Höegh LNG Colombia S.A.S. and Höegh LNG AS ( Höegh Grace ) (incorporated by reference to Exhibit 4.28 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.23†	SRV LNG Carrier Time Charterparty, dated March 20, 2007, between SRV Joint Gas Ltd. and Suez LNG Trading SA, as novated by the Novation Agreement, dated March 25, 2010, among SRV Joint Gas Ltd., GDF Suez LNG Trading SA (formerly known as Suez LNG Trading SA) and GDF Suez Global LNG Supply SA ( Neptune ) (incorporated by reference to Exhibit 10.16 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.23.1†	Amendment No 1. to the SRV LNG Carrier Time Charterparty, dated February 23, 2015, between SRV Joint Gas Ltd. and GDF Suez LNG Supply SA ( Neptune ) (incorporated by reference to Exhibit 4.16.1 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.23.2†	Amendment No 2. to the SRV LNG Carrier Time Charterparty, dated February 23, 2015, between SRV Joint Gas Ltd. and GDF Suez LNG Supply SA ( Neptune ) (incorporated by reference to Exhibit 4.16.2 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.23.3†	Amendment No. 3, dated April 23, 2014, to the SRV LNG Carrier Time Charterparty ( Neptune ) (incorporated by reference to Exhibit 10.16.1 to Amendment No. 4 to the registrant’s Form F-1 Registration Statement (333-197228), filed on August 6, 2014)
4.23.4†	Amendment No. 4, dated December 9, 2016, to the SRV LNG Carrier Time Charterparty ( Neptune ) (incorporated by reference to Exhibit 4.29.4 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.23.5	Deed of Novation and Amendment, dated December 20, 2019, to the SRV LNG Carrier Time Charterparty ( Neptune ), among SRV Joint Gas Ltd., Global LNG SAS and Total Gas & Power Limited. (incorporated by reference to Exhibit 4.25.5 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.23.6††	Amendment No. 5, dated April 1, 2020, to the SRV LNG Carrier Time Charterparty (Neptune) (incorporated by reference to Exhibit 4.25.6 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).

187

Exhibit
Number	Description
4.24†	SRV LNG Carrier Time Charterparty, dated March 20, 2007, between SRV Joint Gas Ltd. and Suez LNG Trading SA, as novated by the Novation Agreement, dated December 20, 2007, among SRV Joint Gas Ltd., Suez LNG Trading SA and SRV Joint Gas Two Ltd., as novated by the Novation Agreement, dated March 25, 2010, among SRV Joint Gas Two Ltd., GDF Suez LNG Trading SA (formerly known as Suez LNG Trading SA) and GDF Suez Global LNG Supply SA, as amended by Amendment No. 1, dated June 20, 2012, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as amended by Amendment No. 2, dated June 20, 2012, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA, as supplemented by the Side Letter, dated November 17, 2013, between SRV Joint Gas Two Ltd. and GDF Suez LNG Supply SA ( Cape Ann ) (incorporated by reference to Exhibit 10.17 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.24.1†	Amendment No. 3, dated April 23, 2014, to the SRV LNG Carrier Time Charterparty (Cape Ann ) (incorporated by reference to Exhibit 10.17.1 to Amendment No. 4 to the registrant’s Form F-1 Registration Statement (333-197228), filed on August 6, 2014)
4.24.2†	Amendment No. 4, dated October 23, 2017, to the SRV LNG Carrier Time Charterparty, as supplemented by the Side Letter, dated October 27, 2017 ( Cape Ann ) (incorporated by reference to Exhibit 4.30.2 to the registrant’s Annual Report on Form 20-F filed on April 6, 2018)
4.24.3	Deed of Novation and Amendment, dated December 20, 2019, to the SRV LNG Carrier Time Charterparty (Cape Ann ), among SRV Joint Gas Two Ltd., Global LNG SAS and Total Gas & Power Limited (incorporated by reference to Exhibit 4.26.3 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.24.4††	Amendment No. 5, dated February 20, 2020, to the SRV LNG Carrier Time Charterparty (Cape Ann ) (incorporated by reference to Exhibit 4.26.4 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020)
4.24.5††	Amendment No. 6, dated April 1, 2020, to the SRV LNG Carrier Time Charterparty (Cape Ann) (incorporated by reference to Exhibit 4.26.5 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.25	Amendment and Restatement Agreement of the Original Lease, Operation and Maintenance Agreement, dated January 25, 2012, between Höegh LNG Ltd. and PT Perusahaan Gas Negara (Persero) Tbk, as novated by the Novation Agreement for Amended & Restated Lease, Operation & Maintenance Agreement, dated September 18, 2013, among PT Perusahaan Gas Negara (Persero) Tbk, Höegh LNG Ltd. and PT Höegh LNG Lampung, as novated by the Novation Agreement for Amended & Restated Lease, Operation & Maintenance Agreement, dated February 21, 2014, among PT Perusahaan Gas Negara (Persero) Tbk, PT PGN LNG Indonesia and PT Höegh LNG Lampung ( PGN FSRU Lampung ) (incorporated by reference to Exhibit 10.18 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.26††	Lease and Maintenance Agreement, dated April 30, 2020, between Hoegh LNG Cyprus Limited and Hoegh LNG Chartering LLC (Höegh Gallant) (incorporated by reference to Exhibit 4.1 to the registrant’s Form 6-K, filed on June 18, 2020).
4.27†	International Leasing Agreement, dated November 1, 2014, between Höegh LNG FSRU IV Ltd. and Sociedad Portuaria El Cayao S.A. E.S.P., as amended by Amendment No. 1 thereto dated September 24, 2015 ( Höegh Grace ) (incorporated by reference to Exhibit 4.33 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.28†	FSRU Operation and Services Agreement, dated November 1, 2014, between Höegh LNG Holdings Ltd. and Sociedad Portuaria El Cayao S.A. E.S.P., as amended by Amendment No. 1 thereto, dated September 24, 2015, as novated by the Deed of Novation, dated October 18, 2016, among Höegh LNG Holdings Ltd., Höegh LNG Colombia S.A.S. and Sociedad Portuaria El Cayao S.A. E.S.P. ( Höegh Grace ) (incorporated by reference to Exhibit 4.34 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)

188

Exhibit
Number	Description
4.29	Second Amended and Restated Shareholders’ Agreement, dated July 18, 2014, among Mitsui O.S.K Lines, Ltd., Höegh LNG Partners Operating LLC and Tokyo LNG Tanker Co., Ltd. (incorporated by reference to Exhibit 4.19 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.30	Shareholders’ Agreement, dated March 13, 2013, between Höegh LNG Lampung Pte Ltd. and PT Bahtera Daya Utama (incorporated by reference to Exhibit 10.20 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.31	Novation Deed, dated August 31, 2010, among Mitsui O.S.K. Lines, Ltd., Tokyo LNG Tanker Co., Ltd., Höegh LNG Ltd. and SRV Joint Gas Ltd. (incorporated by reference to Exhibit 10.21 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.32	Novation Deed, dated August 31, 2010, among Mitsui O.S.K. Lines, Ltd., Tokyo LNG Tanker Co., Ltd., Höegh LNG Ltd. and SRV Joint Gas Two Ltd. (incorporated by reference to Exhibit 10.22 to the registrant's Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.33	Amendment and Restatement Agreement, dated October 9, 2013, among Höegh LNG Lampung Pte Ltd., PT Bahtera Daya Utama and PT Imeco Inter Sarana (incorporated by reference to Exhibit 10.23 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)
4.34	Revolving Loan Agreement, dated August 12, 2014, between Höegh LNG Partners LP and Höegh LNG Holdings Ltd. in the amount of $85,000,000 (incorporated by reference to Exhibit 4.24 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.34.1	Amendment No. 1 to the Revolving Loan Agreement, dated February 28, 2016 (incorporated by reference to Exhibit 4.32.1 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.34.2	Amendment No. 2 to the Revolving Loan Agreement, dated January 29, 2018 (incorporated by reference to Exhibit 4.40.2 to the registrant’s Annual Report on Form 20-F filed on April 6, 2018)
4.34.3	Amendment No. 3 to the Revolving Loan Agreement, dated May 28, 2019 (incorporated by reference to Exhibit 4.36.3 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.35	Neptune Facility Agreement, dated December 20, 2007, among SRV Joint Gas Ltd. and the other parties thereto, as amended by the Amendment Agreement, dated March 25, 2010, the Letter from the Agent for the Lenders, dated August 26, 2010, the Letter from the Agent for the Lenders, dated July 25, 2014 and the Amendment Agreement, dated February 24, 2015 (incorporated by reference to Exhibit 4.26 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.35.1	Amendment Letter, dated December 7, 2016, to Neptune Facility Agreement, between SRV Joint Gas Ltd. and DNB Bank ASA, as security trustee and agent (incorporated by reference to Exhibit 4.41.1 to the registrant’s Annual Report on Form 20-F, filed on April 6, 2017)
4.35.2	Amendment Letter, dated December 20, 2019, to Neptune Facility Agreement, between SRV Joint Gas Ltd. and DNB Bank ASA, as security trustee and agent (incorporated by reference to Exhibit 4.37.2 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.36	Cape Ann Facility Agreement, dated December, 20, 2007, among SRV Joint Gas Two Ltd. and the other parties thereto, as amended by the Amendment Agreement, dated March 25, 2010, the Letter from the Agent for the Lenders, dated August 26, 2010, the Amendment Agreement, dated June 29, 2012 and the Letter from the Agent for the Lenders, dated July 25, 2014 (incorporated by reference to Exhibit 4.27 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

189

Exhibit
Number	Description
4.36.1	Amendment Letter, dated December 20, 2019, to Cape Ann Facility Agreement, between SRV Joint Gas Ltd. and DNB Bank ASA, as security trustee and agent (incorporated by reference to Exhibit 4.38.1 to the registrant’s Annual Report on Form 20-F, filed on April 3, 2020).
4.37	$299 Million Lampung Facility Agreement, dated September 12, 2013, between PT Höegh LNG Lampung and the other parties thereto, as amended by the Second Side Letter, dated December 18, 2014 (incorporated by reference to Exhibit 4.28 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)
4.38	$385 Million Senior Secured Term Loan and Revolving Credit Facility Agreement dated January 29, 2019 among Höegh LNG Partners LP, as borrower, and the other parties thereto (incorporated by reference to Exhibit 4.44 to the registrant’s Annual Report on Form 20-F, filed on April 10, 2019)
4.39	License Agreement, between Leif Höegh & Co. Ltd. and Höegh LNG Partners LP (incorporated by reference to Exhibit 10.29 to Amendment No. 1 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 17, 2014)
4.40	Contribution, Purchase and Sale Agreement, dated August 12, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.39 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.41	Letter Agreement, dated October 1, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Egypt LLC, Höegh LNG Partners LP and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.40 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.42	Option Agreement, dated October 1, 2015, among Höegh LNG Holdings Ltd., Höegh LNG Ltd. and Höegh LNG Partners LP (incorporated by reference to Exhibit 4.41 to the registrant’s Annual Report on Form 20-F, filed on April 28, 2016)
4.43	Contribution, Purchase and Sale Agreement, dated December 1, 2016, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.1 to the registrant’s Report on Form 6-K, filed on December 1, 2016)
4.44	Contribution, Purchase and Sale Agreement, dated November 16, 2017, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.1 to the registrant’s Report on Form 6-K, filed on January 26, 2018)
4.45	Indemnification Agreement, dated September 27, 2017, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Höegh LNG Holdings Ltd. (incorporated by reference to Exhibit 4.1 to the registrant’s Report on Form 6-K, filed on September 28, 2017)
4.46	At-the-Market Issuance Sales Agreement, dated October 18, 2019, among Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC and B. Riley FBR, Inc. (incorporated by reference to Exhibit 1.1 to the registrant’s Report on Form 6-K, filed on October 18, 2019)
8.1*	Subsidiaries of Höegh LNG Partners LP
12.1*	Rule 13a-14(a)/15d-14(a) Certification of the Principal Executive Officer
12.2*	Rule 13a-14(a)/15d-14(a) Certification of the Principal Financial Officer
13.1*	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 of the Principal Executive Officer
13.2*	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 of the Principal Financial Officer

190

Exhibit
Number	Description
15.1*	Schedule I - Condensed Financial Information of Registrant
15.2*	Consent of Independent Registered Public Accounting Firm
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema
101.CAL*	Inline XBRL Taxonomy Extension Schema Calculation Linkbase
101.DEF*	Inline XBRL Taxonomy Extension Schema Definition Linkbase
101.LAB*	Inline XBRL Taxonomy Extension Schema Label Linkbase
101.PRE*	Inline XBRL Taxonomy Extension Schema Presentation Linkbase
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*	Filed herewith.
†	Certain portions have been omitted pursuant to a confidential treatment order. Omitted information has been filed separately with the SEC.
††	Certain identified information has been excluded from the exhibit because it is both (i) not material and (ii) would be competitively harmful if publicly disclosed.

191

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

	HÖEGH LNG PARTNERS LP
Date: April 9, 2021
	By:	/s/ Håvard Furu
		Name:	Håvard Furu
		Title:	Chief Financial Officer

192

INDEX TO THE FINANCIAL STATEMENTS

Höegh LNG Partners LP
Audited Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Income for the Years Ended December 31, 2020, 2019 and 2018	F-5
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018	F-6
Consolidated Balance Sheets as of December 31, 2020 and 2019	F-7
Consolidated Statements of Changes in Partners’ Capital for the Years Ended December 31, 2020, 2019 and 2018	F-9
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018	F-10
Notes to the consolidated financial statements	F-12
Exhibit 15.1 Schedule I - Condensed Financial Information of Registrant

F-1

Report of Independent Registered Public Accounting Firm

To the Unitholders and the Board of Directors of Höegh LNG Partners LP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Höegh LNG Partners LP (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in partners’ capital and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement Schedule I in Exhibit 15.1 of Item 19 (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 Partnership at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated April 9, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Income Taxes – Accounting for Uncertain Tax Positions

Description of the Matter

As discussed in Note 6 to the consolidated financial statements, as of December 31, 2020 the Partnership has recognised uncertain tax positions including associated interest and penalties. The Partnership’s tax positions are subject to audit by local taxing authorities across multiple global subsidiaries and the resolution of such audits may span multiple years. Tax law is complex and often subject to various interpretations, accordingly, the ultimate outcome with respect to taxes the Partnership may owe may differ from the amounts recognised.

F-2

We identified the evaluation of uncertain tax positions as a critical audit matter because a higher degree of auditor judgment was required in evaluating the Partnership’s interpretation of, and compliance with tax law globally across its multiple subsidiaries. In addition, a higher degree of auditor judgment was required in evaluating the Partnership’s estimate of the ultimate resolution of its tax positions.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s identification, recognition and measurement of uncertain tax positions. For example, we tested controls over management’s identification of uncertain tax positions and its application of the recognition and measurement principles, including management’s review of the inputs and calculations for uncertain tax positions. We involved tax professionals with specialized skills to assist in obtaining an understanding of and assessing the technical merits and the amount of the benefit recognized related to the Partnership’s tax positions. Our procedures included, among others, evaluating the Partnership’s interpretation of tax law by developing an independent assessment based on our understanding of tax laws. We also inspected correspondence and assessments with the relevant tax authorities. In addition, we evaluated third-party advice obtained by the Partnership in relation to specific income tax law. We also tested the completeness and accuracy of the underlying data used by the Partnership to calculate its uncertain tax positions. We have also evaluated the adequacy of the Partnership’s disclosures around uncertain tax positions included in Note 6.

/s/ Ernst & Young AS

We have served as the Partnership’s auditor since 2013.

Oslo, Norway

April 9, 2021

F-3

Report of Independent Registered Public Accounting Firm

To the Unitholders and the Board of Directors of Höegh LNG Partners LP

Opinion on Internal Control Over Financial Reporting

We have audited Höegh LNG Partners LP’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Höegh LNG Partners LP (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in partners’ capital and cash flows for each of the three years in the period ended December 31, 2020, the related notes and financial statement Schedule I in Exhibit 15.1 of Item 19 (collectively referred to as the “consolidated financial statements”) and our report dated April 9, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young AS

Oslo, Norway

April 9, 2021

F-4

HÖEGH LNG PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(in thousands of U.S. dollars, except per unit amounts)

	Notes	2020		2019		2018
REVENUES
Time charter revenues	3,4,14,17	$	143,095	$	145,321	$	144,952
Other revenue	3,4		—		115		1,609
Total revenues	3,4		143,095		145,436		146,561
OPERATING EXPENSES
Vessel operating expenses	13,14		(24,072)		(30,870)		(24,195)
Administrative expenses			(9,740)		(9,861)		(8,916)
Depreciation and amortization	10,11		(20,937)		(21,477)		(21,146)
Total operating expenses			(54,749)		(62,208)		(54,257)
Equity in earnings (losses) of joint ventures	3,8		6,420		6,078		17,938
Operating income (loss)	3		94,766		89,306		110,242
FINANCIAL INCOME (EXPENSE), NET
Interest income	14		605		947		725
Interest expense	5,12,14		(24,430)		(27,692)		(26,814)
Gain (loss) on debt extinguishment	5		—		1,030		—
Gain (loss) on derivative instruments	16		—		—		4,681
Other items, net			(2,232)		(3,575)		(2,907)
Total financial income (expense), net	5		(26,057)		(29,290)		(24,315)
Income (loss) before tax			68,709		60,016		85,927
Income tax benefit (expense)	6		(5,564)		(7,275)		(8,305)
Net income (loss)	3	$	63,145		52,741	$	77,622
Preferred unitholders’ interest in net income			14,802		13,850		12,303
Limited partners’ interest in net income (loss)		$	48,343		38,891	$	65,319
Earnings per unit
Common unit public (basic and diluted)	21	$	1.40		1.12	$	1.93
Common unit Höegh LNG (basic and diluted)	21	$	1.51		1.84	$	2.03
Subordinated unit Höegh LNG (basic and diluted)	21	$	—		0.70	$	2.03

The accompanying notes are an integral part of these financial statements.

F-5

HÖEGH LNG PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(in thousands of U.S. dollars)

	Notes	2020		2019	2018
Net income (loss)		$	63,145	52,741	$	77,622
Unrealized gains (losses) on cash flow hedge	16		(11,367)	(12,217)		(2,290)
Income tax benefit (expense)	6,16		(262)	(389)		(299)
Other comprehensive income (loss)			(11,629)	(12,606)		(2,589)
Comprehensive income (loss)		$	51,516	40,135	$	75,033
Preferred unitholders’ interest in net income			14,802	13,850		12,303
Limited partners’ interest in comprehensive income (loss)		$	36,714	26,285	$	62,730

The accompanying notes are an integral part of these financial statements.

F-6

HÖEGH LNG PARTNERS LP

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2020 AND 2019

(in thousands of U.S. dollars)

	Notes	2020		2019
ASSETS
Current assets
Cash and cash equivalents	15	$	31,770	$	39,126
Restricted cash	15		7,198		8,066
Trade receivables	4,15		415		735
Amounts due from affiliates	4,14,15		3,639		4,296
Advances to joint ventures	9,15		3,284		—
Inventory			—		463
Current portion of net investment in financing lease	4		4,969		4,551
Prepaid expenses and other receivables	7		3,883		2,534
Total current assets			55,158		59,771
Long-term assets
Restricted cash	15		12,095		12,627
Accumulated earnings of joint ventures	3,8		9,690		3,270
Advances to joint ventures	9,15		869		3,831
Vessels, net of accumulated depreciation	10		619,620		640,431
Other equipment	10		109		256
Intangibles and goodwill	11		14,056		17,108
Net investment in financing lease	4		269,288		274,353
Long-term deferred tax asset	6		102		217
Other long-term assets			823		936
Total long-term assets			926,652		953,029
Total assets		$	981,810	$	1,012,800

The accompanying notes are an integral part of these financial statements.

F-7

HÖEGH LNG PARTNERS LP

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2020 AND 2019

(in thousands of U.S. dollars)

	Notes	2020		2019
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	12,15	$	59,119	$	44,660
Trade payables			467		533
Amounts due to owners and affiliates	14,15		2,600		2,513
Value added and withholding tax liability			1,445		1,476
Derivative instruments	15,16		6,945		2,907
Accrued liabilities and other payables	13		7,232		11,164
Total current liabilities			77,808		63,253
Long-term liabilities
Long-term debt	12,15		355,470		412,301
Revolving credit facility due to owners and affiliates	14,15		18,465		8,792
Derivative instruments	15,16		19,530		12,028
Long-term tax liability	6		2,668		2,283
Long-term deferred tax liability	6		14,430		12,549
Other long-term liabilities			124		84
Total long-term liabilities			410,687		448,037
Total liabilities			488,495		511,290
EQUITY	19,20,21
8.75% Series A preferred units: 6,752,333 units issued and outstanding at December 31, 2020 and 6,625,590 units issued and outstanding at December 31, 2019			167,760		164,482
Common units public: 18,050,941 units issued and outstanding at December 31, 2020 and 18,028,786 units issued and outstanding at December 31, 2019			308,850		315,176
Common units Höegh LNG: 15,257,498 units issued and outstanding at December 31, 2020 and December 31, 2019			46,277		39,795
Accumulated other comprehensive income (loss)	16		(29,572)		(17,943)
Total partners’ capital			493,315		501,510
Total equity			493,315		501,510
Total liabilities and equity		$	981,810	$	1,012,800

The accompanying notes are an integral part of these financial statements.

F-8

HÖEGH LNG PARTNERS LP

CONSOLIDATED STATEMENTS OF

CHANGES IN PARTNERS’ CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(in thousands of U.S. dollars)

	Partners’ Capital
	8.75%			Common		Accumulated
	Series A		Common	Units		Other
	Preferred		Units	Höegh	Subordinated	Comprehensive	Total
	Units		Public	LNG	Units	Income	Equity
Consolidated balance as of December 31, 2017	$	113,404	317,149	6,513	40,341	(2,748)	$	474,659
Net income		12,303	34,409	4,257	26,653	—		77,622
Cash distributions to unitholders		(13,107)	(31,211)	(3,881)	(24,298)	—		(72,497)
Refund of indemnification received from Höegh LNG		—	—	(325)	(2,028)	—		(2,353)
Cash distributions from Höegh LNG		—	—	234	1,467	—		1,701
Other comprehensive income		—	—	—	—	(2,589)		(2,589)
Net proceeds from issuance of common units		—	4,563	—	—	—		4,563
Net proceeds from issuance of Series A preferred units		38,659	—	—	—	—		38,659
Issuance of units for Board of Directors’ fees		—	200	—	—	—		200
Other and contributions from owners		—	140	46	286	—		472
Consolidated balance as of December 31, 2018	$	151,259	325,250	6,844	42,421	(5,337)	$	520,437
Net income		13,850	20,186	12,973	5,732	—		52,741
Cash distributions to unitholders		(13,692)	(31,663)	(10,051)	(18,398)	—		(73,804)
Refund of indemnification received from Höegh LNG		—	—	(9)	(55)	—		(64)
Conversion of subordinated units to common units		—	—	29,837	(29,837)	—		—
Other comprehensive income		—	—	—	—	(12,606)		(12,606)
Net proceeds from issuance of common units		—	1,029	—	—	—		1,029
Net proceeds from issuance of Series A preferred units		13,065	—	—	—	—		13,065
Issuance of units for Board of Directors’ fees		—	194	—	—	—		194
Other and contributions from owners		—	180	201	137	—		518
Consolidated balance as of December 31, 2019	$	164,482	315,176	39,795	—	(17,943)	$	501,510
Net income		14,802	25,333	23,010	—	—		63,145
Cash distributions to unitholders		(14,698)	(31,737)	(28,451)	—	—		(74,886)
Cumulative change in accounting principle (Note 2)		—	(84)	(72)	—	—		(156)
Other comprehensive income		—	—	—	—	(11,629)		(11,629)
Net proceeds from issuance of Series A preferred units		3,174	—	—	—	—		3,174
Issuance of units for Board of Directors’ fees		—	181	—	—	—		181
Contribution from Höegh LNG		—	—	11,850	—	—		11,850
Other and contributions from owners		—	(19)	145	—	—		126
Consolidated balance as of December 31, 2020	$	167,760	308,850	46,277	—	(29,572)	$	493,315

The accompanying notes are an integral part of these financial statements.

F-9

HÖEGH LNG PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(in thousands of U.S. dollars)

	2020		2019	2018
OPERATING ACTIVITIES
Net income (loss)	$	63,145	52,741	$	77,622
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		20,937	21,477		21,146
Equity in (earnings) losses of joint ventures		(6,420)	(6,078)		(17,938)
Changes in accrued interest income on advances to joint ventures		(321)	(295)		(273)
Amortization of deferred debt issuance cost and fair value of debt assumed		2,289	2,361		700
Amortization in revenue for above market contract		3,052	3,631		3,631
Expenditure for drydocking		—	(3,107)		—
(Gain) loss on debt extinguishment		—	(1,030)		—
Changes in accrued interest expense		(435)	2,246		(605)
Receipts from repayment of principal on financing lease		4,551	4,168		—
Unrealized foreign exchange losses (gains)		(380)	360		181
Gain (loss) on the settlement of the derivatives		—	(199)		—
Proceeds from settlement of derivative instruments		—	1,398		—
Unrealized loss (gain) on derivative instruments		173	21		(4,681)
Non-cash revenue: tax paid directly by charterer		(867)	(867)		(852)
Non-cash income tax expense: tax paid directly by charterer		867	867		852
Deferred tax expense and provision for tax uncertainty		2,118	3,707		5,272
Issuance of units for Board of Directors’ fees		181	194		200
Other adjustments		123	512		472
Changes in working capital:
Trade receivables		176	543		6,344
Inventory		463	183		22
Prepaid expenses and other receivables		(1,168)	(2,081)		(72)
Trade payables		(80)	(10)		155
Amounts due to owners and affiliates		744	244		842
Value added and withholding tax liability		(633)	2,827		4,257
Accrued liabilities and other payables		(2,690)	1,439		(5,594)
Net cash provided by (used in) operating activities		85,825	85,252		91,681
INVESTING ACTIVITIES
Expenditure for vessel and other equipment		(8)	(269)		(747)
Receipts from repayment of principal on financing lease		—	—		3,814
Net cash provided by (used in) investing activities	$	(8)	(269)	$	3,067

The accompanying notes are an integral part of these financial statements.

F-10

HÖEGH LNG PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(in thousands of U.S. dollars)

	2020		2019	2018
FINANCING ACTIVITIES
Proceeds from long-term debt	$	—	368,300	$	—
Proceeds from revolving credit facility due to owners and affiliates		21,750	3,500		5,400
Repayment of long-term debt		(44,660)	(342,416)		(45,458)
Payment of debt issuance costs		—	(5,797)		—
Repayment of revolving credit facility due to owners and affiliates		—	(34,000)		(17,500)
Repayment of customer loan for funding of value added liability on import		—	(438)		(4,993)
Net proceeds from issuance of common units		—	1,029		4,563
Net proceeds from issuance of Series A preferred units		3,174	13,065		38,659
Cash distributions to limited partners and preferred unitholders		(74,886)	(73,804)		(72,497)
Proceeds from indemnifications received from Höegh LNG		—	—		1,701
Repayment of indemnifications received from Höegh LNG		—	(64)		(2,353)
Net cash provided by (used in) financing activities	$	(94,622)	(70,625)	$	(92,478)
Increase (decrease) in cash, cash equivalents and restricted cash		(8,805)	14,358		2,270
Effect of exchange rate changes on cash, cash equivalents and restricted cash		49	7		(97)
Cash, cash equivalents and restricted cash, beginning of period		59,819	45,454		43,281
Cash, cash equivalents and restricted cash, end of period	$	51,063	59,819	$	45,454

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets for the years ended December 31, 2020, 2019, 2018 and 2017.

	2020		2019	2018	2017
Cash and cash equivalents	$	31,770	39,126	26,326	$	22,679
Restricted cash - current asset		7,198	8,066	6,003		6,962
Restricted cash - non-current asset		12,095	12,627	13,125		13,640
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	51,063	59,819	45,454	$	43,281

The accompanying notes are an integral part of these financial statements.

F-11

1.   Description of business

Höegh LNG Partners LP (the “Partnership”) was formed under the laws of the Marshall Islands on April 28, 2014 as an indirect 100% owned subsidiary of Höegh LNG Holdings Ltd. (“Höegh LNG”) for the purpose of acquiring Höegh LNG’s interests in Hoegh LNG Lampung Pte. Ltd., PT Hoegh LNG Lampung (the owner of the PGN FSRU Lampung), SRV Joint Gas Ltd. (the owner of the Neptune), and SRV Joint Gas Two Ltd. (the owner of the Cape Ann) in connection with the Partnership’s initial public offering of its common units (the “IPO”) in August 2014.

On August 12, 2014, the Partnership completed its IPO. Prior to the closing of the IPO, Höegh LNG contributed to the Partnership all of its equity interests and loans and promissory notes due to it and affiliates in each of the entities owning the Neptune, the Cape Ann and the PGN FSRU Lampung. The transfer of the interests was recorded at Höegh LNG’s consolidated book values. At the closing of the IPO (including the exercise by the underwriters of the option to purchase an additional 1,440,000 common units), (i) 11,040,000 common units were sold to the public for net proceeds, after deduction of offering expenses, of $203.5 million; (ii) Höegh LNG owned 2,116,060 common units and 13,156,060 subordinated units, representing approximately 58% of the limited partner interests in the Partnership, and 100% of the incentive distribution rights (“IDRs”) and (iii) a wholly owned subsidiary of Höegh LNG owned the non-economic general partner interest in the Partnership.

Under the partnership agreement, the general partner has irrevocably delegated to the Partnership’s board of directors the power to oversee and direct the operations of, manage and determine the strategies and policies of the Partnership. Four of the seven board members were elected by the common unitholders at the Partnership’s first annual meeting of unitholders held on September 24, 2014. As a result, Höegh LNG, as the owner of the general partner, does not have the power to control the Partnership’s board of directors or the Partnership, and the Partnership is not considered to be under the control of Höegh LNG for United States generally accepted accounting principles (“US GAAP”) purposes. Therefore, the sale of a business from Höegh LNG to the Partnership is a change of control. As a result, the Partnership accounts for acquisitions of businesses under the purchase method of accounting and not as transfers of entities under common control.

On October 1, 2015, the Partnership closed the acquisition of 100% of the shares in Höegh LNG FSRU III Ltd., the entity that indirectly owned the floating storage and regasification unit (“FSRU”) the Höegh Gallant (the “Höegh Gallant entities”). The Höegh Gallant was constructed by Hyundai Heavy Industries Co., Ltd. (“HHI”) and was delivered to Höegh LNG in November 2014.

In December 2016, the Partnership issued and sold 6,588,389 common units in an underwritten public offering for net proceeds of $111.5 million primarily to fund the purchase price of the acquisition of a 51% ownership interest in Höegh LNG Colombia Holding Ltd., the owner of the entities that own and operate the FSRU Höegh Grace (the “Höegh Grace entities”), in January 2017.

On January 3, 2017, the Partnership closed the acquisition of a 51% ownership interest in Höegh Colombia Holding Ltd. On January 1, 2017, the Partnership entered into an agreement with Höegh LNG, under which Höegh LNG granted to the Partnership the authority to make decisions about operations of Höegh LNG Colombia Holding Ltd. from January 1, 2017 to the closing date of the acquisition. As a result, the Partnership has recorded the results of operations of the Höegh Grace entities in its consolidated statement of income from January 1, 2017

On October 5, 2017, the Partnership issued 4,600,000 8.75% Series A cumulative redeemable preferred units (the “Series A preferred units”) for proceeds, net of underwriting discounts and expenses, of $110.9 million. Refer to note 20. A portion of the net proceeds was used to repay outstanding debt under the seller’s credit note related to the Höegh Gallant acquisition and outstanding debt under the revolving credit facility.

On December 1, 2017, the Partnership closed the acquisition of the remaining 49% ownership interest in the Höegh Grace entities with a combination of cash remaining from the net proceeds from the issuance of Series A preferred units and draws on the revolving credit facility.

F-12

On January 26, 2018, the Partnership entered into sales agreement with B. Riley FBR Inc. (the “Agent”). Under the terms of the sales agreement, the Partnership could offer and sell up to $120 million aggregate offering amount of common units and Series A preferred units through the Agent, acting as agent for the Partnership (the “Prior ATM Program”).

On October 18, 2019, the Partnership entered into a sales agreement with the Agent for a new ATM program and terminated the Prior ATM Program. Under the terms of the new sales agreement, the Partnership may offer and sell up to $120 million aggregate offering amount of common units and Series A preferred units, from time to time, through the Agent, acting as an agent for the Partnership. Sales of such units may be made in negotiated transactions that are deemed to be “at the market” offerings, including sales made directly on the New York Stock Exchange or through a market maker other than on an exchange.

The interests in SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., collectively, are referred to as the “joint ventures” and the remaining entities owned by the Partnership, as reflected in the table below are, collectively, referred to as the “subsidiaries” in these consolidated financial statements. The PGN FSRU Lampung, the Höegh Gallant, the Höegh Grace, the Neptune and the Cape Ann are FSRUs and, collectively, referred to in these consolidated financial statements as the vessels or the “FSRUs.” The Tower Yoke Mooring System (the “Mooring”) is an offshore installation that is used to moor the PGN FSRU Lampung to offload the gas into an offshore pipe that transports the gas to a land terminal. PT Hoegh LNG Lampung, Hoegh LNG Cyprus Limited, the owner of the Höegh Gallant, Höegh LNG FSRU IV Ltd., the owner of the Höegh Grace, and the two joint ventures, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., are collectively referred to as the “FSRU-owning entities.”

The Neptune and the Cape Ann operate under long-term time charters with expiration dates in 2029 and 2030, respectively, and, in each case, with an option for the charterer, Global LNG Supply SA, as novated to Total Gas & Power Ltd. in February 2020, both subsidiaries of Total S.A. (“Total”), to extend for up to one additional period of ten years or two additional periods of five years each. The PGN FSRU Lampung, operates under a long term time charter which started in July 2014 with an expiration date in 2034, with an option for the charterer to extend for up to two additional periods of five years each, and uses the Mooring that was constructed, installed and sold to the charterer, PT PGN LNG Indonesia (“PGN LNG”), a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk (“PGN”), a subsidiary of PT Pertamina, a government-controlled, Indonesian oil and gas producer, natural gas transportation and distribution company. The Höegh Gallant operated under a long term time charter which started in April 2015 and expired in April 2020 with Hoegh LNG Egypt LLC (“EgyptCo”), a subsidiary of Höegh LNG. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of the EgyptCo charter until July 2025. On April 30, 2020, the Partnership entered into a lease and maintenance agreement with another subsidiary of Höegh LNG for the time charter of the Höegh Gallant (the “Subsequent Charter”). The Subsequent Charter commenced on May 1, 2020 and expires July 31, 2025. The Höegh Grace operates under a long term time charter which started in December 2016 with Sociedad Portuaria El Cayao S.A. E.S.P. (“SPEC”). SPEC is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. The non-cancellable charter period of 10 years ends in December 2026. The initial term of the charter is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if SPEC waives its rights to terminate in year 10 within a certain deadline, the Partnership will not be able to exercise its right to terminate in year 10.

F-13

The following table lists the entities included in these consolidated financial statements and their purpose as of December 31, 2020.

	Jurisdiction of
	Incorporation
Name	or Registration	Purpose
Höegh LNG Partners LP	Marshall Islands	Holding Company
Höegh LNG Partners Operating LLC (100% owned)	Marshall Islands	Holding Company
Hoegh LNG Services Ltd (100% owned)	United Kingdom	Administration Services Company
Hoegh LNG Lampung Pte. Ltd. (100% owned)	Singapore	Owns 49% of PT Hoegh LNG Lampung
PT Hoegh LNG Lampung (49% owned) (1)	Indonesia	Owns PGN FSRU Lampung
SRV Joint Gas Ltd. (50% owned) (2)	Cayman Islands	Owns Neptune
SRV Joint Gas Two Ltd. (50% owned) (2)	Cayman Islands	Owns Cape Ann
Hoegh LNG Cyprus Limited (100% owned)	Cyprus	Owns Höegh Gallant
Hoegh LNG Cyprus Limited Egypt Branch (100% owned)	Egypt	Branch of Hoegh LNG Cyprus Limited
Höegh LNG Colombia Holding Ltd. (100% owned)	Cayman Islands	Owns 100% of Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S.
Höegh LNG FSRU IV Ltd. (100% indirectly owned)	Cayman Islands	Owns Höegh Grace
Höegh LNG Colombia S.A.S. (100% indirectly owned)	Colombia	Operating Company

(1) PT Hoegh LNG Lampung is a variable interest entity, which is controlled by Hoegh LNG Lampung Pte. Ltd. and is, therefore, 100% consolidated in the consolidated financial statements.

(2) The remaining 50% interest in each joint venture is owned by Mitsui O.S.K. Lines, Ltd. and Tokyo LNG Tanker Co.

2.   Significant accounting policies

Basis of presentation

The consolidated financial statements are prepared in accordance with US GAAP. All intercompany balances and transactions are eliminated.

The consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. Please refer to note 22 for the Partnership’s plan to refinance the Lampung debt facility.

It has been determined that PT Hoegh LNG Lampung, Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd., SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. are variable interest entities. A variable interest entity (“VIE”) is defined by US GAAP as a legal entity where either (a) the voting rights of some investors are not proportional to their rights to receive the expected residual returns of the entity, their obligations to absorb the expected losses of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights, or (b) the equity holders have not provided sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support, or (c) equity interest holders as a group lack the characteristics of a controlling financial interest, including decision making ability and an interest in the entity’s residual risks and rewards. The guidance requires a VIE to be consolidated if any of its interest holders are entitled to a majority of the entity’s residual returns or are exposed to a majority of its expected losses.

F-14

Based upon the criteria set forth in US GAAP, the Partnership has determined that PT Hoegh LNG Lampung is a VIE, as the equity holders, through their equity investments, may not participate fully in the entity’s expected residual returns and substantially all of the entity’s activities either involve, or are conducted on behalf of, the Partnership. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of PT Hoegh LNG Lampung are included in the consolidated financial statements. Dividends may only be paid if the retained earnings are positive and a statutory reserve has been established equal to 20% of its paid-up capital under Indonesian law. PT Hoegh LNG Lampung had not established the required statutory reserves as of December 31, 2020 and 2019. Therefore, PT Hoegh LNG Lampung cannot make dividend payments under Indonesian law. Under the Lampung facility, there are limitations on cash dividends and intercompany loans that can be made to the Partnership. Refer to note 12. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $179.9 million and $169.8 million, respectively.

The Partnership has determined that Hoegh LNG Cyprus Limited is a VIE, as the equity investment does not provide sufficient equity to permit the entity to finance its activities without financial support. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Hoegh LNG Cyprus Limited are included in the consolidated financial statements. Under Cyprus law, dividends may only be distributed out of profits and not from the share capital of the company. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

The Partnership has also determined that Höegh LNG Colombia Holding Ltd. is a VIE since the entity would not be able to finance its activities without financial support and financial guarantees under its subsidiary’s facility to finance the Höegh Grace. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives the majority of the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Höegh LNG Colombia Holding Ltd., and subsidiaries, are included in the consolidated financial statements. Under Cayman Islands law, dividends may only be paid out of profits or capital reserves if the entity is solvent after the distributions. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

Dividends and other distributions from Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd. and Höegh LNG FSRU IV Ltd. may only be distributed if after the dividend payment, the Partnership would remain in compliance with the financial covenants under the $385 million facility. Refer to note 12.

F-15

In addition, the Partnership has determined that the two joint ventures, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., are VIEs since each entity did not have a sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support. The entities have been financed with third party debt and subordinated shareholder loans. The Partnership is not the primary beneficiary, as the Partnership cannot make key operating decisions considered to be most significant to the VIEs but has joint control with the other equity holders. Therefore, the joint ventures are accounted for under the equity method of accounting as the Partnership has significant influence. The Partnership’s carrying value is recorded in advances to joint ventures and accumulated earnings (losses) of joint ventures in the consolidated balance sheets. For SRV Joint Gas Ltd., the Partnership had a receivable for the advances of $3.3 million and $3.0 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $5.5 million and $2.6 million, respectively, as of December 31, 2020 and 2019. The Partnership’s carrying value for SRV Joint Gas Two Ltd. consists of a receivable for the advances of $0.9 million and $0.8 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $4.2 million and $0.7 million, respectively, as of December 31, 2020 and 2019. The major reason that the Partnership had low accumulated earnings in the joint ventures as of December 31, 2019 and the major reason that the Partnership historically has had accumulated losses in the joint ventures, or net liabilities, is due to the fair value adjustments for the interest rate swaps recorded as liabilities on the balance sheets of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. and eliminations for consolidation to the balance sheet. The maximum exposure to loss is the carrying value of the receivables, which is subordinated to the joint ventures’ long-term bank debt, the investments in the joint ventures (accumulated earnings or losses), as the shares are pledged as security for the joint ventures’ long-term bank debt, and Höegh LNG’s commitment under long-term bank loan agreements to fund its share of drydocking costs and remarketing efforts in the event of an early termination of the charters. If the charters terminate for any reason that does not result in a termination fee, the joint ventures’ long-term bank debt would be subject to mandatory repayment. Dividend distributions require a) agreement of the other joint venture owners; b) fulfilment of requirements of the long-term bank loans; c) and under Cayman Islands law may be paid out of profits or capital reserves subject to the joint venture being solvent after the distribution.

Significant accounting policies

Foreign currencies

The reporting currency in the consolidated financial statements is the U.S. dollar, which is the functional currency of the FSRU-owning entities. Nearly all revenues are received in U.S. dollars and a majority of the Partnership’s expenditures for investments and all of the long-term debt are denominated in U.S. dollars. Transactions denominated in other currencies during the year are converted into U.S. dollars using the exchange rates in effect at the time of the transactions. Monetary assets and liabilities that are denominated in currencies other than the U.S. dollar are translated at the exchange rates in effect at the balance sheet date. Resulting gains or losses are reflected in the accompanying consolidated statements of income.

Business combinations and asset acquisitions

Business combinations are accounted for under the purchase method of accounting. Under this method, the purchase price is allocated to identifiable assets acquired and liabilities assumed based on their fair values as of the acquisition date. Any excess of the purchase price over the fair values of net assets is recognized as goodwill. Acquisition related costs are expensed as incurred. The results of entity acquired are included in the consolidated financial statements from the date of acquisition.

Dependent upon facts and circumstances, the assessment of a transaction may be considered the acquisition of an asset, when substantially all of the fair value of assets acquired is concentrated in a single identifiable asset, rather than a business combination. Asset acquisitions are accounted for by allocating the cost of the acquisition to the individual assets acquired and liabilities assumed on a relative fair value basis. Acquisition related costs are capitalized as a component of the cost of the assets acquired.

F-16

Time charter revenue, related contract balances and related expenses

Time charter revenues and related contract balances:

The Partnership is required to evaluate whether two or more contracts should be combined and accounted for as a single contract, whether the contract promises to deliver more than one distinct good or service, or performance obligations, and/or a lease, determine the transaction price under the contract, allocate the transaction price to the lease and the performance obligations and recognize revenue as the performance obligation is satisfied. The Partnership believes the nature of its time charter contracts are the same, regardless of whether the contracts are accounted for as financing leases or operating leases for accounting purposes. As such, when adopting the revised guidance on leases as of January 1, 2019, the Partnership did not elect to apply the practical expedient to not separate lease and services components for operating leases because this would result in inconsistent disclosure for the time charter contracts.

Performance obligations:

The Partnership determined that its time charter contracts contain a lease and a performance obligation for the provision of time charter services. The lease of the vessel, representing the use of the vessel without any associated performance obligations or warranties, is accounted for in accordance with the provisions of Accounting Standards Codification ("ASC") 842, Leases.

The provision of time charter services, including guarantees for the level of performance provided by the time charter contracts, is considered a distinct service and is accounted for in accordance with the provision of ASC 606, Revenue from Contracts with Customers. The Partnership determined that the nature of the time charter services promised, represents a single performance obligation, to stand ready over a 24-hour interval to accept LNG cargos, to transport cargos, to regasify the LNG and discharge the resulting gas into a pipeline in accordance with the charterer’s instructions and requirements.

Time charter services revenue can be recognized as the performance obligation is satisfied over the 24-hour interval to the performance standards specified under the time charter contract. If the performance standards are not met, off-hire, reduced hire, liquidated damages or other performance payments may result.

Contract terms, determination of transaction price and allocation to performance obligations:

The Partnership’s time charter contracts for all FSRUs, except the Höegh Gallant, include day rates or hire rates and warranty provisions with the following components:

● Fixed element: The fixed element is a fixed per day fee intended to cover remuneration for use of the vessel and the provision of time charter services.

● Operating expense reimbursement element: The operating expense reimbursement element is a rate per day intended to cover the operating costs of the vessel, including the crew, insurance, consumables, miscellaneous services, spares and maintenance and repairs costs and management services and fees. The amount of the operating expense reimbursement element may be based on actual cost incurred, or fees subject to indexing or other adjustments after a defined period, or a combination of both.

● Tax reimbursement element: The tax reimbursement element may be a rate per day, based on the estimated liability for the year divided by the number of days in the year, subject to adjustment for actual taxes incurred, or a reimbursement of the costs as the taxes are incurred. The tax reimbursement element may cover withholding taxes, payroll taxes, other local taxes and current income tax expense for the jurisdiction in which the vessel operates as defined by the provisions of the individual time charter contract.

F-17

● Performance warranties element: The performance warranties element includes defined operational capacity and standards that can result in the FSRUs being off-hire or require compensation to the charterer through provision of reduced hire, liquidated damages or performance payments. Examples of performance warranties include the ability to discharge regasified LNG at specified performance rates, guaranteed minimum fuel consumption, guaranteed minimum boil-off rates and the ability to accept cargos.

The Höegh Gallant has a single day rate intended to cover all of the elements listed above. In addition, the time charter contract for the Höegh Gallant includes a provision for off-hire for scheduled maintenance. The joint ventures’ time charter contracts also provide for upfront payments for variable costs for certain vessel modifications, drydocking costs, other additions to equipment or spare parts.

The hire rates for the PGN FSRU Lampung and the joint ventures are invoiced at the beginning of the month. The Höegh Gallant and the Höegh Grace invoice time charter revenues monthly in arrears.

The transaction price is estimated as the standalone selling price for the lease and the time charter services components of the fixed day rate element. Variable consideration per day for operating expense and tax reimbursements is estimated at the most likely amount to which the Partnership is expected to be entitled to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty related to the variable consideration is resolved. When there is significant uncertainty related to that amount of variable consideration to be received, that variable consideration is considered constrained. Typically, variable reimbursements and performance warranties are known at the end of each 24-hour interval, or as subsequently reassessed at the end of the reporting period. However, to the extent interpretations of contractual provisions are complex and/or disputed with the customer, this could give rise to constrained variable consideration. Constrained variable consideration is not estimated.

Variable consideration is allocated entirely to one performance obligation when the variable day rate relates specifically to the efforts to satisfy the single performance obligation. The default method of the relative standalone selling price method was used to allocate the remaining transaction price, principally the fixed element, between the lease and the time charter services. The total estimated transaction price for time charter services is considered variable consideration because it may be reduced by performance warranties.

The Partnership has made a policy election to exclude from the measurement of the transaction price all taxes assessed by a government entity on revenues and collected on behalf of that government entity from customers, such as sales or value added taxes.

Lease revenue recognition:

Leases are classified based upon defined criteria either as sale-type/direct financing leases (“financing leases”) or operating leases. A lease that transfers substantially all of the benefits and risks of the FSRU to the charterer is accounted for as a financing lease by the lessor. All other leases that do not meet the criteria are classified as operating leases. On January 1, 2019, when adopting the revised leasing guidance, the Partnership elected the package of practical expedients and did not reassess conclusions under the previous standard about whether any existing contracts are, or contain leases, lease classification, and initial direct costs for any existing leases. Accordingly, outstanding leases on January 1, 2019, continue to be classified in accordance with the prior lease guidance.

The lease component of time charters that are accounted for as operating leases is recognized on a straight-line basis over the term of the charter. The Höegh Gallant’s time charter, which has a five-year lease term, is accounted for as an operating lease. The Höegh Grace’s time charter contracts, which have a non-cancellable charter period of ten years, are accounted for as an operating lease. Under one of the time charter contracts, the contract provides for additional variable payments, including a finance component, over the initial term depending upon the actual commencement date of the contract within a defined window of potential commencement dates. The variable payments are considered directly related to the lease performance obligation. The revenue, excluding the financing component, is recognized over the initial 10-year term. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for final income tax directly related to the provision of the lease is recorded as a component of lease revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

F-18

The lease component of time charters that are accounted for as financing leases is recognized over the lease term using the effective interest rate method and is included in time charter revenues. Origination costs related to the time charter are a component of the net investment in financing lease and amortized over the lease term using the effective interest method. Financing leases are reflected on the consolidated balance sheets as net investments in financing leases. The PGN FSRU Lampung time charter, which had a 20-year lease term at inception, meets the criteria of transferring substantially all of the benefits and risks to the charterer and is accounted for as a financing lease.

Time charter services revenue recognition:

Variable consideration for the time charter services performance obligation, including amounts allocated to time charter services, estimated reimbursements for vessel operating expenses and estimated reimbursements of certain types of costs and taxes, are recognized as revenues as the performance obligation for the 24-hour interval is fulfilled, subject to adjustment for off-hire and performance warranties. Constrained variable consideration is recognized as revenue on a cumulative catch-up basis when the significant uncertainty related to that amount of variable consideration to be received is resolved. Estimates for variable consideration, including constrained variable consideration, are reassessed at the end of each period. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes directly related to the provision of the time charter services are recorded as a component of time charter service revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

Joint venture FSRUs lease and time charter services revenue recognition:

The Partnership’s interest in the Joint venture FSRUs’ net income is included in the consolidated financial statements under the equity method of accounting, however, the Joint venture FSRUs’ results are presented under the proportional consolidation method for the segment note (note 3) and the time charter revenue note (note 4). The Neptune’s and the Cape Ann’s time charters, which had a twenty-year lease term at inception, are accounted for as operating leases. The joint ventures’ time charters include provisions for the charterer to make upfront payments to compensate for variable cost for certain vessel modifications, drydocking costs, other additions to equipment or spare parts. The expenditures are considered costs required to fulfill the lease component of the contract. Payments for modifications are deferred and amortized over the shorter of the remaining charter period or the useful life of the additions. Payments for reimbursement of drydocking costs are deferred and recognized on a straight line basis over the period to the next drydocking.

The accounting policy for time charter services for the joint ventures is the same as described above.

Significant judgments in revenue recognition:

The Partnership does not provide stand-alone bareboat leases or time charter services for FSRUs. As a result, observable stand-alone transaction prices for the performance obligations are not available. The estimation of the transaction price for the lease and the time charter service performance obligation is complex, subject to a number of input factors, such as market conditions when the contract is entered into, internal return objectives and pricing policies, and requires substantial judgment. Significant changes in the transaction price between the two performance obligations could impact conclusions on the accounting for leases as financing or operating leases. In addition, variable consideration is estimated at the most likely amount that the Partnership expects to be entitled to. Variable consideration is reassessed at the end of the reporting period taking into account performance warranties. The time charter contracts include provisions for performance guarantees that can result in off-hire, reduced hire, liquidated damages or other payments for performance warranties. Measurement of some of the performance warranties can be complex and require properly calibrated equipment on the vessel, complex conversions and computations based on substantial judgment in the interpretation of the contractual provisions. Conclusions on compliance with performance warranties impact the amount of variable consideration recognized for time charter services.

F-19

Contract assets:

Revenue recognized in excess of the monthly invoiced amounts, or accrued revenue, is recorded as contract assets on the consolidated balance sheet. The contract assets are reported in the consolidated balance sheet as a component of prepaid expenses and other receivables.

Contract liabilities:

Advance payments in excess of revenue recognized, or prepayments, and deferred revenue is recorded as contract liabilities on the consolidated balance sheet. Contract assets and liabilities are reported in a net position for each customer contract or combined contracts at the end of each reporting period. Contract liabilities are classified as current or non-current based on the expected timing of recognition of the revenue. Current and non-current contract liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables and other long-term liabilities, respectively.

Refund liabilities:

Amounts invoiced or paid by the customer that are expected to be refunded to the customer are recorded as refund liabilities on the consolidated balance sheet. Refund liabilities may include invoiced amounts for estimated reimbursable operating expenses or other costs and taxes that exceeded the actual costs incurred, or off-hire, reduced hire, liquidated damages, or other payments for performance warranties. Refund liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables.

Remaining performance obligations:

Remaining performance obligations represent the transaction price of contracts with customers under the scope of ASC 606 for which work has not been performed excluding unexercised contract options to extend the term. The Partnership qualifies for and has elected to apply the exemption to disclose the aggregate amount of remaining transaction price allocated to unsatisfied performance obligations at the end of the reporting period as consideration for time charter services is variable and allocated entirely to wholly satisfied performance obligations.

Related expenses:

Voyage expenses include bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls and agency fees. Voyage expenses are all expenses unique to a particular voyage and when a vessel is on hire under time charters are generally the responsibility of, and paid directly by the charterers, and not included in the statement of income. When the vessel is off-hire, voyage expenses, principally fuel, may also be incurred and are paid by the FSRU-owning entity.

Vessel operating expenses, reflected in expenses in the statement of income, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and management fees. Vessel operating expenses also include bunker fuel expenses when the vessel is on hire and the expenses are not directly paid and owed by the charterers. When the vessel is on hire, vessel operating expenses are invoiced as time charter service fees to the charterer or are covered by time charter rates. When the vessel is off-hire, vessel operating expenses are not invoiced to the charterer.

Voyage expenses, if applicable, and vessel operating expenses are expensed when incurred.

Loss contingencies, insurance and other claims

Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. Significant judgment is required to determine the probability and the estimated amount of loss. Such assessments involve complex judgments about future events and estimates and assumptions that are deemed reasonable by management. Accruals are reviewed quarterly and adjusted to reflect the impact of additional information such as the impact of negotiations, advice of legal counsel or settlements.

F-20

Insurance claims for property damage are recorded, net of any deductible amounts, for recoveries up to the amount of loss recognized when the claims to insurance carriers are probable of recovery. Claims for property damage in excess of the loss recognized and for loss of revenue during off-hire, whether from insurance providers or indemnification from Höegh LNG, are considered gain contingencies, which are recognized when the proceeds are received.

Indemnification proceeds from Höegh LNG that cover the Partnership’s costs are accounted for following the guidance of the Securities and Exchange Commission’s Staff Accounting Bulletin (“SAB”) Topic 1.B and SAB Topic 5.T. SAB Topic 1.B provides that the separate financial statements of a subsidiary should reflect any costs of its operations which are incurred by the owner on its behalf. SAB Topic 5.T provides that costs should be reflected as an expense in the subsidiary’s financial statements with a corresponding credit to contributed equity.

Income taxes

Income taxes are accounted for using the liability method. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of income tax expense. The amount of non-cash income tax expense is disclosed separately in the consolidated statement of cash flows.

Deferred tax assets and liabilities are recognized for the tax consequences of temporary differences between the tax and the book bases of assets and liabilities. 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.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. If the more-likely-than-not recognition criterion is met, a tax position is measured based on the cumulative amount that is more-likely-than-not of being sustained upon examination by tax authorities to determine the amount of benefit to be recognized in the consolidated financial statements. Interest and penalties related to uncertain tax positions is recognized in income tax expense in the consolidated statement of income.

Cash and cash equivalents

Cash, banks deposits, time deposits and highly liquid investments with original maturities of three months or less are recognized as cash and cash equivalents.

Restricted cash

Restricted cash includes balances deposited with a bank as required under debt facilities to settle withholding tax, other tax liabilities and other current obligations of the entity, and principal and interest payments as required by the debt facilities. Restricted cash is classified as long-term when the settlement is more than 12 months from the balance sheet date.

Trade receivables and allowance for expected credit losses

Trade receivables are recorded at the invoiced amount and do not bear interest. Trade receivables, contract assets and the net investment in a financing lease is initially recorded by including the current expected credit loss of the asset over the life of the contract. The allowance for expected credit losses is a valuation account that is deducted from the amortized cost of the asset to present the net amount expected to be collected. Each period the allowance for expected credit losses is adjusted through earnings to reflect the revised expected credit losses over the remaining lives of the assets. Receivable amounts are written off against the allowance when the asset is confirmed uncollectible. Expected credit losses are estimated using historical credit loss experience, relevant available information, from internal and external sources, relating to current conditions and reasonable and supportable forecasts of economic conditions impacting the collectability of the assets.

F-21

Investments in accumulated earnings or losses of and advances to joint ventures

Investments in joint ventures are accounted for using the equity method of accounting. Under the equity method of accounting, investments are stated at initial cost and are adjusted for the Partnership’s proportionate share of earnings or losses and dividend distributions. As of December 31, 2020 and 2019, the Partnership had an accumulated share of earnings and the balance is classified on the consolidated balance sheet as an asset on the line accumulated earnings of joint ventures.

Advances to joint ventures represent loan receivables due from the joint ventures and are recorded at cost. Interest on the advances to joint ventures is recorded to interest income in the consolidated statements of income as incurred. The quarterly payments from joint ventures included a payment of interest for the first month of the quarter and repayment of principal. Interest is accrued for the last two months of the quarter for repayment at the end of the loans after the original principal was fully repaid. The joint ventures repaid the original principal of all shareholder loans during 2016. Payments of interest, including accrued interest repaid at the end of the loans, are treated as return on investment and included as a component of net cash provided by operating activities in the consolidated statement of cash flows. Payments of principal are included as a component of net cash provided by investing activities in the consolidated statement of cash flows.

Investments in joint ventures are evaluated for impairment when events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value below its carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the consolidated statement of income.

Loan receivables are impaired when, based on current information and events, it is probable that the full amount of the receivable will not be collected. The amount of the impairment is measured as the difference between the present value of expected future cash flows discounted at the loan’s effective interest rate and the carrying amount. The resulting impairment amount is recognized in earnings.

Inventory

Inventory consists of bunker fuel maintained on the FSRUs, if it is owned by the FSRU-owning entity. Inventory is stated at the lower of cost or net realizable value. Cost is determined using the first-in, first-out method.

Vessels

All costs incurred during the construction of newbuildings, including interest and supervision and technical costs, are capitalized. The cost of an acquired vessel is the fair value. Vessels are stated at cost less accumulated depreciation. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Depreciation is calculated using an estimated useful life of 35 years for the FSRUs.

Modifications to the vessels, including the addition of new equipment, which improves or increases the operational efficiency, functionality or safety of the vessels, are capitalized. These expenditures are amortized over the estimated useful life of the modification.

Expenditures covering recurring routine repairs and maintenance are expensed as incurred.

Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking. For vessels that are newly built, the "built-in overhaul" method of accounting is applied. Under the built-in overhaul method, costs of the newbuilding are segregated into costs that should be depreciated over the useful life of the vessel and costs that require drydocking at periodic intervals. The drydocking component is amortized until the date of the first drydocking following the delivery, upon which the actual drydocking cost is capitalized and the process is repeated. Costs of drydocking incurred to meet regulatory requirements or improve the vessel’s operating efficiency, functionality or safety are generally capitalized. Costs incurred related to routine repairs and maintenance performed during drydocking are expensed.

F-22

Impairment of long-lived assets

Vessels are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. When such events or changes in circumstances are present, the recoverability of vessels is assessed by determining whether the carrying value of such assets will be recovered through undiscounted expected future cash flows. If the vessel’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. An impairment loss is recognized based on the excess of the carrying amount over the fair value of the vessel.

Intangibles and goodwill

Intangible assets are initially measured at their fair value as of the acquisition date of a business combination. All intangible assets of the Partnership have a definite life. Intangible assets with a definite life are amortized over their useful life. Intangible assets with a definite life are tested for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized if the carrying amount exceeds the estimated fair value of the asset.

In determining the useful lives of intangible assets, the expected use of the assets, the contractual provisions that limit the useful life and other economic factors are considered. The contract related intangibles and their useful lives as of the acquisition dates, are as follows:

	Useful life
Intangible category	(Years)
Above market time charter Höegh Gallant	3.4
Option for time charter extension Höegh Gallant	5.3
Above market time charter Höegh Grace	9.5

The intangible for the above market value of the time charter contract associated with the Höegh Gallant was amortized to time charter revenue on a straight line basis over the remaining term of the contract of approximately 3.4 years as of the acquisition date. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of its initial charter until July 2025. On April 30, 2020 the Partnership entered into the Subsequent Charter which commenced on May 1, 2020 and expires July 31, 2025. The intangible for the option for the time charter extension is amortized on a straight line basis over the extension period starting on May 1, 2020, subsequent to impairment testing for recoverability in the preceding periods. The intangible for the above market value of the time charter contract associated with the Höegh Grace is amortized to time charter revenue on a straight line basis calculated per day over the remaining non-cancellable charter term of approximately 9.5 years as of the acquisition date of the initial 51% interest in the Höegh Grace entities.

Goodwill arises when an acquisition is accounted for under the purchase method of accounting. The assets acquired and liabilities assumed are recorded at their fair values as of the acquisition date. Any excess of the consideration over the net assets acquired is recorded as goodwill. Goodwill is not amortized and is tested annually for impairment of value and whenever events or circumstances indicate that the carrying amount may not be recoverable.

Derivative instruments

All derivative instruments are initially recorded at fair value as either assets or liabilities in the consolidated balance sheet and are subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the contract is designated as a hedging instrument and qualifies for hedge accounting.

F-23

For derivative instruments that are not designated or that do not qualify for hedge accounting, the changes in the fair value of the derivative instruments are recognized in earnings. In order to designate a derivative as a cash flow hedge, formal documentation of the relationship between the derivative and the hedged item is required. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge.

Interest rate swaps are used for the management of interest rate risk exposure. The interest rate swaps have the effect of converting a portion of the outstanding debt from a floating to a fixed rate over the life of the transactions. As of January 1, 2019, the following accounting policies became effective for cash flow hedges of interest rate swaps.

For interest rate swaps qualifying as cash flow hedges, the fair value of the portion of the derivative instruments included in the assessment of hedge effectiveness ("hedge effectiveness") and the initial fair value of the hedge component excluded from hedge effectiveness are initially recorded in accumulated other comprehensive income as a component of total equity. Subsequent changes in fair value for the portion of the derivative instruments included in hedge effectiveness are recorded in other comprehensive income. In the periods when the hedged items affect earnings (interest expense is incurred for floating interest rate debt), those amounts are transferred from accumulated other comprehensive income to the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. The initial fair value component excluded from hedge effectiveness is amortized to earnings over the life of the hedging instrument. The amortization is recognized on the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. Any difference in the change in fair value of the hedge components excluded from hedge effectiveness and the amount recognized in earnings is recorded as a component of other comprehensive income.

Prospective and retrospective hedge effectiveness is assessed on an ongoing basis. If a cash flow hedge is no longer deemed highly effective, hedge accounting is discontinued. If a cash flow hedge for an interest rate swap is terminated and the originally hedged item is still considered probable of occurring, the gains and losses initially recognized in accumulated other comprehensive income remain there until the hedged item impacts earnings, at which point they are amortized to earnings on a systematic and rational basis to interest expense in the consolidated statement of income. If the hedged items are no longer considered probable of occurring, amounts recognized in total equity are immediately transferred to interest expense in the consolidated statement of income. Cash flows from derivative instruments that are accounted for as cash flow hedges are classified in the same category as the cash flows from the items being hedged.

For the year ended December 31, 2018, changes in the fair value of the effective portion of the derivative instruments qualifying as cash flow hedges were initially recorded in other comprehensive income as a component of total equity. Any hedge ineffectiveness was recognized immediately in earnings, as were any gains and losses or amortization on the portion of the derivative instruments that were excluded from the assessment of hedge effectiveness. In the periods when the hedged items affect earnings, those amounts were transferred from accumulated other comprehensive income to the gain (loss) on derivative instruments line in the consolidated statement of income.

Deferred debt issuance costs and fair value of debt assumed

Debt issuance costs, including arrangement fees and legal expenses, are deferred and presented as a direct deduction from the outstanding principal of the related debt in the consolidated balance sheet and amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the deferred debt issuance costs is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

The discount or premium arising in a business combination for the difference in the fair value of the debt assumed compared to the outstanding principal is reported in the consolidated balance sheet as a direct adjustment to the outstanding principal of the related debt and amortized on an effective interest rate method over the term of the relevant loan. Amortization of fair value of the debt assumed is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the discount or premium is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

F-24

Use of estimates

The preparation of financial statements in accordance with US 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. Significant estimates subject to such estimates and assumptions include revenue recognition, purchase price allocation, the useful lives of vessels, drydocking, loss contingencies and the value of derivative instruments.

Recently adopted accounting pronouncements

Allowance for expected credit losses: On January 1, 2020, the Partnership adopted the Financial Accounting Standards Board’s (“FASB”) revised guidance on Financial Instruments – Credit Losses: Measurement of Credit Losses, which replaces the incurred loss methodology with a current expected credit loss (CECL) methodology that requires consideration of a broader range of reasonable and supportable information to estimate credit losses. The new guidance is applicable to financial assets measured at amortized cost, including trade receivables, contract assets and net investment in financing leases and applied with a modified retrospective method. The Partnership recorded a net decrease to retained earnings of $0.16 million as of January 1, 2020 for the cumulative effect of adopting the new standard. The cumulative effect includes allowances for expected credit losses recognized of $0.1 million (related to the net investment in financing lease) and $0.06 million (related to trade receivables). Refer to note 4.

For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard.

On January 1, 2020, the Partnership adopted FASB's revised guidance for Intangibles - Goodwill and Other: Simplifying the test for Goodwill Impairment, which simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The adoption of the standard did not have an impact on the consolidated financial statements.

Recently issued accounting pronouncements

In December 2019, FASB issued revised guidance for Income Taxes – Simplifying the Accounting for Income Taxes. The revised guidance eliminates certain exceptions to the guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance is effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted in interim or annual periods for which public business entities have not yet issued financial statements. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements and related disclosures. The Partnership implemented the revised guidance on January 1, 2021.

In March 2020, FASB issued final guidance for Reference Rate Reform to provide temporary optional expedients and exceptions to the guidance in US GAAP on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. For all types of hedging relationships, the guidance allows an entity to change the reference rate and other critical terms related to reference rate reform without having to dedesignate the relationship. The guidance is effective upon issuance through December 31, 2022. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements for the expected transitions from LIBOR to alternative reference rates. In January 2021 FASB issued an update to the guidance from 2020 to clarify its scope.

F-25

3.   Segment information

There are two operating segments. The segment profit measure is Segment EBITDA, which is defined as earnings before interest, taxes, depreciation, amortization and impairment, and other financial items (gain (loss) on debt extinguishment, gain (loss) on derivative instruments and other items, net). Segment EBITDA is reconciled to operating income and net income in the segment presentation below. The two segments are “Majority held FSRUs” and “Joint venture FSRUs.” In addition, unallocated corporate costs, interest income from advances to joint ventures and interest expense related to the outstanding balance on the $85 million revolving credit facility and the $385 million facility are included in “Other.”

For the years ended December 31, 2020, 2019 and 2018, Majority held FSRUs includes the financing lease related to the PGN FSRU Lampung and the operating leases related to the Höegh Gallant and the Höegh Grace.

As of December 31, 2020, 2019 and 2018, Joint venture FSRUs include two 50% owned FSRUs, the Neptune and the Cape Ann, that operate under long term time charters with one charterer.

The accounting policies applied to the segments are the same as those applied in the consolidated financial statements, except that i) Joint venture FSRUs are presented under the proportional consolidation method for the segment note and under equity accounting for the consolidated financial statements and ii) internal interest income and interest expense between the Partnership’s subsidiaries that eliminate in consolidation are not included in the segment columns for the other financial income (expense), net line. Under the proportional consolidation method, 50% of the Joint venture FSRUs’ revenues, expenses and assets are reflected in the segment note. Management monitors the results of operations of joint ventures under the proportional consolidation method and not the equity method of accounting.

In time charters, the charterer, not the Partnership, controls the choice of locations or routes the FSRUs serve. Accordingly, the presentation of information by geographical region is not meaningful. The following tables include the results for the segments for the years ended December 31, 2020, 2019 and 2018.

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	143,095	43,572	—	186,667	(43,572)	(1)	$	143,095
Total revenues		143,095	43,572	—	186,667				143,095
Operating expenses		(27,462)	(9,452)	(6,350)	(43,264)	9,452	(1)		(33,812)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,420	(1)		6,420
Segment EBITDA		115,633	34,120	(6,350)	143,403
Depreciation, amortization and impairment		(20,937)	(9,965)	—	(30,902)	9,965	(1)		(20,937)
Operating income (loss)		94,696	24,155	(6,350)	112,501				94,766
Gain (loss) on derivative instruments		—	(6,073)	—	(6,073)	6,073	(1)		—
Other financial income (expense), net		(9,072)	(11,662)	(16,985)	(37,719)	11,662	(1)		(26,057)
Income (loss) before tax		85,624	6,420	(23,335)	68,709	—			68,709
Income tax expense		(5,564)	—	—	(5,564)	—			(5,564)
Net income (loss)	$	80,060	6,420	(23,335)	63,145	—		$	63,145
Preferred unitholders’ interest in net income		—	—	—	—	14,802	(2)		14,802
Limited partners’ interest in net income (loss)	$	80,060	6,420	(23,335)	63,145	(14,802)	(2)	$	48,343

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

F-26

	As of December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	619,620	242,226	—	861,846	(242,226)	(1)	$	619,620
Net investment in financing lease		274,257	—	—	274,257	—			274,257
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	4,153	4,153	—			4,153
Total assets		969,278	267,003	12,532	1,248,813	(267,003)	(1)		981,810
Accumulated earnings of joint ventures		—	—	50	50	9,640	(1)		9,690
Expenditures for vessels & equipment		8	75	—	83	(75)	(2)		8
Expenditures for drydocking		—	2	—	2	(2)	(2)		—
Principal repayment financing lease		4,551	—	—	4,551	—			4,551
Amortization of above market contract	$	3,052	—	—	3,052	—		$	3,052

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	145,321	42,433	—	187,754	(42,433)	(1)	$	145,321
Other revenue		115	—	—	115		(1)		115
Total revenues		145,436	42,433	—	187,869				145,436
Operating expenses (2)		(34,266)	(9,044)	(6,465)	(49,775)	9,044	(1)		(40,731)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,078	(1)		6,078
Segment EBITDA		111,170	33,389	(6,465)	138,094
Depreciation, amortization and impairment		(21,477)	(10,030)	—	(31,507)	10,030	(1)		(21,477)
Operating income (loss)		89,693	23,359	(6,465)	106,587				89,306
Gain (loss) on debt extinguishment		1,030	—	—	1,030		(1)		1,030
Gain (loss) on derivative instruments		—	(5,209)	—	(5,209)	5,209	(1)		—
Other financial income (expense), net		(12,511)	(12,072)	(17,809)	(42,392)	12,072	(1)		(30,320)
Income (loss) before tax		78,212	6,078	(24,274)	60,016	—			60,016
Income tax expense		(7,278)	—	3	(7,275)	—			(7,275)
Net income (loss)	$	70,934	6,078	(24,271)	52,741	—		$	52,741
Preferred unitholders’ interest in net income		—	—	—	—	13,850	(3)		13,850
Limited partners’ interest in net income (loss)	$	70,934	6,078	(24,271)	52,741	(13,850)	(3)	$	38,891

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) The Partnership's Indonesian subsidiary was assessed a property tax and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The retroactive assessment was as a result of the issuance of a new regulation in 2019, defining FSRUs as subject to the existing Indonesian property tax law. The property tax and penalties were recorded as a component of vessel operating expenses.

F-27

(3) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

	As of December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	640,431	252,789	—	893,220	(252,789)	(1)	$	640,431
Net investment in financing lease		278,904	—	—	278,904	—			278,904
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	3,831	3,831	—			3,831
Total assets		996,201	284,174	16,599	1,296,974	(284,174)	(1)		1,012,800
Accumulated earnings of joint ventures		—	—	50	50	3,220	(1)		3,270
Expenditures for vessels & equipment		211	195	—	406	(195)	(2)		211
Expenditures for drydocking		3,107	913	—	4,020	(913)	(2)		3,107
Impairment/retirement of equipment		—	(75)	—	(75)	75	(2)		—
Principal repayment financing lease		4,168	—	—	4,168	—			4,168
Amortization of above market contract	$	3,631	—	—	3,631	—		$	3,631

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	144,952	43,169	—	188,121	(43,169)	(1)	$	144,952
Other revenue		1,609	—	—	1,609		(1)		1,609
Total revenues		146,561	43,169	—	173,846				146,561
Operating expenses		(27,294)	(10,932)	(5,817)	(44,043)	10,932	(1)		(33,111)
Equity in earnings (losses) of joint ventures		—	—	—	—	17,938	(1)		17,938
Segment EBITDA		119,267	32,237	(5,817)	145,687
Depreciation and amortization		(21,146)	(9,725)	—	(30,871)	9,725	(1)		(21,146)
Operating income (loss)		98,121	22,512	(5,817)	114,816				110,242
Gain (loss) on derivative instruments		4,681	8,496	—	13,177	(8,496)	(1)		4,681
Other financial income (expense), net		(26,381)	(13,070)	(2,615)	(42,066)	13,070	(1)		(28,996)
Income (loss) before tax		76,421	17,938	(8,432)	85,927	—			85,927
Income tax benefit (expense)		(8,253)	—	(52)	(8,305)	—			(8,305)
Net income (loss)	$	68,168	17,938	(8,484)	77,622	—		$	77,622
Preferred unitholders’ interest in net income		—	—	—	—	12,303	(2)		12,303
Limited partners’ interest in net income (loss)	$	68,168	17,938	(8,484)	77,622	(12,303)	(2)	$	65,319

(1) Eliminations reverse each of the income statement line items of the proportional consolidation amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs’ net income (loss) to Equity in earnings (loss) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

F-28

For the years ended December 31, 2020, 2019 and 2018, the percentage of consolidated total revenues from the following customers accounted for over 10% of the Partnership’s consolidated total revenues:

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019		2018
PT PGN LNG Indonesia	33	%	33	%	33	%
Höegh LNG	30	%	31	%	31	%
Sociedad Portuaria El Cayao S.A. E.S.P.	37	%	36	%	36	%

4.   Time charter revenues and related contract balances

The Partnership presents its revenue by segment, disaggregated by revenue recognized in accordance with accounting standards on leasing and on revenue from contracts with customers for time charter services. In addition, material elements where the nature, amount, timing and uncertainty of revenue and cash flows differ from the monthly invoicing under time charter contracts are separately presented. Revenue recognized for the Majority held FSRUs includes the amortization of above market contract intangibles. Revenue recognized for Joint venture FSRUs include the amortization of deferred revenues related to the charterer’s reimbursements for certain vessel modifications and drydocking costs. As a result, the timing of cash flows differs from monthly time charter invoicing. The Partnership believes the nature of its time charter contracts are the same, regardless of whether the contracts are accounted for as financing leases or operating leases for accounting purposes. As such, the Partnership did not apply the practical expedient in the lease guidance to combine lease and services components for operating leases because this would result in inconsistent disclosure for the time charter contracts.

The following tables summarize the disaggregated revenue of the Partnership by segment for the twelve months ended December 31, 2020, 2019 and 2018:

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	87,948	25,760	—	113,708	(25,760)	$	87,948
Time charter service revenues, excluding amortization		58,199	15,098	—	73,297	(15,098)		58,199
Amortization of above market contract intangibles		(3,052)	—	—	(3,052)	—		(3,052)
Amortization of deferred revenue for modifications & drydock		—	2,714	—	2,714	(2,714)		—
Total revenues (4)	$	143,095	43,572	—	186,667	(43,572)	$	143,095

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	88,889	25,690	—	114,579	(25,690)	$	88,889
Time charter service revenues, excluding amortization		60,063	14,095	—	74,158	(14,095)		60,063
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,648	—	2,648	(2,648)		—
Other revenue (3)		115	—	—	115	—		115
Total revenues (4)	$	145,436	42,433	—	187,869	(42,433)	$	145,436

F-29

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization	$	89,215	25,690	—	114,905	(25,690)	$	89,215
Time charter service revenues, excluding amortization		59,368	15,078	—	74,446	(15,078)		59,368
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,401	—	2,401	(2,401)		—
Other revenue (3)		1,609	—	—	1,609	—		1,609
Total revenues (4)	$	146,561	43,169	—	189,730	(43,169)	$	146,561

(1) Eliminations reverse the proportional amounts of revenue for Joint venture FSRUs to reflect the consolidated revenues included in the consolidated income statement. The Partnership’s share of the Joint venture FSRUs revenues is included in Equity in earnings (losses) of joint ventures on the consolidated income statement.

(2) The financing lease revenues comprise about one-fourth of the total lease revenues for the years ended December 31, 2020 and 2019.

(3) Other revenue consists of insurance proceeds received for prior period claims related to repairs under the Mooring warranty and for repairs for the Höegh Gallant. The Partnership was indemnified by Höegh LNG for the cost of the repairs related to the Mooring, subject to repayment to the extent recovered from insurance proceeds. Refer to notes 3 and 17.

(4) Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of total revenues and is disclosed separately in the consolidated statement of cash flows.

The Partnership’s risk and exposure related to uncertainty of revenues or cash flows related to its long-term time charter contracts primarily relate to the credit risk associated with the individual charterers. Payments are due under time charter contracts regardless of the demand for the charterers’ gas output or the utilization of the FSRU.

The consolidated trade receivables, contract assets, contract liabilities and refund liabilities included in the table below, exclude the balances for the Joint venture FSRUs. The Partnership’s share of net assets in the Joint venture FSRUs are recorded in the consolidated balance sheet using the equity method on the line accumulated losses in joint ventures.

The following table summarizes the allocation of consolidated receivables between lease and service components:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Trade receivable for lease	$	2,608	$	2,898
Trade receivable for time charter services		1,506		2,133
Allowance for expected credit losses		(60)		—
Total trade receivable and amounts due from affiliates	$	4,054	$	5,031

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There were no impairment losses for trade receivables for lease or time charter services or contract assets for the year ended December 31, 2019.

F-30

The following table summarizes the consolidated contract assets, contract liabilities and refund liabilities to customers, as of December 31, 2020 and 2019:

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2020	$	279	$	(125)
Additions		—		(841)
Reduction for receivables recorded		(18)		—
Reduction for revenue recognized (excluding amortization)		—		10
Reduction for revenue recognized from previous years		—		48
Repayments of refund liabilities to charterer		—		17
Balance December 31, 2020	$	261	$	(891)

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2019	$	—	$	(1,834)
Additions		279		(65)
Reduction for receivables recorded		—		89
Reduction for revenue recognized from previous years		—		497
Repayments of refund liabilities to charterer		—		1,188
Balance December 31, 2019	$	279	$	(125)

Contract assets are reported in the consolidated balance sheet as a component of prepaid expenses and other receivables. Current and non-current contract liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables and other long-term liabilities, respectively. Refund liabilities are reported in the consolidated balance sheet as a component of accrued liabilities and other payables.

The service-related contract asset reflected in the balance sheet relates to accrued revenue for reimbursable costs from charterers.

Refund liabilities to charterers include invoiced revenue to be refunded to charterers for estimated reimbursable costs that exceeded the actual cost incurred and for non-compliance with performance warranties in the time charter contracts that result in reduction of hire, liquidated damages or other performance related payments.

During the year ended December 31, 2019 the major changes in the refund liability to charterers related to the settlement of a 2018 performance claim of $1,101 and the recognition of $497 of revenue related to conclusion of an audit by a charterer related to 2018 reimbursable expenses.

F-31

Minimum contractual future revenues:

As of December 31, 2020, the minimum contractual future revenues to be received under the time charters for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace during the next five years and thereafter are as follows:

(in thousands of U.S. dollars)	Service related		Lease related		Total
2021	$	32,369		90,441	$	122,810
2022		32,369		90,441		122,810
2023		32,369		90,441		122,810
2024		32,369		90,441		122,810
2025		27,091		77,717		104,808
Thereafter		96,683		286,467		383,150
Total - undiscounted	$	253,250		725,948	$	979,198
Operating lease			$	321,724
Financing lease				404,224
Discounting effect				(172,499)
Financing lease receivable			$	231,725

The long-term time charter for the PGN FSRU Lampung with PGN LNG has an initial term of 20 years from the acceptance date of October 30, 2014 and the contract expires in 2034. The time charter hire payments began July 21, 2014 when the project was ready to begin commissioning. The lease element of the time charter is accounted for as a financing lease. The minimum contractual future revenues in the table above include the fixed payments for the lease and services elements for the initial term but exclude the variable fees from the charterer for vessel operating expenses and reimbursement of tax expenses. The charterer has an option to purchase the PGN FSRU Lampung, which can be exercised after the third anniversary of the commencement of the charter until the twentieth anniversary, at stated prices in the time charter. The minimum contractual future revenues do not include the unexercised purchase option price. Should the purchase option be exercised in the short to medium term, the contractual price would exceed the net investment in financing lease, but the future hire payments would cease. The time charter also provides options for the charterer to extend the lease term for two five-year periods. Unexercised option periods are excluded from the minimum contractual future revenues.

The long-term time charter for the Höegh Gallant had an initial term of five years from April 2015 and the contract expired in 2020. On February 27, 2020, the Partnership exercised its right to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration or termination of the initial five-year charter until July 2025 at a rate equal to 90% of the rate payable pursuant to the current charter plus any incremental taxes or operating expenses as a result of the new charter. On April 30, 2020, the Partnership entered into a Subsequent Charter with Höegh LNG for the Höegh Gallant. The Subsequent Charter commenced on May 1, 2020 and expires on July 31, 2025. The lease element of the time charter is accounted for as an operating lease. The minimum contractual future revenues in the table above include the fixed payments for the lease element and the services element which also covers the vessel operating expenses and taxes.

The long-term time charter for the Höegh Grace has an initial term of 20 years and the contract expires in 2036. The minimum contractual future revenues in the table above include the fixed payments for the lease element and services element but exclude the variable fees from the charterer for vessel operating expenses and reimbursement of certain taxes. The non-cancellable charter period is 10 years. The initial term of the lease is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if the charterer waives its right to terminate in year 10 within a certain deadline, the Partnership will not be able to exercise its right to terminate in year 10. The charterer has an option to purchase the Höegh Grace at a price specified in the Höegh Grace charter in year 15 and year 20 of such charter. The minimum contractual future revenues do not include the unexercised purchase option price. Only the non-cancellable lease period is included the minimum contractual future revenues.

F-32

Net investment in financing lease:

The lease element of time charter hire for the PGN FSRU Lampung is recognized over the lease term using the effective interest rate method and is included in time charter revenues. The financing lease is reflected on the consolidated balance sheets as net investment in financing lease, a receivable, as follows:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Minimum lease payments	$	589,074	$	589,074
Unguaranteed residual value		146,000		146,000
Unearned income		(440,345)		(440,345)
Initial direct cost, net		3,095		3,095
Net investment in financing lease at origination		297,824		297,824
Principal repayment and amortization		(23,471)		(18,920)
Allowance for credit loss		(96)		—
Net investment in financing lease at period end		274,257		278,904
Less: Current portion		(4,969)		(4,551)
Long term net investment in financing lease	$	269,288	$	274,353
Net investment in financing lease consists of:
Financing lease receivable	$	231,725	$	240,000
Unguaranteed residual value		42,532		38,904
Net investment in financing lease at period end	$	274,257	$	278,904

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There was no impairment loss, or allowance for doubtful accounts, for the year ended December 31, 2019.

5.   Financial income (expense), net

The components of financial income (expense), net are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Interest income	$	605	947	$	725
Interest expense:
Interest expense		(22,003)	(24,950)		(26,077)
Commitment fees		(138)	(381)		(37)
Amortization of debt issuance cost and fair value of debt assumed		(2,289)	(2,361)		(700)
Total interest expense		(24,430)	(27,692)		(26,814)
Gain (loss) on debt extinguishment		—	1,030		—
Gain (loss) on derivative instruments		—	—		4,681
Other items, net:
Foreign exchange gain (loss)		444	(396)		(193)
Bank charges, fees and other		(276)	(297)		(143)
Withholding tax on interest expense and other		(2,400)	(2,882)		(2,571)
Total other items, net		(2,232)	(3,575)		(2,907)
Total financial income (expense), net	$	(26,057)	(29,290)	$	(24,315)

F-33

Interest income related to cash balances and interest accrued on the advances to the joint ventures for each of the years ended December 31, 2020, 2019 and 2018. As of January 1, 2019, interest expense includes reclassifications from accumulated other comprehensive income and amortization of the components excluded from hedge effectiveness related to derivatives due to the adoption of the revised guidance for derivatives and hedging. The entire change in fair value of the cash flow hedge included in the assessment of hedge effectiveness is included in other comprehensive income with the result that the hedge ineffectiveness is no longer recognized in earnings. Refer to note 2. For the year ended December 31, 2018, gain (loss) on derivatives included the gain or loss on hedge ineffectiveness as well as amortization related to derivatives. Refer to note 16 for additional information on the types of gains and losses on derivatives included in interest expense for the years ended December 31, 2020 and 2019. Interest expense also includes interest related to the revolving credit facility from Höegh LNG, the $385 million facility, the Lampung facility and the Gallant/Grace facility until January 31, 2019. The gain on debt extinguishment relates to the refinancing of the Gallant/Grace facility with the $385 million facility. When the entities owning the Höegh Gallant and the Höegh Grace were acquired, a premium on the debt under the Gallant facility and the Grace facility was recognized. The unamortized balance was recorded as a gain when the debt was extinguished on January 31, 2019. Refer to notes 12, 14 and 15.

6.   Income tax

The components of income tax expense recognized in the consolidated statements of income are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Current tax (benefit) expense	$	3,832	4,126	$	4,759
Deferred tax (benefit) expense for
Change in temporary differences		1,335	3,341		3,290
Tax loss and tax credit carried forward		393	(196)		247
Change in valuation allowance		4	4		9
Total deferred tax (benefit) expense		1,732	3,149		3,546
Total income tax (benefit) expense	$	5,564	7,275	$	8,305

Deferred tax (benefit) expense recognized in the consolidated statements of comprehensive income as a component of other comprehensive income (“OCI”) are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Cash flow hedge derivative instruments	$	262	389	$	299
Deferred tax (benefit) expense recognized in OCI	$	262	389	$	299

F-34

The reconciliation of the income before tax at the statutory rate in the Marshall Islands to the actual income tax expense for each year is as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Income before tax	$	68,709	60,016	$	85,927
At applicable statutory tax rate
Amount computed at corporate tax of 0%		—	—		—
Foreign tax rate differences		4,972	5,425		7,513
Permanent differences:
Amended tax return: reinstatement of tax loss carryforward		—	—		—
Tax audit or amended tax return: change in uncertain tax position		385	558		(41)
Non-deductible interest expense		571	1,477		875
Non-deductible withholding tax		625	717		838
Non-deductible loss on derivatives		(114)	120		—
Tax exemptions		(13)	(13)		(36)
Non-deductible other financial items		(106)	194		116
Other non-deductible costs		(18)	45		63
Tax credits		(742)	(1,252)		(1,032)
Adjustment for valuation allowance		4	4		9
Tax expense (benefit) for year	$	5,564	7,275	$	8,305

Deferred income tax assets (liabilities) are summarized as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Deferred tax assets:
Accrued liabilities and other payables	$	124	$	235
Derivative instruments		422		565
Other equipment		8		9
Tax credits carried forward		1,421		1,818
Tax loss carryforward		32		57
Valuation allowance		(32)		(57)
Deferred tax liabilities:
Accrued interest income		(4,575)		(4,123)
Accrued liabilities and other payables		(400)		(385)
Financing lease		(11,328)		(10,451)
Deferred tax assets (liabilities), net	$	(14,328)	$	(12,332)

The Partnership is not subject to Marshall Islands corporate income taxes. The Partnership's subsidiaries incorporated in Singapore, Indonesia, Cyprus, and the UK are subject to tax on their income, and the Partnership's Columbian subsidiary is subject to tax on certain Colombian source income. For the years ended December 31, 2020, 2019 and 2018, the income tax expense principally related to subsidiaries in Indonesia, Singapore and Colombia. The Singapore subsidiary’s taxable income mainly arises from internal interest income. The charterer in Colombia pays certain taxes directly to the Colombian tax authorities on behalf of the Partnership’s subsidiaries that own and operate the Höegh Grace. The tax payments are a mechanism for advance collection of part of the income taxes for the Colombian subsidiary and a final income tax on Colombian source income for the non-Colombian subsidiary. The Partnership concluded these third-party payments to the tax authorities represent income taxes that must be accounted for under the guidance for income taxes. The amount of non-cash income tax expense was $867, $867 and $852 for the years ended December 31, 2020, 2019 and 2018.

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For the year ended December 31, 2017, income tax benefits were recorded of $1,486 and $2,228 for the reinstatement of the tax loss carryforward and the reversal of an uncertain tax position, respectively, due to the amendment of the 2016 tax return of the Indonesian subsidiary. The amendment was a result of a reevaluation of the application of the infrastructure industry exemption to regulations introduced in 2016 placing limitations on interest expense deductions. The infrastructure exemption was also applied by the Indonesian subsidiary for the reported income tax expense for the years ended December 31, 2020, 2019 and 2018.

In December of 2018, the Indonesian tax authorities concluded an audit of corporate income tax filings for the Indonesian subsidiary for the years ended December 31, 2013 and 2014. The outcome of the audit reduced the historical tax loss carryforward, mainly due to disallowed expenses, resulting in a settlement of $885 with respect to the unrecognized tax benefits originating in 2013. For the year ended December 31, 2018, tax benefits of $434 were recorded reflecting a reduction to the uncertain tax position originating in 2013 based on the audit’s conclusion. In addition, there was an increase to the uncertain tax position of $418 for a tax position taken in the 2018 tax return which was not more-likely-than-not to be sustained.

For the years ended December 31, 2020 and 2019, there was an increase to the uncertain tax position of $385 and $558, respectively, for a tax position to be taken in the 2020 and 2019 tax return which is not more-likely-than-not to be sustained. As of December 31, 2020 and 2019, the unrecognized tax benefits were $2,668 and $2,283, respectively.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. Changes in the unrecognized tax benefits is summarized below:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Unrecognized tax benefits as of January 1,	$	(2,283)	(1,725)	$	(2,626)
Decrease related to prior year tax positions		—	—		434
Increase related to current year tax positions		(385)	(558)		(418)
Settlements		—	—		885
Unrecognized tax benefits as of December 31,	$	(2,668)	(2,283)	$	(1,725)

Tax loss carryforwards of $256 expire between 2021 and 2025. Tax credits carried forward of $430 and $991 expire in 2021 and 2022, respectively. The tax returns of Singapore and Indonesia are subject to examination for four years and five years, respectively, from the year of filing. For Colombia, tax returns are subject to examination for three years from the due date of the return. The tax returns from the years 2016 and subsequent years remain subject to review for Indonesia and Singapore. For Colombia, tax returns from the years 2017 and subsequent years remain subject to review. Refer to note 17.

7.   Prepaid expenses and other receivables

The components of prepaid expenses and other receivables are as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Prepaid expenses	$	2,140	$	752
Other receivables		1,743		1,782
Total other prepaid expenses and other receivables	$	3,883	$	2,534

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8.   Investments in joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accumulated earnings of joint ventures	$	9,690	$	3,270

The Partnership has a 50% interest in each of SRV Joint Gas Ltd. (owner of the Neptune) and SRV Joint Gas Two Ltd. (owner of the Cape Ann). The following table presents the summarized financial information for 100% of the combined joint ventures on an aggregated basis.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020			2019		2018
Time charter revenues	$	78,687		77,051		$	79,654
Other income		8,457		7,814			6,684
Total revenues		87,144		84,865			86,338
Operating expenses		(18,904)		(18,088)			(21,864)
Depreciation and amortization		(20,546)		(20,524)			(20,065)
Impairment of long-lived assets (1)		—		(149)			—
Operating income		47,694		46,104			44,409
Unrealized gain (loss) on derivative instruments		(12,146)		(10,418)			16,992
Other financial expense, net		(23,324)		(24,144)			(26,140)
Net income (loss)	$	12,224		11,542		$	35,261
Share of joint ventures owned		50	%	50	%		50	%
Share of joint ventures net income (loss) before eliminations		6,112		5,771			17,631
Eliminations		308		307			307
Equity in earnings (losses) of joint ventures	$	6,420		6,078		$	17,938

(1) At the completion of the class renewal survey of the Neptune, certain equipment was identified that was impaired.

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	As of
	December 31,
(in thousands of U.S. dollars)	2020			2019
Cash and cash equivalents	$	13,455		$	17,897
Restricted cash		21,264			9,250
Other current assets		178			973
Total current assets		34,897			28,120
Restricted cash		14,656			34,650
Vessels, net of accumulated depreciation		499,318			521,060
Total long-term assets		513,974			555,710
Current portion of long-term debt		199,030			28,297
Amounts and loans due to owners and affiliates		7,278			629
Derivative instruments		14,687			13,089
Refund liabilities (1)		1,040			26,691
Other current liabilities		8,811			10,327
Total current liabilities		230,846			79,033
Long-term debt		176,385			375,091
Loans due to owners and affiliates		1,737			7,663
Derivative instruments		69,618			59,070
Other long-term liabilities		36,040			40,952
Total long-term liabilities		283,780			482,776
Net assets (liabilities)	$	34,245		$	22,021
Share of joint ventures owned		50	%		50	%
Share of joint ventures net assets (liabilities) before eliminations		17,123			11,011
Eliminations		(7,433)			(7,741)
Accumulated earnings (losses) of joint ventures	$	9,690		$	3,270

(1) Refund liabilities include the liability for the boil-off claim and other refundable amounts due to the charterer.

9.   Advances to joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Current portion of advances to joint ventures	$	3,284	$	—
Long-term advances to joint ventures		869		3,831
Advances/shareholder loans to joint ventures	$	4,153	$	3,831

The Partnership had advances of $3.3 million and $3.0 million due from SRV Joint Gas Ltd. as of December 31, 2020 and 2019, respectively. The Partnership had advances of $0.9 million and $0.8 million due from SRV Joint Gas Two Ltd. as of December 31, 2020 and 2019, respectively.

The advances consist of shareholder loans where the principal amounts, including accrued interest, are repaid based on available cash after servicing of long-term bank debt. The shareholder loans are due not later than the 12th anniversary of delivery date of each FSRU. The Neptune and the Cape Ann were delivered on November 30, 2009 and June 1, 2010, respectively. The shareholder loans are subordinated to long-term bank debt and the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt. Under terms of the shareholder loan agreements, the repayments shall be prioritized over any dividend payment to the owners of the joint ventures. The shareholder loans bear interest at a fixed rate of 8.0% per year. The other joint venture partners have, on a combined basis, an equal amount of shareholder loans outstanding at the same terms to each of the joint ventures.

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The shareholder loans financed part of the construction of the vessels and operating expenses until the delivery and commencement of the operations of the Neptune and the Cape Ann. In 2011, the joint ventures began repaying principal and a portion of the interest expense based on available cash after servicing of the external debt. The quarterly payments have included a payment of interest for the first month of the quarter and a repayment of principal. Interest was accrued for the last two months of the quarter for repayment at the end of the loans after the original principal was fully repaid. The joint ventures repaid the original principal of all shareholder loans during 2016. As of December 31, 2020 and 2019, the outstanding balances are accrued interest on the shareholder loans.

As of September 30, 2017, the joint ventures suspended payments on the shareholder loans pending the outcome of the boil-off claim. As of April 1, 2020, the joint ventures reached an agreement on the boil-off claim requiring settlement during 2020. The outstanding balance on the shareholder loans was classified as long-term as of December 31, 2019. Based on the final settlement of the boil-off claim made in December 2020 in addition to meeting certain conditions for making distributions as described below, the outstanding balance on the shareholder loan due from SRV Joint Gas Ltd. has been classified as current as of December 31, 2020 while the outstanding balance on the shareholder loan due from SRV Joint Gas Two Ltd. has been classified as non-current as of December 31, 2020. Refer to note 17 under “Joint ventures boil-off settlement.” The advances, including accrued interest, can be repaid based on available cash after servicing of long-term bank debt. There are no financial covenants in the joint ventures’ bank debt facilities, but certain other covenants and restrictions apply. Certain conditions apply to making distributions for the shareholder loans or dividends, including meeting a 1.20 historical and projected debt service coverage ratio. As of December 31, 2020, both the 1.20 historical and projected debt service coverage ratios were met by SRV Joint Gas Ltd. As a result, SRV Joint Gas Ltd. qualifies to make payments on the shareholder loans or other distributions. As of December 31, 2020, SRV Joint Gas Two Ltd. did not meet the 1.20 historical debt service coverage ratio but did meet the projected debt service coverage ratio. As a result, no payments on the shareholder loans or other distributions can be made by SRV Joint Gas Two Ltd. until the debt service coverage ratio is met in future periods.

10.   Vessels and other equipment

			Dry-
(in thousands of U.S. dollars)	Vessel		docking	Total
Historical cost December 31, 2018	$	706,715	6,667	$	713,382
Additions		183	3,107		3,290
Historical cost December 31, 2019		706,898	9,774		716,672
Depreciation for the year		(19,393)	(1,777)		(21,170)
Accumulated depreciation December 31, 2019		(70,264)	(5,977)		(76,241)
Vessels, net December 31, 2019		636,634	3,797		640,431
Historical cost December 31, 2019		706,898	9,774		716,672
Additions		8	—		8
Historical cost December 31, 2020		706,906	9,774		716,680
Depreciation for the year		(19,398)	(1,421)		(20,819)
Accumulated depreciation December 31, 2020		(89,662)	(7,398)		(97,060)
Vessels, net December 31, 2020	$	617,244	2,376	$	619,620

As of December 31, 2020, other equipment consists principally of office equipment, computers and a right-of-use-asset. As of December 31, 2019, other equipment consists principally of warehouse, office equipment, computers and a right-of-use asset. Other equipment of $308 and $845 is recorded net of accumulated depreciation of $260 and $679 in the consolidated balance sheet as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, the right-of-use assets and lease liability for operating leases was $61 and $91, respectively. Depreciation expense for other equipment was $118, $307 and $159 for the years ended December 31, 2020, 2019 and 2018, respectively.

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11.   Intangibles and goodwill

			Option
	Above		for time
	market time		charter	Total
(in thousands of U.S. dollars)	charter		extension	Intangibles	Goodwill	Total
Historical cost December 31, 2018	$	22,760	8,000	30,760	251	$	31,011
Amortization for the year		(3,631)	—	(3,631)	—		(3,631)
Accumulated amortization, December 31, 2019		(13,903)	—	(13,903)	—		(13,903)
Intangibles and goodwill, December 31, 2019		8,857	8,000	16,857	251		17,108
Historical cost December 31, 2019		22,760	8,000	30,760	251		31,011
Additions		—	—	—	—		—
Historical cost December 31, 2020		22,760	8,000	30,760	251		31,011
Amortization for the year		(2,030)	(1,022)	(3,052)	—		(3,052)
Accumulated amortization, December 31, 2020		(15,933)	(1,022)	(16,955)	—		(16,955)
Intangibles and goodwill, December 31, 2020	$	6,827	6,978	13,805	251	$	14,056

The following table presents estimated future amortization expense for the intangibles:

(in thousands of U.S. dollars)	Total
2021	$	2,755
2022		2,755
2023		2,755
2024		2,762
2025		2,116
2026 and thereafter	$	662

12.   Long-term debt

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Lampung facility:
Export credit tranche	$	79,324	$	94,210
FSRU tranche		18,635		22,812
$385 million facility:
Commercial tranche		230,705		249,635
Export credit tranche		44,500		51,167
Revolving credit tranche		48,300		48,300
Outstanding principal		421,464		466,124
Lampung facility unamortized debt issuance cost		(2,999)		(4,309)
$385 million facility unamortized debt issuance costs		(3,876)		(4,854)
Total debt		414,589		456,961
Less: Current portion of long-term debt		(59,119)		(44,660)
Long-term debt	$	355,470	$	412,301

Lampung facility

In September 2013, PT Hoegh LNG Lampung (the “Borrower”) entered into a secured $299 million term loan facility (the “Lampung facility”) with a syndicate of banks and an export credit agency for the purpose of financing a portion of the construction of the PGN FSRU Lampung and the Mooring. Höegh LNG is the guarantor for the Lampung facility. The facility was drawn in installments as construction was completed. The term loan facility includes two commercial tranches, the FSRU tranche and the Mooring tranche, and the export credit tranche. The interest rates vary by tranche. The full principal amount on the Mooring tranche and accrued interest was repaid in 2014.

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The FSRU tranche has an interest rate of LIBOR plus a margin of 3.4%. The interest rate for the export credit tranche is LIBOR plus a margin of 2.3%. The FSRU tranche is repayable quarterly over 7 years with a final balloon payment of $15.5 million due on October 30, 2021. The export credit tranche is repayable in quarterly installments over 12 years assuming the balloon payment of the FSRU tranche is refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the outstanding balance upon maturity of the FSRU tranche. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 4.7% and 6.2% respectively.

The primary financial covenants under the Lampung facility are as follows:

● Borrower must maintain a minimum debt service coverage ratio of 1.10 to 1.00 for the preceding nine-month period tested on each quarterly repayment date;

● Guarantor’s book equity must be greater than the higher of (i) $200 million and (ii) 25% of total assets; and

● Guarantor’s free liquid assets (cash and cash equivalents or available draws on credit facilities) must be greater than $20 million.

As of December 31, 2020 and 2019, the Borrower and the guarantor were in compliance with the financial covenants.

Höegh LNG, as guarantor, has issued the following guarantees related to the Lampung facility that remain in effect as of December 31, 2020: (a) an unconditional and irrevocable on-demand guarantee for the repayment of the balloon repayment installment of the FSRU tranche callable only at final maturity of the FSRU tranche; (b) an unconditional and irrevocable on-demand guarantee for all amounts due in respect of the export credit agent in the event that the export credit agent exercises its prepayment right for the export credit tranche if the FSRU tranche is not refinanced; and (c) an undertaking that, if the time charter is terminated for an event of vessel force majeure, under certain conditions, a guarantee will be provided for the outstanding debt, less insurance proceeds for vessel force majeure. In addition, all project agreements and guarantees are assigned to the bank syndicate and the export credit agent, all cash accounts and the shares in PT Hoegh LNG Lampung and Hoegh LNG Lampung Pte. Ltd. are pledged in favor of the bank syndicate and the export credit agent.

The Lampung facility requires cash reserves that are held for specifically designated uses, including working capital, operations and maintenance and debt service reserves. Distributions are subject to “waterfall” provisions that allocate revenues to specified priorities of use (such as operating expenses, scheduled debt service, targeted debt service reserves and any other reserves) with the remaining cash being distributable only on certain dates and subject to satisfaction of certain conditions, including meeting a 1.20 historical debt service coverage ratio, no default or event of default then continuing or resulting from such distribution and the guarantor not being in breach of the financial covenants applicable to it. The Lampung facility limits, among other things, the ability of the Borrower to change its business, sell or grant liens on its property including the PGN FSRU Lampung, incur additional indebtedness or guarantee other indebtedness, make investments or acquisitions, enter into intercompany transactions and make distributions.

Gallant/Grace facility

The Gallant/Grace facility included two borrowers, the Partnership’s subsidiaries owning the Höegh Gallant and the Höegh Grace. The Gallant/Grace facility included two commercial tranches and the export credit tranche related to the Höegh Gallant (the “Gallant facility”) and a commercial tranche and the export credit tranche related to the Höegh Grace (the “Grace facility”). All of the tranches under the Gallant/Grace facility were cross-defaulted, cross-collateralized and cross-guaranteed. The obligations of the Borrowers were joint and several. The interest rates varied by tranche. Höegh LNG, Höegh LNG Colombia Holding Ltd., Höegh LNG FSRU III Ltd. and the Partnership were guarantors for the facility.

On January 31, 2019, the outstanding balance and the accrued interest of $303.2 million and $1.6 million, respectively, on the Gallant/Grace facility was repaid from the proceeds of the $385 million facility. The unamortized balance of the fair value of debt assumed, or premium, was recorded as a gain when the debt was extinguished. Refer to note 5. The interest rate swaps related to the Gallant/Grace facility were terminated on the same date. Refer to note 16.

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$385 million facility

On January 29, 2019, the Partnership entered into a loan agreement with a syndicate of banks to refinance the outstanding balances of the Gallant/Grace facility. Höegh LNG Partners LP is the borrower (the “Borrower”) for the senior secured term loan and revolving credit facility (the “$385 million facility”). The aggregate borrowing capacity is $320 million on the senior secured term loan and $63 million on the revolving credit tranche. Hoegh LNG Cyprus Limited, which owns the Höegh Gallant, and Höegh LNG FSRU IV Ltd., the owner of the Höegh Grace (collectively, the "Vessel Owners"), and Höegh LNG Colombia S.A.S., are guarantors for the facility (collectively, the "guarantors"). The facility is secured by, among other things, a first priority mortgage of the Höegh Gallant and the Höegh Grace, an assignment of the Hoegh LNG Cyprus Limited’s, Höegh LNG FSRU IV Ltd.’s, Höegh LNG Colombia S.A.S.’s rights under their respective time charters and earnings and a pledge of the Borrower’s and Guarantor’s cash accounts. The Partnership and its subsidiaries have provided a pledge of shares in Hoegh LNG Cyprus Limited, Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S

The senior secured term loan related to the $385 million facility includes a commercial tranche and the export credit tranche. Each tranche is divided into two term loans for each of the Höegh Gallant and the Höegh Grace.

On January 31, 2019, the Partnership drew $320 million under the commercial and the export credit tranches on the $385 million facility to settle $303.2 million and $1.6 million of the outstanding balance and accrued interest, respectively, on the Gallant/Grace facility and used proceeds of $5.5 million to pay arrangement fees due under the $385 million facility. The remaining proceeds of $9.6 million were used for general partnership purposes. On August 12, 2019, the Partnership drew $48.3 million under the revolving credit tranche of the $385 million facility, of which $34.0 million was used to repay part of the outstanding balance on the $85 million revolving credit facility due to Höegh LNG.

The commercial tranche and the revolving credit tranche related to the $385 million facility have an interest rate of LIBOR plus a margin of 2.30%. The commitment fee on the undrawn portion of the revolving credit tranche is approximately 1.6%. The interest rate for the export credit tranche related to the $385 million facility have fixed interest rates and guarantee commissions of 3.98% and 3.88% on the term loans related to the Höegh Gallant and the Höegh Grace, respectively. The commercial tranche is repayable quarterly with a final balloon payment of $136.1 million due in January 2026. The term loans for export credit tranche related to the Höegh Gallant and the Höegh Grace are repayable in quarterly installments with the final payments in October 2026 and April 2028, respectively, assuming the balloon payments of the commercial tranches are refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the total outstanding balance on both the terms loans of the export credit tranche of $9.5 million upon maturity of the commercial tranche. Any outstanding balance on the revolving credit facility is due in full in January 2026. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 3.4% and 4.7%, respectively.

The primary financial covenants under the $385 million facility are as follows:

●     The Partnership must maintain

o     Consolidated book equity (excluding hedge reserves and mark to market value of derivatives) equal to the greater of

● 25% of total assets, and

● $150 million

o     Consolidated working capital (current assets, excluding intercompany receivables and marked-to-market value of any financial derivative, less current liabilities, excluding intercompany payables, marked-to-market value of any financial derivative and the current portion of long-term debt) shall at all times be greater than zero

o     Minimum liquidity (cash and cash equivalents and available draws under a bank credit facility for a term of more than 12 months) equal to the greater of

● $15 million, and

● $2.5 million multiplied by the number of vessels owned or leased by the Partnership (prorated for partial ownership), subject to a cap of $20 million

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o     A ratio of combined EBITDA for the Vessel Owners to debt service (principal repayments, guarantee commission, commitment fees and interest expense) for the preceding twelve months of a minimum of 115%

As of December 31, 2020 and 2019, the Borrower and the Vessel Owners were in compliance with the financial covenants.

In addition, a security maintenance ratio based on the aggregate market value of the Höegh Gallant, the Höegh Grace and any additional security must be at least 125% of the aggregate outstanding loan balance.

If the security maintenance ratio is not maintained, the relevant Borrower has 30 days to provide more security or to repay part of the loan to be in compliance with the ratio no later than 30 days after notice from the lenders.

Under the $385 million facility, cash accounts are freely available for the use of the Borrower and the guarantors, unless there is an event of default. Events of default include, among other things, change of control of Höegh LNG or the Partnership due to the failure of Höegh LNG to own at least 25% of the Partnership’s common units. Cash can be distributed as dividends or to service loans of owners and affiliates provided that after the distribution the Borrower and the guarantors would remain in compliance with the financial covenants. The $385 million facility limits, among other things, the ability of the Borrower and the guarantors to change their business, grant liens on the Höegh Gallant or the Höegh Grace, incur additional indebtedness that is not at pari passu with the $385 million facility, enter into intercompany debt that is not subordinated to the $385 million facility and for the Vessel Owners to make investments or acquisitions.

The principal on long-term debt outstanding as of December 31, 2020 was repayable as follows:

(in thousands of U.S. dollars)	Total
2021	$	123,557
2022		25,597
2023		25,597
2024		25,597
2025		25,597
2026 and thereafter		195,519
Total	$	421,464

The table includes the maturity of the FSRU tranche of the Lampung facility in 2021 and assumes the exercise of the prepayment right for the export credit tranche of the Lampung facility in the same period.

13.   Accrued liabilities and other payables

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accrued operating and administrative expenses	$	3,042	$	3,314
Accrued property tax		—		3,033
Accrued interest		2,641		2,850
Current tax payable		469		818
Refund liabilities (note 4)		891		125
Lease liability (note 2 and note 10)		39		75
Other accruals and payables		150		949
Total accrued liabilities and other payables	$	7,232	$	11,164

Refer to note 4 for additional information on the refund liability to charterers. Refer to notes 2 and 10 for additional information on the lease liability.

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14.   Related party transactions

Income (expenses) from related parties

As described in Related party agreements below, subsidiaries of Höegh LNG have provided administrative services to the Partnership and ship management and/or technical support services for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace, as well as leasing the Höegh Gallant.

Related party amounts included in the consolidated statements of income for the years ended December 31, 2020, 2019 and 2018 or included in the consolidated balance sheets as of December 31, 2020 and 2019 are as follows:

(in thousands of U.S. dollars)	2020		2019	2018
Revenues
Time charter revenue Höegh Gallant (1)	$	45,274	47,173	$	47,108
Operating expenses
Vessel operating expenses (2)		(21,328)	(24,523)		(21,520)
Hours, travel expense and overhead (3) and Board of Directors’ fees (4)		(4,353)	(4,072)		(3,671)
Financial (income) expense
Interest income from joint ventures (5)		321	295		273
Interest expense and commitment fees to Höegh LNG (6)		(64)	(1,882)		(2,938)
Total	$	19,850	16,991	$	19,252

	As of
Balance sheet	December 31,
(in thousands of U.S. dollars)	2020		2019
Equity
Contribution from Höegh LNG (7)	$	11,850	$	—
Repayment of indemnification received from Höegh LNG (8)		—		(64)
Issuance of units for Board of Directors’ fees (4)		181		194
Other and contribution from owner (9)		109		485
Total	$	12,140	$	615

1) Time charter revenue Höegh Gallant: Subsidiaries of Höegh LNG, have leased the Höegh Gallant.

2) Vessel operating expenses: Subsidiaries of Höegh LNG provide ship management of vessels, including crews and the provision of all other services and supplies.

3) Hours, travel expenses and overhead: Subsidiaries of Höegh LNG provide management, accounting, bookkeeping and administrative support under administrative service agreements. These services are charges based upon the actual hours incurred for each individual as registered in the time-write system based on a rate which includes a provision for overhead and any associated travel expenses.

4) Board of Directors’ fees: Total Board of Directors’ fees were $571, $496 and $501 for the years ended December 31, 2020, 2019 and 2018, respectively. Part of the compensation is awarded as common units of the Partnership. Effective September 4, 2020, a total of 15,528 common units were awarded to non-employee directors as compensation of $162 for part of directors’ fees for 2020 under the Höegh LNG Partners LP Long Term Incentive Plan. Effective June 4, 2019 and June 6, 2018, a total of 11,180 and 11,050 common units, respectively, of the Partnership were awarded to non-employee directors as compensation of $194 and $200, respectively, for part of directors’ fees for 2019 and 2018. The awards were recorded as administrative expense and as an issuance of common units. Common units are recorded when issued.

5) Interest income from joint ventures: The Partnership and its joint venture partners have provided subordinated financing to the joint ventures as shareholder loans. Interest income for the Partnership’s shareholder loans to the joint ventures is recorded as interest income.

6) Interest expense and commitment fees to Höegh LNG and affiliates: Höegh LNG and its affiliates provided an $85 million revolving credit facility for general partnership purposes. The Partnership incurred a commitment fee on the undrawn balance until January 29, 2018 and an interest expense on the drawn balance.

F-44

7) Non-cash contribution from/distribution to Höegh LNG: As described under “Indemnification” below, on April 8, and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint-ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. These non-cash settlements, totaling $11.9 million, were recorded as an increase in equity.

8) Cash contribution from/distribution to Höegh LNG: As described under “Indemnifications” below, Höegh LNG made indemnification payments to the Partnership or received refunds of indemnification from the Partnership which were recorded as contributions or distributions to equity.

9) Other and contribution from owner: Höegh LNG granted share-based incentives to certain key employees whose services benefit the Partnership. Related expenses are recorded as administrative expenses and as a contribution from owner since the Partnership is not invoiced for this employee benefit. Effective March 26, 2020, March 21, 2019 and September 14, 2018, the Partnership granted or extended the terms for 8,100, 10,917 and 28,018 phantom units, respectively, to the Chief Executive Officer and Chief Financial Officer of the Partnership. Related expenses are recorded over the vesting period as an administrative expense and as increase in equity. On August 6, 2020, the Partnership announced that the Partnership’s Chief Executive Officer and Chief Financial Officer resigned, which resulted in 15,378 of the phantom units not vesting, resulting in a reduction in administration expense and equity for the forfeited units. The remaining 4,861 unvested phantom units will vest in 2021.

Dividends to Höegh LNG: The Partnership has declared and paid quarterly distributions totaling $28.5 million, $28.4 million and $28.2 million to Höegh LNG for each of the years ended December 31, 2020, 2019 and 2018, respectively.

Receivables and payables from related parties

Amounts due from affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due from affiliates	$	3,639	$	4,296

The amount due from affiliates relates to a receivable for time charter hire from subsidiaries of Höegh LNG for the Höegh Gallant time charter and prefunding for intercompany services. The time charter hire is due 18 days from the receipt of the invoice. Time charter hire is invoiced at the end of the month in arrears.

Amounts due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due to owners and affiliates	$	2,600	$	2,513

As of December 31, 2020 and 2019 amounts due to owners and affiliates principally relate to trade payables for services provided by subsidiaries of Höegh LNG.

Revolving credit facility due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Revolving credit facility due to owners and affiliates - non-current portion	$	18,465	$	8,792

F-45

In August 2014, upon the closing of the IPO, the Partnership entered into an $85 million revolving credit facility with Höegh LNG, to be used to fund acquisitions and working capital requirements of the Partnership. The credit facility is unsecured and was repayable on January 1, 2020. On May 28, 2019, the repayment date on the $85 million revolving credit facility was extended to January 1, 2023 and the terms amended for the interest rate to be LIBOR plus a margin of 1.4% in 2019, 3.0% in 2020 and 4.0% thereafter. On April 8, and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures’ boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the revolving credit facility. On April 24, 2020, August 7, 2020 and October 23, 2020, the Partnership drew $4.5 million, $6.6 million and $10.7 million, respectively, on the revolving credit facility. The outstanding revolving credit facility had a weighted average interest rate for the years ended December 31, 2020 and 2019 of 3.6% and 6.6%, respectively.

Related party agreements

In connection with the IPO the Partnership entered into several agreements including:

(i) An $85 million revolving credit facility with Höegh LNG, which was undrawn at the closing of the IPO;

(ii) An omnibus agreement with Höegh LNG, the general partner, and Höegh LNG Partners Operating LLC (the “operating company”) governing, among other things:

a. To what extent the Partnership and Höegh LNG may compete with each other;

b. The Partnership’s rights of first offer on certain FSRUs and LNG carriers operating under charters of five or more years; and

c. Höegh LNG’s provision of certain indemnities to the Partnership.

(iii) An administrative services agreement with Hoegh LNG Services Ltd., UK (“Höegh UK”), pursuant to which Höegh UK provided certain administrative services to the Partnership. This agreement expired during 2019; and

(iv) Höegh UK entered into administrative services agreements with Höegh LNG AS (“Höegh Norway”) and Leif Höegh (U.K.) Limited, pursuant to which Höegh Norway and Leif Höegh (U.K.) Limited provided Höegh UK certain administrative services. Additionally, the operating company entered into an administrative services agreement with Leif Höegh (U.K.) Limited to allow Leif Höegh (U.K.) Limited to provide services directly to the operating company. Each of these agreements expired, or were terminated by mutual agreement, during 2019.

Existing agreements remained in place following the IPO for provision of certain services to the Partnership’s vessel owning joint ventures or entity, of which the material agreements are as follows:

● The joint ventures are parties to ship management agreements with Höegh LNG Fleet Management AS (“Höegh LNG Management”) pursuant to which Höegh LNG Management provides the joint ventures with technical and maritime management and crewing of the Neptune and the Cape Ann, and Höegh Norway is a party to a sub-technical support agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides technical support services with respect to the PGN FSRU Lampung; and

● The joint ventures are parties to commercial and administration management agreements with Höegh Norway, and PT Hoegh LNG Lampung is a party to a technical information and services agreement with Höegh Norway.

F-46

Subsequent to the IPO, the Partnership has acquired vessel owning entities. Existing agreements remained in place following the acquisition for the time charter of the Höegh Gallant and receipt of certain services, of which the material agreements are as follows:

● Hoegh LNG Cyprus Limited acting through its Egyptian Branch had a lease and maintenance agreement (the “time charter”) with EgyptCo for the lease and maintenance of the Höegh Gallant and the provision of crew and certain ship management services for a combined daily hire rate. The time charter started in April 2015 and expired in April 2020;

● Hoegh LNG Cyprus Limited is party to a ship management agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides the technical management of the Höegh Gallant, and Hoegh LNG Maritime Management Pte. Ltd. (“Höegh Maritime Management”) is a party to a secondment agreement, as amended, with Hoegh LNG Cyprus Limited pursuant to which Höegh Maritime Management provides qualified crew for the Höegh Gallant; and

● Hoegh LNG Cyprus Limited is party to a management agreement with Höegh Norway, pursuant to which Höegh Norway provides administrative, commercial and technical management services, each as instructed from time to time by Hoegh LNG Cyprus Limited.

Existing agreements remained in place for the time charter of the Höegh Grace following the acquisition and receipt of certain services, of which the material agreements are as follows:

● a ship management agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides technical and maritime management services;

● a manning agreement with Höegh Fleet Services Philippines Inc. to recruit and engage crew for the vessel;

● a technical services agreement with Höegh Norway to provide technical services for the vessel;

● a management consulting agreement with Höegh Norway to provide support related to certain management activities;

● a crew recruitment consulting services agreement with Höegh Maritime Management to provide professional consulting services in connection with recruitment of crew and other employees;

● an agreement for provision of professional payment services with Höegh Maritime Management to provide services in connection with the payment of monthly salaries to the crew and employees working on the vessel; and

● a spare parts procurement and insurance services agreement with Höegh LNG Management to arrange for the supply of spare parts and the insurance coverage for the vessel.

In December 2019, the Partnership and the operating company entered into an administrative services agreement with Höegh Norway, pursuant to which Höegh Norway provides certain administrative services to the Partnership.

On April 30, 2020, the Partnership entered into a lease and maintenance agreement with a subsidiary of Höegh LNG for the time charter of the Höegh Gallant and the provision of crew and certain ship management services for use as either an FSRU or an LNG carrier for a combined daily hire rate. The terms of the agreement were approved by the Partnership’s board of directors and the conflicts committee. The Subsequent Charter commenced on May 1, 2020 and expires July 31, 2025.

F-47

Indemnifications

Environmental indemnifications:

Under the omnibus agreement, Höegh LNG agreed to indemnify the Partnership until August 12, 2019 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to the Partnership to the extent arising prior to the time they were contributed or sold to the Partnership. No indemnification claims were filed for environmental liabilities under the agreement prior to its expiration.

Other indemnifications:

Under the omnibus agreement Höegh LNG also agreed to indemnify the Partnership for losses:

1. related to certain defects in title to the assets contributed or sold to the Partnership and any failure to obtain, prior to the time they were contributed to the Partnership, certain consents and permits necessary to conduct the business, which liabilities arose within three years after the closing of the IPO;

2. related to certain tax liabilities attributable to the operation of the assets contributed or sold to the Partnership prior to the time they were contributed or sold;

3. in the event that the Partnership did not receive hire rate payments under the PGN FSRU Lampung time charter for the period commencing on August 12, 2014 through the earlier of (i) the date of acceptance of the PGN FSRU Lampung or (ii) the termination of such time charter. The Partnership was indemnified by Höegh LNG for the September and October 2014 invoices not paid by PGN LNG in 2014 (refer to note 17);

4. with respect to any obligation to pay liquidated damages to PGN LNG under the PGN FSRU Lampung time charter for failure to deliver the PGN FSRU Lampung by the scheduled delivery date set forth in the PGN FSRU Lampung time charter;

5. with respect to any non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project (including the construction of the Mooring) occurring prior to the date of acceptance of the PGN FSRU Lampung pursuant to the time charter; and

6. pursuant to a letter agreement dated August 12, 2015, Höegh LNG confirmed that the indemnification provisions of the omnibus agreement include indemnification for all non-budgeted, non-creditable Indonesian value added taxes and non-budgeted Indonesian withholding taxes, including any related impact on cash flow from PT Hoegh LNG Lampung and interest and penalties associated with any non-timely Indonesian tax filings related to the ownership or operation of the PGN FSRU Lampung and the Mooring whether incurred (i) prior to the closing date of the IPO, (ii) after the closing date of the IPO to the extent such taxes, interest, penalties or related impact on cash flows relate to periods of ownership or operation of the PGN FSRU Lampung and the Mooring and are not subject to prior indemnification payments or deemed reimbursable by the charterer under its audit of the taxes related to the PGN FSRU Lampung time charter for periods up to and including June 30, 2015, or (iii) after June 30, 2015 to the extent withholding taxes exceed the minimum amount of withholding tax due under Indonesian tax regulations due to lack of documentation or untimely withholding tax filings.

No indemnification claim was filed or received for the year ended December 31, 2020. For the years ended December 31, 2019 and 2018, the Partnership refunded to Höegh LNG approximately $0.1 million and $2.4 million, respectively, related to insurance proceeds received related to the warranty provision and costs for previous years determined to be reimbursable by the charterer. For the year ended December 31, 2018, the Partnership received indemnification payment from Höegh LNG for non-budgeted expenses (including warranty provisions, other non-budgeted expenses and replacement capital expenditure) of $0.9 million which was recorded as a contribution to equity. Indemnification payments received from Höegh LNG are subject to repayment to the extent the amounts are subsequently recovered from insurance or deemed reimbursable by the charterer. Refer to note 17.

F-48

Under the contribution, purchase and sale agreement entered into with respect to the purchase of the Höegh Gallant entities, Höegh LNG will indemnify the Partnership for:

1. losses from breach of warranty;

2. losses related to certain environmental and tax liabilities attributable to the operation of the Höegh Gallant prior to the closing date;

3. all capital gains tax or other export duty incurred in connection with the transfer of the Höegh Gallant outside of Höegh LNG Cyprus Limited’s permanent establishment in a Public Free Zone in Egypt;

4. any recurring non-budgeted costs owed to Höegh LNG Management with respect to payroll taxes;

5. any non-budgeted losses suffered or incurred in connection with the commencement of services under the time charter with EgyptCo or EgyptCo’s time charter with EGAS; and

6. liabilities under the Gallant/Grace facility not attributable to the Höegh Gallant.

No indemnification claims were filed or received for the years ended December 31, 2020 and 2019. For the year ended December 31, 2018, the Partnership received an indemnification payment from Höegh LNG for losses incurred in connection with the time charter with EgyptCo of $0.5 million which was recorded as a contribution to equity. Refer to note 17.

Under the contribution, purchase and sale agreements entered into with respect to the acquisitions of the 51% and 49% ownership interests in the Höegh Grace entities, Höegh LNG will indemnify the Partnership for:

1. losses from breach of warranty;

2. losses related to certain environmental liabilities, damages or repair costs and tax liabilities attributable to the operation of the Höegh Grace prior to the closing date;

3. any recurring non-budgeted costs owed to tax authorities with respect to payroll taxes, taxes related to social security payments, corporate income taxes (including income tax for equality and surcharge on income tax for equality), withholding tax, port associations, local Cartagena tax, and financial transaction tax, including any penalties associated with taxes to the extent not reimbursed by the charterer; and

4. any non-budgeted losses suffered or incurred in connection with commencement of services under the Höegh Grace charter with SPEC.

No indemnification claims were filed or received for the years ended December 31, 2020, 2019 and 2018. Refer to note 17.

On September 27, 2017, the Partnership entered into an indemnification agreement with Höegh LNG with respect to the boil-off claims under the Neptune and Cape Ann time charters, pursuant to which Höegh LNG will, among other things, indemnify the Partnership for its share of any losses and expenses related to or arising from the failure of either Neptune or Cape Ann to meet the performance standards related to the daily boil-off of LNG under their respective time charters (including any cash impact that may result from any settlement with respect to such claims) For the year ended December 31, 2018 the Partnership received indemnification payments of $0.3 million from Höegh LNG. For the year ended December 31, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint-ventures boil-off settlement payments to its charter by a reduction of $11.9 million on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. Indemnification payments and the non-cash settlements were recorded as contribution to equity and increases to equity respectively. Refer to note 17 to our consolidated financial statements.

F-49

15.   Financial Instruments

Fair value measurements

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Cash and cash equivalents and restricted cash – The fair value of the cash, cash equivalents, and restricted cash approximates its carrying amounts reported in the consolidated balance sheets.

Amounts due from (to) owners and affiliates – The fair value of the non-interest bearing receivables or payables approximates their carrying amounts reported in the consolidated balance sheets since the receivables or payables are to be settled consistent with trade receivables and payables.

Derivative instruments – The fair values of the interest rate swaps are estimated based on the present value of cash flows over the term of the instruments based on the relevant LIBOR interest rate curves, adjusted for the subsidiary’s credit worthiness and the credit worthiness of the counterparty to the derivative.

Advances (shareholder loans) to joint ventures – The fair values of the fixed rate subordinated shareholder loans are estimated using discounted cash flow analyses based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the joint ventures.

Lampung and $385 million facilities – The fair values of the variable rate debt are estimated based on the present value of cash flows over the term of the instruments based on the estimated currently available margins and LIBOR interest rates as of the balance sheet date for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

Revolving credit due to owners and affiliates – The fair value of the variable rate debt is estimated based on the present value of cash flows over the term of the instruments based on the estimated currently available margins and LIBOR interest rates as of the balance sheet date for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

The fair value estimates are categorized by a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value as follows:

Level 1: Observable inputs such as quoted prices in active markets;

Level 2: Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

F-50

The following table includes the estimated fair value and carrying value of those assets and liabilities that are measured at fair value on a recurring and non-recurring basis, as well as the estimated fair value of the financial instruments that are not accounted for at a fair value on a recurring basis. Trade payables and receivables for which the estimated fair values are equivalent to carrying values are not specified below.

		As of			As of
		December 31, 2020			December 31, 2019
		Carrying		Fair	Carrying	Fair
		amount		value	amount	value
		Asset		Asset	Asset	Asset
(in thousands of U.S. dollars)	Level	(Liability)		(Liability)	(Liability)	(Liability)
Recurring:
Cash and cash equivalents	1	$	31,770	31,770	39,126	$	39,126
Restricted cash	1		19,293	19,293	20,693		20,693
Derivative instruments	2		(26,475)	(26,475)	(14,935)		(14,935)
Other:
Amounts due from affiliate	2		3,639	3,639	4,296		4,296
Advances (shareholder loans) to joint ventures	2		4,153	4,305	3,831		4,029
Current amounts due to owners and affiliates	2		(2,600)	(2,600)	(2,513)		(2,513)
Lampung facility	2		(94,960)	(99,295)	(112,713)		(119,598)
$385 million facility	2		(319,629)	(323,342)	(344,248)		(352,219)
Revolving credit facility due to owners and affiliates	2	$	(18,465)	(16,987)	(8,792)	$	(8,717)

Financing receivables and net investment in financing lease

The following table contains a summary of the class of financial asset, year of origination and the method by which the credit quality is monitored on a quarterly basis:

Class		Credit Quality		As of December 31,
(in thousands of U.S. dollars)	Year	Indicator	Grade	2020		2019
Advances/shareholder loans to joint ventures	2006	Collection experience	Performing	$	4,153	$	3,831
Net investment in financing lease	2014	Credit Information	Performing	$	274,257	$	278,904

The shareholder loans to joint ventures are classified as advances to joint ventures in the consolidated balance sheet. Refer to note 9.

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There were no impairment losses for trade receivables for lease or time charter services or contract assets for the year ended December 31, 2019. For the net investment in financing lease, the Partnership monitors quarterly actual credit losses, forecasts of LNG demand and changes in charterer or guarantor-specific publicly available financial and credit information in developing expected credit losses. The Partnership has never incurred actual credit losses related to the net investment in financing lease. The Partnership measures the allowance for credit losses for the net investment in financing lease using the probability of default and loss given default method.

16.   Risk management and concentrations of risk

Derivative instruments can be used in accordance with the overall risk management policy.

Interest rate risk, derivative instruments and cash flow hedges

Cash flow hedging strategy

F-51

The Partnership is exposed to fluctuations in cash flows from floating interest rate exposure on its long-term debt used principally to finance its vessels. Interest rate swaps are used for the management of the floating interest rate risk exposure. The interest rate swaps have the effect of converting a portion of the outstanding debt from a floating to a fixed rate over the life of the interest rate swaps. Interest rate swaps exchange a receipt of floating interest for a payment of fixed interest which reduces the exposure to interest rate variability on the Partnership’s outstanding floating-rate debt over the life of the interest rate swaps. As of December 31, 2020 and 2019, there were interest rate swap agreements related to the Lampung facility (“Lampung interest rate swaps”) and the commercial tranche of the $385 million facility (“$385 million interest rate swaps”) floating rate debt that are designated as cash flow hedges for accounting purposes. As of December 31, 2020, the following interest rate swap agreements were outstanding:

				Fair
				value			Fixed
	Interest			carrying			interest
	rate	Notional		amount			rate
(in thousands of U.S. dollars)	index	amount		liability		Term	(1)
LIBOR-based debt
Lampung interest rate swaps (2)	LIBOR	$	97,960	$	(5,680)	Sep 2026	2.800	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,560)	Jan 2026	2.941	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,197)	Oct 2025	2.838	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,111)	Jan 2026	2.735	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(4,927)	Jan 2026	2.650	%

1) Excludes the margins paid on the floating-rate debt.

2) All interest rate swaps are U.S. dollar denominated and the notional amount reduces quarterly from the effective date of the interest rate swaps.

The Borrower under the Lampung facility entered five forward starting swap agreements with identical terms for a total notional amount of $237.1 million with an effective date of March 17, 2014. The swaps amortize over 12 years to match the amortization profile of the Lampung facility and exchange 3-month USD LIBOR variable interest payments for fixed rate payments at 2.8%. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments on the Lampung facility. As of December 29, 2014, a prepayment of $7.9 million on the Lampung facility occurred which resulted in an amendment of the original interest rate swaps and the hedge was de-designated for accounting purposes. The other terms of the amended interest rate swaps did not change but the nominal amount of the interest rate swaps was reduced to match the outstanding debt. The amended interest rate swaps were re-designated as a cash flow hedge for accounting purposes.

As of October 1, 2015, the Partnership acquired the Höegh Gallant entities which had outstanding debt under the Gallant facility and three associated interest rate swap agreements with a total notional amount of $146.3 million. The swaps amortized to match the debt amortization of the Gallant facility until the scheduled repayment date in September 2019. The swaps exchanged 3-month USD LIBOR variable interest payments for fixed rate payments ranging from 1.9105% to 1.9145%. As of October 1, 2015, the interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $146.3 million of the commercial tranches of the Gallant facility. Hedge accounting was discontinued in the fourth quarter of 2018 as a result of firm commitment for the refinancing of the Gallant facility which was planned to occur in January 2019.

Effective as of January 1, 2017, the Partnership acquired the Höegh Grace entities which had outstanding debt under the Grace facility and three associated interest rate swap agreements with a total notional amount of $164.0 million. The swaps amortized to match the debt amortization of the Grace facility until the scheduled repayment date in June 2020. The swaps exchanged 3-month USD LIBOR variable interest payments for fixed rate payments ranging from 2.305% to 2.315%. As of January 1, 2017, the interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $164.0 million of the commercial tranches of the Grace facility. Hedge accounting was discontinued in the fourth quarter of 2018 as a result of firm commitment for the refinancing of the Grace facility which was planned to occur in January 2019.

F-52

As of December 31, 2018, the Partnership had entered into forward starting interest rate swaps with a nominal amount of $130.0 million to hedge part of the interest rate risk on the floating element of the interest rate for the commercial tranches of the $385 million facility. The Partnership makes fixed payments of 2.941% and 2.838%, based on a nominal amount of $65.0 million for each, in exchange for floating payments. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $130.0 million of the commercial tranches of the $385 million facility which was expected to be drawn and was drawn on January 31, 2019. In February 2019, the Partnership entered into interest rate swaps related to the $385 million facility with a nominal amount of $127.7 million for which the Partnership makes fixed payments of 2.650% and 2.735% based on nominal amount of $63.8 million for each. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $127.7 million of the commercial tranches of the $385 million facility. The swaps amortize over approximately 7 years to match the outstanding balances of the commercial tranches of the $385 million facility until the maturity dates. The export credit tranches have a fixed interest rate and, therefore, no variability in cash flows as a result of changes in interest rates.

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the consolidated balance sheets.

	Current		Long-term		Current		Long-term
	assets:		assets:		liabilities:		liabilities:
	derivative		derivative		derivative		derivative
(in thousands of U.S. dollars)	instruments		instruments		instruments		instruments
As of December 31, 2020
Interest rate swaps	$	—	$	—	$	(6,945)	$	(19,530)
As of December 31, 2019
Interest rate swaps	$	—	$	—	$	(2,907)	$	(12,028)

The following effects of cash flow hedges relating to interest rate swaps are included in gain (loss) on derivative instruments in the consolidated statements of income for the years ended December 31, 2020 and 2019.

	Year ended
	December 31, 2020
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(5,849)	$	—
Amortization of amount excluded from hedge effectiveness		851		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(1,024)		262
Total gains (losses) on derivative instruments	$	(6,022)	$	262

	Year ended
	December 31, 2019
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(956)	$	—
Amortization of amount excluded from hedge effectiveness		966		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(987)		389
Settlement of cash flow hedge		199		—
Total gains (losses) on derivative instruments	$	(778)	$	389

F-53

The settlement of cash flow hedge related to the interest rate swaps for Gallant/Grace facility. The Gallant/Grace interest rate swaps were terminated when the facility was extinguished on January 31, 2019. Due to the termination, the counterparties of the Gallant/Grace facility interest rate swaps paid settlement amounts resulting in a gain on the settlement of the cash flow hedge.

The following effects of cash flow hedges relating to interest rate swaps are included in total gains (losses) on derivative instruments in the consolidated statements of income for the year ended December 31, 2018.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2018
Interest rate swaps:
Ineffective portion of cash flow hedge	$	(990)
Amortization of amount excluded from hedge effectiveness		2,969
Reclassification discontinued hedge from OCI		3,557
Reclassification from accumulated other comprehensive income		(855)
Unrealized gains (losses)		4,681
Realized gains (losses)		—
Total gains (losses) on derivative instruments	$	4,681

For the year ended December 31, 2018, the reclassification to earnings from other comprehensive income (“OCI”) for the discontinued cash flow hedges relates to Gallant/Grace facility which was to be refinanced on January 31, 2019. The accumulated other comprehensive income balance for the cash flow hedge is reclassified to earnings when the hedged future cash flows are no longer expected to occur.

F-54

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income, changes in accumulated OCI and on earnings is as follows as of and for the years ended December 31, 2020 and 2019.

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Effective portion of unrealized loss on cash flow hedge		(18,240)	—		(18,240)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		5,849	—		5,849		(5,849)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		1,024	(262)		762		(1,024)		262
Other comprehensive income for period		(11,367)	(262)		(11,629)
Accumulated OCI as of December 31, 2020	$	(29,486)	(86)	$	(29,572)
Gain (loss) reclassified to earnings						$	(6,873)	$	262

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2018	$	(5,902)	565	$	(5,337)
Initial value of interest rate swap to be recognized in earnings on amortization approach		(625)	—		(625)
Effective portion of unrealized loss on cash flow hedge		(13,535)	—		(13,535)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		956	—		956		(956)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		987	(389)		598		(987)		389
Other comprehensive income for period		(12,217)	(389)		(12,606)
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Gain (loss) reclassified to earnings						$	(1,943)	$	389

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income and changes in accumulated OCI is as follows as of and for the year ended December 31, 2018.

	Cash Flow Hedge
	Before tax		Tax benefit		Accumulated
(in thousands of U.S. dollars)	gains (losses)		(expense)	Net of tax	OCI
Balance as of December 31, 2017	$	(3,612)	864	(2,748)	$	(2,748)
Effective portion of unrealized loss on cash flow hedge		412	—	412		412
Reclassification of amortization of cash flow hedge to earnings		855	(299)	556		556
Reclassification of discontinued cash flow hedge to earnings		(3,557)	—	(3,557)		(3,557)
Other comprehensive income for period		(2,290)	(299)	(2,589)		(2,589)
Balance as of December 31, 2018	$	(5,902)	565	(5,337)	$	(5,337)

As of December 31, 2020, the estimated amounts to be reclassified from accumulated other comprehensive income to earnings during the next twelve months is $7.9 million.

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Foreign exchange risk

All financing, interest expenses from financing and most of the Partnership’s revenue and expenditures for vessel improvements are denominated in U.S. dollars. Certain operating expenses can be denominated in currencies other than U.S. dollars. For the years ended December 31, 2020, 2019 and 2018, no derivative instruments have been used to manage foreign exchange risk.

Credit risk

Credit risk is the exposure to credit loss in the event of non-performance by the counterparties related to cash and cash equivalents, restricted cash, trade receivables, net investment in financing lease, amounts due from affiliates and interest rate swap agreements. In order to minimize counterparty risk, bank relationships are established with counterparties with acceptable credit ratings at the time of the transactions. Credit risk related to receivables is limited by performing ongoing credit evaluations of the customers’ or counterparty’s financial condition. PGN guarantees PGN LNG's obligations under the PGN FSRU Lampung time charter. Höegh LNG provides a guarantee for its subsidiary’s payment obligations under the Subsequent Charter for the Höegh Gallant. Refer to note 2 for a discussion of the allowance for expected credit loss.

Concentrations of risk

Financial instruments, which potentially subject the Partnership to significant concentrations of credit risk, consist principally of cash and cash equivalents, restricted cash, trade receivables, amounts due from affiliates and derivative contracts (interest rate swaps). The maximum exposure to loss due to credit risk is the book value at the balance sheet date. The Partnership does not have a policy of requiring collateral or security. Cash and cash equivalents and restricted cash are placed with qualified financial institutions. Periodic evaluations are performed of the relative credit standing of those financial institutions. In addition, exposure is limited by diversifying among counterparties. There are three charterers so there is a concentration of risk related to trade receivables. While the maximum exposure to loss due to credit risk is the book value of trade receivables at the balance sheet date, should the time charters for the PGN FSRU Lampung or the Höegh Grace terminate prematurely, or Höegh LNG prematurely terminate the Subsequent Charter for the Höegh Gallant, or the option to acquire the PGN FSRU Lampung be exercised, there could be delays in obtaining new time charters and the hire rates could be lower depending upon the prevailing market conditions.

17.   Commitments and contingencies

Contractual commitments

As of December 31, 2020, the Partnership has no material commitments for capital expenditures. However, during the fourth quarter of 2020, part of the procedures for the on-water class renewal survey for the Höegh Grace commenced. No off-hire occurred during the fourth quarter of 2020. The remainder of the on-water class renewal survey is expected to be completed during the first half of 2021. Expenditures totaling approximately $0.6 million were incurred as of December 31, 2020.

As of December 31, 2020, there were no material contractual purchase commitments.

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Claims and Contingencies

Joint ventures boil-off settlement

Under the Neptune and the Cape Ann time charters, the joint ventures undertake to ensure that the vessel always meets specified performance standards during the term of the time charters. The performance standards include the vessel not exceeding a maximum average daily boil-off of LNG, subject to certain contractual exclusions, as specified in the time charter. Pursuant to the charters, the hire rate is subject to deduction by the charterer of, among other things, sums due in respect of the joint ventures’ failure to satisfy the specified performance standards during the period. On September 8, 2017, the charterer notified the joint ventures that it was formally making a claim for compensation in accordance with the provisions of the charters for a stated quantity of LNG exceeding the maximum average daily boil-off since the beginning for the charters. Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. As of September 30, 2017, the joint ventures determined the liability associated with the boil-off claim was probable and could be reasonably estimated resulting in a total accrual of $23.7 million which was recorded as a reduction of time charter revenues in the third quarter of 2017. As a precaution, the joint ventures suspended payments on their shareholder loans as of September 30, 2017 pending the outcome of the boil-off claim. Refer to note 8. The Partnership's 50% share of the accrual was approximately $11.9 million. The claim was referred to arbitration.

In February 2020, each of the joint ventures and the charterer reached a commercial settlement addressing all the past and future claims related to boil-off with respect to the Neptune and the Cape Ann. The settlement amount was in line with the accrual made by the joint ventures. Accordingly, the accrual was unchanged as of December 31, 2019. The settlement reached was subject to executing final binding agreements between the parties. The final settlement and release agreements were signed on and had an effective date of April 1, 2020. Among other things, the settlement provided that 1) the boil-off claim, up to the effective date of the settlement agreements, would be settled for an aggregate amount of $23.7 million, paid in instalments during 2020, 2) the costs of the arbitration tribunal would be equally split between the parties and each party would settle its legal and other costs, 3) the joint ventures have or would implement technical upgrades on the vessels at their own cost to minimize boil-off, and 4) the relevant provisions of the time charters would be amended regarding the computation and settlement of prospective boil-off claims. The Partnership’s 50% share of the settlement was the same as its share of the accrual, or approximately $11.9 million. As a result, the settlement had no impact to the Partnership’s consolidated income statement for the year ended December 31, 2020.

The first installment of the settlement of $17.2 million was paid by the joint ventures in April 2020. The Partnership’s 50% share was $8.6 million. The second and final installment of the settlement of $6.5 million was paid by the joint ventures in December 2020. The Partnership’s 50% share was $3.3 million.

The Partnership is indemnified by Höegh LNG for its share of the cash impact of the settlement, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreement. On April 8, 2020 and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG.

Höegh LNG and the other major owner guarantee the performance and payment obligations of the joint ventures under the time charters.

The Partnership was indemnified by Höegh LNG for its share of the cash impact of the settlement, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreement. Höegh LNG will indemnify the Partnership for the Partnership’s share of such costs. For the year ended December 31, 2018 the Partnership received indemnification payments of $0.3 million from Höegh LNG, related to the boil-off claim. Indemnification payments were recorded as contributions to equity. Refer to note 14. On March 12, 2021, the partnership was indemnified by Höegh LNG for its share of the joint ventures performance claims for the year ended December 31, 2020 by a reduction of $0.3 million on its outstanding balance on the $85 million revolving credit facility from Höegh LNG

F-57

Indonesian corporate income tax

Based upon the Partnership’ s experience in Indonesia, tax regulations, guidance and interpretation in Indonesia may not always be clear and may be subject to alternative interpretations or changes in interpretations over time. The Partnership’s Indonesian subsidiary is subject to examination by the Indonesian tax authorities for the years from 2016 through 2020 for up to five years following the completion of a fiscal year. As a result, it is likely there will be an examination by the Indonesian tax authorities for the tax return for 2016 during 2021. The examinations may lead to ordinary course adjustments or proposed adjustments to the Partnership’s taxes with respect to years under examination. In December 2018, the examination for the years 2013 and 2014 was completed. Refer to note 6 for additional information. On January 22, 2021 the Partnership’s Indonesian subsidiary received a letter from the Indonesian tax authorities that there will be an examination by the Indonesian tax authorities for the tax returns from 2016 to 2020 during 2021. Future examinations may or may not result in changes to the Partnership’s provisions on tax filings from 2016 through 2020. As of December 31, 2020, the unrecognized tax benefits for uncertain tax positions were $2.7 million.

Indonesian property tax

The Partnership's Indonesian subsidiary was assessed for Land and Building tax (“property tax”) and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The assessment was due to the issuance of the Indonesian Minister of Finance’s Decree No. 186/PMK.03/2019 (“PMK 186/2019”) which defines FSRUs as a “Building” subject to the tax. The Partnership’s Indonesian subsidiary has appealed the assessment. Depending on the level of appeal pursued, the appeal process could take a number of years to conclude. There can be no assurance of the result of the appeal or whether the Indonesian subsidiary will prevail. As a result, the property tax and penalties were expensed as a component of vessel operating expenses for the year ended December 31, 2019. Until the appeal is concluded, the Indonesian subsidiary will be required to pay an annual property tax of approximately $0.5 million.

PGN LNG claims including delay liquidated damages

The Partnership was indemnified by Höegh LNG for i) any hire rate payments not received under the PGN FSRU Lampung time charter for the period commencing on August 12, 2014 through the acceptance date of the PGN FSRU Lampung and ii) non-budgeted expenses (including warranty costs associated with repairs of the Mooring) incurred in connection with the PGN FSRU Lampung project prior to the date of acceptance, and for iii) certain subsequently incurred non-budgeted costs and expenses.

No indemnification claim was filed for the year ended December 31, 2020. For the years ended December 31, 2019 and 2018, the Partnership refunded to Höegh LNG approximately $0.1 million and $2.4 million, respectively, related to insurance proceeds received related to the warranty provision and costs for previous years determined to be reimbursable by the charterer. For the year ended December 31, 2018, the Partnership received indemnification payments from Höegh LNG for non-budgeted expenses (including warranty provisions, other non-budgeted expenses and replacement capital expenditure) of $0.9 million which was recorded as a contribution to equity. Indemnification payments received from Höegh LNG are subject to repayment to the extent the amounts are subsequently recovered from insurance or deemed reimbursable by the charterer. Refer to note 14.

Höegh Gallant claims and indemnification

The Partnership was indemnified by Höegh LNG for losses incurred in connection with the commencement of services under the time charter with EgyptCo (including technical issues) incurred in connection with the Höegh Gallant.

No indemnification claims were filed or received for the years ended December 31, 2020 and 2019. For the year ended December 31, 2018, the Partnership received indemnification payments from Höegh LNG for losses incurred in connection with the time charter with EgyptCo of $0.5 million which were recorded as contributions to equity. Refer to note 14.

F-58

18.   Supplemental cash flow information

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Supplemental disclosure of non-cash investing activities
Non-cash expenditures for vessel and other equipment	$	—	—	$	(229)
Supplemental disclosure of non-cash financing activities
Non-cash indemnifications received	$	11,850	—	$	—

Refer to note 14 for non-cash indemnification received information.

19.   Issuance of common units and Series A preferred units

From the commencement of the Prior ATM program in January 2018 through December 31, 2020, the Partnership sold 2,152,333 Series A preferred units and 306,266 common units under the ATM programs and received net proceeds of $54.9 million and $5.6 million, respectively. The compensation paid to the Agent for such sales was $1.1 million.

For the year ended December 31, 2020, the Partnership did not issue any common units under the ATM program. For the year ended December 31, 2020, the Partnership sold 126,743 Series A preferred units at an average gross sales price of $25.50 per unit for net proceeds after sales commissions, of $3.2 million. The Partnership has paid an aggregate of $0.1 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2020. Proceeds in the table below are included for all units for the year ended December 31, 2020.

	Year ended
	December 31, 2020
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	—	3,231	$	3,231
Less: Commissions		—	(57)		(57)
Net proceeds for units issued	$	—	3,174	$	3,174

For the year ended December 31, 2019, the Partnership sold 53,160 common units at an average gross sales price of $19.60 per unit for net proceeds, after sales commissions, of $1.0 million. For the year ended December 31, 2019, the Partnership sold 496,520 Series A preferred units at an average gross sales price of $26.79 per unit for net proceeds, after sales commissions, of $13.1 million. The Partnership has paid an aggregate of $0.2 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2019. Proceeds in the table below are included for all units issued for the year ended December 31, 2019.

	Year ended December 31, 2019
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	1,042	13,298	$	14,340
Less: Commissions		(13)	(233)		(246)
Net proceeds for units issued	$	1,029	13,065	$	14,094

F-59

For the year ended December 31, 2018, the Partnership sold 253,106 common units at an average gross sales price of $18.26 per unit for net proceeds, after sales commissions, of $4.6 million. For the year ended December 31, 2018, the Partnership sold 1,529,070 Series A preferred units at an average gross sales price of $25.74 per unit for net proceeds, after sales commissions, of $38.7 million. The Partnership has paid an aggregate of $0.8 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2018. Proceeds in the table below are included for all units issued for the year ended December 31, 2018.

	Year ended December 31, 2018
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	4,623	39,360	$	43,983
Less: Commissions		(60)	(701)		(761)
Net proceeds for units issued	$	4,563	38,659	$	43,222

20.   Common, subordinated and preferred units

The following table shows the movements in the number of common units, subordinated units and preferred units during the years ended December 31, 2020, 2019 and 2018:

		Common		8.75%
	Common	Units		Series A
	Units	Höegh	Subordinated	Preferred
(in units)	Public	LNG	Units	Units
December 31, 2017	17,648,844	2,116,060	13,156,060	4,600,000
June 6, 2018; Awards to non-employee directors as compensation for directors' fees	8,840	—	—	—
July 5, 2018; Awards to non-employee directors as compensation for directors' fees	2,210	—	—	—
Units issued to staff at Höegh LNG during 2018	14,622	(14,622)	—	—
Phantom units issued to CEO/CFO during 2018	17,079	—	—	—
ATM program (from January 26, 2018 to December 31, 2018)	253,106	—	—	1,529,070
December 31, 2018	17,944,701	2,101,438	13,156,060	6,129,070
June 4, 2019; Awards to non-employee directors as compensation for directors' fees	8,944	—	—	—
July 16, 2019; Awards to non-employee directors as compensation for directors' fees	2,236	—	—	—
August 16, 2019; Subordinated units converted to common units	—	13,156,060	(13,156,060)	—
Phantom units issued to CEO/CFO during 2019	19,745	—	—	—
ATM program (from January 1, 2019 to December 31, 2019)	53,160	—	—	496,520
December 31, 2019	18,028,786	15,257,498	—	6,625,590
September 4, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
September 15, 2020; Awards to non-employee directors as compensation for directors' fees	7,764	—	—	—
October 23, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
Phantom units issued to CEO/CFO during 2020	6,627	—	—	—
ATM program (from January 1, 2020 to December 31, 2020)	—	—	—	126,743
December 31, 2020	18,050,941	15,257,498	—	6,752,333

The subordination period, as defined in the Second Amended and Restated Agreement of Limited Partnership of Höegh LNG Partners LP, for the subordinated units ended on August 16, 2019. All of the subordinated units, which were owned by Höegh LNG, converted to common units on a one-for-one basis. As of December 31, 2020 and 2019, Höegh LNG owned 15,257,498 common units. As of December 31, 2018, Höegh LNG owned 2,101,438 common units and 13,156,060 subordinated units.

F-60

Refer to note 21 for information on distributions to common and subordinated unitholders.

The Series A preferred units represent perpetual equity interests in the Partnership and, unlike the Partnership’s debt, do not give rise to a claim for payment of a principal amount at a particular date. The Series A preferred units rank senior to the Partnership’s common units as to the payment of distributions and amounts payable upon liquidation, dissolution or winding up but junior to all the Partnership’s debt and other liabilities. The Series A preferred units have a liquidation preference of $25.00 per unit. At any time on or after October 5, 2022, the Partnership may redeem, in whole or in part, the Series A preferred units at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. The distribution rate on the Series A preferred units is 8.75% per annum of the $25.00 per unit value (equivalent to $2.1875 per annum per unit). The distributions are cumulative and recorded when declared. However, since the Series A preferred units rank senior to the Partnership’s common units, the portion of net income, equivalent to the Series A preferred units’ paid and undeclared distributions for that period, is reflected as Preferred unitholders’ interest in net income on the consolidated statement of income. Distributions are payable quarterly, when, and if declared by the Partnership’s board of directors out of legally available funds for such purpose. Holders of the Series A preferred units generally have no voting rights. However, if and whenever distributions payable on the Series A preferred units are in arrears for six or more quarterly periods, whether or not consecutive, holders of Series A preferred units will be entitled to replace one of the members of the Partnership’s board of directors appointed by the general partner with a person nominated by such holders.

21.   Earning per unit and cash distributions

The calculation of basic and diluted earnings per unit are presented below:

	Year ended December 31,
(in thousands of U.S. dollars, except per unit numbers)	2020		2019		2018
Net income	$	63,145		52,741	$	77,622
Adjustment for:
Preferred unitholders’ interest in net income		14,802		13,850		12,303
Limited partners' interest in net income		48,343		38,891		65,319
Less: Dividends paid or to be paid (1)		(60,222)		(60,149)		(59,952)
Under (over) distributed earnings		(11,879)		(21,258)		5,367
Under (over) distributed earnings attributable to:
Common units public		(6,437)		(11,514)		2,900
Common units Höegh LNG		(5,442)		(3,211)		340
Subordinated units Höegh LNG (4)		—		(6,533)		2,127
	$	(11,879)		(21,258)	$	5,367
Basic weighted average units outstanding (in thousands)
Common units public		18,034		17,986		17,856
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Diluted weighted average units outstanding (in thousands)
Common units public		18,037		17,995		17,864
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Basic and diluted earnings per unit (2):
Common unit public	$	1.40	$	1.12	$	1.93
Common unit Höegh LNG (3)	$	1.51	$	1.84	$	2.03
Subordinated unit Höegh LNG (3) (4)	$	—	$	0.70	$	2.03

(1) Includes all distributions paid or to be paid in relationship to the period, regardless of whether the declaration and payment dates were prior to the end of the period and is based the number of units outstanding at the period end.

F-61

(2) Effective March 26, 2020, granted 8,100 phantom units to the CEO/CFO of the Partnership, one-third of such phantom units vest as of November 30, 2021, 2022 and 2023, respectively. Effective March 21, 2019, granted 10,917 phantom units to the CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective March 23, 2018, the Partnership granted 14,584 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective June 3, 2016, the Partnership granted 21,500 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of December 31, 2017, November 30, 2018 and November 30, 2019, respectively. On September 14, 2018, the plan was amended to extend the terms and conditions of such unvested units for the grants effective March 23, 2017 and June 3, 2016 of the then-serving CEO/CFO that resigned as CEO/CFO of the Partnership. The phantom units impact the diluted weighted average units outstanding. As a result of the resignation of the CEO/CFO of the Partnership in August 2020, a total of 15,378 of the unvested phantom units terminated.

(3) Includes total amounts attributable to incentive distributions rights of $1,598, $1,597 and $1,591 for the years ended December 31, 2020, 2019 and 2018, respectively. For the year ended December 31, 2020 the full amount was attributable to common units owned by Höegh LNG. For the years ended December 31, 2019 and 2018, respectively, $908 and $219 was attributed to common units owned by Höegh LNG and $688 and $1,372 was attributed to subordinated units owned by Höegh LNG.

(4) On August 16, 2019, all subordinated units converted into common units on a one-for-one basis.

Earnings per unit is calculated by dividing net income by the weighted average number of common and subordinated units outstanding during the applicable period.

The common unitholders’ interest in net income is calculated as if all net income were distributed according to terms of the Partnership’s Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), regardless of whether those earnings would or could be distributed. The Partnership Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash. Available cash, a contractual defined term, generally means all cash on hand at the end of the quarter after deduction for cash reserves established by the board of directors and the Partnership’s subsidiaries to i) provide for the proper conduct of the business (including reserves for future capital expenditures and for the anticipated credit needs); ii) comply with applicable law, any of the debt instruments or other agreements; iii) provide funds for payments on the Series A preferred units; and iv) provide funds for distributions to the unitholders for any one or more of the next four quarters. Therefore, the earnings per unit are not indicative of future cash distributions that may be made. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on derivative instruments and unrealized gains or losses on foreign exchange transactions.

In addition, Höegh LNG currently holds all the IDRs in the Partnership. IDRs represent the rights to receive an increasing percentage of quarterly distributions of available cash for operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

Distributions of available cash from operating surplus are to be made among the unitholders and the holders of the IDRs in the following manner for any quarter after the subordination period:

● first, 100.0% to all common unitholders, pro rata, until each such unitholder receives a total of $0.388125 per unit for that quarter;

● second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of the IDRs, pro rata, until each such unitholder receives a total of $0.421875 per unit for that quarter;

● third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of the IDRs, pro rata, until each such unitholder receives a total of $0.50625 per unit for that quarter; and

● thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of the IDRs, pro rata.

In each case, the percentage interests set forth above assume that the Partnership does not issue additional classes of equity securities.

F-62

22.   Subsequent events

On February 12, 2021, the Partnership paid a cash distribution of $15.1 million, or $0.44 per common unit, with respect to the three months ended December 31, 2020, equivalent to $1.76 per unit on an annualized basis.

On February 16, 2021, the Partnership paid a cash distribution of $3.9 million, or $0.546875 per Series A preferred unit, for the period commencing on November 15, 2020 to February 14, 2021.

For the period from January 1, 2021 to April 9, 2021, the Partnership sold an aggregate of 52,603 common units under the ATM program at an average gross sales price of $15.75 per unit and received net proceeds, after sales commissions, of $0.8 million and 336,992 Series A preferred units under the ATM program at an average gross sales price of $25.12 per units and received net proceeds, after sales commissions, of $8.3 million.

On March 8, 2021, Höegh LNG announced a recommended offer by Leif Höegh & Co. Ltd. (“LHC”) and funds managed by Morgan Stanley Infrastructure Partners (“MSIP”) through a 50/50 joint venture, Larus Holding Limited (“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates (the “Amalgamation”). Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange. The Amalgamation has been approved by Höegh LNG's shareholders and bondholders and is anticipated to close in the first half of 2021. The Amalgamation is subject to waivers of specific change of control and delisting provisions in relation to certain of the Partnership's and Höegh LNG's credit agreements, as well as the satisfaction of other customary closing conditions. Following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement in connection with the IPO will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels (as defined in “Major Unitholders and Related Party Transactions - Related Party Transactions - Omnibus Agreement - Non Competition”), (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

The commercial tranche of the Lampung facility becomes due in October 2021 and the export credit tranche can be called if the commercial tranche is not refinanced. To address the liquidity needs, the Partnership is at an advanced stage of the process to refinance the Lampung facility. As of April 9, 2021, a group of lending banks have provided a credit approved term sheet for the refinancing of both the commercial tranche and the export credit tranche. The refinancing is subject to completion of the loan documentation and satisfaction of customary closing conditions before drawdown. The refinancing is expected to be completed before the due date of the commercial tranche in October 2021. Accordingly, based on the refinancing plans, we believe we have sufficient resources to meet our anticipated liquidity requirements for at least the next 12 months.

F-63

EX-4.3

Exhibit 4.3

HÖEGH LNG PARTNERS LP

AMENDED AND RESTATED NON-EMPLOYEE DIRECTOR COMPENSATION PLAN

FOR THE PERIOD 2020-2021

(As approved by the Board on June 4, 2019, amended April 24, 2020 and September 11, 2020)

The non-employee members of the Board of Directors (the “Board”) of Höegh LNG Partners LP (the “Partnership”) will be entitled to receive the following compensation:

1.     Retainer Fees

● Each non-employee director will receive an annual cash retainer fee of USD 40,600 (subject to adjustment from time to time, as determined by the Board) for each year of service as a director.

● The Chairman of the Board of Directors will receive an annual cash retainer fee of USD 21,900 (subject to adjustment from time to time, as determined by the Board) for each year of service in such capacity.

● The Chairs of the Audit and Conflict Committees will each receive an annual cash retainer fee of USD 21,900 (subject to adjustment from time to time, as determined by the Board) for each year of service in such capacity.

● Other committee members will receive an annual cash retainer fee of USD 11,000 (subject to adjustment from time to time, as determined by the Board) for each year of service in such capacity.

2.     Equity Awards

● Each non-employee director will receive an annual equity-based award (with award type, vesting and all other terms and conditions to be determined by the Board for any given year), valued at USD 40,600 (subject to adjustment from time to time, as determined by the Board) on the applicable date of grant, for each year of service as a director, which such award will be granted under the Höegh LNG Partners LP Long Term Incentive Plan, as amended from time to time (the “Plan”), or a successor plan, program or arrangement. Subject to approval by the Board, the Partnership may elect to pay cash (or a combination of equity and cash) in lieu of the equity-based award described in this Section 2 to any one or more directors.

3.     Expense Reimbursement

● Each non-employee director will be reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Board or its committees and related to the director’s participation in the Partnership’s general education and orientation programs for directors.

EX-4.4.1

Exhibit 4.4.1

ADDENDUM NO. 1

TO

ADMINISTRATIVE SERVICES AGREEMENT

This Addendum no. 1 (the “Amendment”) to the Administrative Services Agreement entered into on December 20, 2019 and effective as of July 3, 2019 (the “Agreement”), is made with effect from August 21, 2020 between:

(i) Höegh LNG Partners LP (the ”MLP”);

(ii) Höegh LNG Partners Operating LLC (the “Operating Company”);

and

(ii) Höegh LNG AS (as “Höegh Norway”);

(each a “Party” and together the “Parties”).

WHEREAS The Chief Executive Officer and Chief Financial Officer, Steffen Føreid, has notified the board of his resignation; and

WHEREAS The Parties agree that the Agreement should include specifications on how Höegh Norway should be reimbursed.

NOW THEREFORE the Parties have agreed as follows:

1. Section 2. General to be extended to include reimbursement and that the following articles are to be added to Section 2:

“(b) The MLP or the Operating Company (as applicable) shall reimburse Höegh Norway on a monthly basis in arrears for all costs and expenses reasonably incurred by Höegh Norway in connection with the provision of the Administrative Services for the preceding month;

(c) the MLP or the Operating Company (as applicable) shall pay to Höegh Norway on a monthly basis in arrears a services fee equal to 3.00% of Höegh Norway’s Costs and Expenses, including direct payroll costs for the preceding month;

(d) within 20 days after the end of each calendar month, Höegh Norway shall submit to the MLP and the Operating Company for payment an invoice covering the Costs and Expenses and the Services Fees. Each invoice will contain such supporting detail as may be reasonably required to validate such amounts due; and

(e) the MLP or the Operating Company (as applicable) shall make payment owed pursuant to this Section 2(a) within 45 days of the date of each invoice (any such day on which a payment is due, a “Due Date”).  All invoices for the Costs and Expenses and the Services Fees will be submitted in and paid in U.S. Dollars.  All amounts not paid within 10 days after the Due Date bear interest at the rate of 3.00% per annum above LIBOR as of the Due Date from such Due Date until the date payment is received in full by Höegh Norway.”

Page 1 of 2

(f) Schedule B Managers, of the Agreement to read:

SCHEDULE B MANAGERS

Name	Position with the Operating Company	Position with the MLP
Sveinung J. S. Støhle	Chief Executive Officer	Chief Executive Officer
Håvard Furu	Chief Financial Officer	Chief Financial Officer

2. Section 16. Notice to be amended to reflect that notices to the MLP and the Operating Company shall be for the attention of Håvard Furu. Notice details to Höegh Norway remain unchanged.

3. All other terms of the Agreement remain unchanged.

IN WITNESS WHEREOF, the Parties have executed this Agreement on, and effective as of, the date first above written.

HÖEGH LNG PARTNERS LP
By:	/s/ Håvard Furu
	Name:	Håvard Furu
	Title:	Chief Financial Officer
HÖEGH LNG PARTNERS OPERATING LLC
By:	/s/ Håvard Furu
	Name:	Håvard Furu
	Title:	Chief Financial Officer
HÖEGH LNG AS
By:	/s/ Sveinung J.S. Støhle
	Name:	Sveinung J. S. Støhle
	Title:	General Manager

Page 2 of 2

EX-4.4.2

Exhibit 4.4.2

ADDENDUM NO. 2

TO

ADMINISTRATIVE SERVICES AGREEMENT

This Addendum no. 2 (the “Amendment”) to the Administrative Services Agreement entered into on December 20, 2019 and effective as of July 3, 2019 and as amended by Addendum no. 1 dated and effective as of August 21, 2020 (the “Agreement”) is made with effect from April 9, 2021 between:

(i)          Höegh LNG Partners LP (the ”MLP”);

(ii)         Höegh LNG Partners Operating LLC (the “Operating Company”);

and

(ii)         Höegh LNG AS (as “Höegh Norway”);

(each a “Party” and together the “Parties”).

WHEREAS             The ultimate parent company of Höegh Norway has entered into an agreement and plan of amalgamation with Larus Limited dated 8 March 2021 (the “Amalgamation”); and

WHEREAS             The Parties wants to confirm their agreement that the Agreement will continue in full force and effect following the consummation of the Amalgamation by way of entering into this Amendment.

NOW THEREFORE the Parties have agreed as follows:

1.    The Parties agree that the Agreement will continue in full force and effect following the consummation of the Amalgamation. For the avoidance of doubt, Höegh Norway undertakes not to enforce any rights to terminate the Agreement pursuant to Section 10 (b) (i) as a result of the consummation of the Amalgamation.

2.    All other terms of the Agreement remain unchanged.

IN WITNESS WHEREOF, the Parties have executed this Agreement on, and effective as of, the dates first above written.

HÖEGH LNG PARTNERS LP
By:	/s/ Sveinung J.S. Støhle
	Name:	Sveinung J.S. Støhle
	Title:	Chief Executive Officer

Page 1 of 2

HÖEGH LNG PARTNERS OPERATING LLC
By:	/s/ Sveinung J.S. Støhle
	Name:	Sveinung J.S. Støhle
	Title:	Chief Executive Officer

HÖEGH LNG AS
By:	/s/ Morten W. Høegh
	Name:	Morten W. Høegh
	Title:	Chairman

Page 2 of 2

EX-8.1

Exhibit 8.1

Subsidiaries of Höegh LNG Partners LP

Subsidiary	Ownership Interest	Jurisdiction of Formation
Höegh LNG Partners Operating LLC	100%	Republic of the Marshall Islands
SRV Joint Gas Ltd.	50%	Cayman Islands
SRV Joint Gas Two Ltd.	50%	Cayman Islands
Höegh LNG Lampung Pte Ltd.	100%	Singapore
Höegh LNG Services Ltd.	100%	United Kingdom
PT Hoegh LNG Lampung	49%	Indonesia
Hoegh LNG Cyprus Limited	100%	Cyprus
Hoegh LNG Cyprus Limited Egypt Branch	100%	Egypt
Höegh LNG Colombia Holding Ltd.	100%	Cayman Islands
Höegh LNG FSRU IV Ltd.	100%	Cayman Islands
Höegh LNG Colombia S.A.S.	100%	Colombia

EX-12.1

Exhibit 12.1

CERTIFICATION

I, Sveinung J. S. Støhle, certify that:

1. I have reviewed this annual report on Form 20-F of Höegh LNG Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 9, 2021		HÖEGH LNG PARTNERS LP
	By:	/s/ Sveinung J. S. Støhle
	Name:	Sveinung J. S. Støhle
	Title:	Chief Executive Officer (Principal Executive Officer)

EX-12.2

Exhibit 12.2

CERTIFICATION

I, Håvard Furu, certify that:

1. I have reviewed this annual report on Form 20-F of Höegh LNG Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 9, 2021		HÖEGH LNG PARTNERS LP
	By:	/s/ Håvard Furu
	Name:	Håvard Furu
	Title:	Chief Financial Officer (Principal Financial Officer)

EX-13.1

Exhibit 13.1

CERTIFICATION PURSUANT TO

18 U.S.C. 1350

Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of Höegh LNG Partners LP, a Marshall Islands limited partnership (the “Partnership”), certifies, to such officer’s knowledge, that:

The annual report on Form 20-F for the year ended December 31, 2020 of the Partnership (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: April 9, 2021		HÖEGH LNG PARTNERS LP
	By:	/s/ Sveinung J. S. Støhle
	Name:	Sveinung J. S. Støhle
	Title:	Chief Executive Officer (Principal Executive Officer)

EX-13.2

Exhibit 13.2

CERTIFICATION PURSUANT TO

18 U.S.C. 1350

Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of Höegh LNG Partners LP, a Marshall Islands limited partnership (the “Partnership”), certifies, to such officer’s knowledge, that:

The annual report on Form 20-F for the year ended December 31, 2020 of the Partnership (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: April 9, 2021		HÖEGH LNG PARTNERS LP
	By:	/s/ Håvard Furu
	Name:	Håvard Furu
	Title:	Chief Financial Officer (Principal Financial Officer)

EX-15.1

Exhibit 15.1

Schedule I – Condensed Financial Information of Registrant

CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Total revenue	$	—	—	$	—
EXPENSES
Administrative expenses		(6,279)	(6,473)		(5,822)
Equity in earnings of subsidiaries		64,296	60,315		68,359
Equity in earnings (losses) of joint ventures		6,420	6,078		17,938
Interest income		15,983	11,205		93
Interest expense		(17,139)	(18,242)		(2,938)
Other items, net		(136)	(142)		(8)
Net income	$	63,145	52,741	$	77,622
Share of subsidiaries unrealized losses on cash flow hedges		(11,367)	(12,217)		(2,290)
Share of subsidiaries income tax benefit		(262)	(389)		(299)
Comprehensive income	$	51,516	40,135	$	75,033

See accompanying notes to condensed financial statements.

1

CONDENSED BALANCE SHEETS

	As of  December 31,
(in thousands of U.S. dollars)	2020		2019
Cash	$	2,058	$	6,934
Current portion of long-term loans to subsidiaries		26,717		25,597
Promissory note from subsidiaries		123,248		123,248
Prepaid expenses and other receivables		1,097		224
Total current assets		153,120		156,003
Accumulated earnings of joint ventures		9,690		3,270
Loans to subsidiaries		237,489		260,636
Investments in subsidiaries		455,582		449,570
Total long-term assets		702,761		713,476
Total assets	$	855,881	$	869,479
LIABILITIES AND PARTNER’S CAPITAL
Current portion of long-term debt	$	25,597	$	25,597
Trade payables		86		52
Amounts due to owners and affiliates		732		398
Derivative instruments		4,699		1,821
Accrued liabilities and other payables		2,860		3,155
Total current liabilities		33,974		31,023
Long-term debt		294,032		318,650
Loans due to owners and affiliates		18,465		8,792
Derivative instruments		16,095		9,504
Total long-term liabilities		328,592		336,946
Total liabilities		362,566		367,969
Total partners’ capital		493,315		501,510
Total liabilities and partners’ capital	$	855,881	$	869,479

See accompanying notes to condensed financial statements.

2

CONDENSED STATEMENT OF CASH FLOW

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Net cash provided by operating activities	$	48,656	33,130	$	42,401
INVESTING ACTIVITIES
Long-term loan due from subsidiaries		22,027	(286,133)		—
Net cash provided by (used in) investing activities		22,027	(286,133)		—
FINANCING ACTIVITIES
Net proceeds from issuance of Series A Preferred Units		3,174	13,065		38,659
Net proceeds from issuance of common units		—	1,029		4,563
Proceeds from long-term debt		—	368,300		—
Proceeds from loans due to owners and affiliates		21,750	3,500		5,400
Repayment of long-term debt		(25,597)	(19,198)		—
Repayment of debt issuance cost		—	(5,797)		—
Repayment of amounts due to owners and affiliates		—	(34,000)		(17,500)
Proceeds from indemnifications received from Höegh LNG		—	—		1,701
Repayment of indemnifications received from Höegh LNG		—	(64)		(2,535)
Cash distributions to limited partners		(74,886)	(73,804)		(72,497)
Net cash provided by (used in) financing activities		(75,559)	253,301		(42,209)
Increase (decrease) in cash, cash equivalents and restricted cash		(4,876)	(72)		374
Cash, cash equivalents and restricted cash, beginning of period		6,934	7,006		6,632
Cash, cash equivalents and restricted cash, end of period	$	2,058	6,934	$	7,006

See accompanying notes to condensed financial statements.

3

1. Basis of presentation

Höegh LNG Partners LP – the Parent company is a Marshall Islands limited partnership formed on April 28, 2014.

In the parent-only financial statements, the investment in subsidiaries and investment in joint ventures are stated at cost plus equity in undistributed earnings of subsidiaries and accumulated earnings in joint ventures since the date of acquisition and the closing of the initial public offering of Höegh LNG Partners LP (the “Partnership”) on August 12, 2014. The Partnership’s share of net income of its unconsolidated subsidiaries and joint ventures is included in the condensed income statement using the equity method. The Parent company’s financial statements should be read in conjunction with the Partnership’s consolidated financial statements contained elsewhere in the Partnership’s Report on Form 20-F for the year ended December 31, 2020.

2. Dividends

A cash dividend of $55.8 million, $42.4 million and $51.7 million was paid to the Parent company from its consolidated subsidiaries for the years ended December 31, 2020, 2019 and 2018, respectively.

4

EX-15.2

Exhibit 15.2

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-211840) pertaining to the Höegh LNG Partners LP Long Term Incentive Plan and Höegh LNG Holdings Ltd. Phantom Unit Awards and the Registration Statement (Form F-3 No. 333-234011) of Höegh LNG Partners LP and in the related Prospectus of our reports dated April 9, 2021, with respect to the consolidated financial statements of Höegh LNG Partners LP and the effectiveness of internal control over financial reporting of Höegh LNG Partners LP included in this Annual Report (Form 20-F) for the year ended December 31, 2020.

/s/ Ernst & Young AS

Oslo, Norway

April 9, 2021

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2020 shares
Document Information [Line Items]
Document Type	20-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Registrant Name	Höegh LNG Partners LP
Entity Central Index Key	0001603016
Current Fiscal Year End Date	--12-31
Document Annual Report	true
Document Registration Statement	false
Document Shell Company Report	false
Document Transition Report	false
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Filer Category	Accelerated Filer
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity File Number	001-36588
Entity Incorporation, State or Country Code	1T
Entity Address, Address Line One	Canon’s Court
Entity Address, Address Line Two	22 Victoria Street
Entity Address, Postal Zip Code	HM 12
Entity Address, City or Town	Hamilton
Entity Address, Country	BM
Document Accounting Standard	U.S. GAAP
ICFR Auditor Attestation Flag	true
Business Contact [Member]
Document Information [Line Items]
Contact Personnel Name	Håvard Furu
Entity Address, Address Line One	Canon’s Court
Entity Address, Address Line Two	22 Victoria Street
Entity Address, Postal Zip Code	HM 12
Entity Address, City or Town	Hamilton
Entity Address, Country	BM
Contact Personnel Email Address	havard.furu@hoeghlng.com
City Area Code	47
Local Phone Number	9-912-3443
Common Stock [Member]
Document Information [Line Items]
Title of 12(b) Security	Common units representing limited partner interests
Trading Symbol	HMLP
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding	33,308,439
Series A Preferred Stock [Member]
Document Information [Line Items]
Title of 12(b) Security	Series A cumulative redeemable preferred units representing limited partner interests
Trading Symbol	HMLP PRA
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding	6,752,333

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES
Time charter revenues	$ 143,095	$ 145,321	$ 144,952
Other revenue	0	115	1,609
Total revenues	143,095	145,436	146,561
OPERATING EXPENSES
Vessel operating expenses	(24,072)	(30,870)	(24,195)
Administrative expenses	(9,740)	(9,861)	(8,916)
Depreciation and amortization	(20,937)	(21,477)	(21,146)
Total operating expenses	(54,749)	(62,208)	(54,257)
Equity in earnings (losses) of joint ventures	6,420	6,078	17,938
Operating income (loss)	94,766	89,306	110,242
FINANCIAL INCOME (EXPENSE), NET
Interest income	605	947	725
Interest expense	(24,430)	(27,692)	(26,814)
Gain (loss) on debt extinguishment	0	1,030	0
Gain (loss) on derivative instruments	0	0	4,681
Other items, net	(2,232)	(3,575)	(2,907)
Total financial income (expense), net	(26,057)	(29,290)	(24,315)
Income (loss) before tax	68,709	60,016	85,927
Income tax benefit (expense)	(5,564)	(7,275)	(8,305)
Net income (loss)	63,145	52,741	77,622
Preferred unitholders' interest in net income	14,802	13,850	12,303
Limited partners' interest in net income (loss)	48,343	38,891	65,319
Common units public [Member]
FINANCIAL INCOME (EXPENSE), NET
Net income (loss)	$ 25,333	$ 20,186	$ 34,409
Earnings per unit
Earnings per share, basic and diluted	$ 1.40	$ 1.12	$ 1.93
Common units Hegh LNG [Member]
FINANCIAL INCOME (EXPENSE), NET
Net income (loss)	$ 23,010	$ 12,973	$ 4,257
Earnings per unit
Earnings per share, basic and diluted	$ 1.51	$ 1.84	$ 2.03
Subordinated unit Hegh LNG [Member]
FINANCIAL INCOME (EXPENSE), NET
Net income (loss)	$ 0	$ 5,732	$ 26,653
Earnings per unit
Earnings per share, basic and diluted	$ 0	$ 0.70	$ 2.03

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net income (loss)	$ 63,145	$ 52,741	$ 77,622
Unrealized gains (losses) on cash flow hedge	(11,367)	(12,217)	(2,290)
Income tax benefit (expense)	(262)	(389)	(299)
Other comprehensive income (loss)	(11,629)	(12,606)	(2,589)
Comprehensive income (loss)	51,516	40,135	75,033
Preferred unitholders' interest in net income	14,802	13,850	12,303
Limited partners' interest in comprehensive income (loss)	$ 36,714	$ 26,285	$ 62,730

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 31,770	$ 39,126
Restricted cash	7,198	8,066
Trade receivables	415	735
Amounts due from affiliates	3,639	4,296
Advances to joint ventures	3,284	0
Inventory	0	463
Current portion of net investment in financing lease	4,969	4,551
Prepaid expenses and other receivables	3,883	2,534
Total current assets	55,158	59,771
Long-term assets
Restricted cash	12,095	12,627
Accumulated earnings of joint ventures	9,690	3,270
Advances to joint ventures	869	3,831
Vessels, net of accumulated depreciation	619,620	640,431
Other equipment	109	256
Intangibles and goodwill	14,056	17,108
Net investment in financing lease	269,288	274,353
Long-term deferred tax asset	102	217
Other long-term assets	823	936
Total long-term assets	926,652	953,029
Total assets	981,810	1,012,800
Current liabilities
Current portion of long-term debt	59,119	44,660
Trade payables	467	533
Amounts due to owners and affiliates	2,600	2,513
Value added and withholding tax liability	1,445	1,476
Derivative instruments	6,945	2,907
Accrued liabilities and other payables	7,232	11,164
Total current liabilities	77,808	63,253
Long-term liabilities
Long-term debt	355,470	412,301
Revolving credit facility due to owners and affiliates	18,465	8,792
Derivative instruments	19,530	12,028
Long-term tax liability	2,668	2,283
Long-term deferred tax liability	14,430	12,549
Other long-term liabilities	124	84
Total long-term liabilities	410,687	448,037
Total liabilities	488,495	511,290
EQUITY
Accumulated other comprehensive income (loss)	(29,572)	(17,943)
Total partners' capital	493,315	501,510
Total equity	493,315	501,510
Total liabilities and equity	981,810	1,012,800
8.75% Series A Preferred Units [Member]
EQUITY
Total partners' capital	167,760	164,482
Total equity	167,760	164,482
Common units public [Member]
EQUITY
Total partners' capital	308,850	315,176
Total equity	308,850	315,176
Common units Hegh LNG [Member]
EQUITY
Total partners' capital	46,277	39,795
Total equity	46,277	39,795
Subordinated unit Hegh LNG [Member]
EQUITY
Total equity	$ 0	$ 0

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2020	Dec. 31, 2019
8.75% Series A Preferred Units [Member]
General Partners' Capital Account, Units Issued	6,752,333	6,625,590
General Partners' Capital Account, Units Outstanding	6,752,333	6,625,590
Common units public [Member]
General Partners' Capital Account, Units Issued	18,050,941	18,028,786
General Partners' Capital Account, Units Outstanding	18,050,941	18,028,786
Common units Hegh LNG [Member]
General Partners' Capital Account, Units Issued	15,257,498	15,257,498
General Partners' Capital Account, Units Outstanding	15,257,498	15,257,498

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CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Thousands	8.75% Series A Preferred Units [Member]	Common units public [Member]	Common units Hegh LNG [Member]	Subordinated unit Hegh LNG [Member]	Accumulated Other Comprehensive Income [Member]	Total
Balance at Dec. 31, 2017	$ 113,404	$ 317,149	$ 6,513	$ 40,341	$ (2,748)	$ 474,659
Net income	12,303	34,409	4,257	26,653	0	77,622
Cash distributions to unitholders	(13,107)	(31,211)	(3,881)	(24,298)	0	(72,497)
Repayment of indemnifications received from Hoegh LNG	0	0	(325)	(2,028)	0	(2,353)
Cash distributions from Hegh LNG	0	0	234	1,467	0	1,701
Other comprehensive income	0	0	0	0	(2,589)	(2,589)
Net proceeds from issuance of common units	0	4,563	0	0	0	4,563
Net proceeds from issuance of Series A Preferred Units	38,659	0	0	0	0	38,659
Issuance of units for Board of Directors' fees	0	200	0	0	0	200
Other and contributions from owners	0	140	46	286	0	472
Balance at Dec. 31, 2018	151,259	325,250	6,844	42,421	(5,337)	520,437
Net income	13,850	20,186	12,973	5,732	0	52,741
Cash distributions to unitholders	(13,692)	(31,663)	(10,051)	(18,398)	0	(73,804)
Repayment of indemnifications received from Hoegh LNG	0	0	(9)	(55)	0	(64)
Conversion of subordinated units to common units	0	0	29,837	(29,837)	0	0
Other comprehensive income	0	0	0	0	(12,606)	(12,606)
Net proceeds from issuance of common units	0	1,029	0	0	0	1,029
Net proceeds from issuance of Series A Preferred Units	13,065	0	0	0	0	13,065
Issuance of units for Board of Directors' fees	0	194	0	0	0	194
Other and contributions from owners	0	180	201	137	0	518
Balance at Dec. 31, 2019	164,482	315,176	39,795	0	(17,943)	501,510
Net income	14,802	25,333	23,010	0	0	63,145
Cash distributions to unitholders	(14,698)	(31,737)	(28,451)	0	0	(74,886)
Cumulative change in accounting principle (Note 2)	0	(84)	(72)	0	0	(156)
Repayment of indemnifications received from Hoegh LNG						0
Other comprehensive income	0	0	0	0	(11,629)	(11,629)
Net proceeds from issuance of Series A Preferred Units	3,174	0	0	0	0	3,174
Issuance of units for Board of Directors' fees	0	181	0	0	0	181
Contribution from Hegh LNG	0	0	11,850	0	0	11,850
Other and contributions from owners	0	(19)	145	0	0	126
Balance at Dec. 31, 2020	$ 167,760	$ 308,850	$ 46,277	$ 0	$ (29,572)	$ 493,315

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
OPERATING ACTIVITIES
Net income (loss)	$ 63,145	$ 52,741	$ 77,622
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	20,937	21,477	21,146
Equity in (earnings) losses of joint ventures	(6,420)	(6,078)	(17,938)
Changes in accrued interest income on advances to joint ventures	(321)	(295)	(273)
Amortization of deferred debt issuance cost and fair value of debt assumed	2,289	2,361	700
Amortization in revenue for above market contract	3,052	3,631	3,631
Expenditure for drydocking	0	(3,107)	0
(Gain) loss on debt extinguishment	0	(1,030)	0
Changes in accrued interest expense	(435)	2,246	(605)
Receipts from repayment of principal on financing lease	4,551	4,168	0
Unrealized foreign exchange losses (gains)	(380)	360	181
Gain (loss) on the settlement of the derivatives	0	(199)	0
Proceeds from settlement of derivative instruments	0	1,398	0
Unrealized loss (gain) on derivative instruments	173	21	(4,681)
Non-cash revenue: tax paid directly by charterer	(867)	(867)	(852)
Non-cash income tax expense: tax paid directly by charterer	867	867	852
Deferred tax expense and provision for tax uncertainty	2,118	3,707	5,272
Issuance of units for Board of Directors' fees	181	194	200
Other adjustments	123	512	472
Changes in working capital:
Trade receivables	176	543	6,344
Inventory	463	183	22
Prepaid expenses and other receivables	(1,168)	(2,081)	(72)
Trade payables	(80)	(10)	155
Amounts due to owners and affiliates	744	244	842
Value added and withholding tax liability	(633)	2,827	4,257
Accrued liabilities and other payables	(2,690)	1,439	(5,594)
Net cash provided by (used in) operating activities	85,825	85,252	91,681
INVESTING ACTIVITIES
Expenditure for vessel and other equipment	(8)	(269)	(747)
Receipts from repayment of principal on financing lease	0	0	3,814
Net cash provided by (used in) investing activities	(8)	(269)	3,067
FINANCING ACTIVITIES
Proceeds from long term debt	0	368,300	0
Proceeds from revolving credit facility due to owners and affiliates	21,750	3,500	5,400
Repayment of long-term debt	(44,660)	(342,416)	(45,458)
Payment of debt issuance costs	0	(5,797)	0
Repayment of revolving credit facility due to owners and affiliates	0	(34,000)	(17,500)
Repayment of customer loan for funding of value added liability on import	0	(438)	(4,993)
Net proceeds from issuance of common units	0	1,029	4,563
Net proceeds from issuance of Series A preferred units	3,174	13,065	38,659
Cash distributions to limited partners and preferred unitholders	(74,886)	(73,804)	(72,497)
Proceeds from indemnifications received from Hoegh LNG	0	0	1,701
Repayment of indemnifications received from Hoegh LNG	0	(64)	(2,353)
Net cash provided by (used in) financing activities	(94,622)	(70,625)	(92,478)
Increase (decrease) in cash, cash equivalents and restricted cash	(8,805)	14,358	2,270
Effect of exchange rate changes on cash, cash equivalents and restricted cash	49	7	(97)
Cash, cash equivalents and restricted cash, beginning of period	59,819	45,454	43,281
Cash, cash equivalents and restricted cash, end of period	$ 51,063	$ 59,819	$ 45,454

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash and cash equivalents	$ 31,770	$ 39,126	$ 26,326	$ 22,679
Restricted cash - current asset	7,198	8,066	6,003	6,962
Restricted cash - non-current asset	12,095	12,627	13,125	13,640
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$ 51,063	$ 59,819	$ 45,454	$ 43,281

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Description of business

12 Months Ended

Dec. 31, 2020

Description of business

Description of business

1.   Description of business

Höegh LNG Partners LP (the “Partnership”) was formed under the laws of the Marshall Islands on April 28, 2014 as an indirect 100% owned subsidiary of Höegh LNG Holdings Ltd. (“Höegh LNG”) for the purpose of acquiring Höegh LNG’s interests in Hoegh LNG Lampung Pte. Ltd., PT Hoegh LNG Lampung (the owner of the PGN FSRU Lampung), SRV Joint Gas Ltd. (the owner of the Neptune), and SRV Joint Gas Two Ltd. (the owner of the Cape Ann) in connection with the Partnership’s initial public offering of its common units (the “IPO”) in August 2014.

On August 12, 2014, the Partnership completed its IPO. Prior to the closing of the IPO, Höegh LNG contributed to the Partnership all of its equity interests and loans and promissory notes due to it and affiliates in each of the entities owning the Neptune, the Cape Ann and the PGN FSRU Lampung. The transfer of the interests was recorded at Höegh LNG’s consolidated book values. At the closing of the IPO (including the exercise by the underwriters of the option to purchase an additional 1,440,000 common units), (i) 11,040,000 common units were sold to the public for net proceeds, after deduction of offering expenses, of $203.5 million; (ii) Höegh LNG owned 2,116,060 common units and 13,156,060 subordinated units, representing approximately 58% of the limited partner interests in the Partnership, and 100% of the incentive distribution rights (“IDRs”) and (iii) a wholly owned subsidiary of Höegh LNG owned the non-economic general partner interest in the Partnership.

Under the partnership agreement, the general partner has irrevocably delegated to the Partnership’s board of directors the power to oversee and direct the operations of, manage and determine the strategies and policies of the Partnership. Four of the seven board members were elected by the common unitholders at the Partnership’s first annual meeting of unitholders held on September 24, 2014. As a result, Höegh LNG, as the owner of the general partner, does not have the power to control the Partnership’s board of directors or the Partnership, and the Partnership is not considered to be under the control of Höegh LNG for United States generally accepted accounting principles (“US GAAP”) purposes. Therefore, the sale of a business from Höegh LNG to the Partnership is a change of control. As a result, the Partnership accounts for acquisitions of businesses under the purchase method of accounting and not as transfers of entities under common control.

On October 1, 2015, the Partnership closed the acquisition of 100% of the shares in Höegh LNG FSRU III Ltd., the entity that indirectly owned the floating storage and regasification unit (“FSRU”) the Höegh Gallant (the “Höegh Gallant entities”). The Höegh Gallant was constructed by Hyundai Heavy Industries Co., Ltd. (“HHI”) and was delivered to Höegh LNG in November 2014.

In December 2016, the Partnership issued and sold 6,588,389 common units in an underwritten public offering for net proceeds of $111.5 million primarily to fund the purchase price of the acquisition of a 51% ownership interest in Höegh LNG Colombia Holding Ltd., the owner of the entities that own and operate the FSRU Höegh Grace (the “Höegh Grace entities”), in January 2017.

On January 3, 2017, the Partnership closed the acquisition of a 51% ownership interest in Höegh Colombia Holding Ltd. On January 1, 2017, the Partnership entered into an agreement with Höegh LNG, under which Höegh LNG granted to the Partnership the authority to make decisions about operations of Höegh LNG Colombia Holding Ltd. from January 1, 2017 to the closing date of the acquisition. As a result, the Partnership has recorded the results of operations of the Höegh Grace entities in its consolidated statement of income from January 1, 2017

On October 5, 2017, the Partnership issued 4,600,000 8.75% Series A cumulative redeemable preferred units (the “Series A preferred units”) for proceeds, net of underwriting discounts and expenses, of $110.9 million. Refer to note 20. A portion of the net proceeds was used to repay outstanding debt under the seller’s credit note related to the Höegh Gallant acquisition and outstanding debt under the revolving credit facility.

On December 1, 2017, the Partnership closed the acquisition of the remaining 49% ownership interest in the Höegh Grace entities with a combination of cash remaining from the net proceeds from the issuance of Series A preferred units and draws on the revolving credit facility.

On January 26, 2018, the Partnership entered into sales agreement with B. Riley FBR Inc. (the “Agent”). Under the terms of the sales agreement, the Partnership could offer and sell up to $120 million aggregate offering amount of common units and Series A preferred units through the Agent, acting as agent for the Partnership (the “Prior ATM Program”).

On October 18, 2019, the Partnership entered into a sales agreement with the Agent for a new ATM program and terminated the Prior ATM Program. Under the terms of the new sales agreement, the Partnership may offer and sell up to $120 million aggregate offering amount of common units and Series A preferred units, from time to time, through the Agent, acting as an agent for the Partnership. Sales of such units may be made in negotiated transactions that are deemed to be “at the market” offerings, including sales made directly on the New York Stock Exchange or through a market maker other than on an exchange.

The interests in SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., collectively, are referred to as the “joint ventures” and the remaining entities owned by the Partnership, as reflected in the table below are, collectively, referred to as the “subsidiaries” in these consolidated financial statements. The PGN FSRU Lampung, the Höegh Gallant, the Höegh Grace, the Neptune and the Cape Ann are FSRUs and, collectively, referred to in these consolidated financial statements as the vessels or the “FSRUs.” The Tower Yoke Mooring System (the “Mooring”) is an offshore installation that is used to moor the PGN FSRU Lampung to offload the gas into an offshore pipe that transports the gas to a land terminal. PT Hoegh LNG Lampung, Hoegh LNG Cyprus Limited, the owner of the Höegh Gallant, Höegh LNG FSRU IV Ltd., the owner of the Höegh Grace, and the two joint ventures, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., are collectively referred to as the “FSRU-owning entities.”

The Neptune and the Cape Ann operate under long-term time charters with expiration dates in 2029 and 2030, respectively, and, in each case, with an option for the charterer, Global LNG Supply SA, as novated to Total Gas & Power Ltd. in February 2020, both subsidiaries of Total S.A. (“Total”), to extend for up to one additional period of ten years or two additional periods of five years each. The PGN FSRU Lampung, operates under a long term time charter which started in July 2014 with an expiration date in 2034, with an option for the charterer to extend for up to two additional periods of five years each, and uses the Mooring that was constructed, installed and sold to the charterer, PT PGN LNG Indonesia (“PGN LNG”), a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk (“PGN”), a subsidiary of PT Pertamina, a government-controlled, Indonesian oil and gas producer, natural gas transportation and distribution company. The Höegh Gallant operated under a long term time charter which started in April 2015 and expired in April 2020 with Hoegh LNG Egypt LLC (“EgyptCo”), a subsidiary of Höegh LNG. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of the EgyptCo charter until July 2025. On April 30, 2020, the Partnership entered into a lease and maintenance agreement with another subsidiary of Höegh LNG for the time charter of the Höegh Gallant (the “Subsequent Charter”). The Subsequent Charter commenced on May 1, 2020 and expires July 31, 2025. The Höegh Grace operates under a long term time charter which started in December 2016 with Sociedad Portuaria El Cayao S.A. E.S.P. (“SPEC”). SPEC is owned 51% by Promigas S.A. ESP, a Colombian company focused on the transportation and distribution of natural gas, and 49% by private equity investors. The non-cancellable charter period of 10 years ends in December 2026. The initial term of the charter is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if SPEC waives its rights to terminate in year 10 within a certain deadline, the Partnership will not be able to exercise its right to terminate in year 10.

The following table lists the entities included in these consolidated financial statements and their purpose as of December 31, 2020.

	Jurisdiction of
	Incorporation
Name	or Registration	Purpose
Höegh LNG Partners LP	Marshall Islands	Holding Company
Höegh LNG Partners Operating LLC (100% owned)	Marshall Islands	Holding Company
Hoegh LNG Services Ltd (100% owned)	United Kingdom	Administration Services Company
Hoegh LNG Lampung Pte. Ltd. (100% owned)	Singapore	Owns 49% of PT Hoegh LNG Lampung
PT Hoegh LNG Lampung (49% owned) (1)	Indonesia	Owns PGN FSRU Lampung
SRV Joint Gas Ltd. (50% owned) (2)	Cayman Islands	Owns Neptune
SRV Joint Gas Two Ltd. (50% owned) (2)	Cayman Islands	Owns Cape Ann
Hoegh LNG Cyprus Limited (100% owned)	Cyprus	Owns Höegh Gallant
Hoegh LNG Cyprus Limited Egypt Branch (100% owned)	Egypt	Branch of Hoegh LNG Cyprus Limited
Höegh LNG Colombia Holding Ltd. (100% owned)	Cayman Islands	Owns 100% of Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S.
Höegh LNG FSRU IV Ltd. (100% indirectly owned)	Cayman Islands	Owns Höegh Grace
Höegh LNG Colombia S.A.S. (100% indirectly owned)	Colombia	Operating Company

(1) PT Hoegh LNG Lampung is a variable interest entity, which is controlled by Hoegh LNG Lampung Pte. Ltd. and is, therefore, 100% consolidated in the consolidated financial statements.

(2) The remaining 50% interest in each joint venture is owned by Mitsui O.S.K. Lines, Ltd. and Tokyo LNG Tanker Co.

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Significant accounting policies

12 Months Ended

Dec. 31, 2020

Significant accounting policies

Significant accounting policies

2.   Significant accounting policies

Basis of presentation

The consolidated financial statements are prepared in accordance with US GAAP. All intercompany balances and transactions are eliminated.

The consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. Please refer to note 22 for the Partnership’s plan to refinance the Lampung debt facility.

It has been determined that PT Hoegh LNG Lampung, Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd., SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. are variable interest entities. A variable interest entity (“VIE”) is defined by US GAAP as a legal entity where either (a) the voting rights of some investors are not proportional to their rights to receive the expected residual returns of the entity, their obligations to absorb the expected losses of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights, or (b) the equity holders have not provided sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support, or (c) equity interest holders as a group lack the characteristics of a controlling financial interest, including decision making ability and an interest in the entity’s residual risks and rewards. The guidance requires a VIE to be consolidated if any of its interest holders are entitled to a majority of the entity’s residual returns or are exposed to a majority of its expected losses.

Based upon the criteria set forth in US GAAP, the Partnership has determined that PT Hoegh LNG Lampung is a VIE, as the equity holders, through their equity investments, may not participate fully in the entity’s expected residual returns and substantially all of the entity’s activities either involve, or are conducted on behalf of, the Partnership. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of PT Hoegh LNG Lampung are included in the consolidated financial statements. Dividends may only be paid if the retained earnings are positive and a statutory reserve has been established equal to 20% of its paid-up capital under Indonesian law. PT Hoegh LNG Lampung had not established the required statutory reserves as of December 31, 2020 and 2019. Therefore, PT Hoegh LNG Lampung cannot make dividend payments under Indonesian law. Under the Lampung facility, there are limitations on cash dividends and intercompany loans that can be made to the Partnership. Refer to note 12. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $179.9 million and $169.8 million, respectively.

The Partnership has determined that Hoegh LNG Cyprus Limited is a VIE, as the equity investment does not provide sufficient equity to permit the entity to finance its activities without financial support. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Hoegh LNG Cyprus Limited are included in the consolidated financial statements. Under Cyprus law, dividends may only be distributed out of profits and not from the share capital of the company. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

The Partnership has also determined that Höegh LNG Colombia Holding Ltd. is a VIE since the entity would not be able to finance its activities without financial support and financial guarantees under its subsidiary’s facility to finance the Höegh Grace. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives the majority of the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Höegh LNG Colombia Holding Ltd., and subsidiaries, are included in the consolidated financial statements. Under Cayman Islands law, dividends may only be paid out of profits or capital reserves if the entity is solvent after the distributions. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

Dividends and other distributions from Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd. and Höegh LNG FSRU IV Ltd. may only be distributed if after the dividend payment, the Partnership would remain in compliance with the financial covenants under the $385 million facility. Refer to note 12.

In addition, the Partnership has determined that the two joint ventures, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., are VIEs since each entity did not have a sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support. The entities have been financed with third party debt and subordinated shareholder loans. The Partnership is not the primary beneficiary, as the Partnership cannot make key operating decisions considered to be most significant to the VIEs but has joint control with the other equity holders. Therefore, the joint ventures are accounted for under the equity method of accounting as the Partnership has significant influence. The Partnership’s carrying value is recorded in advances to joint ventures and accumulated earnings (losses) of joint ventures in the consolidated balance sheets. For SRV Joint Gas Ltd., the Partnership had a receivable for the advances of $3.3 million and $3.0 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $5.5 million and $2.6 million, respectively, as of December 31, 2020 and 2019. The Partnership’s carrying value for SRV Joint Gas Two Ltd. consists of a receivable for the advances of $0.9 million and $0.8 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $4.2 million and $0.7 million, respectively, as of December 31, 2020 and 2019. The major reason that the Partnership had low accumulated earnings in the joint ventures as of December 31, 2019 and the major reason that the Partnership historically has had accumulated losses in the joint ventures, or net liabilities, is due to the fair value adjustments for the interest rate swaps recorded as liabilities on the balance sheets of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. and eliminations for consolidation to the balance sheet. The maximum exposure to loss is the carrying value of the receivables, which is subordinated to the joint ventures’ long-term bank debt, the investments in the joint ventures (accumulated earnings or losses), as the shares are pledged as security for the joint ventures’ long-term bank debt, and Höegh LNG’s commitment under long-term bank loan agreements to fund its share of drydocking costs and remarketing efforts in the event of an early termination of the charters. If the charters terminate for any reason that does not result in a termination fee, the joint ventures’ long-term bank debt would be subject to mandatory repayment. Dividend distributions require a) agreement of the other joint venture owners; b) fulfilment of requirements of the long-term bank loans; c) and under Cayman Islands law may be paid out of profits or capital reserves subject to the joint venture being solvent after the distribution.

Significant accounting policies

Foreign currencies

The reporting currency in the consolidated financial statements is the U.S. dollar, which is the functional currency of the FSRU-owning entities. Nearly all revenues are received in U.S. dollars and a majority of the Partnership’s expenditures for investments and all of the long-term debt are denominated in U.S. dollars. Transactions denominated in other currencies during the year are converted into U.S. dollars using the exchange rates in effect at the time of the transactions. Monetary assets and liabilities that are denominated in currencies other than the U.S. dollar are translated at the exchange rates in effect at the balance sheet date. Resulting gains or losses are reflected in the accompanying consolidated statements of income.

Business combinations and asset acquisitions

Business combinations are accounted for under the purchase method of accounting. Under this method, the purchase price is allocated to identifiable assets acquired and liabilities assumed based on their fair values as of the acquisition date. Any excess of the purchase price over the fair values of net assets is recognized as goodwill. Acquisition related costs are expensed as incurred. The results of entity acquired are included in the consolidated financial statements from the date of acquisition.

Dependent upon facts and circumstances, the assessment of a transaction may be considered the acquisition of an asset, when substantially all of the fair value of assets acquired is concentrated in a single identifiable asset, rather than a business combination. Asset acquisitions are accounted for by allocating the cost of the acquisition to the individual assets acquired and liabilities assumed on a relative fair value basis. Acquisition related costs are capitalized as a component of the cost of the assets acquired.

Time charter revenue, related contract balances and related expenses

Time charter revenues and related contract balances:

The Partnership is required to evaluate whether two or more contracts should be combined and accounted for as a single contract, whether the contract promises to deliver more than one distinct good or service, or performance obligations, and/or a lease, determine the transaction price under the contract, allocate the transaction price to the lease and the performance obligations and recognize revenue as the performance obligation is satisfied. The Partnership believes the nature of its time charter contracts are the same, regardless of whether the contracts are accounted for as financing leases or operating leases for accounting purposes. As such, when adopting the revised guidance on leases as of January 1, 2019, the Partnership did not elect to apply the practical expedient to not separate lease and services components for operating leases because this would result in inconsistent disclosure for the time charter contracts.

Performance obligations:

The Partnership determined that its time charter contracts contain a lease and a performance obligation for the provision of time charter services. The lease of the vessel, representing the use of the vessel without any associated performance obligations or warranties, is accounted for in accordance with the provisions of Accounting Standards Codification ("ASC") 842, Leases.

The provision of time charter services, including guarantees for the level of performance provided by the time charter contracts, is considered a distinct service and is accounted for in accordance with the provision of ASC 606, Revenue from Contracts with Customers. The Partnership determined that the nature of the time charter services promised, represents a single performance obligation, to stand ready over a 24-hour interval to accept LNG cargos, to transport cargos, to regasify the LNG and discharge the resulting gas into a pipeline in accordance with the charterer’s instructions and requirements.

Time charter services revenue can be recognized as the performance obligation is satisfied over the 24-hour interval to the performance standards specified under the time charter contract. If the performance standards are not met, off-hire, reduced hire, liquidated damages or other performance payments may result.

Contract terms, determination of transaction price and allocation to performance obligations:

The Partnership’s time charter contracts for all FSRUs, except the Höegh Gallant, include day rates or hire rates and warranty provisions with the following components:

● Fixed element: The fixed element is a fixed per day fee intended to cover remuneration for use of the vessel and the provision of time charter services.

● Operating expense reimbursement element: The operating expense reimbursement element is a rate per day intended to cover the operating costs of the vessel, including the crew, insurance, consumables, miscellaneous services, spares and maintenance and repairs costs and management services and fees. The amount of the operating expense reimbursement element may be based on actual cost incurred, or fees subject to indexing or other adjustments after a defined period, or a combination of both.

● Tax reimbursement element: The tax reimbursement element may be a rate per day, based on the estimated liability for the year divided by the number of days in the year, subject to adjustment for actual taxes incurred, or a reimbursement of the costs as the taxes are incurred. The tax reimbursement element may cover withholding taxes, payroll taxes, other local taxes and current income tax expense for the jurisdiction in which the vessel operates as defined by the provisions of the individual time charter contract.

● Performance warranties element: The performance warranties element includes defined operational capacity and standards that can result in the FSRUs being off-hire or require compensation to the charterer through provision of reduced hire, liquidated damages or performance payments. Examples of performance warranties include the ability to discharge regasified LNG at specified performance rates, guaranteed minimum fuel consumption, guaranteed minimum boil-off rates and the ability to accept cargos.

The Höegh Gallant has a single day rate intended to cover all of the elements listed above. In addition, the time charter contract for the Höegh Gallant includes a provision for off-hire for scheduled maintenance. The joint ventures’ time charter contracts also provide for upfront payments for variable costs for certain vessel modifications, drydocking costs, other additions to equipment or spare parts.

The hire rates for the PGN FSRU Lampung and the joint ventures are invoiced at the beginning of the month. The Höegh Gallant and the Höegh Grace invoice time charter revenues monthly in arrears.

The transaction price is estimated as the standalone selling price for the lease and the time charter services components of the fixed day rate element. Variable consideration per day for operating expense and tax reimbursements is estimated at the most likely amount to which the Partnership is expected to be entitled to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty related to the variable consideration is resolved. When there is significant uncertainty related to that amount of variable consideration to be received, that variable consideration is considered constrained. Typically, variable reimbursements and performance warranties are known at the end of each 24-hour interval, or as subsequently reassessed at the end of the reporting period. However, to the extent interpretations of contractual provisions are complex and/or disputed with the customer, this could give rise to constrained variable consideration. Constrained variable consideration is not estimated.

Variable consideration is allocated entirely to one performance obligation when the variable day rate relates specifically to the efforts to satisfy the single performance obligation. The default method of the relative standalone selling price method was used to allocate the remaining transaction price, principally the fixed element, between the lease and the time charter services. The total estimated transaction price for time charter services is considered variable consideration because it may be reduced by performance warranties.

The Partnership has made a policy election to exclude from the measurement of the transaction price all taxes assessed by a government entity on revenues and collected on behalf of that government entity from customers, such as sales or value added taxes.

Lease revenue recognition:

Leases are classified based upon defined criteria either as sale-type/direct financing leases (“financing leases”) or operating leases. A lease that transfers substantially all of the benefits and risks of the FSRU to the charterer is accounted for as a financing lease by the lessor. All other leases that do not meet the criteria are classified as operating leases. On January 1, 2019, when adopting the revised leasing guidance, the Partnership elected the package of practical expedients and did not reassess conclusions under the previous standard about whether any existing contracts are, or contain leases, lease classification, and initial direct costs for any existing leases. Accordingly, outstanding leases on January 1, 2019, continue to be classified in accordance with the prior lease guidance.

The lease component of time charters that are accounted for as operating leases is recognized on a straight-line basis over the term of the charter. The Höegh Gallant’s time charter, which has a five-year lease term, is accounted for as an operating lease. The Höegh Grace’s time charter contracts, which have a non-cancellable charter period of ten years, are accounted for as an operating lease. Under one of the time charter contracts, the contract provides for additional variable payments, including a finance component, over the initial term depending upon the actual commencement date of the contract within a defined window of potential commencement dates. The variable payments are considered directly related to the lease performance obligation. The revenue, excluding the financing component, is recognized over the initial 10-year term. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for final income tax directly related to the provision of the lease is recorded as a component of lease revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

The lease component of time charters that are accounted for as financing leases is recognized over the lease term using the effective interest rate method and is included in time charter revenues. Origination costs related to the time charter are a component of the net investment in financing lease and amortized over the lease term using the effective interest method. Financing leases are reflected on the consolidated balance sheets as net investments in financing leases. The PGN FSRU Lampung time charter, which had a 20-year lease term at inception, meets the criteria of transferring substantially all of the benefits and risks to the charterer and is accounted for as a financing lease.

Time charter services revenue recognition:

Variable consideration for the time charter services performance obligation, including amounts allocated to time charter services, estimated reimbursements for vessel operating expenses and estimated reimbursements of certain types of costs and taxes, are recognized as revenues as the performance obligation for the 24-hour interval is fulfilled, subject to adjustment for off-hire and performance warranties. Constrained variable consideration is recognized as revenue on a cumulative catch-up basis when the significant uncertainty related to that amount of variable consideration to be received is resolved. Estimates for variable consideration, including constrained variable consideration, are reassessed at the end of each period. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes directly related to the provision of the time charter services are recorded as a component of time charter service revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

Joint venture FSRUs lease and time charter services revenue recognition:

The Partnership’s interest in the Joint venture FSRUs’ net income is included in the consolidated financial statements under the equity method of accounting, however, the Joint venture FSRUs’ results are presented under the proportional consolidation method for the segment note (note 3) and the time charter revenue note (note 4). The Neptune’s and the Cape Ann’s time charters, which had a twenty-year lease term at inception, are accounted for as operating leases. The joint ventures’ time charters include provisions for the charterer to make upfront payments to compensate for variable cost for certain vessel modifications, drydocking costs, other additions to equipment or spare parts. The expenditures are considered costs required to fulfill the lease component of the contract. Payments for modifications are deferred and amortized over the shorter of the remaining charter period or the useful life of the additions. Payments for reimbursement of drydocking costs are deferred and recognized on a straight line basis over the period to the next drydocking.

The accounting policy for time charter services for the joint ventures is the same as described above.

Significant judgments in revenue recognition:

The Partnership does not provide stand-alone bareboat leases or time charter services for FSRUs. As a result, observable stand-alone transaction prices for the performance obligations are not available. The estimation of the transaction price for the lease and the time charter service performance obligation is complex, subject to a number of input factors, such as market conditions when the contract is entered into, internal return objectives and pricing policies, and requires substantial judgment. Significant changes in the transaction price between the two performance obligations could impact conclusions on the accounting for leases as financing or operating leases. In addition, variable consideration is estimated at the most likely amount that the Partnership expects to be entitled to. Variable consideration is reassessed at the end of the reporting period taking into account performance warranties. The time charter contracts include provisions for performance guarantees that can result in off-hire, reduced hire, liquidated damages or other payments for performance warranties. Measurement of some of the performance warranties can be complex and require properly calibrated equipment on the vessel, complex conversions and computations based on substantial judgment in the interpretation of the contractual provisions. Conclusions on compliance with performance warranties impact the amount of variable consideration recognized for time charter services.

Contract assets:

Revenue recognized in excess of the monthly invoiced amounts, or accrued revenue, is recorded as contract assets on the consolidated balance sheet. The contract assets are reported in the consolidated balance sheet as a component of prepaid expenses and other receivables.

Contract liabilities:

Advance payments in excess of revenue recognized, or prepayments, and deferred revenue is recorded as contract liabilities on the consolidated balance sheet. Contract assets and liabilities are reported in a net position for each customer contract or combined contracts at the end of each reporting period. Contract liabilities are classified as current or non-current based on the expected timing of recognition of the revenue. Current and non-current contract liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables and other long-term liabilities, respectively.

Refund liabilities:

Amounts invoiced or paid by the customer that are expected to be refunded to the customer are recorded as refund liabilities on the consolidated balance sheet. Refund liabilities may include invoiced amounts for estimated reimbursable operating expenses or other costs and taxes that exceeded the actual costs incurred, or off-hire, reduced hire, liquidated damages, or other payments for performance warranties. Refund liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables.

Remaining performance obligations:

Remaining performance obligations represent the transaction price of contracts with customers under the scope of ASC 606 for which work has not been performed excluding unexercised contract options to extend the term. The Partnership qualifies for and has elected to apply the exemption to disclose the aggregate amount of remaining transaction price allocated to unsatisfied performance obligations at the end of the reporting period as consideration for time charter services is variable and allocated entirely to wholly satisfied performance obligations.

Related expenses:

Voyage expenses include bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls and agency fees. Voyage expenses are all expenses unique to a particular voyage and when a vessel is on hire under time charters are generally the responsibility of, and paid directly by the charterers, and not included in the statement of income. When the vessel is off-hire, voyage expenses, principally fuel, may also be incurred and are paid by the FSRU-owning entity.

Vessel operating expenses, reflected in expenses in the statement of income, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and management fees. Vessel operating expenses also include bunker fuel expenses when the vessel is on hire and the expenses are not directly paid and owed by the charterers. When the vessel is on hire, vessel operating expenses are invoiced as time charter service fees to the charterer or are covered by time charter rates. When the vessel is off-hire, vessel operating expenses are not invoiced to the charterer.

Voyage expenses, if applicable, and vessel operating expenses are expensed when incurred.

Loss contingencies, insurance and other claims

Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. Significant judgment is required to determine the probability and the estimated amount of loss. Such assessments involve complex judgments about future events and estimates and assumptions that are deemed reasonable by management. Accruals are reviewed quarterly and adjusted to reflect the impact of additional information such as the impact of negotiations, advice of legal counsel or settlements.

Insurance claims for property damage are recorded, net of any deductible amounts, for recoveries up to the amount of loss recognized when the claims to insurance carriers are probable of recovery. Claims for property damage in excess of the loss recognized and for loss of revenue during off-hire, whether from insurance providers or indemnification from Höegh LNG, are considered gain contingencies, which are recognized when the proceeds are received.

Indemnification proceeds from Höegh LNG that cover the Partnership’s costs are accounted for following the guidance of the Securities and Exchange Commission’s Staff Accounting Bulletin (“SAB”) Topic 1.B and SAB Topic 5.T. SAB Topic 1.B provides that the separate financial statements of a subsidiary should reflect any costs of its operations which are incurred by the owner on its behalf. SAB Topic 5.T provides that costs should be reflected as an expense in the subsidiary’s financial statements with a corresponding credit to contributed equity.

Income taxes

Income taxes are accounted for using the liability method. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of income tax expense. The amount of non-cash income tax expense is disclosed separately in the consolidated statement of cash flows.

Deferred tax assets and liabilities are recognized for the tax consequences of temporary differences between the tax and the book bases of assets and liabilities. 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.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. If the more-likely-than-not recognition criterion is met, a tax position is measured based on the cumulative amount that is more-likely-than-not of being sustained upon examination by tax authorities to determine the amount of benefit to be recognized in the consolidated financial statements. Interest and penalties related to uncertain tax positions is recognized in income tax expense in the consolidated statement of income.

Cash and cash equivalents

Cash, banks deposits, time deposits and highly liquid investments with original maturities of three months or less are recognized as cash and cash equivalents.

Restricted cash

Restricted cash includes balances deposited with a bank as required under debt facilities to settle withholding tax, other tax liabilities and other current obligations of the entity, and principal and interest payments as required by the debt facilities. Restricted cash is classified as long-term when the settlement is more than 12 months from the balance sheet date.

Trade receivables and allowance for expected credit losses

Trade receivables are recorded at the invoiced amount and do not bear interest. Trade receivables, contract assets and the net investment in a financing lease is initially recorded by including the current expected credit loss of the asset over the life of the contract. The allowance for expected credit losses is a valuation account that is deducted from the amortized cost of the asset to present the net amount expected to be collected. Each period the allowance for expected credit losses is adjusted through earnings to reflect the revised expected credit losses over the remaining lives of the assets. Receivable amounts are written off against the allowance when the asset is confirmed uncollectible. Expected credit losses are estimated using historical credit loss experience, relevant available information, from internal and external sources, relating to current conditions and reasonable and supportable forecasts of economic conditions impacting the collectability of the assets.

Investments in accumulated earnings or losses of and advances to joint ventures

Investments in joint ventures are accounted for using the equity method of accounting. Under the equity method of accounting, investments are stated at initial cost and are adjusted for the Partnership’s proportionate share of earnings or losses and dividend distributions. As of December 31, 2020 and 2019, the Partnership had an accumulated share of earnings and the balance is classified on the consolidated balance sheet as an asset on the line accumulated earnings of joint ventures.

Advances to joint ventures represent loan receivables due from the joint ventures and are recorded at cost. Interest on the advances to joint ventures is recorded to interest income in the consolidated statements of income as incurred. The quarterly payments from joint ventures included a payment of interest for the first month of the quarter and repayment of principal. Interest is accrued for the last two months of the quarter for repayment at the end of the loans after the original principal was fully repaid. The joint ventures repaid the original principal of all shareholder loans during 2016. Payments of interest, including accrued interest repaid at the end of the loans, are treated as return on investment and included as a component of net cash provided by operating activities in the consolidated statement of cash flows. Payments of principal are included as a component of net cash provided by investing activities in the consolidated statement of cash flows.

Investments in joint ventures are evaluated for impairment when events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value below its carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the consolidated statement of income.

Loan receivables are impaired when, based on current information and events, it is probable that the full amount of the receivable will not be collected. The amount of the impairment is measured as the difference between the present value of expected future cash flows discounted at the loan’s effective interest rate and the carrying amount. The resulting impairment amount is recognized in earnings.

Inventory

Inventory consists of bunker fuel maintained on the FSRUs, if it is owned by the FSRU-owning entity. Inventory is stated at the lower of cost or net realizable value. Cost is determined using the first-in, first-out method.

Vessels

All costs incurred during the construction of newbuildings, including interest and supervision and technical costs, are capitalized. The cost of an acquired vessel is the fair value. Vessels are stated at cost less accumulated depreciation. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Depreciation is calculated using an estimated useful life of 35 years for the FSRUs.

Modifications to the vessels, including the addition of new equipment, which improves or increases the operational efficiency, functionality or safety of the vessels, are capitalized. These expenditures are amortized over the estimated useful life of the modification.

Expenditures covering recurring routine repairs and maintenance are expensed as incurred.

Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking. For vessels that are newly built, the "built-in overhaul" method of accounting is applied. Under the built-in overhaul method, costs of the newbuilding are segregated into costs that should be depreciated over the useful life of the vessel and costs that require drydocking at periodic intervals. The drydocking component is amortized until the date of the first drydocking following the delivery, upon which the actual drydocking cost is capitalized and the process is repeated. Costs of drydocking incurred to meet regulatory requirements or improve the vessel’s operating efficiency, functionality or safety are generally capitalized. Costs incurred related to routine repairs and maintenance performed during drydocking are expensed.

Impairment of long-lived assets

Vessels are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. When such events or changes in circumstances are present, the recoverability of vessels is assessed by determining whether the carrying value of such assets will be recovered through undiscounted expected future cash flows. If the vessel’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. An impairment loss is recognized based on the excess of the carrying amount over the fair value of the vessel.

Intangibles and goodwill

Intangible assets are initially measured at their fair value as of the acquisition date of a business combination. All intangible assets of the Partnership have a definite life. Intangible assets with a definite life are amortized over their useful life. Intangible assets with a definite life are tested for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized if the carrying amount exceeds the estimated fair value of the asset.

In determining the useful lives of intangible assets, the expected use of the assets, the contractual provisions that limit the useful life and other economic factors are considered. The contract related intangibles and their useful lives as of the acquisition dates, are as follows:

	Useful life
Intangible category	(Years)
Above market time charter Höegh Gallant	3.4
Option for time charter extension Höegh Gallant	5.3
Above market time charter Höegh Grace	9.5

The intangible for the above market value of the time charter contract associated with the Höegh Gallant was amortized to time charter revenue on a straight line basis over the remaining term of the contract of approximately 3.4 years as of the acquisition date. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of its initial charter until July 2025. On April 30, 2020 the Partnership entered into the Subsequent Charter which commenced on May 1, 2020 and expires July 31, 2025. The intangible for the option for the time charter extension is amortized on a straight line basis over the extension period starting on May 1, 2020, subsequent to impairment testing for recoverability in the preceding periods. The intangible for the above market value of the time charter contract associated with the Höegh Grace is amortized to time charter revenue on a straight line basis calculated per day over the remaining non-cancellable charter term of approximately 9.5 years as of the acquisition date of the initial 51% interest in the Höegh Grace entities.

Goodwill arises when an acquisition is accounted for under the purchase method of accounting. The assets acquired and liabilities assumed are recorded at their fair values as of the acquisition date. Any excess of the consideration over the net assets acquired is recorded as goodwill. Goodwill is not amortized and is tested annually for impairment of value and whenever events or circumstances indicate that the carrying amount may not be recoverable.

Derivative instruments

All derivative instruments are initially recorded at fair value as either assets or liabilities in the consolidated balance sheet and are subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the contract is designated as a hedging instrument and qualifies for hedge accounting.

For derivative instruments that are not designated or that do not qualify for hedge accounting, the changes in the fair value of the derivative instruments are recognized in earnings. In order to designate a derivative as a cash flow hedge, formal documentation of the relationship between the derivative and the hedged item is required. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge.

Interest rate swaps are used for the management of interest rate risk exposure. The interest rate swaps have the effect of converting a portion of the outstanding debt from a floating to a fixed rate over the life of the transactions. As of January 1, 2019, the following accounting policies became effective for cash flow hedges of interest rate swaps.

For interest rate swaps qualifying as cash flow hedges, the fair value of the portion of the derivative instruments included in the assessment of hedge effectiveness ("hedge effectiveness") and the initial fair value of the hedge component excluded from hedge effectiveness are initially recorded in accumulated other comprehensive income as a component of total equity. Subsequent changes in fair value for the portion of the derivative instruments included in hedge effectiveness are recorded in other comprehensive income. In the periods when the hedged items affect earnings (interest expense is incurred for floating interest rate debt), those amounts are transferred from accumulated other comprehensive income to the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. The initial fair value component excluded from hedge effectiveness is amortized to earnings over the life of the hedging instrument. The amortization is recognized on the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. Any difference in the change in fair value of the hedge components excluded from hedge effectiveness and the amount recognized in earnings is recorded as a component of other comprehensive income.

Prospective and retrospective hedge effectiveness is assessed on an ongoing basis. If a cash flow hedge is no longer deemed highly effective, hedge accounting is discontinued. If a cash flow hedge for an interest rate swap is terminated and the originally hedged item is still considered probable of occurring, the gains and losses initially recognized in accumulated other comprehensive income remain there until the hedged item impacts earnings, at which point they are amortized to earnings on a systematic and rational basis to interest expense in the consolidated statement of income. If the hedged items are no longer considered probable of occurring, amounts recognized in total equity are immediately transferred to interest expense in the consolidated statement of income. Cash flows from derivative instruments that are accounted for as cash flow hedges are classified in the same category as the cash flows from the items being hedged.

For the year ended December 31, 2018, changes in the fair value of the effective portion of the derivative instruments qualifying as cash flow hedges were initially recorded in other comprehensive income as a component of total equity. Any hedge ineffectiveness was recognized immediately in earnings, as were any gains and losses or amortization on the portion of the derivative instruments that were excluded from the assessment of hedge effectiveness. In the periods when the hedged items affect earnings, those amounts were transferred from accumulated other comprehensive income to the gain (loss) on derivative instruments line in the consolidated statement of income.

Deferred debt issuance costs and fair value of debt assumed

Debt issuance costs, including arrangement fees and legal expenses, are deferred and presented as a direct deduction from the outstanding principal of the related debt in the consolidated balance sheet and amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the deferred debt issuance costs is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

The discount or premium arising in a business combination for the difference in the fair value of the debt assumed compared to the outstanding principal is reported in the consolidated balance sheet as a direct adjustment to the outstanding principal of the related debt and amortized on an effective interest rate method over the term of the relevant loan. Amortization of fair value of the debt assumed is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the discount or premium is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

Use of estimates

The preparation of financial statements in accordance with US 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. Significant estimates subject to such estimates and assumptions include revenue recognition, purchase price allocation, the useful lives of vessels, drydocking, loss contingencies and the value of derivative instruments.

Recently adopted accounting pronouncements

Allowance for expected credit losses: On January 1, 2020, the Partnership adopted the Financial Accounting Standards Board’s (“FASB”) revised guidance on Financial Instruments – Credit Losses: Measurement of Credit Losses, which replaces the incurred loss methodology with a current expected credit loss (CECL) methodology that requires consideration of a broader range of reasonable and supportable information to estimate credit losses. The new guidance is applicable to financial assets measured at amortized cost, including trade receivables, contract assets and net investment in financing leases and applied with a modified retrospective method. The Partnership recorded a net decrease to retained earnings of $0.16 million as of January 1, 2020 for the cumulative effect of adopting the new standard. The cumulative effect includes allowances for expected credit losses recognized of $0.1 million (related to the net investment in financing lease) and $0.06 million (related to trade receivables). Refer to note 4.

For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard.

On January 1, 2020, the Partnership adopted FASB's revised guidance for Intangibles - Goodwill and Other: Simplifying the test for Goodwill Impairment, which simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The adoption of the standard did not have an impact on the consolidated financial statements.

Recently issued accounting pronouncements

In December 2019, FASB issued revised guidance for Income Taxes – Simplifying the Accounting for Income Taxes. The revised guidance eliminates certain exceptions to the guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance is effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted in interim or annual periods for which public business entities have not yet issued financial statements. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements and related disclosures. The Partnership implemented the revised guidance on January 1, 2021.

In March 2020, FASB issued final guidance for Reference Rate Reform to provide temporary optional expedients and exceptions to the guidance in US GAAP on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. For all types of hedging relationships, the guidance allows an entity to change the reference rate and other critical terms related to reference rate reform without having to dedesignate the relationship. The guidance is effective upon issuance through December 31, 2022. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements for the expected transitions from LIBOR to alternative reference rates. In January 2021 FASB issued an update to the guidance from 2020 to clarify its scope.

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Segment information

12 Months Ended

Dec. 31, 2020

Segment information

Segment information

3.   Segment information

There are two operating segments. The segment profit measure is Segment EBITDA, which is defined as earnings before interest, taxes, depreciation, amortization and impairment, and other financial items (gain (loss) on debt extinguishment, gain (loss) on derivative instruments and other items, net). Segment EBITDA is reconciled to operating income and net income in the segment presentation below. The two segments are “Majority held FSRUs” and “Joint venture FSRUs.” In addition, unallocated corporate costs, interest income from advances to joint ventures and interest expense related to the outstanding balance on the $85 million revolving credit facility and the $385 million facility are included in “Other.”

For the years ended December 31, 2020, 2019 and 2018, Majority held FSRUs includes the financing lease related to the PGN FSRU Lampung and the operating leases related to the Höegh Gallant and the Höegh Grace.

As of December 31, 2020, 2019 and 2018, Joint venture FSRUs include two 50% owned FSRUs, the Neptune and the Cape Ann, that operate under long term time charters with one charterer.

The accounting policies applied to the segments are the same as those applied in the consolidated financial statements, except that i) Joint venture FSRUs are presented under the proportional consolidation method for the segment note and under equity accounting for the consolidated financial statements and ii) internal interest income and interest expense between the Partnership’s subsidiaries that eliminate in consolidation are not included in the segment columns for the other financial income (expense), net line. Under the proportional consolidation method, 50% of the Joint venture FSRUs’ revenues, expenses and assets are reflected in the segment note. Management monitors the results of operations of joint ventures under the proportional consolidation method and not the equity method of accounting.

In time charters, the charterer, not the Partnership, controls the choice of locations or routes the FSRUs serve. Accordingly, the presentation of information by geographical region is not meaningful. The following tables include the results for the segments for the years ended December 31, 2020, 2019 and 2018.

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	143,095	43,572	—	186,667	(43,572)	(1)	$	143,095
Total revenues		143,095	43,572	—	186,667				143,095
Operating expenses		(27,462)	(9,452)	(6,350)	(43,264)	9,452	(1)		(33,812)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,420	(1)		6,420
Segment EBITDA		115,633	34,120	(6,350)	143,403
Depreciation, amortization and impairment		(20,937)	(9,965)	—	(30,902)	9,965	(1)		(20,937)
Operating income (loss)		94,696	24,155	(6,350)	112,501				94,766
Gain (loss) on derivative instruments		—	(6,073)	—	(6,073)	6,073	(1)		—
Other financial income (expense), net		(9,072)	(11,662)	(16,985)	(37,719)	11,662	(1)		(26,057)
Income (loss) before tax		85,624	6,420	(23,335)	68,709	—			68,709
Income tax expense		(5,564)	—	—	(5,564)	—			(5,564)
Net income (loss)	$	80,060	6,420	(23,335)	63,145	—		$	63,145
Preferred unitholders’ interest in net income		—	—	—	—	14,802	(2)		14,802
Limited partners’ interest in net income (loss)	$	80,060	6,420	(23,335)	63,145	(14,802)	(2)	$	48,343

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

	As of December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	619,620	242,226	—	861,846	(242,226)	(1)	$	619,620
Net investment in financing lease		274,257	—	—	274,257	—			274,257
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	4,153	4,153	—			4,153
Total assets		969,278	267,003	12,532	1,248,813	(267,003)	(1)		981,810
Accumulated earnings of joint ventures		—	—	50	50	9,640	(1)		9,690
Expenditures for vessels & equipment		8	75	—	83	(75)	(2)		8
Expenditures for drydocking		—	2	—	2	(2)	(2)		—
Principal repayment financing lease		4,551	—	—	4,551	—			4,551
Amortization of above market contract	$	3,052	—	—	3,052	—		$	3,052

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	145,321	42,433	—	187,754	(42,433)	(1)	$	145,321
Other revenue		115	—	—	115		(1)		115
Total revenues		145,436	42,433	—	187,869				145,436
Operating expenses (2)		(34,266)	(9,044)	(6,465)	(49,775)	9,044	(1)		(40,731)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,078	(1)		6,078
Segment EBITDA		111,170	33,389	(6,465)	138,094
Depreciation, amortization and impairment		(21,477)	(10,030)	—	(31,507)	10,030	(1)		(21,477)
Operating income (loss)		89,693	23,359	(6,465)	106,587				89,306
Gain (loss) on debt extinguishment		1,030	—	—	1,030		(1)		1,030
Gain (loss) on derivative instruments		—	(5,209)	—	(5,209)	5,209	(1)		—
Other financial income (expense), net		(12,511)	(12,072)	(17,809)	(42,392)	12,072	(1)		(30,320)
Income (loss) before tax		78,212	6,078	(24,274)	60,016	—			60,016
Income tax expense		(7,278)	—	3	(7,275)	—			(7,275)
Net income (loss)	$	70,934	6,078	(24,271)	52,741	—		$	52,741
Preferred unitholders’ interest in net income		—	—	—	—	13,850	(3)		13,850
Limited partners’ interest in net income (loss)	$	70,934	6,078	(24,271)	52,741	(13,850)	(3)	$	38,891

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) The Partnership's Indonesian subsidiary was assessed a property tax and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The retroactive assessment was as a result of the issuance of a new regulation in 2019, defining FSRUs as subject to the existing Indonesian property tax law. The property tax and penalties were recorded as a component of vessel operating expenses.

(3) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

	As of December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	640,431	252,789	—	893,220	(252,789)	(1)	$	640,431
Net investment in financing lease		278,904	—	—	278,904	—			278,904
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	3,831	3,831	—			3,831
Total assets		996,201	284,174	16,599	1,296,974	(284,174)	(1)		1,012,800
Accumulated earnings of joint ventures		—	—	50	50	3,220	(1)		3,270
Expenditures for vessels & equipment		211	195	—	406	(195)	(2)		211
Expenditures for drydocking		3,107	913	—	4,020	(913)	(2)		3,107
Impairment/retirement of equipment		—	(75)	—	(75)	75	(2)		—
Principal repayment financing lease		4,168	—	—	4,168	—			4,168
Amortization of above market contract	$	3,631	—	—	3,631	—		$	3,631

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	144,952	43,169	—	188,121	(43,169)	(1)	$	144,952
Other revenue		1,609	—	—	1,609		(1)		1,609
Total revenues		146,561	43,169	—	173,846				146,561
Operating expenses		(27,294)	(10,932)	(5,817)	(44,043)	10,932	(1)		(33,111)
Equity in earnings (losses) of joint ventures		—	—	—	—	17,938	(1)		17,938
Segment EBITDA		119,267	32,237	(5,817)	145,687
Depreciation and amortization		(21,146)	(9,725)	—	(30,871)	9,725	(1)		(21,146)
Operating income (loss)		98,121	22,512	(5,817)	114,816				110,242
Gain (loss) on derivative instruments		4,681	8,496	—	13,177	(8,496)	(1)		4,681
Other financial income (expense), net		(26,381)	(13,070)	(2,615)	(42,066)	13,070	(1)		(28,996)
Income (loss) before tax		76,421	17,938	(8,432)	85,927	—			85,927
Income tax benefit (expense)		(8,253)	—	(52)	(8,305)	—			(8,305)
Net income (loss)	$	68,168	17,938	(8,484)	77,622	—		$	77,622
Preferred unitholders’ interest in net income		—	—	—	—	12,303	(2)		12,303
Limited partners’ interest in net income (loss)	$	68,168	17,938	(8,484)	77,622	(12,303)	(2)	$	65,319

(1) Eliminations reverse each of the income statement line items of the proportional consolidation amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs’ net income (loss) to Equity in earnings (loss) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

For the years ended December 31, 2020, 2019 and 2018, the percentage of consolidated total revenues from the following customers accounted for over 10% of the Partnership’s consolidated total revenues:

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019		2018
PT PGN LNG Indonesia	33	%	33	%	33	%
Höegh LNG	30	%	31	%	31	%
Sociedad Portuaria El Cayao S.A. E.S.P.	37	%	36	%	36	%

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Time charter revenues and related contract balances

12 Months Ended

Dec. 31, 2020

Time charter revenues and related contract balances

Time charter revenues and related contract balances

4.   Time charter revenues and related contract balances

The Partnership presents its revenue by segment, disaggregated by revenue recognized in accordance with accounting standards on leasing and on revenue from contracts with customers for time charter services. In addition, material elements where the nature, amount, timing and uncertainty of revenue and cash flows differ from the monthly invoicing under time charter contracts are separately presented. Revenue recognized for the Majority held FSRUs includes the amortization of above market contract intangibles. Revenue recognized for Joint venture FSRUs include the amortization of deferred revenues related to the charterer’s reimbursements for certain vessel modifications and drydocking costs. As a result, the timing of cash flows differs from monthly time charter invoicing. The Partnership believes the nature of its time charter contracts are the same, regardless of whether the contracts are accounted for as financing leases or operating leases for accounting purposes. As such, the Partnership did not apply the practical expedient in the lease guidance to combine lease and services components for operating leases because this would result in inconsistent disclosure for the time charter contracts.

The following tables summarize the disaggregated revenue of the Partnership by segment for the twelve months ended December 31, 2020, 2019 and 2018:

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	87,948	25,760	—	113,708	(25,760)	$	87,948
Time charter service revenues, excluding amortization		58,199	15,098	—	73,297	(15,098)		58,199
Amortization of above market contract intangibles		(3,052)	—	—	(3,052)	—		(3,052)
Amortization of deferred revenue for modifications & drydock		—	2,714	—	2,714	(2,714)		—
Total revenues (4)	$	143,095	43,572	—	186,667	(43,572)	$	143,095

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	88,889	25,690	—	114,579	(25,690)	$	88,889
Time charter service revenues, excluding amortization		60,063	14,095	—	74,158	(14,095)		60,063
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,648	—	2,648	(2,648)		—
Other revenue (3)		115	—	—	115	—		115
Total revenues (4)	$	145,436	42,433	—	187,869	(42,433)	$	145,436

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization	$	89,215	25,690	—	114,905	(25,690)	$	89,215
Time charter service revenues, excluding amortization		59,368	15,078	—	74,446	(15,078)		59,368
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,401	—	2,401	(2,401)		—
Other revenue (3)		1,609	—	—	1,609	—		1,609
Total revenues (4)	$	146,561	43,169	—	189,730	(43,169)	$	146,561

(1) Eliminations reverse the proportional amounts of revenue for Joint venture FSRUs to reflect the consolidated revenues included in the consolidated income statement. The Partnership’s share of the Joint venture FSRUs revenues is included in Equity in earnings (losses) of joint ventures on the consolidated income statement.

(2) The financing lease revenues comprise about one-fourth of the total lease revenues for the years ended December 31, 2020 and 2019.

(3) Other revenue consists of insurance proceeds received for prior period claims related to repairs under the Mooring warranty and for repairs for the Höegh Gallant. The Partnership was indemnified by Höegh LNG for the cost of the repairs related to the Mooring, subject to repayment to the extent recovered from insurance proceeds. Refer to notes 3 and 17.

(4) Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of total revenues and is disclosed separately in the consolidated statement of cash flows.

The Partnership’s risk and exposure related to uncertainty of revenues or cash flows related to its long-term time charter contracts primarily relate to the credit risk associated with the individual charterers. Payments are due under time charter contracts regardless of the demand for the charterers’ gas output or the utilization of the FSRU.

The consolidated trade receivables, contract assets, contract liabilities and refund liabilities included in the table below, exclude the balances for the Joint venture FSRUs. The Partnership’s share of net assets in the Joint venture FSRUs are recorded in the consolidated balance sheet using the equity method on the line accumulated losses in joint ventures.

The following table summarizes the allocation of consolidated receivables between lease and service components:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Trade receivable for lease	$	2,608	$	2,898
Trade receivable for time charter services		1,506		2,133
Allowance for expected credit losses		(60)		—
Total trade receivable and amounts due from affiliates	$	4,054	$	5,031

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There were no impairment losses for trade receivables for lease or time charter services or contract assets for the year ended December 31, 2019.

The following table summarizes the consolidated contract assets, contract liabilities and refund liabilities to customers, as of December 31, 2020 and 2019:

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2020	$	279	$	(125)
Additions		—		(841)
Reduction for receivables recorded		(18)		—
Reduction for revenue recognized (excluding amortization)		—		10
Reduction for revenue recognized from previous years		—		48
Repayments of refund liabilities to charterer		—		17
Balance December 31, 2020	$	261	$	(891)

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2019	$	—	$	(1,834)
Additions		279		(65)
Reduction for receivables recorded		—		89
Reduction for revenue recognized from previous years		—		497
Repayments of refund liabilities to charterer		—		1,188
Balance December 31, 2019	$	279	$	(125)

Contract assets are reported in the consolidated balance sheet as a component of prepaid expenses and other receivables. Current and non-current contract liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables and other long-term liabilities, respectively. Refund liabilities are reported in the consolidated balance sheet as a component of accrued liabilities and other payables.

The service-related contract asset reflected in the balance sheet relates to accrued revenue for reimbursable costs from charterers.

Refund liabilities to charterers include invoiced revenue to be refunded to charterers for estimated reimbursable costs that exceeded the actual cost incurred and for non-compliance with performance warranties in the time charter contracts that result in reduction of hire, liquidated damages or other performance related payments.

During the year ended December 31, 2019 the major changes in the refund liability to charterers related to the settlement of a 2018 performance claim of $1,101 and the recognition of $497 of revenue related to conclusion of an audit by a charterer related to 2018 reimbursable expenses.

Minimum contractual future revenues:

As of December 31, 2020, the minimum contractual future revenues to be received under the time charters for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace during the next five years and thereafter are as follows:

(in thousands of U.S. dollars)	Service related		Lease related		Total
2021	$	32,369		90,441	$	122,810
2022		32,369		90,441		122,810
2023		32,369		90,441		122,810
2024		32,369		90,441		122,810
2025		27,091		77,717		104,808
Thereafter		96,683		286,467		383,150
Total - undiscounted	$	253,250		725,948	$	979,198
Operating lease			$	321,724
Financing lease				404,224
Discounting effect				(172,499)
Financing lease receivable			$	231,725

The long-term time charter for the PGN FSRU Lampung with PGN LNG has an initial term of 20 years from the acceptance date of October 30, 2014 and the contract expires in 2034. The time charter hire payments began July 21, 2014 when the project was ready to begin commissioning. The lease element of the time charter is accounted for as a financing lease. The minimum contractual future revenues in the table above include the fixed payments for the lease and services elements for the initial term but exclude the variable fees from the charterer for vessel operating expenses and reimbursement of tax expenses. The charterer has an option to purchase the PGN FSRU Lampung, which can be exercised after the third anniversary of the commencement of the charter until the twentieth anniversary, at stated prices in the time charter. The minimum contractual future revenues do not include the unexercised purchase option price. Should the purchase option be exercised in the short to medium term, the contractual price would exceed the net investment in financing lease, but the future hire payments would cease. The time charter also provides options for the charterer to extend the lease term for two five-year periods. Unexercised option periods are excluded from the minimum contractual future revenues.

The long-term time charter for the Höegh Gallant had an initial term of five years from April 2015 and the contract expired in 2020. On February 27, 2020, the Partnership exercised its right to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration or termination of the initial five-year charter until July 2025 at a rate equal to 90% of the rate payable pursuant to the current charter plus any incremental taxes or operating expenses as a result of the new charter. On April 30, 2020, the Partnership entered into a Subsequent Charter with Höegh LNG for the Höegh Gallant. The Subsequent Charter commenced on May 1, 2020 and expires on July 31, 2025. The lease element of the time charter is accounted for as an operating lease. The minimum contractual future revenues in the table above include the fixed payments for the lease element and the services element which also covers the vessel operating expenses and taxes.

The long-term time charter for the Höegh Grace has an initial term of 20 years and the contract expires in 2036. The minimum contractual future revenues in the table above include the fixed payments for the lease element and services element but exclude the variable fees from the charterer for vessel operating expenses and reimbursement of certain taxes. The non-cancellable charter period is 10 years. The initial term of the lease is 20 years. However, each party has an unconditional option to cancel the charter after 10 and 15 years without penalty. However, if the charterer waives its right to terminate in year 10 within a certain deadline, the Partnership will not be able to exercise its right to terminate in year 10. The charterer has an option to purchase the Höegh Grace at a price specified in the Höegh Grace charter in year 15 and year 20 of such charter. The minimum contractual future revenues do not include the unexercised purchase option price. Only the non-cancellable lease period is included the minimum contractual future revenues.

Net investment in financing lease:

The lease element of time charter hire for the PGN FSRU Lampung is recognized over the lease term using the effective interest rate method and is included in time charter revenues. The financing lease is reflected on the consolidated balance sheets as net investment in financing lease, a receivable, as follows:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Minimum lease payments	$	589,074	$	589,074
Unguaranteed residual value		146,000		146,000
Unearned income		(440,345)		(440,345)
Initial direct cost, net		3,095		3,095
Net investment in financing lease at origination		297,824		297,824
Principal repayment and amortization		(23,471)		(18,920)
Allowance for credit loss		(96)		—
Net investment in financing lease at period end		274,257		278,904
Less: Current portion		(4,969)		(4,551)
Long term net investment in financing lease	$	269,288	$	274,353
Net investment in financing lease consists of:
Financing lease receivable	$	231,725	$	240,000
Unguaranteed residual value		42,532		38,904
Net investment in financing lease at period end	$	274,257	$	278,904

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There was no impairment loss, or allowance for doubtful accounts, for the year ended December 31, 2019.

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Financial income (expense), net

12 Months Ended

Dec. 31, 2020

Financial income (expense), net

Financial income (expense), net

5.   Financial income (expense), net

The components of financial income (expense), net are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Interest income	$	605	947	$	725
Interest expense:
Interest expense		(22,003)	(24,950)		(26,077)
Commitment fees		(138)	(381)		(37)
Amortization of debt issuance cost and fair value of debt assumed		(2,289)	(2,361)		(700)
Total interest expense		(24,430)	(27,692)		(26,814)
Gain (loss) on debt extinguishment		—	1,030		—
Gain (loss) on derivative instruments		—	—		4,681
Other items, net:
Foreign exchange gain (loss)		444	(396)		(193)
Bank charges, fees and other		(276)	(297)		(143)
Withholding tax on interest expense and other		(2,400)	(2,882)		(2,571)
Total other items, net		(2,232)	(3,575)		(2,907)
Total financial income (expense), net	$	(26,057)	(29,290)	$	(24,315)

Interest income related to cash balances and interest accrued on the advances to the joint ventures for each of the years ended December 31, 2020, 2019 and 2018. As of January 1, 2019, interest expense includes reclassifications from accumulated other comprehensive income and amortization of the components excluded from hedge effectiveness related to derivatives due to the adoption of the revised guidance for derivatives and hedging. The entire change in fair value of the cash flow hedge included in the assessment of hedge effectiveness is included in other comprehensive income with the result that the hedge ineffectiveness is no longer recognized in earnings. Refer to note 2. For the year ended December 31, 2018, gain (loss) on derivatives included the gain or loss on hedge ineffectiveness as well as amortization related to derivatives. Refer to note 16 for additional information on the types of gains and losses on derivatives included in interest expense for the years ended December 31, 2020 and 2019. Interest expense also includes interest related to the revolving credit facility from Höegh LNG, the $385 million facility, the Lampung facility and the Gallant/Grace facility until January 31, 2019. The gain on debt extinguishment relates to the refinancing of the Gallant/Grace facility with the $385 million facility. When the entities owning the Höegh Gallant and the Höegh Grace were acquired, a premium on the debt under the Gallant facility and the Grace facility was recognized. The unamortized balance was recorded as a gain when the debt was extinguished on January 31, 2019. Refer to notes 12, 14 and 15.

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Income tax

12 Months Ended

Dec. 31, 2020

Income tax

Income tax

6.   Income tax

The components of income tax expense recognized in the consolidated statements of income are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Current tax (benefit) expense	$	3,832	4,126	$	4,759
Deferred tax (benefit) expense for
Change in temporary differences		1,335	3,341		3,290
Tax loss and tax credit carried forward		393	(196)		247
Change in valuation allowance		4	4		9
Total deferred tax (benefit) expense		1,732	3,149		3,546
Total income tax (benefit) expense	$	5,564	7,275	$	8,305

Deferred tax (benefit) expense recognized in the consolidated statements of comprehensive income as a component of other comprehensive income (“OCI”) are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Cash flow hedge derivative instruments	$	262	389	$	299
Deferred tax (benefit) expense recognized in OCI	$	262	389	$	299

The reconciliation of the income before tax at the statutory rate in the Marshall Islands to the actual income tax expense for each year is as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Income before tax	$	68,709	60,016	$	85,927
At applicable statutory tax rate
Amount computed at corporate tax of 0%		—	—		—
Foreign tax rate differences		4,972	5,425		7,513
Permanent differences:
Amended tax return: reinstatement of tax loss carryforward		—	—		—
Tax audit or amended tax return: change in uncertain tax position		385	558		(41)
Non-deductible interest expense		571	1,477		875
Non-deductible withholding tax		625	717		838
Non-deductible loss on derivatives		(114)	120		—
Tax exemptions		(13)	(13)		(36)
Non-deductible other financial items		(106)	194		116
Other non-deductible costs		(18)	45		63
Tax credits		(742)	(1,252)		(1,032)
Adjustment for valuation allowance		4	4		9
Tax expense (benefit) for year	$	5,564	7,275	$	8,305

Deferred income tax assets (liabilities) are summarized as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Deferred tax assets:
Accrued liabilities and other payables	$	124	$	235
Derivative instruments		422		565
Other equipment		8		9
Tax credits carried forward		1,421		1,818
Tax loss carryforward		32		57
Valuation allowance		(32)		(57)
Deferred tax liabilities:
Accrued interest income		(4,575)		(4,123)
Accrued liabilities and other payables		(400)		(385)
Financing lease		(11,328)		(10,451)
Deferred tax assets (liabilities), net	$	(14,328)	$	(12,332)

The Partnership is not subject to Marshall Islands corporate income taxes. The Partnership's subsidiaries incorporated in Singapore, Indonesia, Cyprus, and the UK are subject to tax on their income, and the Partnership's Columbian subsidiary is subject to tax on certain Colombian source income. For the years ended December 31, 2020, 2019 and 2018, the income tax expense principally related to subsidiaries in Indonesia, Singapore and Colombia. The Singapore subsidiary’s taxable income mainly arises from internal interest income. The charterer in Colombia pays certain taxes directly to the Colombian tax authorities on behalf of the Partnership’s subsidiaries that own and operate the Höegh Grace. The tax payments are a mechanism for advance collection of part of the income taxes for the Colombian subsidiary and a final income tax on Colombian source income for the non-Colombian subsidiary. The Partnership concluded these third-party payments to the tax authorities represent income taxes that must be accounted for under the guidance for income taxes. The amount of non-cash income tax expense was $867, $867 and $852 for the years ended December 31, 2020, 2019 and 2018.

For the year ended December 31, 2017, income tax benefits were recorded of $1,486 and $2,228 for the reinstatement of the tax loss carryforward and the reversal of an uncertain tax position, respectively, due to the amendment of the 2016 tax return of the Indonesian subsidiary. The amendment was a result of a reevaluation of the application of the infrastructure industry exemption to regulations introduced in 2016 placing limitations on interest expense deductions. The infrastructure exemption was also applied by the Indonesian subsidiary for the reported income tax expense for the years ended December 31, 2020, 2019 and 2018.

In December of 2018, the Indonesian tax authorities concluded an audit of corporate income tax filings for the Indonesian subsidiary for the years ended December 31, 2013 and 2014. The outcome of the audit reduced the historical tax loss carryforward, mainly due to disallowed expenses, resulting in a settlement of $885 with respect to the unrecognized tax benefits originating in 2013. For the year ended December 31, 2018, tax benefits of $434 were recorded reflecting a reduction to the uncertain tax position originating in 2013 based on the audit’s conclusion. In addition, there was an increase to the uncertain tax position of $418 for a tax position taken in the 2018 tax return which was not more-likely-than-not to be sustained.

For the years ended December 31, 2020 and 2019, there was an increase to the uncertain tax position of $385 and $558, respectively, for a tax position to be taken in the 2020 and 2019 tax return which is not more-likely-than-not to be sustained. As of December 31, 2020 and 2019, the unrecognized tax benefits were $2,668 and $2,283, respectively.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. Changes in the unrecognized tax benefits is summarized below:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Unrecognized tax benefits as of January 1,	$	(2,283)	(1,725)	$	(2,626)
Decrease related to prior year tax positions		—	—		434
Increase related to current year tax positions		(385)	(558)		(418)
Settlements		—	—		885
Unrecognized tax benefits as of December 31,	$	(2,668)	(2,283)	$	(1,725)

Tax loss carryforwards of $256 expire between 2021 and 2025. Tax credits carried forward of $430 and $991 expire in 2021 and 2022, respectively. The tax returns of Singapore and Indonesia are subject to examination for four years and five years, respectively, from the year of filing. For Colombia, tax returns are subject to examination for three years from the due date of the return. The tax returns from the years 2016 and subsequent years remain subject to review for Indonesia and Singapore. For Colombia, tax returns from the years 2017 and subsequent years remain subject to review. Refer to note 17.

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Prepaid expenses and other receivables

12 Months Ended

Dec. 31, 2020

Prepaid expenses and other receivables

Prepaid expenses and other receivables

7.   Prepaid expenses and other receivables

The components of prepaid expenses and other receivables are as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Prepaid expenses	$	2,140	$	752
Other receivables		1,743		1,782
Total other prepaid expenses and other receivables	$	3,883	$	2,534

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Investments in joint ventures

12 Months Ended

Dec. 31, 2020

Investments in joint ventures

Investments in joint ventures

8.   Investments in joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accumulated earnings of joint ventures	$	9,690	$	3,270

The Partnership has a 50% interest in each of SRV Joint Gas Ltd. (owner of the Neptune) and SRV Joint Gas Two Ltd. (owner of the Cape Ann). The following table presents the summarized financial information for 100% of the combined joint ventures on an aggregated basis.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020			2019		2018
Time charter revenues	$	78,687		77,051		$	79,654
Other income		8,457		7,814			6,684
Total revenues		87,144		84,865			86,338
Operating expenses		(18,904)		(18,088)			(21,864)
Depreciation and amortization		(20,546)		(20,524)			(20,065)
Impairment of long-lived assets (1)		—		(149)			—
Operating income		47,694		46,104			44,409
Unrealized gain (loss) on derivative instruments		(12,146)		(10,418)			16,992
Other financial expense, net		(23,324)		(24,144)			(26,140)
Net income (loss)	$	12,224		11,542		$	35,261
Share of joint ventures owned		50	%	50	%		50	%
Share of joint ventures net income (loss) before eliminations		6,112		5,771			17,631
Eliminations		308		307			307
Equity in earnings (losses) of joint ventures	$	6,420		6,078		$	17,938

(1) At the completion of the class renewal survey of the Neptune, certain equipment was identified that was impaired.

	As of
	December 31,
(in thousands of U.S. dollars)	2020			2019
Cash and cash equivalents	$	13,455		$	17,897
Restricted cash		21,264			9,250
Other current assets		178			973
Total current assets		34,897			28,120
Restricted cash		14,656			34,650
Vessels, net of accumulated depreciation		499,318			521,060
Total long-term assets		513,974			555,710
Current portion of long-term debt		199,030			28,297
Amounts and loans due to owners and affiliates		7,278			629
Derivative instruments		14,687			13,089
Refund liabilities (1)		1,040			26,691
Other current liabilities		8,811			10,327
Total current liabilities		230,846			79,033
Long-term debt		176,385			375,091
Loans due to owners and affiliates		1,737			7,663
Derivative instruments		69,618			59,070
Other long-term liabilities		36,040			40,952
Total long-term liabilities		283,780			482,776
Net assets (liabilities)	$	34,245		$	22,021
Share of joint ventures owned		50	%		50	%
Share of joint ventures net assets (liabilities) before eliminations		17,123			11,011
Eliminations		(7,433)			(7,741)
Accumulated earnings (losses) of joint ventures	$	9,690		$	3,270

(1) Refund liabilities include the liability for the boil-off claim and other refundable amounts due to the charterer.

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Advances to joint ventures

12 Months Ended

Dec. 31, 2020

Advances to joint ventures

Advances to joint ventures

9.   Advances to joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Current portion of advances to joint ventures	$	3,284	$	—
Long-term advances to joint ventures		869		3,831
Advances/shareholder loans to joint ventures	$	4,153	$	3,831

The Partnership had advances of $3.3 million and $3.0 million due from SRV Joint Gas Ltd. as of December 31, 2020 and 2019, respectively. The Partnership had advances of $0.9 million and $0.8 million due from SRV Joint Gas Two Ltd. as of December 31, 2020 and 2019, respectively.

The advances consist of shareholder loans where the principal amounts, including accrued interest, are repaid based on available cash after servicing of long-term bank debt. The shareholder loans are due not later than the 12th anniversary of delivery date of each FSRU. The Neptune and the Cape Ann were delivered on November 30, 2009 and June 1, 2010, respectively. The shareholder loans are subordinated to long-term bank debt and the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt. Under terms of the shareholder loan agreements, the repayments shall be prioritized over any dividend payment to the owners of the joint ventures. The shareholder loans bear interest at a fixed rate of 8.0% per year. The other joint venture partners have, on a combined basis, an equal amount of shareholder loans outstanding at the same terms to each of the joint ventures.

The shareholder loans financed part of the construction of the vessels and operating expenses until the delivery and commencement of the operations of the Neptune and the Cape Ann. In 2011, the joint ventures began repaying principal and a portion of the interest expense based on available cash after servicing of the external debt. The quarterly payments have included a payment of interest for the first month of the quarter and a repayment of principal. Interest was accrued for the last two months of the quarter for repayment at the end of the loans after the original principal was fully repaid. The joint ventures repaid the original principal of all shareholder loans during 2016. As of December 31, 2020 and 2019, the outstanding balances are accrued interest on the shareholder loans.

As of September 30, 2017, the joint ventures suspended payments on the shareholder loans pending the outcome of the boil-off claim. As of April 1, 2020, the joint ventures reached an agreement on the boil-off claim requiring settlement during 2020. The outstanding balance on the shareholder loans was classified as long-term as of December 31, 2019. Based on the final settlement of the boil-off claim made in December 2020 in addition to meeting certain conditions for making distributions as described below, the outstanding balance on the shareholder loan due from SRV Joint Gas Ltd. has been classified as current as of December 31, 2020 while the outstanding balance on the shareholder loan due from SRV Joint Gas Two Ltd. has been classified as non-current as of December 31, 2020. Refer to note 17 under “Joint ventures boil-off settlement.” The advances, including accrued interest, can be repaid based on available cash after servicing of long-term bank debt. There are no financial covenants in the joint ventures’ bank debt facilities, but certain other covenants and restrictions apply. Certain conditions apply to making distributions for the shareholder loans or dividends, including meeting a 1.20 historical and projected debt service coverage ratio. As of December 31, 2020, both the 1.20 historical and projected debt service coverage ratios were met by SRV Joint Gas Ltd. As a result, SRV Joint Gas Ltd. qualifies to make payments on the shareholder loans or other distributions. As of December 31, 2020, SRV Joint Gas Two Ltd. did not meet the 1.20 historical debt service coverage ratio but did meet the projected debt service coverage ratio. As a result, no payments on the shareholder loans or other distributions can be made by SRV Joint Gas Two Ltd. until the debt service coverage ratio is met in future periods.

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Vessels and other equipment

12 Months Ended

Dec. 31, 2020

Vessels and other equipment

Vessels and other equipment

10.   Vessels and other equipment

			Dry-
(in thousands of U.S. dollars)	Vessel		docking	Total
Historical cost December 31, 2018	$	706,715	6,667	$	713,382
Additions		183	3,107		3,290
Historical cost December 31, 2019		706,898	9,774		716,672
Depreciation for the year		(19,393)	(1,777)		(21,170)
Accumulated depreciation December 31, 2019		(70,264)	(5,977)		(76,241)
Vessels, net December 31, 2019		636,634	3,797		640,431
Historical cost December 31, 2019		706,898	9,774		716,672
Additions		8	—		8
Historical cost December 31, 2020		706,906	9,774		716,680
Depreciation for the year		(19,398)	(1,421)		(20,819)
Accumulated depreciation December 31, 2020		(89,662)	(7,398)		(97,060)
Vessels, net December 31, 2020	$	617,244	2,376	$	619,620

As of December 31, 2020, other equipment consists principally of office equipment, computers and a right-of-use-asset. As of December 31, 2019, other equipment consists principally of warehouse, office equipment, computers and a right-of-use asset. Other equipment of $308 and $845 is recorded net of accumulated depreciation of $260 and $679 in the consolidated balance sheet as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, the right-of-use assets and lease liability for operating leases was $61 and $91, respectively. Depreciation expense for other equipment was $118, $307 and $159 for the years ended December 31, 2020, 2019 and 2018, respectively.

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Intangibles and goodwill

12 Months Ended

Dec. 31, 2020

Intangibles and goodwill

Intangibles and goodwill

11.   Intangibles and goodwill

			Option
	Above		for time
	market time		charter	Total
(in thousands of U.S. dollars)	charter		extension	Intangibles	Goodwill	Total
Historical cost December 31, 2018	$	22,760	8,000	30,760	251	$	31,011
Amortization for the year		(3,631)	—	(3,631)	—		(3,631)
Accumulated amortization, December 31, 2019		(13,903)	—	(13,903)	—		(13,903)
Intangibles and goodwill, December 31, 2019		8,857	8,000	16,857	251		17,108
Historical cost December 31, 2019		22,760	8,000	30,760	251		31,011
Additions		—	—	—	—		—
Historical cost December 31, 2020		22,760	8,000	30,760	251		31,011
Amortization for the year		(2,030)	(1,022)	(3,052)	—		(3,052)
Accumulated amortization, December 31, 2020		(15,933)	(1,022)	(16,955)	—		(16,955)
Intangibles and goodwill, December 31, 2020	$	6,827	6,978	13,805	251	$	14,056

The following table presents estimated future amortization expense for the intangibles:

(in thousands of U.S. dollars)	Total
2021	$	2,755
2022		2,755
2023		2,755
2024		2,762
2025		2,116
2026 and thereafter	$	662

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Long-term debt

12 Months Ended

Dec. 31, 2020

Long-term debt

Long-term debt

12.   Long-term debt

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Lampung facility:
Export credit tranche	$	79,324	$	94,210
FSRU tranche		18,635		22,812
$385 million facility:
Commercial tranche		230,705		249,635
Export credit tranche		44,500		51,167
Revolving credit tranche		48,300		48,300
Outstanding principal		421,464		466,124
Lampung facility unamortized debt issuance cost		(2,999)		(4,309)
$385 million facility unamortized debt issuance costs		(3,876)		(4,854)
Total debt		414,589		456,961
Less: Current portion of long-term debt		(59,119)		(44,660)
Long-term debt	$	355,470	$	412,301

Lampung facility

In September 2013, PT Hoegh LNG Lampung (the “Borrower”) entered into a secured $299 million term loan facility (the “Lampung facility”) with a syndicate of banks and an export credit agency for the purpose of financing a portion of the construction of the PGN FSRU Lampung and the Mooring. Höegh LNG is the guarantor for the Lampung facility. The facility was drawn in installments as construction was completed. The term loan facility includes two commercial tranches, the FSRU tranche and the Mooring tranche, and the export credit tranche. The interest rates vary by tranche. The full principal amount on the Mooring tranche and accrued interest was repaid in 2014.

The FSRU tranche has an interest rate of LIBOR plus a margin of 3.4%. The interest rate for the export credit tranche is LIBOR plus a margin of 2.3%. The FSRU tranche is repayable quarterly over 7 years with a final balloon payment of $15.5 million due on October 30, 2021. The export credit tranche is repayable in quarterly installments over 12 years assuming the balloon payment of the FSRU tranche is refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the outstanding balance upon maturity of the FSRU tranche. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 4.7% and 6.2% respectively.

The primary financial covenants under the Lampung facility are as follows:

● Borrower must maintain a minimum debt service coverage ratio of 1.10 to 1.00 for the preceding nine-month period tested on each quarterly repayment date;

● Guarantor’s book equity must be greater than the higher of (i) $200 million and (ii) 25% of total assets; and

● Guarantor’s free liquid assets (cash and cash equivalents or available draws on credit facilities) must be greater than $20 million.

As of December 31, 2020 and 2019, the Borrower and the guarantor were in compliance with the financial covenants.

Höegh LNG, as guarantor, has issued the following guarantees related to the Lampung facility that remain in effect as of December 31, 2020: (a) an unconditional and irrevocable on-demand guarantee for the repayment of the balloon repayment installment of the FSRU tranche callable only at final maturity of the FSRU tranche; (b) an unconditional and irrevocable on-demand guarantee for all amounts due in respect of the export credit agent in the event that the export credit agent exercises its prepayment right for the export credit tranche if the FSRU tranche is not refinanced; and (c) an undertaking that, if the time charter is terminated for an event of vessel force majeure, under certain conditions, a guarantee will be provided for the outstanding debt, less insurance proceeds for vessel force majeure. In addition, all project agreements and guarantees are assigned to the bank syndicate and the export credit agent, all cash accounts and the shares in PT Hoegh LNG Lampung and Hoegh LNG Lampung Pte. Ltd. are pledged in favor of the bank syndicate and the export credit agent.

The Lampung facility requires cash reserves that are held for specifically designated uses, including working capital, operations and maintenance and debt service reserves. Distributions are subject to “waterfall” provisions that allocate revenues to specified priorities of use (such as operating expenses, scheduled debt service, targeted debt service reserves and any other reserves) with the remaining cash being distributable only on certain dates and subject to satisfaction of certain conditions, including meeting a 1.20 historical debt service coverage ratio, no default or event of default then continuing or resulting from such distribution and the guarantor not being in breach of the financial covenants applicable to it. The Lampung facility limits, among other things, the ability of the Borrower to change its business, sell or grant liens on its property including the PGN FSRU Lampung, incur additional indebtedness or guarantee other indebtedness, make investments or acquisitions, enter into intercompany transactions and make distributions.

Gallant/Grace facility

The Gallant/Grace facility included two borrowers, the Partnership’s subsidiaries owning the Höegh Gallant and the Höegh Grace. The Gallant/Grace facility included two commercial tranches and the export credit tranche related to the Höegh Gallant (the “Gallant facility”) and a commercial tranche and the export credit tranche related to the Höegh Grace (the “Grace facility”). All of the tranches under the Gallant/Grace facility were cross-defaulted, cross-collateralized and cross-guaranteed. The obligations of the Borrowers were joint and several. The interest rates varied by tranche. Höegh LNG, Höegh LNG Colombia Holding Ltd., Höegh LNG FSRU III Ltd. and the Partnership were guarantors for the facility.

On January 31, 2019, the outstanding balance and the accrued interest of $303.2 million and $1.6 million, respectively, on the Gallant/Grace facility was repaid from the proceeds of the $385 million facility. The unamortized balance of the fair value of debt assumed, or premium, was recorded as a gain when the debt was extinguished. Refer to note 5. The interest rate swaps related to the Gallant/Grace facility were terminated on the same date. Refer to note 16.

$385 million facility

On January 29, 2019, the Partnership entered into a loan agreement with a syndicate of banks to refinance the outstanding balances of the Gallant/Grace facility. Höegh LNG Partners LP is the borrower (the “Borrower”) for the senior secured term loan and revolving credit facility (the “$385 million facility”). The aggregate borrowing capacity is $320 million on the senior secured term loan and $63 million on the revolving credit tranche. Hoegh LNG Cyprus Limited, which owns the Höegh Gallant, and Höegh LNG FSRU IV Ltd., the owner of the Höegh Grace (collectively, the "Vessel Owners"), and Höegh LNG Colombia S.A.S., are guarantors for the facility (collectively, the "guarantors"). The facility is secured by, among other things, a first priority mortgage of the Höegh Gallant and the Höegh Grace, an assignment of the Hoegh LNG Cyprus Limited’s, Höegh LNG FSRU IV Ltd.’s, Höegh LNG Colombia S.A.S.’s rights under their respective time charters and earnings and a pledge of the Borrower’s and Guarantor’s cash accounts. The Partnership and its subsidiaries have provided a pledge of shares in Hoegh LNG Cyprus Limited, Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S

The senior secured term loan related to the $385 million facility includes a commercial tranche and the export credit tranche. Each tranche is divided into two term loans for each of the Höegh Gallant and the Höegh Grace.

On January 31, 2019, the Partnership drew $320 million under the commercial and the export credit tranches on the $385 million facility to settle $303.2 million and $1.6 million of the outstanding balance and accrued interest, respectively, on the Gallant/Grace facility and used proceeds of $5.5 million to pay arrangement fees due under the $385 million facility. The remaining proceeds of $9.6 million were used for general partnership purposes. On August 12, 2019, the Partnership drew $48.3 million under the revolving credit tranche of the $385 million facility, of which $34.0 million was used to repay part of the outstanding balance on the $85 million revolving credit facility due to Höegh LNG.

The commercial tranche and the revolving credit tranche related to the $385 million facility have an interest rate of LIBOR plus a margin of 2.30%. The commitment fee on the undrawn portion of the revolving credit tranche is approximately 1.6%. The interest rate for the export credit tranche related to the $385 million facility have fixed interest rates and guarantee commissions of 3.98% and 3.88% on the term loans related to the Höegh Gallant and the Höegh Grace, respectively. The commercial tranche is repayable quarterly with a final balloon payment of $136.1 million due in January 2026. The term loans for export credit tranche related to the Höegh Gallant and the Höegh Grace are repayable in quarterly installments with the final payments in October 2026 and April 2028, respectively, assuming the balloon payments of the commercial tranches are refinanced. If not, the export credit agent can exercise a prepayment right for repayment of the total outstanding balance on both the terms loans of the export credit tranche of $9.5 million upon maturity of the commercial tranche. Any outstanding balance on the revolving credit facility is due in full in January 2026. The weighted average interest rate, excluding the impact of the associated interest rate swaps, for the years ended December 31, 2020 and 2019 was 3.4% and 4.7%, respectively.

The primary financial covenants under the $385 million facility are as follows:

●     The Partnership must maintain

o     Consolidated book equity (excluding hedge reserves and mark to market value of derivatives) equal to the greater of

● 25% of total assets, and

● $150 million

o     Consolidated working capital (current assets, excluding intercompany receivables and marked-to-market value of any financial derivative, less current liabilities, excluding intercompany payables, marked-to-market value of any financial derivative and the current portion of long-term debt) shall at all times be greater than zero

o     Minimum liquidity (cash and cash equivalents and available draws under a bank credit facility for a term of more than 12 months) equal to the greater of

● $15 million, and

● $2.5 million multiplied by the number of vessels owned or leased by the Partnership (prorated for partial ownership), subject to a cap of $20 million

o     A ratio of combined EBITDA for the Vessel Owners to debt service (principal repayments, guarantee commission, commitment fees and interest expense) for the preceding twelve months of a minimum of 115%

As of December 31, 2020 and 2019, the Borrower and the Vessel Owners were in compliance with the financial covenants.

In addition, a security maintenance ratio based on the aggregate market value of the Höegh Gallant, the Höegh Grace and any additional security must be at least 125% of the aggregate outstanding loan balance.

If the security maintenance ratio is not maintained, the relevant Borrower has 30 days to provide more security or to repay part of the loan to be in compliance with the ratio no later than 30 days after notice from the lenders.

Under the $385 million facility, cash accounts are freely available for the use of the Borrower and the guarantors, unless there is an event of default. Events of default include, among other things, change of control of Höegh LNG or the Partnership due to the failure of Höegh LNG to own at least 25% of the Partnership’s common units. Cash can be distributed as dividends or to service loans of owners and affiliates provided that after the distribution the Borrower and the guarantors would remain in compliance with the financial covenants. The $385 million facility limits, among other things, the ability of the Borrower and the guarantors to change their business, grant liens on the Höegh Gallant or the Höegh Grace, incur additional indebtedness that is not at pari passu with the $385 million facility, enter into intercompany debt that is not subordinated to the $385 million facility and for the Vessel Owners to make investments or acquisitions.

The principal on long-term debt outstanding as of December 31, 2020 was repayable as follows:

(in thousands of U.S. dollars)	Total
2021	$	123,557
2022		25,597
2023		25,597
2024		25,597
2025		25,597
2026 and thereafter		195,519
Total	$	421,464

The table includes the maturity of the FSRU tranche of the Lampung facility in 2021 and assumes the exercise of the prepayment right for the export credit tranche of the Lampung facility in the same period.

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Accrued liabilities and payables

12 Months Ended

Dec. 31, 2020

Accrued liabilities and payables

Accrued liabilities and payables

13.   Accrued liabilities and other payables

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accrued operating and administrative expenses	$	3,042	$	3,314
Accrued property tax		—		3,033
Accrued interest		2,641		2,850
Current tax payable		469		818
Refund liabilities (note 4)		891		125
Lease liability (note 2 and note 10)		39		75
Other accruals and payables		150		949
Total accrued liabilities and other payables	$	7,232	$	11,164

Refer to note 4 for additional information on the refund liability to charterers. Refer to notes 2 and 10 for additional information on the lease liability.

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Related party transactions

12 Months Ended

Dec. 31, 2020

Related party transactions

Related party transactions

14.   Related party transactions

Income (expenses) from related parties

As described in Related party agreements below, subsidiaries of Höegh LNG have provided administrative services to the Partnership and ship management and/or technical support services for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace, as well as leasing the Höegh Gallant.

Related party amounts included in the consolidated statements of income for the years ended December 31, 2020, 2019 and 2018 or included in the consolidated balance sheets as of December 31, 2020 and 2019 are as follows:

(in thousands of U.S. dollars)	2020		2019	2018
Revenues
Time charter revenue Höegh Gallant (1)	$	45,274	47,173	$	47,108
Operating expenses
Vessel operating expenses (2)		(21,328)	(24,523)		(21,520)
Hours, travel expense and overhead (3) and Board of Directors’ fees (4)		(4,353)	(4,072)		(3,671)
Financial (income) expense
Interest income from joint ventures (5)		321	295		273
Interest expense and commitment fees to Höegh LNG (6)		(64)	(1,882)		(2,938)
Total	$	19,850	16,991	$	19,252

	As of
Balance sheet	December 31,
(in thousands of U.S. dollars)	2020		2019
Equity
Contribution from Höegh LNG (7)	$	11,850	$	—
Repayment of indemnification received from Höegh LNG (8)		—		(64)
Issuance of units for Board of Directors’ fees (4)		181		194
Other and contribution from owner (9)		109		485
Total	$	12,140	$	615

1) Time charter revenue Höegh Gallant: Subsidiaries of Höegh LNG, have leased the Höegh Gallant.

2) Vessel operating expenses: Subsidiaries of Höegh LNG provide ship management of vessels, including crews and the provision of all other services and supplies.

3) Hours, travel expenses and overhead: Subsidiaries of Höegh LNG provide management, accounting, bookkeeping and administrative support under administrative service agreements. These services are charges based upon the actual hours incurred for each individual as registered in the time-write system based on a rate which includes a provision for overhead and any associated travel expenses.

4) Board of Directors’ fees: Total Board of Directors’ fees were $571, $496 and $501 for the years ended December 31, 2020, 2019 and 2018, respectively. Part of the compensation is awarded as common units of the Partnership. Effective September 4, 2020, a total of 15,528 common units were awarded to non-employee directors as compensation of $162 for part of directors’ fees for 2020 under the Höegh LNG Partners LP Long Term Incentive Plan. Effective June 4, 2019 and June 6, 2018, a total of 11,180 and 11,050 common units, respectively, of the Partnership were awarded to non-employee directors as compensation of $194 and $200, respectively, for part of directors’ fees for 2019 and 2018. The awards were recorded as administrative expense and as an issuance of common units. Common units are recorded when issued.

5) Interest income from joint ventures: The Partnership and its joint venture partners have provided subordinated financing to the joint ventures as shareholder loans. Interest income for the Partnership’s shareholder loans to the joint ventures is recorded as interest income.

6) Interest expense and commitment fees to Höegh LNG and affiliates: Höegh LNG and its affiliates provided an $85 million revolving credit facility for general partnership purposes. The Partnership incurred a commitment fee on the undrawn balance until January 29, 2018 and an interest expense on the drawn balance.

7) Non-cash contribution from/distribution to Höegh LNG: As described under “Indemnification” below, on April 8, and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint-ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. These non-cash settlements, totaling $11.9 million, were recorded as an increase in equity.

8) Cash contribution from/distribution to Höegh LNG: As described under “Indemnifications” below, Höegh LNG made indemnification payments to the Partnership or received refunds of indemnification from the Partnership which were recorded as contributions or distributions to equity.

9) Other and contribution from owner: Höegh LNG granted share-based incentives to certain key employees whose services benefit the Partnership. Related expenses are recorded as administrative expenses and as a contribution from owner since the Partnership is not invoiced for this employee benefit. Effective March 26, 2020, March 21, 2019 and September 14, 2018, the Partnership granted or extended the terms for 8,100, 10,917 and 28,018 phantom units, respectively, to the Chief Executive Officer and Chief Financial Officer of the Partnership. Related expenses are recorded over the vesting period as an administrative expense and as increase in equity. On August 6, 2020, the Partnership announced that the Partnership’s Chief Executive Officer and Chief Financial Officer resigned, which resulted in 15,378 of the phantom units not vesting, resulting in a reduction in administration expense and equity for the forfeited units. The remaining 4,861 unvested phantom units will vest in 2021.

Dividends to Höegh LNG: The Partnership has declared and paid quarterly distributions totaling $28.5 million, $28.4 million and $28.2 million to Höegh LNG for each of the years ended December 31, 2020, 2019 and 2018, respectively.

Receivables and payables from related parties

Amounts due from affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due from affiliates	$	3,639	$	4,296

The amount due from affiliates relates to a receivable for time charter hire from subsidiaries of Höegh LNG for the Höegh Gallant time charter and prefunding for intercompany services. The time charter hire is due 18 days from the receipt of the invoice. Time charter hire is invoiced at the end of the month in arrears.

Amounts due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due to owners and affiliates	$	2,600	$	2,513

As of December 31, 2020 and 2019 amounts due to owners and affiliates principally relate to trade payables for services provided by subsidiaries of Höegh LNG.

Revolving credit facility due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Revolving credit facility due to owners and affiliates - non-current portion	$	18,465	$	8,792

In August 2014, upon the closing of the IPO, the Partnership entered into an $85 million revolving credit facility with Höegh LNG, to be used to fund acquisitions and working capital requirements of the Partnership. The credit facility is unsecured and was repayable on January 1, 2020. On May 28, 2019, the repayment date on the $85 million revolving credit facility was extended to January 1, 2023 and the terms amended for the interest rate to be LIBOR plus a margin of 1.4% in 2019, 3.0% in 2020 and 4.0% thereafter. On April 8, and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures’ boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the revolving credit facility. On April 24, 2020, August 7, 2020 and October 23, 2020, the Partnership drew $4.5 million, $6.6 million and $10.7 million, respectively, on the revolving credit facility. The outstanding revolving credit facility had a weighted average interest rate for the years ended December 31, 2020 and 2019 of 3.6% and 6.6%, respectively.

Related party agreements

In connection with the IPO the Partnership entered into several agreements including:

(i) An $85 million revolving credit facility with Höegh LNG, which was undrawn at the closing of the IPO;

(ii) An omnibus agreement with Höegh LNG, the general partner, and Höegh LNG Partners Operating LLC (the “operating company”) governing, among other things:

a. To what extent the Partnership and Höegh LNG may compete with each other;

b. The Partnership’s rights of first offer on certain FSRUs and LNG carriers operating under charters of five or more years; and

c. Höegh LNG’s provision of certain indemnities to the Partnership.

(iii) An administrative services agreement with Hoegh LNG Services Ltd., UK (“Höegh UK”), pursuant to which Höegh UK provided certain administrative services to the Partnership. This agreement expired during 2019; and

(iv) Höegh UK entered into administrative services agreements with Höegh LNG AS (“Höegh Norway”) and Leif Höegh (U.K.) Limited, pursuant to which Höegh Norway and Leif Höegh (U.K.) Limited provided Höegh UK certain administrative services. Additionally, the operating company entered into an administrative services agreement with Leif Höegh (U.K.) Limited to allow Leif Höegh (U.K.) Limited to provide services directly to the operating company. Each of these agreements expired, or were terminated by mutual agreement, during 2019.

Existing agreements remained in place following the IPO for provision of certain services to the Partnership’s vessel owning joint ventures or entity, of which the material agreements are as follows:

● The joint ventures are parties to ship management agreements with Höegh LNG Fleet Management AS (“Höegh LNG Management”) pursuant to which Höegh LNG Management provides the joint ventures with technical and maritime management and crewing of the Neptune and the Cape Ann, and Höegh Norway is a party to a sub-technical support agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides technical support services with respect to the PGN FSRU Lampung; and

● The joint ventures are parties to commercial and administration management agreements with Höegh Norway, and PT Hoegh LNG Lampung is a party to a technical information and services agreement with Höegh Norway.

Subsequent to the IPO, the Partnership has acquired vessel owning entities. Existing agreements remained in place following the acquisition for the time charter of the Höegh Gallant and receipt of certain services, of which the material agreements are as follows:

● Hoegh LNG Cyprus Limited acting through its Egyptian Branch had a lease and maintenance agreement (the “time charter”) with EgyptCo for the lease and maintenance of the Höegh Gallant and the provision of crew and certain ship management services for a combined daily hire rate. The time charter started in April 2015 and expired in April 2020;

● Hoegh LNG Cyprus Limited is party to a ship management agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides the technical management of the Höegh Gallant, and Hoegh LNG Maritime Management Pte. Ltd. (“Höegh Maritime Management”) is a party to a secondment agreement, as amended, with Hoegh LNG Cyprus Limited pursuant to which Höegh Maritime Management provides qualified crew for the Höegh Gallant; and

● Hoegh LNG Cyprus Limited is party to a management agreement with Höegh Norway, pursuant to which Höegh Norway provides administrative, commercial and technical management services, each as instructed from time to time by Hoegh LNG Cyprus Limited.

Existing agreements remained in place for the time charter of the Höegh Grace following the acquisition and receipt of certain services, of which the material agreements are as follows:

● a ship management agreement with Höegh LNG Management pursuant to which Höegh LNG Management provides technical and maritime management services;

● a manning agreement with Höegh Fleet Services Philippines Inc. to recruit and engage crew for the vessel;

● a technical services agreement with Höegh Norway to provide technical services for the vessel;

● a management consulting agreement with Höegh Norway to provide support related to certain management activities;

● a crew recruitment consulting services agreement with Höegh Maritime Management to provide professional consulting services in connection with recruitment of crew and other employees;

● an agreement for provision of professional payment services with Höegh Maritime Management to provide services in connection with the payment of monthly salaries to the crew and employees working on the vessel; and

● a spare parts procurement and insurance services agreement with Höegh LNG Management to arrange for the supply of spare parts and the insurance coverage for the vessel.

In December 2019, the Partnership and the operating company entered into an administrative services agreement with Höegh Norway, pursuant to which Höegh Norway provides certain administrative services to the Partnership.

On April 30, 2020, the Partnership entered into a lease and maintenance agreement with a subsidiary of Höegh LNG for the time charter of the Höegh Gallant and the provision of crew and certain ship management services for use as either an FSRU or an LNG carrier for a combined daily hire rate. The terms of the agreement were approved by the Partnership’s board of directors and the conflicts committee. The Subsequent Charter commenced on May 1, 2020 and expires July 31, 2025.

Indemnifications

Environmental indemnifications:

Under the omnibus agreement, Höegh LNG agreed to indemnify the Partnership until August 12, 2019 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to the Partnership to the extent arising prior to the time they were contributed or sold to the Partnership. No indemnification claims were filed for environmental liabilities under the agreement prior to its expiration.

Other indemnifications:

Under the omnibus agreement Höegh LNG also agreed to indemnify the Partnership for losses:

1. related to certain defects in title to the assets contributed or sold to the Partnership and any failure to obtain, prior to the time they were contributed to the Partnership, certain consents and permits necessary to conduct the business, which liabilities arose within three years after the closing of the IPO;

2. related to certain tax liabilities attributable to the operation of the assets contributed or sold to the Partnership prior to the time they were contributed or sold;

3. in the event that the Partnership did not receive hire rate payments under the PGN FSRU Lampung time charter for the period commencing on August 12, 2014 through the earlier of (i) the date of acceptance of the PGN FSRU Lampung or (ii) the termination of such time charter. The Partnership was indemnified by Höegh LNG for the September and October 2014 invoices not paid by PGN LNG in 2014 (refer to note 17);

4. with respect to any obligation to pay liquidated damages to PGN LNG under the PGN FSRU Lampung time charter for failure to deliver the PGN FSRU Lampung by the scheduled delivery date set forth in the PGN FSRU Lampung time charter;

5. with respect to any non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project (including the construction of the Mooring) occurring prior to the date of acceptance of the PGN FSRU Lampung pursuant to the time charter; and

6. pursuant to a letter agreement dated August 12, 2015, Höegh LNG confirmed that the indemnification provisions of the omnibus agreement include indemnification for all non-budgeted, non-creditable Indonesian value added taxes and non-budgeted Indonesian withholding taxes, including any related impact on cash flow from PT Hoegh LNG Lampung and interest and penalties associated with any non-timely Indonesian tax filings related to the ownership or operation of the PGN FSRU Lampung and the Mooring whether incurred (i) prior to the closing date of the IPO, (ii) after the closing date of the IPO to the extent such taxes, interest, penalties or related impact on cash flows relate to periods of ownership or operation of the PGN FSRU Lampung and the Mooring and are not subject to prior indemnification payments or deemed reimbursable by the charterer under its audit of the taxes related to the PGN FSRU Lampung time charter for periods up to and including June 30, 2015, or (iii) after June 30, 2015 to the extent withholding taxes exceed the minimum amount of withholding tax due under Indonesian tax regulations due to lack of documentation or untimely withholding tax filings.

No indemnification claim was filed or received for the year ended December 31, 2020. For the years ended December 31, 2019 and 2018, the Partnership refunded to Höegh LNG approximately $0.1 million and $2.4 million, respectively, related to insurance proceeds received related to the warranty provision and costs for previous years determined to be reimbursable by the charterer. For the year ended December 31, 2018, the Partnership received indemnification payment from Höegh LNG for non-budgeted expenses (including warranty provisions, other non-budgeted expenses and replacement capital expenditure) of $0.9 million which was recorded as a contribution to equity. Indemnification payments received from Höegh LNG are subject to repayment to the extent the amounts are subsequently recovered from insurance or deemed reimbursable by the charterer. Refer to note 17.

Under the contribution, purchase and sale agreement entered into with respect to the purchase of the Höegh Gallant entities, Höegh LNG will indemnify the Partnership for:

1. losses from breach of warranty;

2. losses related to certain environmental and tax liabilities attributable to the operation of the Höegh Gallant prior to the closing date;

3. all capital gains tax or other export duty incurred in connection with the transfer of the Höegh Gallant outside of Höegh LNG Cyprus Limited’s permanent establishment in a Public Free Zone in Egypt;

4. any recurring non-budgeted costs owed to Höegh LNG Management with respect to payroll taxes;

5. any non-budgeted losses suffered or incurred in connection with the commencement of services under the time charter with EgyptCo or EgyptCo’s time charter with EGAS; and

6. liabilities under the Gallant/Grace facility not attributable to the Höegh Gallant.

No indemnification claims were filed or received for the years ended December 31, 2020 and 2019. For the year ended December 31, 2018, the Partnership received an indemnification payment from Höegh LNG for losses incurred in connection with the time charter with EgyptCo of $0.5 million which was recorded as a contribution to equity. Refer to note 17.

Under the contribution, purchase and sale agreements entered into with respect to the acquisitions of the 51% and 49% ownership interests in the Höegh Grace entities, Höegh LNG will indemnify the Partnership for:

1. losses from breach of warranty;

2. losses related to certain environmental liabilities, damages or repair costs and tax liabilities attributable to the operation of the Höegh Grace prior to the closing date;

3. any recurring non-budgeted costs owed to tax authorities with respect to payroll taxes, taxes related to social security payments, corporate income taxes (including income tax for equality and surcharge on income tax for equality), withholding tax, port associations, local Cartagena tax, and financial transaction tax, including any penalties associated with taxes to the extent not reimbursed by the charterer; and

4. any non-budgeted losses suffered or incurred in connection with commencement of services under the Höegh Grace charter with SPEC.

No indemnification claims were filed or received for the years ended December 31, 2020, 2019 and 2018. Refer to note 17.

On September 27, 2017, the Partnership entered into an indemnification agreement with Höegh LNG with respect to the boil-off claims under the Neptune and Cape Ann time charters, pursuant to which Höegh LNG will, among other things, indemnify the Partnership for its share of any losses and expenses related to or arising from the failure of either Neptune or Cape Ann to meet the performance standards related to the daily boil-off of LNG under their respective time charters (including any cash impact that may result from any settlement with respect to such claims) For the year ended December 31, 2018 the Partnership received indemnification payments of $0.3 million from Höegh LNG. For the year ended December 31, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint-ventures boil-off settlement payments to its charter by a reduction of $11.9 million on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. Indemnification payments and the non-cash settlements were recorded as contribution to equity and increases to equity respectively. Refer to note 17 to our consolidated financial statements.

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Financial Instruments

12 Months Ended

Dec. 31, 2020

Financial Instruments

Financial Instruments

15.   Financial Instruments

Fair value measurements

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Cash and cash equivalents and restricted cash – The fair value of the cash, cash equivalents, and restricted cash approximates its carrying amounts reported in the consolidated balance sheets.

Amounts due from (to) owners and affiliates – The fair value of the non-interest bearing receivables or payables approximates their carrying amounts reported in the consolidated balance sheets since the receivables or payables are to be settled consistent with trade receivables and payables.

Derivative instruments – The fair values of the interest rate swaps are estimated based on the present value of cash flows over the term of the instruments based on the relevant LIBOR interest rate curves, adjusted for the subsidiary’s credit worthiness and the credit worthiness of the counterparty to the derivative.

Advances (shareholder loans) to joint ventures – The fair values of the fixed rate subordinated shareholder loans are estimated using discounted cash flow analyses based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the joint ventures.

Lampung and $385 million facilities – The fair values of the variable rate debt are estimated based on the present value of cash flows over the term of the instruments based on the estimated currently available margins and LIBOR interest rates as of the balance sheet date for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

Revolving credit due to owners and affiliates – The fair value of the variable rate debt is estimated based on the present value of cash flows over the term of the instruments based on the estimated currently available margins and LIBOR interest rates as of the balance sheet date for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

The fair value estimates are categorized by a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value as follows:

Level 1: Observable inputs such as quoted prices in active markets;

Level 2: Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The following table includes the estimated fair value and carrying value of those assets and liabilities that are measured at fair value on a recurring and non-recurring basis, as well as the estimated fair value of the financial instruments that are not accounted for at a fair value on a recurring basis. Trade payables and receivables for which the estimated fair values are equivalent to carrying values are not specified below.

		As of			As of
		December 31, 2020			December 31, 2019
		Carrying		Fair	Carrying	Fair
		amount		value	amount	value
		Asset		Asset	Asset	Asset
(in thousands of U.S. dollars)	Level	(Liability)		(Liability)	(Liability)	(Liability)
Recurring:
Cash and cash equivalents	1	$	31,770	31,770	39,126	$	39,126
Restricted cash	1		19,293	19,293	20,693		20,693
Derivative instruments	2		(26,475)	(26,475)	(14,935)		(14,935)
Other:
Amounts due from affiliate	2		3,639	3,639	4,296		4,296
Advances (shareholder loans) to joint ventures	2		4,153	4,305	3,831		4,029
Current amounts due to owners and affiliates	2		(2,600)	(2,600)	(2,513)		(2,513)
Lampung facility	2		(94,960)	(99,295)	(112,713)		(119,598)
$385 million facility	2		(319,629)	(323,342)	(344,248)		(352,219)
Revolving credit facility due to owners and affiliates	2	$	(18,465)	(16,987)	(8,792)	$	(8,717)

Financing receivables and net investment in financing lease

The following table contains a summary of the class of financial asset, year of origination and the method by which the credit quality is monitored on a quarterly basis:

Class		Credit Quality		As of December 31,
(in thousands of U.S. dollars)	Year	Indicator	Grade	2020		2019
Advances/shareholder loans to joint ventures	2006	Collection experience	Performing	$	4,153	$	3,831
Net investment in financing lease	2014	Credit Information	Performing	$	274,257	$	278,904

The shareholder loans to joint ventures are classified as advances to joint ventures in the consolidated balance sheet. Refer to note 9.

Refer to note 2 for information related to the allowance for expected credit losses recorded on January 1, 2020. For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard. There were no impairment losses for trade receivables for lease or time charter services or contract assets for the year ended December 31, 2019. For the net investment in financing lease, the Partnership monitors quarterly actual credit losses, forecasts of LNG demand and changes in charterer or guarantor-specific publicly available financial and credit information in developing expected credit losses. The Partnership has never incurred actual credit losses related to the net investment in financing lease. The Partnership measures the allowance for credit losses for the net investment in financing lease using the probability of default and loss given default method.

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Risk management and concentrations of risk

12 Months Ended

Dec. 31, 2020

Risk management and concentrations of risk

Risk management and concentrations of risk

16.   Risk management and concentrations of risk

Derivative instruments can be used in accordance with the overall risk management policy.

Interest rate risk, derivative instruments and cash flow hedges

Cash flow hedging strategy

The Partnership is exposed to fluctuations in cash flows from floating interest rate exposure on its long-term debt used principally to finance its vessels. Interest rate swaps are used for the management of the floating interest rate risk exposure. The interest rate swaps have the effect of converting a portion of the outstanding debt from a floating to a fixed rate over the life of the interest rate swaps. Interest rate swaps exchange a receipt of floating interest for a payment of fixed interest which reduces the exposure to interest rate variability on the Partnership’s outstanding floating-rate debt over the life of the interest rate swaps. As of December 31, 2020 and 2019, there were interest rate swap agreements related to the Lampung facility (“Lampung interest rate swaps”) and the commercial tranche of the $385 million facility (“$385 million interest rate swaps”) floating rate debt that are designated as cash flow hedges for accounting purposes. As of December 31, 2020, the following interest rate swap agreements were outstanding:

				Fair
				value			Fixed
	Interest			carrying			interest
	rate	Notional		amount			rate
(in thousands of U.S. dollars)	index	amount		liability		Term	(1)
LIBOR-based debt
Lampung interest rate swaps (2)	LIBOR	$	97,960	$	(5,680)	Sep 2026	2.800	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,560)	Jan 2026	2.941	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,197)	Oct 2025	2.838	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,111)	Jan 2026	2.735	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(4,927)	Jan 2026	2.650	%

1) Excludes the margins paid on the floating-rate debt.

2) All interest rate swaps are U.S. dollar denominated and the notional amount reduces quarterly from the effective date of the interest rate swaps.

The Borrower under the Lampung facility entered five forward starting swap agreements with identical terms for a total notional amount of $237.1 million with an effective date of March 17, 2014. The swaps amortize over 12 years to match the amortization profile of the Lampung facility and exchange 3-month USD LIBOR variable interest payments for fixed rate payments at 2.8%. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments on the Lampung facility. As of December 29, 2014, a prepayment of $7.9 million on the Lampung facility occurred which resulted in an amendment of the original interest rate swaps and the hedge was de-designated for accounting purposes. The other terms of the amended interest rate swaps did not change but the nominal amount of the interest rate swaps was reduced to match the outstanding debt. The amended interest rate swaps were re-designated as a cash flow hedge for accounting purposes.

As of October 1, 2015, the Partnership acquired the Höegh Gallant entities which had outstanding debt under the Gallant facility and three associated interest rate swap agreements with a total notional amount of $146.3 million. The swaps amortized to match the debt amortization of the Gallant facility until the scheduled repayment date in September 2019. The swaps exchanged 3-month USD LIBOR variable interest payments for fixed rate payments ranging from 1.9105% to 1.9145%. As of October 1, 2015, the interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $146.3 million of the commercial tranches of the Gallant facility. Hedge accounting was discontinued in the fourth quarter of 2018 as a result of firm commitment for the refinancing of the Gallant facility which was planned to occur in January 2019.

Effective as of January 1, 2017, the Partnership acquired the Höegh Grace entities which had outstanding debt under the Grace facility and three associated interest rate swap agreements with a total notional amount of $164.0 million. The swaps amortized to match the debt amortization of the Grace facility until the scheduled repayment date in June 2020. The swaps exchanged 3-month USD LIBOR variable interest payments for fixed rate payments ranging from 2.305% to 2.315%. As of January 1, 2017, the interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $164.0 million of the commercial tranches of the Grace facility. Hedge accounting was discontinued in the fourth quarter of 2018 as a result of firm commitment for the refinancing of the Grace facility which was planned to occur in January 2019.

As of December 31, 2018, the Partnership had entered into forward starting interest rate swaps with a nominal amount of $130.0 million to hedge part of the interest rate risk on the floating element of the interest rate for the commercial tranches of the $385 million facility. The Partnership makes fixed payments of 2.941% and 2.838%, based on a nominal amount of $65.0 million for each, in exchange for floating payments. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $130.0 million of the commercial tranches of the $385 million facility which was expected to be drawn and was drawn on January 31, 2019. In February 2019, the Partnership entered into interest rate swaps related to the $385 million facility with a nominal amount of $127.7 million for which the Partnership makes fixed payments of 2.650% and 2.735% based on nominal amount of $63.8 million for each. The interest rate swaps were designated for accounting purposes as cash flow hedges of the variable interest payments for $127.7 million of the commercial tranches of the $385 million facility. The swaps amortize over approximately 7 years to match the outstanding balances of the commercial tranches of the $385 million facility until the maturity dates. The export credit tranches have a fixed interest rate and, therefore, no variability in cash flows as a result of changes in interest rates.

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the consolidated balance sheets.

	Current		Long-term		Current		Long-term
	assets:		assets:		liabilities:		liabilities:
	derivative		derivative		derivative		derivative
(in thousands of U.S. dollars)	instruments		instruments		instruments		instruments
As of December 31, 2020
Interest rate swaps	$	—	$	—	$	(6,945)	$	(19,530)
As of December 31, 2019
Interest rate swaps	$	—	$	—	$	(2,907)	$	(12,028)

The following effects of cash flow hedges relating to interest rate swaps are included in gain (loss) on derivative instruments in the consolidated statements of income for the years ended December 31, 2020 and 2019.

	Year ended
	December 31, 2020
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(5,849)	$	—
Amortization of amount excluded from hedge effectiveness		851		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(1,024)		262
Total gains (losses) on derivative instruments	$	(6,022)	$	262

	Year ended
	December 31, 2019
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(956)	$	—
Amortization of amount excluded from hedge effectiveness		966		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(987)		389
Settlement of cash flow hedge		199		—
Total gains (losses) on derivative instruments	$	(778)	$	389

The settlement of cash flow hedge related to the interest rate swaps for Gallant/Grace facility. The Gallant/Grace interest rate swaps were terminated when the facility was extinguished on January 31, 2019. Due to the termination, the counterparties of the Gallant/Grace facility interest rate swaps paid settlement amounts resulting in a gain on the settlement of the cash flow hedge.

The following effects of cash flow hedges relating to interest rate swaps are included in total gains (losses) on derivative instruments in the consolidated statements of income for the year ended December 31, 2018.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2018
Interest rate swaps:
Ineffective portion of cash flow hedge	$	(990)
Amortization of amount excluded from hedge effectiveness		2,969
Reclassification discontinued hedge from OCI		3,557
Reclassification from accumulated other comprehensive income		(855)
Unrealized gains (losses)		4,681
Realized gains (losses)		—
Total gains (losses) on derivative instruments	$	4,681

For the year ended December 31, 2018, the reclassification to earnings from other comprehensive income (“OCI”) for the discontinued cash flow hedges relates to Gallant/Grace facility which was to be refinanced on January 31, 2019. The accumulated other comprehensive income balance for the cash flow hedge is reclassified to earnings when the hedged future cash flows are no longer expected to occur.

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income, changes in accumulated OCI and on earnings is as follows as of and for the years ended December 31, 2020 and 2019.

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Effective portion of unrealized loss on cash flow hedge		(18,240)	—		(18,240)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		5,849	—		5,849		(5,849)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		1,024	(262)		762		(1,024)		262
Other comprehensive income for period		(11,367)	(262)		(11,629)
Accumulated OCI as of December 31, 2020	$	(29,486)	(86)	$	(29,572)
Gain (loss) reclassified to earnings						$	(6,873)	$	262

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2018	$	(5,902)	565	$	(5,337)
Initial value of interest rate swap to be recognized in earnings on amortization approach		(625)	—		(625)
Effective portion of unrealized loss on cash flow hedge		(13,535)	—		(13,535)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		956	—		956		(956)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		987	(389)		598		(987)		389
Other comprehensive income for period		(12,217)	(389)		(12,606)
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Gain (loss) reclassified to earnings						$	(1,943)	$	389

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income and changes in accumulated OCI is as follows as of and for the year ended December 31, 2018.

	Cash Flow Hedge
	Before tax		Tax benefit		Accumulated
(in thousands of U.S. dollars)	gains (losses)		(expense)	Net of tax	OCI
Balance as of December 31, 2017	$	(3,612)	864	(2,748)	$	(2,748)
Effective portion of unrealized loss on cash flow hedge		412	—	412		412
Reclassification of amortization of cash flow hedge to earnings		855	(299)	556		556
Reclassification of discontinued cash flow hedge to earnings		(3,557)	—	(3,557)		(3,557)
Other comprehensive income for period		(2,290)	(299)	(2,589)		(2,589)
Balance as of December 31, 2018	$	(5,902)	565	(5,337)	$	(5,337)

As of December 31, 2020, the estimated amounts to be reclassified from accumulated other comprehensive income to earnings during the next twelve months is $7.9 million.

Foreign exchange risk

All financing, interest expenses from financing and most of the Partnership’s revenue and expenditures for vessel improvements are denominated in U.S. dollars. Certain operating expenses can be denominated in currencies other than U.S. dollars. For the years ended December 31, 2020, 2019 and 2018, no derivative instruments have been used to manage foreign exchange risk.

Credit risk

Credit risk is the exposure to credit loss in the event of non-performance by the counterparties related to cash and cash equivalents, restricted cash, trade receivables, net investment in financing lease, amounts due from affiliates and interest rate swap agreements. In order to minimize counterparty risk, bank relationships are established with counterparties with acceptable credit ratings at the time of the transactions. Credit risk related to receivables is limited by performing ongoing credit evaluations of the customers’ or counterparty’s financial condition. PGN guarantees PGN LNG's obligations under the PGN FSRU Lampung time charter. Höegh LNG provides a guarantee for its subsidiary’s payment obligations under the Subsequent Charter for the Höegh Gallant. Refer to note 2 for a discussion of the allowance for expected credit loss.

Concentrations of risk

Financial instruments, which potentially subject the Partnership to significant concentrations of credit risk, consist principally of cash and cash equivalents, restricted cash, trade receivables, amounts due from affiliates and derivative contracts (interest rate swaps). The maximum exposure to loss due to credit risk is the book value at the balance sheet date. The Partnership does not have a policy of requiring collateral or security. Cash and cash equivalents and restricted cash are placed with qualified financial institutions. Periodic evaluations are performed of the relative credit standing of those financial institutions. In addition, exposure is limited by diversifying among counterparties. There are three charterers so there is a concentration of risk related to trade receivables. While the maximum exposure to loss due to credit risk is the book value of trade receivables at the balance sheet date, should the time charters for the PGN FSRU Lampung or the Höegh Grace terminate prematurely, or Höegh LNG prematurely terminate the Subsequent Charter for the Höegh Gallant, or the option to acquire the PGN FSRU Lampung be exercised, there could be delays in obtaining new time charters and the hire rates could be lower depending upon the prevailing market conditions.

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Commitments and contingencies

12 Months Ended

Dec. 31, 2020

Commitments and contingencies

Commitments and contingencies

17.   Commitments and contingencies

Contractual commitments

As of December 31, 2020, the Partnership has no material commitments for capital expenditures. However, during the fourth quarter of 2020, part of the procedures for the on-water class renewal survey for the Höegh Grace commenced. No off-hire occurred during the fourth quarter of 2020. The remainder of the on-water class renewal survey is expected to be completed during the first half of 2021. Expenditures totaling approximately $0.6 million were incurred as of December 31, 2020.

As of December 31, 2020, there were no material contractual purchase commitments.

Claims and Contingencies

Joint ventures boil-off settlement

Under the Neptune and the Cape Ann time charters, the joint ventures undertake to ensure that the vessel always meets specified performance standards during the term of the time charters. The performance standards include the vessel not exceeding a maximum average daily boil-off of LNG, subject to certain contractual exclusions, as specified in the time charter. Pursuant to the charters, the hire rate is subject to deduction by the charterer of, among other things, sums due in respect of the joint ventures’ failure to satisfy the specified performance standards during the period. On September 8, 2017, the charterer notified the joint ventures that it was formally making a claim for compensation in accordance with the provisions of the charters for a stated quantity of LNG exceeding the maximum average daily boil-off since the beginning for the charters. Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. As of September 30, 2017, the joint ventures determined the liability associated with the boil-off claim was probable and could be reasonably estimated resulting in a total accrual of $23.7 million which was recorded as a reduction of time charter revenues in the third quarter of 2017. As a precaution, the joint ventures suspended payments on their shareholder loans as of September 30, 2017 pending the outcome of the boil-off claim. Refer to note 8. The Partnership's 50% share of the accrual was approximately $11.9 million. The claim was referred to arbitration.

In February 2020, each of the joint ventures and the charterer reached a commercial settlement addressing all the past and future claims related to boil-off with respect to the Neptune and the Cape Ann. The settlement amount was in line with the accrual made by the joint ventures. Accordingly, the accrual was unchanged as of December 31, 2019. The settlement reached was subject to executing final binding agreements between the parties. The final settlement and release agreements were signed on and had an effective date of April 1, 2020. Among other things, the settlement provided that 1) the boil-off claim, up to the effective date of the settlement agreements, would be settled for an aggregate amount of $23.7 million, paid in instalments during 2020, 2) the costs of the arbitration tribunal would be equally split between the parties and each party would settle its legal and other costs, 3) the joint ventures have or would implement technical upgrades on the vessels at their own cost to minimize boil-off, and 4) the relevant provisions of the time charters would be amended regarding the computation and settlement of prospective boil-off claims. The Partnership’s 50% share of the settlement was the same as its share of the accrual, or approximately $11.9 million. As a result, the settlement had no impact to the Partnership’s consolidated income statement for the year ended December 31, 2020.

The first installment of the settlement of $17.2 million was paid by the joint ventures in April 2020. The Partnership’s 50% share was $8.6 million. The second and final installment of the settlement of $6.5 million was paid by the joint ventures in December 2020. The Partnership’s 50% share was $3.3 million.

The Partnership is indemnified by Höegh LNG for its share of the cash impact of the settlement, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreement. On April 8, 2020 and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG.

Höegh LNG and the other major owner guarantee the performance and payment obligations of the joint ventures under the time charters.

The Partnership was indemnified by Höegh LNG for its share of the cash impact of the settlement, the arbitration costs and any legal expenses, the technical modifications of the vessels and any prospective boil-off claims or other direct impacts of the settlement agreement. Höegh LNG will indemnify the Partnership for the Partnership’s share of such costs. For the year ended December 31, 2018 the Partnership received indemnification payments of $0.3 million from Höegh LNG, related to the boil-off claim. Indemnification payments were recorded as contributions to equity. Refer to note 14. On March 12, 2021, the partnership was indemnified by Höegh LNG for its share of the joint ventures performance claims for the year ended December 31, 2020 by a reduction of $0.3 million on its outstanding balance on the $85 million revolving credit facility from Höegh LNG

Indonesian corporate income tax

Based upon the Partnership’ s experience in Indonesia, tax regulations, guidance and interpretation in Indonesia may not always be clear and may be subject to alternative interpretations or changes in interpretations over time. The Partnership’s Indonesian subsidiary is subject to examination by the Indonesian tax authorities for the years from 2016 through 2020 for up to five years following the completion of a fiscal year. As a result, it is likely there will be an examination by the Indonesian tax authorities for the tax return for 2016 during 2021. The examinations may lead to ordinary course adjustments or proposed adjustments to the Partnership’s taxes with respect to years under examination. In December 2018, the examination for the years 2013 and 2014 was completed. Refer to note 6 for additional information. On January 22, 2021 the Partnership’s Indonesian subsidiary received a letter from the Indonesian tax authorities that there will be an examination by the Indonesian tax authorities for the tax returns from 2016 to 2020 during 2021. Future examinations may or may not result in changes to the Partnership’s provisions on tax filings from 2016 through 2020. As of December 31, 2020, the unrecognized tax benefits for uncertain tax positions were $2.7 million.

Indonesian property tax

The Partnership's Indonesian subsidiary was assessed for Land and Building tax (“property tax”) and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The assessment was due to the issuance of the Indonesian Minister of Finance’s Decree No. 186/PMK.03/2019 (“PMK 186/2019”) which defines FSRUs as a “Building” subject to the tax. The Partnership’s Indonesian subsidiary has appealed the assessment. Depending on the level of appeal pursued, the appeal process could take a number of years to conclude. There can be no assurance of the result of the appeal or whether the Indonesian subsidiary will prevail. As a result, the property tax and penalties were expensed as a component of vessel operating expenses for the year ended December 31, 2019. Until the appeal is concluded, the Indonesian subsidiary will be required to pay an annual property tax of approximately $0.5 million.

PGN LNG claims including delay liquidated damages

The Partnership was indemnified by Höegh LNG for i) any hire rate payments not received under the PGN FSRU Lampung time charter for the period commencing on August 12, 2014 through the acceptance date of the PGN FSRU Lampung and ii) non-budgeted expenses (including warranty costs associated with repairs of the Mooring) incurred in connection with the PGN FSRU Lampung project prior to the date of acceptance, and for iii) certain subsequently incurred non-budgeted costs and expenses.

No indemnification claim was filed for the year ended December 31, 2020. For the years ended December 31, 2019 and 2018, the Partnership refunded to Höegh LNG approximately $0.1 million and $2.4 million, respectively, related to insurance proceeds received related to the warranty provision and costs for previous years determined to be reimbursable by the charterer. For the year ended December 31, 2018, the Partnership received indemnification payments from Höegh LNG for non-budgeted expenses (including warranty provisions, other non-budgeted expenses and replacement capital expenditure) of $0.9 million which was recorded as a contribution to equity. Indemnification payments received from Höegh LNG are subject to repayment to the extent the amounts are subsequently recovered from insurance or deemed reimbursable by the charterer. Refer to note 14.

Höegh Gallant claims and indemnification

The Partnership was indemnified by Höegh LNG for losses incurred in connection with the commencement of services under the time charter with EgyptCo (including technical issues) incurred in connection with the Höegh Gallant.

No indemnification claims were filed or received for the years ended December 31, 2020 and 2019. For the year ended December 31, 2018, the Partnership received indemnification payments from Höegh LNG for losses incurred in connection with the time charter with EgyptCo of $0.5 million which were recorded as contributions to equity. Refer to note 14.

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Supplemental cash flow information

12 Months Ended

Dec. 31, 2020

Supplemental cash flow information

Supplemental cash flow information

18.   Supplemental cash flow information

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Supplemental disclosure of non-cash investing activities
Non-cash expenditures for vessel and other equipment	$	—	—	$	(229)
Supplemental disclosure of non-cash financing activities
Non-cash indemnifications received	$	11,850	—	$	—

Refer to note 14 for non-cash indemnification received information.

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Issuance of common units and Series A Preferred Units

12 Months Ended

Dec. 31, 2020

Issuance of common units and Series A Preferred Units

Issuance of common units and Series A Preferred Units

19.   Issuance of common units and Series A preferred units

From the commencement of the Prior ATM program in January 2018 through December 31, 2020, the Partnership sold 2,152,333 Series A preferred units and 306,266 common units under the ATM programs and received net proceeds of $54.9 million and $5.6 million, respectively. The compensation paid to the Agent for such sales was $1.1 million.

For the year ended December 31, 2020, the Partnership did not issue any common units under the ATM program. For the year ended December 31, 2020, the Partnership sold 126,743 Series A preferred units at an average gross sales price of $25.50 per unit for net proceeds after sales commissions, of $3.2 million. The Partnership has paid an aggregate of $0.1 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2020. Proceeds in the table below are included for all units for the year ended December 31, 2020.

	Year ended
	December 31, 2020
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	—	3,231	$	3,231
Less: Commissions		—	(57)		(57)
Net proceeds for units issued	$	—	3,174	$	3,174

For the year ended December 31, 2019, the Partnership sold 53,160 common units at an average gross sales price of $19.60 per unit for net proceeds, after sales commissions, of $1.0 million. For the year ended December 31, 2019, the Partnership sold 496,520 Series A preferred units at an average gross sales price of $26.79 per unit for net proceeds, after sales commissions, of $13.1 million. The Partnership has paid an aggregate of $0.2 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2019. Proceeds in the table below are included for all units issued for the year ended December 31, 2019.

	Year ended December 31, 2019
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	1,042	13,298	$	14,340
Less: Commissions		(13)	(233)		(246)
Net proceeds for units issued	$	1,029	13,065	$	14,094

For the year ended December 31, 2018, the Partnership sold 253,106 common units at an average gross sales price of $18.26 per unit for net proceeds, after sales commissions, of $4.6 million. For the year ended December 31, 2018, the Partnership sold 1,529,070 Series A preferred units at an average gross sales price of $25.74 per unit for net proceeds, after sales commissions, of $38.7 million. The Partnership has paid an aggregate of $0.8 million in sales commissions to the Agent in connection with such sales for the period ended December 31, 2018. Proceeds in the table below are included for all units issued for the year ended December 31, 2018.

	Year ended December 31, 2018
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	4,623	39,360	$	43,983
Less: Commissions		(60)	(701)		(761)
Net proceeds for units issued	$	4,563	38,659	$	43,222

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Common, subordinated and preferred units

12 Months Ended

Dec. 31, 2020

Common, subordinated and preferred units

Common, subordinated and preferred units

20.   Common, subordinated and preferred units

The following table shows the movements in the number of common units, subordinated units and preferred units during the years ended December 31, 2020, 2019 and 2018:

		Common		8.75%
	Common	Units		Series A
	Units	Höegh	Subordinated	Preferred
(in units)	Public	LNG	Units	Units
December 31, 2017	17,648,844	2,116,060	13,156,060	4,600,000
June 6, 2018; Awards to non-employee directors as compensation for directors' fees	8,840	—	—	—
July 5, 2018; Awards to non-employee directors as compensation for directors' fees	2,210	—	—	—
Units issued to staff at Höegh LNG during 2018	14,622	(14,622)	—	—
Phantom units issued to CEO/CFO during 2018	17,079	—	—	—
ATM program (from January 26, 2018 to December 31, 2018)	253,106	—	—	1,529,070
December 31, 2018	17,944,701	2,101,438	13,156,060	6,129,070
June 4, 2019; Awards to non-employee directors as compensation for directors' fees	8,944	—	—	—
July 16, 2019; Awards to non-employee directors as compensation for directors' fees	2,236	—	—	—
August 16, 2019; Subordinated units converted to common units	—	13,156,060	(13,156,060)	—
Phantom units issued to CEO/CFO during 2019	19,745	—	—	—
ATM program (from January 1, 2019 to December 31, 2019)	53,160	—	—	496,520
December 31, 2019	18,028,786	15,257,498	—	6,625,590
September 4, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
September 15, 2020; Awards to non-employee directors as compensation for directors' fees	7,764	—	—	—
October 23, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
Phantom units issued to CEO/CFO during 2020	6,627	—	—	—
ATM program (from January 1, 2020 to December 31, 2020)	—	—	—	126,743
December 31, 2020	18,050,941	15,257,498	—	6,752,333

The subordination period, as defined in the Second Amended and Restated Agreement of Limited Partnership of Höegh LNG Partners LP, for the subordinated units ended on August 16, 2019. All of the subordinated units, which were owned by Höegh LNG, converted to common units on a one-for-one basis. As of December 31, 2020 and 2019, Höegh LNG owned 15,257,498 common units. As of December 31, 2018, Höegh LNG owned 2,101,438 common units and 13,156,060 subordinated units.

Refer to note 21 for information on distributions to common and subordinated unitholders.

The Series A preferred units represent perpetual equity interests in the Partnership and, unlike the Partnership’s debt, do not give rise to a claim for payment of a principal amount at a particular date. The Series A preferred units rank senior to the Partnership’s common units as to the payment of distributions and amounts payable upon liquidation, dissolution or winding up but junior to all the Partnership’s debt and other liabilities. The Series A preferred units have a liquidation preference of $25.00 per unit. At any time on or after October 5, 2022, the Partnership may redeem, in whole or in part, the Series A preferred units at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. The distribution rate on the Series A preferred units is 8.75% per annum of the $25.00 per unit value (equivalent to $2.1875 per annum per unit). The distributions are cumulative and recorded when declared. However, since the Series A preferred units rank senior to the Partnership’s common units, the portion of net income, equivalent to the Series A preferred units’ paid and undeclared distributions for that period, is reflected as Preferred unitholders’ interest in net income on the consolidated statement of income. Distributions are payable quarterly, when, and if declared by the Partnership’s board of directors out of legally available funds for such purpose. Holders of the Series A preferred units generally have no voting rights. However, if and whenever distributions payable on the Series A preferred units are in arrears for six or more quarterly periods, whether or not consecutive, holders of Series A preferred units will be entitled to replace one of the members of the Partnership’s board of directors appointed by the general partner with a person nominated by such holders.

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Earning per unit and cash distributions

12 Months Ended

Dec. 31, 2020

Earning per unit and cash distributions

Earning per unit and cash distributions

21.   Earning per unit and cash distributions

The calculation of basic and diluted earnings per unit are presented below:

	Year ended December 31,
(in thousands of U.S. dollars, except per unit numbers)	2020		2019		2018
Net income	$	63,145		52,741	$	77,622
Adjustment for:
Preferred unitholders’ interest in net income		14,802		13,850		12,303
Limited partners' interest in net income		48,343		38,891		65,319
Less: Dividends paid or to be paid (1)		(60,222)		(60,149)		(59,952)
Under (over) distributed earnings		(11,879)		(21,258)		5,367
Under (over) distributed earnings attributable to:
Common units public		(6,437)		(11,514)		2,900
Common units Höegh LNG		(5,442)		(3,211)		340
Subordinated units Höegh LNG (4)		—		(6,533)		2,127
	$	(11,879)		(21,258)	$	5,367
Basic weighted average units outstanding (in thousands)
Common units public		18,034		17,986		17,856
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Diluted weighted average units outstanding (in thousands)
Common units public		18,037		17,995		17,864
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Basic and diluted earnings per unit (2):
Common unit public	$	1.40	$	1.12	$	1.93
Common unit Höegh LNG (3)	$	1.51	$	1.84	$	2.03
Subordinated unit Höegh LNG (3) (4)	$	—	$	0.70	$	2.03

(1) Includes all distributions paid or to be paid in relationship to the period, regardless of whether the declaration and payment dates were prior to the end of the period and is based the number of units outstanding at the period end.

(2) Effective March 26, 2020, granted 8,100 phantom units to the CEO/CFO of the Partnership, one-third of such phantom units vest as of November 30, 2021, 2022 and 2023, respectively. Effective March 21, 2019, granted 10,917 phantom units to the CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective March 23, 2018, the Partnership granted 14,584 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective June 3, 2016, the Partnership granted 21,500 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of December 31, 2017, November 30, 2018 and November 30, 2019, respectively. On September 14, 2018, the plan was amended to extend the terms and conditions of such unvested units for the grants effective March 23, 2017 and June 3, 2016 of the then-serving CEO/CFO that resigned as CEO/CFO of the Partnership. The phantom units impact the diluted weighted average units outstanding. As a result of the resignation of the CEO/CFO of the Partnership in August 2020, a total of 15,378 of the unvested phantom units terminated.

(3) Includes total amounts attributable to incentive distributions rights of $1,598, $1,597 and $1,591 for the years ended December 31, 2020, 2019 and 2018, respectively. For the year ended December 31, 2020 the full amount was attributable to common units owned by Höegh LNG. For the years ended December 31, 2019 and 2018, respectively, $908 and $219 was attributed to common units owned by Höegh LNG and $688 and $1,372 was attributed to subordinated units owned by Höegh LNG.

(4) On August 16, 2019, all subordinated units converted into common units on a one-for-one basis.

Earnings per unit is calculated by dividing net income by the weighted average number of common and subordinated units outstanding during the applicable period.

The common unitholders’ interest in net income is calculated as if all net income were distributed according to terms of the Partnership’s Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), regardless of whether those earnings would or could be distributed. The Partnership Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash. Available cash, a contractual defined term, generally means all cash on hand at the end of the quarter after deduction for cash reserves established by the board of directors and the Partnership’s subsidiaries to i) provide for the proper conduct of the business (including reserves for future capital expenditures and for the anticipated credit needs); ii) comply with applicable law, any of the debt instruments or other agreements; iii) provide funds for payments on the Series A preferred units; and iv) provide funds for distributions to the unitholders for any one or more of the next four quarters. Therefore, the earnings per unit are not indicative of future cash distributions that may be made. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on derivative instruments and unrealized gains or losses on foreign exchange transactions.

In addition, Höegh LNG currently holds all the IDRs in the Partnership. IDRs represent the rights to receive an increasing percentage of quarterly distributions of available cash for operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

Distributions of available cash from operating surplus are to be made among the unitholders and the holders of the IDRs in the following manner for any quarter after the subordination period:

● first, 100.0% to all common unitholders, pro rata, until each such unitholder receives a total of $0.388125 per unit for that quarter;

● second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of the IDRs, pro rata, until each such unitholder receives a total of $0.421875 per unit for that quarter;

● third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of the IDRs, pro rata, until each such unitholder receives a total of $0.50625 per unit for that quarter; and

● thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of the IDRs, pro rata.

In each case, the percentage interests set forth above assume that the Partnership does not issue additional classes of equity securities.

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Subsequent events

12 Months Ended

Dec. 31, 2020

Subsequent events

Subsequent events

22.   Subsequent events

On February 12, 2021, the Partnership paid a cash distribution of $15.1 million, or $0.44 per common unit, with respect to the three months ended December 31, 2020, equivalent to $1.76 per unit on an annualized basis.

On February 16, 2021, the Partnership paid a cash distribution of $3.9 million, or $0.546875 per Series A preferred unit, for the period commencing on November 15, 2020 to February 14, 2021.

For the period from January 1, 2021 to April 9, 2021, the Partnership sold an aggregate of 52,603 common units under the ATM program at an average gross sales price of $15.75 per unit and received net proceeds, after sales commissions, of $0.8 million and 336,992 Series A preferred units under the ATM program at an average gross sales price of $25.12 per units and received net proceeds, after sales commissions, of $8.3 million.

On March 8, 2021, Höegh LNG announced a recommended offer by Leif Höegh & Co. Ltd. (“LHC”) and funds managed by Morgan Stanley Infrastructure Partners (“MSIP”) through a 50/50 joint venture, Larus Holding Limited (“JVCo”), to acquire the remaining issued and outstanding shares of Höegh LNG not currently owned by LHC or its affiliates (the “Amalgamation”). Immediately following the completion of the Amalgamation, Höegh LNG would be wholly-owned by JVCo, and the common shares of Höegh LNG would be delisted from the Oslo Stock Exchange. The Amalgamation has been approved by Höegh LNG's shareholders and bondholders and is anticipated to close in the first half of 2021. The Amalgamation is subject to waivers of specific change of control and delisting provisions in relation to certain of the Partnership's and Höegh LNG's credit agreements, as well as the satisfaction of other customary closing conditions. Following the consummation of the Amalgamation, unless otherwise agreed between the parties, some provisions of the omnibus agreement in connection with the IPO will terminate by their terms, including (i) the prohibition on Höegh LNG from acquiring, owning, operating or chartering any Five-Year Vessels (as defined in “Major Unitholders and Related Party Transactions - Related Party Transactions - Omnibus Agreement - Non Competition”), (ii) the prohibition on us from acquiring, owning, operating or chartering any Non-Five-Year Vessels, and (iii) the rights of first offer associated with those rights. As a consequence, following the consummation of the Amalgamation, unless otherwise agreed between the parties, Höegh LNG will not be required to offer us Five-Year Vessels and will be permitted to compete with us.

The commercial tranche of the Lampung facility becomes due in October 2021 and the export credit tranche can be called if the commercial tranche is not refinanced. To address the liquidity needs, the Partnership is at an advanced stage of the process to refinance the Lampung facility. As of April 9, 2021, a group of lending banks have provided a credit approved term sheet for the refinancing of both the commercial tranche and the export credit tranche. The refinancing is subject to completion of the loan documentation and satisfaction of customary closing conditions before drawdown. The refinancing is expected to be completed before the due date of the commercial tranche in October 2021. Accordingly, based on the refinancing plans, we believe we have sufficient resources to meet our anticipated liquidity requirements for at least the next 12 months.

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Schedule I

12 Months Ended

Dec. 31, 2020

Schedule I

Schedule I

Exhibit 15.1

Schedule I – Condensed Financial Information of Registrant

CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Total revenue	$	—	—	$	—
EXPENSES
Administrative expenses		(6,279)	(6,473)		(5,822)
Equity in earnings of subsidiaries		64,296	60,315		68,359
Equity in earnings (losses) of joint ventures		6,420	6,078		17,938
Interest income		15,983	11,205		93
Interest expense		(17,139)	(18,242)		(2,938)
Other items, net		(136)	(142)		(8)
Net income	$	63,145	52,741	$	77,622
Share of subsidiaries unrealized losses on cash flow hedges		(11,367)	(12,217)		(2,290)
Share of subsidiaries income tax benefit		(262)	(389)		(299)
Comprehensive income	$	51,516	40,135	$	75,033

See accompanying notes to condensed financial statements.

CONDENSED BALANCE SHEETS

	As of  December 31,
(in thousands of U.S. dollars)	2020		2019
Cash	$	2,058	$	6,934
Current portion of long-term loans to subsidiaries		26,717		25,597
Promissory note from subsidiaries		123,248		123,248
Prepaid expenses and other receivables		1,097		224
Total current assets		153,120		156,003
Accumulated earnings of joint ventures		9,690		3,270
Loans to subsidiaries		237,489		260,636
Investments in subsidiaries		455,582		449,570
Total long-term assets		702,761		713,476
Total assets	$	855,881	$	869,479
LIABILITIES AND PARTNER’S CAPITAL
Current portion of long-term debt	$	25,597	$	25,597
Trade payables		86		52
Amounts due to owners and affiliates		732		398
Derivative instruments		4,699		1,821
Accrued liabilities and other payables		2,860		3,155
Total current liabilities		33,974		31,023
Long-term debt		294,032		318,650
Loans due to owners and affiliates		18,465		8,792
Derivative instruments		16,095		9,504
Total long-term liabilities		328,592		336,946
Total liabilities		362,566		367,969
Total partners’ capital		493,315		501,510
Total liabilities and partners’ capital	$	855,881	$	869,479

See accompanying notes to condensed financial statements.

CONDENSED STATEMENT OF CASH FLOW

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Net cash provided by operating activities	$	48,656	33,130	$	42,401
INVESTING ACTIVITIES
Long-term loan due from subsidiaries		22,027	(286,133)		—
Net cash provided by (used in) investing activities		22,027	(286,133)		—
FINANCING ACTIVITIES
Net proceeds from issuance of Series A Preferred Units		3,174	13,065		38,659
Net proceeds from issuance of common units		—	1,029		4,563
Proceeds from long-term debt		—	368,300		—
Proceeds from loans due to owners and affiliates		21,750	3,500		5,400
Repayment of long-term debt		(25,597)	(19,198)		—
Repayment of debt issuance cost		—	(5,797)		—
Repayment of amounts due to owners and affiliates		—	(34,000)		(17,500)
Proceeds from indemnifications received from Höegh LNG		—	—		1,701
Repayment of indemnifications received from Höegh LNG		—	(64)		(2,535)
Cash distributions to limited partners		(74,886)	(73,804)		(72,497)
Net cash provided by (used in) financing activities		(75,559)	253,301		(42,209)
Increase (decrease) in cash, cash equivalents and restricted cash		(4,876)	(72)		374
Cash, cash equivalents and restricted cash, beginning of period		6,934	7,006		6,632
Cash, cash equivalents and restricted cash, end of period	$	2,058	6,934	$	7,006

See accompanying notes to condensed financial statements.

1. Basis of presentation

Höegh LNG Partners LP – the Parent company is a Marshall Islands limited partnership formed on April 28, 2014.

In the parent-only financial statements, the investment in subsidiaries and investment in joint ventures are stated at cost plus equity in undistributed earnings of subsidiaries and accumulated earnings in joint ventures since the date of acquisition and the closing of the initial public offering of Höegh LNG Partners LP (the “Partnership”) on August 12, 2014. The Partnership’s share of net income of its unconsolidated subsidiaries and joint ventures is included in the condensed income statement using the equity method. The Parent company’s financial statements should be read in conjunction with the Partnership’s consolidated financial statements contained elsewhere in the Partnership’s Report on Form 20-F for the year ended December 31, 2020.

2. Dividends

A cash dividend of $55.8 million, $42.4 million and $51.7 million was paid to the Parent company from its consolidated subsidiaries for the years ended December 31, 2020, 2019 and 2018, respectively.

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Significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2020

Significant accounting policies

Basis of presentation

Basis of presentation

The consolidated financial statements are prepared in accordance with US GAAP. All intercompany balances and transactions are eliminated.

The consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. Please refer to note 22 for the Partnership’s plan to refinance the Lampung debt facility.

It has been determined that PT Hoegh LNG Lampung, Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd., SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. are variable interest entities. A variable interest entity (“VIE”) is defined by US GAAP as a legal entity where either (a) the voting rights of some investors are not proportional to their rights to receive the expected residual returns of the entity, their obligations to absorb the expected losses of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights, or (b) the equity holders have not provided sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support, or (c) equity interest holders as a group lack the characteristics of a controlling financial interest, including decision making ability and an interest in the entity’s residual risks and rewards. The guidance requires a VIE to be consolidated if any of its interest holders are entitled to a majority of the entity’s residual returns or are exposed to a majority of its expected losses.

Based upon the criteria set forth in US GAAP, the Partnership has determined that PT Hoegh LNG Lampung is a VIE, as the equity holders, through their equity investments, may not participate fully in the entity’s expected residual returns and substantially all of the entity’s activities either involve, or are conducted on behalf of, the Partnership. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of PT Hoegh LNG Lampung are included in the consolidated financial statements. Dividends may only be paid if the retained earnings are positive and a statutory reserve has been established equal to 20% of its paid-up capital under Indonesian law. PT Hoegh LNG Lampung had not established the required statutory reserves as of December 31, 2020 and 2019. Therefore, PT Hoegh LNG Lampung cannot make dividend payments under Indonesian law. Under the Lampung facility, there are limitations on cash dividends and intercompany loans that can be made to the Partnership. Refer to note 12. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $179.9 million and $169.8 million, respectively.

The Partnership has determined that Hoegh LNG Cyprus Limited is a VIE, as the equity investment does not provide sufficient equity to permit the entity to finance its activities without financial support. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives all the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Hoegh LNG Cyprus Limited are included in the consolidated financial statements. Under Cyprus law, dividends may only be distributed out of profits and not from the share capital of the company. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

The Partnership has also determined that Höegh LNG Colombia Holding Ltd. is a VIE since the entity would not be able to finance its activities without financial support and financial guarantees under its subsidiary’s facility to finance the Höegh Grace. The Partnership is the primary beneficiary, as it has the power to make key operating decisions considered to be most significant to the VIE and receives the majority of the expected benefits or expected losses. Therefore, 100% of the assets, liabilities, revenues and expenses of Höegh LNG Colombia Holding Ltd., and subsidiaries, are included in the consolidated financial statements. Under Cayman Islands law, dividends may only be paid out of profits or capital reserves if the entity is solvent after the distributions. As of December 31, 2020 and 2019, restricted net assets of the consolidated subsidiaries were $0.0 million.

Dividends and other distributions from Hoegh LNG Cyprus Limited, Höegh LNG Colombia Holding Ltd. and Höegh LNG FSRU IV Ltd. may only be distributed if after the dividend payment, the Partnership would remain in compliance with the financial covenants under the $385 million facility. Refer to note 12.

In addition, the Partnership has determined that the two joint ventures, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., are VIEs since each entity did not have a sufficient equity investment to permit the entity to finance its activities without additional subordinated financial support. The entities have been financed with third party debt and subordinated shareholder loans. The Partnership is not the primary beneficiary, as the Partnership cannot make key operating decisions considered to be most significant to the VIEs but has joint control with the other equity holders. Therefore, the joint ventures are accounted for under the equity method of accounting as the Partnership has significant influence. The Partnership’s carrying value is recorded in advances to joint ventures and accumulated earnings (losses) of joint ventures in the consolidated balance sheets. For SRV Joint Gas Ltd., the Partnership had a receivable for the advances of $3.3 million and $3.0 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $5.5 million and $2.6 million, respectively, as of December 31, 2020 and 2019. The Partnership’s carrying value for SRV Joint Gas Two Ltd. consists of a receivable for the advances of $0.9 million and $0.8 million as of December 31, 2020 and 2019, respectively. The Partnership’s accumulated earnings, or its share of net assets, was $4.2 million and $0.7 million, respectively, as of December 31, 2020 and 2019. The major reason that the Partnership had low accumulated earnings in the joint ventures as of December 31, 2019 and the major reason that the Partnership historically has had accumulated losses in the joint ventures, or net liabilities, is due to the fair value adjustments for the interest rate swaps recorded as liabilities on the balance sheets of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. and eliminations for consolidation to the balance sheet. The maximum exposure to loss is the carrying value of the receivables, which is subordinated to the joint ventures’ long-term bank debt, the investments in the joint ventures (accumulated earnings or losses), as the shares are pledged as security for the joint ventures’ long-term bank debt, and Höegh LNG’s commitment under long-term bank loan agreements to fund its share of drydocking costs and remarketing efforts in the event of an early termination of the charters. If the charters terminate for any reason that does not result in a termination fee, the joint ventures’ long-term bank debt would be subject to mandatory repayment. Dividend distributions require a) agreement of the other joint venture owners; b) fulfilment of requirements of the long-term bank loans; c) and under Cayman Islands law may be paid out of profits or capital reserves subject to the joint venture being solvent after the distribution.

Foreign currencies

Foreign currencies

The reporting currency in the consolidated financial statements is the U.S. dollar, which is the functional currency of the FSRU-owning entities. Nearly all revenues are received in U.S. dollars and a majority of the Partnership’s expenditures for investments and all of the long-term debt are denominated in U.S. dollars. Transactions denominated in other currencies during the year are converted into U.S. dollars using the exchange rates in effect at the time of the transactions. Monetary assets and liabilities that are denominated in currencies other than the U.S. dollar are translated at the exchange rates in effect at the balance sheet date. Resulting gains or losses are reflected in the accompanying consolidated statements of income.

Business combinations and asset acquisitions

Business combinations and asset acquisitions

Business combinations are accounted for under the purchase method of accounting. Under this method, the purchase price is allocated to identifiable assets acquired and liabilities assumed based on their fair values as of the acquisition date. Any excess of the purchase price over the fair values of net assets is recognized as goodwill. Acquisition related costs are expensed as incurred. The results of entity acquired are included in the consolidated financial statements from the date of acquisition.

Dependent upon facts and circumstances, the assessment of a transaction may be considered the acquisition of an asset, when substantially all of the fair value of assets acquired is concentrated in a single identifiable asset, rather than a business combination. Asset acquisitions are accounted for by allocating the cost of the acquisition to the individual assets acquired and liabilities assumed on a relative fair value basis. Acquisition related costs are capitalized as a component of the cost of the assets acquired.

Time charter revenue, related contract balances and related expenses

Time charter revenue, related contract balances and related expenses

Time charter revenues and related contract balances:

The Partnership is required to evaluate whether two or more contracts should be combined and accounted for as a single contract, whether the contract promises to deliver more than one distinct good or service, or performance obligations, and/or a lease, determine the transaction price under the contract, allocate the transaction price to the lease and the performance obligations and recognize revenue as the performance obligation is satisfied. The Partnership believes the nature of its time charter contracts are the same, regardless of whether the contracts are accounted for as financing leases or operating leases for accounting purposes. As such, when adopting the revised guidance on leases as of January 1, 2019, the Partnership did not elect to apply the practical expedient to not separate lease and services components for operating leases because this would result in inconsistent disclosure for the time charter contracts.

Performance obligations:

The Partnership determined that its time charter contracts contain a lease and a performance obligation for the provision of time charter services. The lease of the vessel, representing the use of the vessel without any associated performance obligations or warranties, is accounted for in accordance with the provisions of Accounting Standards Codification ("ASC") 842, Leases.

The provision of time charter services, including guarantees for the level of performance provided by the time charter contracts, is considered a distinct service and is accounted for in accordance with the provision of ASC 606, Revenue from Contracts with Customers. The Partnership determined that the nature of the time charter services promised, represents a single performance obligation, to stand ready over a 24-hour interval to accept LNG cargos, to transport cargos, to regasify the LNG and discharge the resulting gas into a pipeline in accordance with the charterer’s instructions and requirements.

Time charter services revenue can be recognized as the performance obligation is satisfied over the 24-hour interval to the performance standards specified under the time charter contract. If the performance standards are not met, off-hire, reduced hire, liquidated damages or other performance payments may result.

Contract terms, determination of transaction price and allocation to performance obligations:

The Partnership’s time charter contracts for all FSRUs, except the Höegh Gallant, include day rates or hire rates and warranty provisions with the following components:

● Fixed element: The fixed element is a fixed per day fee intended to cover remuneration for use of the vessel and the provision of time charter services.

● Operating expense reimbursement element: The operating expense reimbursement element is a rate per day intended to cover the operating costs of the vessel, including the crew, insurance, consumables, miscellaneous services, spares and maintenance and repairs costs and management services and fees. The amount of the operating expense reimbursement element may be based on actual cost incurred, or fees subject to indexing or other adjustments after a defined period, or a combination of both.

● Tax reimbursement element: The tax reimbursement element may be a rate per day, based on the estimated liability for the year divided by the number of days in the year, subject to adjustment for actual taxes incurred, or a reimbursement of the costs as the taxes are incurred. The tax reimbursement element may cover withholding taxes, payroll taxes, other local taxes and current income tax expense for the jurisdiction in which the vessel operates as defined by the provisions of the individual time charter contract.

● Performance warranties element: The performance warranties element includes defined operational capacity and standards that can result in the FSRUs being off-hire or require compensation to the charterer through provision of reduced hire, liquidated damages or performance payments. Examples of performance warranties include the ability to discharge regasified LNG at specified performance rates, guaranteed minimum fuel consumption, guaranteed minimum boil-off rates and the ability to accept cargos.

The Höegh Gallant has a single day rate intended to cover all of the elements listed above. In addition, the time charter contract for the Höegh Gallant includes a provision for off-hire for scheduled maintenance. The joint ventures’ time charter contracts also provide for upfront payments for variable costs for certain vessel modifications, drydocking costs, other additions to equipment or spare parts.

The hire rates for the PGN FSRU Lampung and the joint ventures are invoiced at the beginning of the month. The Höegh Gallant and the Höegh Grace invoice time charter revenues monthly in arrears.

The transaction price is estimated as the standalone selling price for the lease and the time charter services components of the fixed day rate element. Variable consideration per day for operating expense and tax reimbursements is estimated at the most likely amount to which the Partnership is expected to be entitled to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty related to the variable consideration is resolved. When there is significant uncertainty related to that amount of variable consideration to be received, that variable consideration is considered constrained. Typically, variable reimbursements and performance warranties are known at the end of each 24-hour interval, or as subsequently reassessed at the end of the reporting period. However, to the extent interpretations of contractual provisions are complex and/or disputed with the customer, this could give rise to constrained variable consideration. Constrained variable consideration is not estimated.

Variable consideration is allocated entirely to one performance obligation when the variable day rate relates specifically to the efforts to satisfy the single performance obligation. The default method of the relative standalone selling price method was used to allocate the remaining transaction price, principally the fixed element, between the lease and the time charter services. The total estimated transaction price for time charter services is considered variable consideration because it may be reduced by performance warranties.

The Partnership has made a policy election to exclude from the measurement of the transaction price all taxes assessed by a government entity on revenues and collected on behalf of that government entity from customers, such as sales or value added taxes.

Lease revenue recognition:

Leases are classified based upon defined criteria either as sale-type/direct financing leases (“financing leases”) or operating leases. A lease that transfers substantially all of the benefits and risks of the FSRU to the charterer is accounted for as a financing lease by the lessor. All other leases that do not meet the criteria are classified as operating leases. On January 1, 2019, when adopting the revised leasing guidance, the Partnership elected the package of practical expedients and did not reassess conclusions under the previous standard about whether any existing contracts are, or contain leases, lease classification, and initial direct costs for any existing leases. Accordingly, outstanding leases on January 1, 2019, continue to be classified in accordance with the prior lease guidance.

The lease component of time charters that are accounted for as operating leases is recognized on a straight-line basis over the term of the charter. The Höegh Gallant’s time charter, which has a five-year lease term, is accounted for as an operating lease. The Höegh Grace’s time charter contracts, which have a non-cancellable charter period of ten years, are accounted for as an operating lease. Under one of the time charter contracts, the contract provides for additional variable payments, including a finance component, over the initial term depending upon the actual commencement date of the contract within a defined window of potential commencement dates. The variable payments are considered directly related to the lease performance obligation. The revenue, excluding the financing component, is recognized over the initial 10-year term. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for final income tax directly related to the provision of the lease is recorded as a component of lease revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

The lease component of time charters that are accounted for as financing leases is recognized over the lease term using the effective interest rate method and is included in time charter revenues. Origination costs related to the time charter are a component of the net investment in financing lease and amortized over the lease term using the effective interest method. Financing leases are reflected on the consolidated balance sheets as net investments in financing leases. The PGN FSRU Lampung time charter, which had a 20-year lease term at inception, meets the criteria of transferring substantially all of the benefits and risks to the charterer and is accounted for as a financing lease.

Time charter services revenue recognition:

Variable consideration for the time charter services performance obligation, including amounts allocated to time charter services, estimated reimbursements for vessel operating expenses and estimated reimbursements of certain types of costs and taxes, are recognized as revenues as the performance obligation for the 24-hour interval is fulfilled, subject to adjustment for off-hire and performance warranties. Constrained variable consideration is recognized as revenue on a cumulative catch-up basis when the significant uncertainty related to that amount of variable consideration to be received is resolved. Estimates for variable consideration, including constrained variable consideration, are reassessed at the end of each period. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes directly related to the provision of the time charter services are recorded as a component of time charter service revenues. The amount of non-cash revenue is disclosed separately in the consolidated statement of cash flows.

Joint venture FSRUs lease and time charter services revenue recognition:

The Partnership’s interest in the Joint venture FSRUs’ net income is included in the consolidated financial statements under the equity method of accounting, however, the Joint venture FSRUs’ results are presented under the proportional consolidation method for the segment note (note 3) and the time charter revenue note (note 4). The Neptune’s and the Cape Ann’s time charters, which had a twenty-year lease term at inception, are accounted for as operating leases. The joint ventures’ time charters include provisions for the charterer to make upfront payments to compensate for variable cost for certain vessel modifications, drydocking costs, other additions to equipment or spare parts. The expenditures are considered costs required to fulfill the lease component of the contract. Payments for modifications are deferred and amortized over the shorter of the remaining charter period or the useful life of the additions. Payments for reimbursement of drydocking costs are deferred and recognized on a straight line basis over the period to the next drydocking.

The accounting policy for time charter services for the joint ventures is the same as described above.

Significant judgments in revenue recognition:

The Partnership does not provide stand-alone bareboat leases or time charter services for FSRUs. As a result, observable stand-alone transaction prices for the performance obligations are not available. The estimation of the transaction price for the lease and the time charter service performance obligation is complex, subject to a number of input factors, such as market conditions when the contract is entered into, internal return objectives and pricing policies, and requires substantial judgment. Significant changes in the transaction price between the two performance obligations could impact conclusions on the accounting for leases as financing or operating leases. In addition, variable consideration is estimated at the most likely amount that the Partnership expects to be entitled to. Variable consideration is reassessed at the end of the reporting period taking into account performance warranties. The time charter contracts include provisions for performance guarantees that can result in off-hire, reduced hire, liquidated damages or other payments for performance warranties. Measurement of some of the performance warranties can be complex and require properly calibrated equipment on the vessel, complex conversions and computations based on substantial judgment in the interpretation of the contractual provisions. Conclusions on compliance with performance warranties impact the amount of variable consideration recognized for time charter services.

Contract assets:

Revenue recognized in excess of the monthly invoiced amounts, or accrued revenue, is recorded as contract assets on the consolidated balance sheet. The contract assets are reported in the consolidated balance sheet as a component of prepaid expenses and other receivables.

Contract liabilities:

Advance payments in excess of revenue recognized, or prepayments, and deferred revenue is recorded as contract liabilities on the consolidated balance sheet. Contract assets and liabilities are reported in a net position for each customer contract or combined contracts at the end of each reporting period. Contract liabilities are classified as current or non-current based on the expected timing of recognition of the revenue. Current and non-current contract liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables and other long-term liabilities, respectively.

Refund liabilities:

Amounts invoiced or paid by the customer that are expected to be refunded to the customer are recorded as refund liabilities on the consolidated balance sheet. Refund liabilities may include invoiced amounts for estimated reimbursable operating expenses or other costs and taxes that exceeded the actual costs incurred, or off-hire, reduced hire, liquidated damages, or other payments for performance warranties. Refund liabilities are reported in the consolidated balance sheet as components of accrued liabilities and other payables.

Remaining performance obligations:

Remaining performance obligations represent the transaction price of contracts with customers under the scope of ASC 606 for which work has not been performed excluding unexercised contract options to extend the term. The Partnership qualifies for and has elected to apply the exemption to disclose the aggregate amount of remaining transaction price allocated to unsatisfied performance obligations at the end of the reporting period as consideration for time charter services is variable and allocated entirely to wholly satisfied performance obligations.

Related expenses:

Voyage expenses include bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls and agency fees. Voyage expenses are all expenses unique to a particular voyage and when a vessel is on hire under time charters are generally the responsibility of, and paid directly by the charterers, and not included in the statement of income. When the vessel is off-hire, voyage expenses, principally fuel, may also be incurred and are paid by the FSRU-owning entity.

Vessel operating expenses, reflected in expenses in the statement of income, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and management fees. Vessel operating expenses also include bunker fuel expenses when the vessel is on hire and the expenses are not directly paid and owed by the charterers. When the vessel is on hire, vessel operating expenses are invoiced as time charter service fees to the charterer or are covered by time charter rates. When the vessel is off-hire, vessel operating expenses are not invoiced to the charterer.

Voyage expenses, if applicable, and vessel operating expenses are expensed when incurred.

Loss contingencies, insurance and other claims

Loss contingencies, insurance and other claims

Accruals are recorded for loss contingencies or claims when it is probable that a liability will be incurred, and the amount of loss can be reasonably estimated. Significant judgment is required to determine the probability and the estimated amount of loss. Such assessments involve complex judgments about future events and estimates and assumptions that are deemed reasonable by management. Accruals are reviewed quarterly and adjusted to reflect the impact of additional information such as the impact of negotiations, advice of legal counsel or settlements.

Insurance claims for property damage are recorded, net of any deductible amounts, for recoveries up to the amount of loss recognized when the claims to insurance carriers are probable of recovery. Claims for property damage in excess of the loss recognized and for loss of revenue during off-hire, whether from insurance providers or indemnification from Höegh LNG, are considered gain contingencies, which are recognized when the proceeds are received.

Indemnification proceeds from Höegh LNG that cover the Partnership’s costs are accounted for following the guidance of the Securities and Exchange Commission’s Staff Accounting Bulletin (“SAB”) Topic 1.B and SAB Topic 5.T. SAB Topic 1.B provides that the separate financial statements of a subsidiary should reflect any costs of its operations which are incurred by the owner on its behalf. SAB Topic 5.T provides that costs should be reflected as an expense in the subsidiary’s financial statements with a corresponding credit to contributed equity.

Income taxes

Income taxes

Income taxes are accounted for using the liability method. Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of income tax expense. The amount of non-cash income tax expense is disclosed separately in the consolidated statement of cash flows.

Deferred tax assets and liabilities are recognized for the tax consequences of temporary differences between the tax and the book bases of assets and liabilities. 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.

Benefits of uncertain tax positions are recognized when it is more-likely-than-not that a tax position taken in a tax return will be sustained upon examination based on the technical merits of the position. If the more-likely-than-not recognition criterion is met, a tax position is measured based on the cumulative amount that is more-likely-than-not of being sustained upon examination by tax authorities to determine the amount of benefit to be recognized in the consolidated financial statements. Interest and penalties related to uncertain tax positions is recognized in income tax expense in the consolidated statement of income.

Cash and cash equivalents

Cash and cash equivalents

Cash, banks deposits, time deposits and highly liquid investments with original maturities of three months or less are recognized as cash and cash equivalents.

Restricted cash and cash designated for acquisition

Restricted cash

Restricted cash includes balances deposited with a bank as required under debt facilities to settle withholding tax, other tax liabilities and other current obligations of the entity, and principal and interest payments as required by the debt facilities. Restricted cash is classified as long-term when the settlement is more than 12 months from the balance sheet date.

Trade receivables and allowance for expected credit losses

Trade receivables and allowance for expected credit losses

Trade receivables are recorded at the invoiced amount and do not bear interest. Trade receivables, contract assets and the net investment in a financing lease is initially recorded by including the current expected credit loss of the asset over the life of the contract. The allowance for expected credit losses is a valuation account that is deducted from the amortized cost of the asset to present the net amount expected to be collected. Each period the allowance for expected credit losses is adjusted through earnings to reflect the revised expected credit losses over the remaining lives of the assets. Receivable amounts are written off against the allowance when the asset is confirmed uncollectible. Expected credit losses are estimated using historical credit loss experience, relevant available information, from internal and external sources, relating to current conditions and reasonable and supportable forecasts of economic conditions impacting the collectability of the assets.

Investments in accumulated earnings or losses of and advances to joint ventures

Investments in accumulated earnings or losses of and advances to joint ventures

Investments in joint ventures are accounted for using the equity method of accounting. Under the equity method of accounting, investments are stated at initial cost and are adjusted for the Partnership’s proportionate share of earnings or losses and dividend distributions. As of December 31, 2020 and 2019, the Partnership had an accumulated share of earnings and the balance is classified on the consolidated balance sheet as an asset on the line accumulated earnings of joint ventures.

Advances to joint ventures represent loan receivables due from the joint ventures and are recorded at cost. Interest on the advances to joint ventures is recorded to interest income in the consolidated statements of income as incurred. The quarterly payments from joint ventures included a payment of interest for the first month of the quarter and repayment of principal. Interest is accrued for the last two months of the quarter for repayment at the end of the loans after the original principal was fully repaid. The joint ventures repaid the original principal of all shareholder loans during 2016. Payments of interest, including accrued interest repaid at the end of the loans, are treated as return on investment and included as a component of net cash provided by operating activities in the consolidated statement of cash flows. Payments of principal are included as a component of net cash provided by investing activities in the consolidated statement of cash flows.

Investments in joint ventures are evaluated for impairment when events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value below its carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the consolidated statement of income.

Loan receivables are impaired when, based on current information and events, it is probable that the full amount of the receivable will not be collected. The amount of the impairment is measured as the difference between the present value of expected future cash flows discounted at the loan’s effective interest rate and the carrying amount. The resulting impairment amount is recognized in earnings.

Inventory

Inventory

Inventory consists of bunker fuel maintained on the FSRUs, if it is owned by the FSRU-owning entity. Inventory is stated at the lower of cost or net realizable value. Cost is determined using the first-in, first-out method.

Vessels

Vessels

All costs incurred during the construction of newbuildings, including interest and supervision and technical costs, are capitalized. The cost of an acquired vessel is the fair value. Vessels are stated at cost less accumulated depreciation. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Depreciation is calculated using an estimated useful life of 35 years for the FSRUs.

Modifications to the vessels, including the addition of new equipment, which improves or increases the operational efficiency, functionality or safety of the vessels, are capitalized. These expenditures are amortized over the estimated useful life of the modification.

Expenditures covering recurring routine repairs and maintenance are expensed as incurred.

Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking. For vessels that are newly built, the "built-in overhaul" method of accounting is applied. Under the built-in overhaul method, costs of the newbuilding are segregated into costs that should be depreciated over the useful life of the vessel and costs that require drydocking at periodic intervals. The drydocking component is amortized until the date of the first drydocking following the delivery, upon which the actual drydocking cost is capitalized and the process is repeated. Costs of drydocking incurred to meet regulatory requirements or improve the vessel’s operating efficiency, functionality or safety are generally capitalized. Costs incurred related to routine repairs and maintenance performed during drydocking are expensed.

Impairment of long-lived assets

Impairment of long-lived assets

Vessels are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. When such events or changes in circumstances are present, the recoverability of vessels is assessed by determining whether the carrying value of such assets will be recovered through undiscounted expected future cash flows. If the vessel’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. An impairment loss is recognized based on the excess of the carrying amount over the fair value of the vessel.

Intangibles and goodwill

Intangibles and goodwill

Intangible assets are initially measured at their fair value as of the acquisition date of a business combination. All intangible assets of the Partnership have a definite life. Intangible assets with a definite life are amortized over their useful life. Intangible assets with a definite life are tested for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized if the carrying amount exceeds the estimated fair value of the asset.

In determining the useful lives of intangible assets, the expected use of the assets, the contractual provisions that limit the useful life and other economic factors are considered. The contract related intangibles and their useful lives as of the acquisition dates, are as follows:

	Useful life
Intangible category	(Years)
Above market time charter Höegh Gallant	3.4
Option for time charter extension Höegh Gallant	5.3
Above market time charter Höegh Grace	9.5

The intangible for the above market value of the time charter contract associated with the Höegh Gallant was amortized to time charter revenue on a straight line basis over the remaining term of the contract of approximately 3.4 years as of the acquisition date. On February 27, 2020, the Partnership exercised its right pursuant to an option agreement to cause Höegh LNG or its subsidiary to charter the Höegh Gallant from the expiration of its initial charter until July 2025. On April 30, 2020 the Partnership entered into the Subsequent Charter which commenced on May 1, 2020 and expires July 31, 2025. The intangible for the option for the time charter extension is amortized on a straight line basis over the extension period starting on May 1, 2020, subsequent to impairment testing for recoverability in the preceding periods. The intangible for the above market value of the time charter contract associated with the Höegh Grace is amortized to time charter revenue on a straight line basis calculated per day over the remaining non-cancellable charter term of approximately 9.5 years as of the acquisition date of the initial 51% interest in the Höegh Grace entities.

Goodwill arises when an acquisition is accounted for under the purchase method of accounting. The assets acquired and liabilities assumed are recorded at their fair values as of the acquisition date. Any excess of the consideration over the net assets acquired is recorded as goodwill. Goodwill is not amortized and is tested annually for impairment of value and whenever events or circumstances indicate that the carrying amount may not be recoverable.

Derivative instruments

Derivative instruments

All derivative instruments are initially recorded at fair value as either assets or liabilities in the consolidated balance sheet and are subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the contract is designated as a hedging instrument and qualifies for hedge accounting.

For derivative instruments that are not designated or that do not qualify for hedge accounting, the changes in the fair value of the derivative instruments are recognized in earnings. In order to designate a derivative as a cash flow hedge, formal documentation of the relationship between the derivative and the hedged item is required. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge.

Interest rate swaps are used for the management of interest rate risk exposure. The interest rate swaps have the effect of converting a portion of the outstanding debt from a floating to a fixed rate over the life of the transactions. As of January 1, 2019, the following accounting policies became effective for cash flow hedges of interest rate swaps.

For interest rate swaps qualifying as cash flow hedges, the fair value of the portion of the derivative instruments included in the assessment of hedge effectiveness ("hedge effectiveness") and the initial fair value of the hedge component excluded from hedge effectiveness are initially recorded in accumulated other comprehensive income as a component of total equity. Subsequent changes in fair value for the portion of the derivative instruments included in hedge effectiveness are recorded in other comprehensive income. In the periods when the hedged items affect earnings (interest expense is incurred for floating interest rate debt), those amounts are transferred from accumulated other comprehensive income to the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. The initial fair value component excluded from hedge effectiveness is amortized to earnings over the life of the hedging instrument. The amortization is recognized on the same line (interest expense) in the consolidated statement of income as the earnings effect of the hedged item. Any difference in the change in fair value of the hedge components excluded from hedge effectiveness and the amount recognized in earnings is recorded as a component of other comprehensive income.

Prospective and retrospective hedge effectiveness is assessed on an ongoing basis. If a cash flow hedge is no longer deemed highly effective, hedge accounting is discontinued. If a cash flow hedge for an interest rate swap is terminated and the originally hedged item is still considered probable of occurring, the gains and losses initially recognized in accumulated other comprehensive income remain there until the hedged item impacts earnings, at which point they are amortized to earnings on a systematic and rational basis to interest expense in the consolidated statement of income. If the hedged items are no longer considered probable of occurring, amounts recognized in total equity are immediately transferred to interest expense in the consolidated statement of income. Cash flows from derivative instruments that are accounted for as cash flow hedges are classified in the same category as the cash flows from the items being hedged.

For the year ended December 31, 2018, changes in the fair value of the effective portion of the derivative instruments qualifying as cash flow hedges were initially recorded in other comprehensive income as a component of total equity. Any hedge ineffectiveness was recognized immediately in earnings, as were any gains and losses or amortization on the portion of the derivative instruments that were excluded from the assessment of hedge effectiveness. In the periods when the hedged items affect earnings, those amounts were transferred from accumulated other comprehensive income to the gain (loss) on derivative instruments line in the consolidated statement of income.

Deferred debt issuance costs and fair value of debt assumed

Deferred debt issuance costs and fair value of debt assumed

Debt issuance costs, including arrangement fees and legal expenses, are deferred and presented as a direct deduction from the outstanding principal of the related debt in the consolidated balance sheet and amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the deferred debt issuance costs is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

The discount or premium arising in a business combination for the difference in the fair value of the debt assumed compared to the outstanding principal is reported in the consolidated balance sheet as a direct adjustment to the outstanding principal of the related debt and amortized on an effective interest rate method over the term of the relevant loan. Amortization of fair value of the debt assumed is included as a component of interest expense. If a loan or part of a loan is repaid early, any unamortized portion of the discount or premium is recognized as interest expense proportionate to the amount of the early repayment in the period in which the loan is repaid.

Use of estimates

Use of estimates

The preparation of financial statements in accordance with US 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. Significant estimates subject to such estimates and assumptions include revenue recognition, purchase price allocation, the useful lives of vessels, drydocking, loss contingencies and the value of derivative instruments.

Recently adopted accounting pronouncements and Recently issued accounting pronouncements

Recently adopted accounting pronouncements

Allowance for expected credit losses: On January 1, 2020, the Partnership adopted the Financial Accounting Standards Board’s (“FASB”) revised guidance on Financial Instruments – Credit Losses: Measurement of Credit Losses, which replaces the incurred loss methodology with a current expected credit loss (CECL) methodology that requires consideration of a broader range of reasonable and supportable information to estimate credit losses. The new guidance is applicable to financial assets measured at amortized cost, including trade receivables, contract assets and net investment in financing leases and applied with a modified retrospective method. The Partnership recorded a net decrease to retained earnings of $0.16 million as of January 1, 2020 for the cumulative effect of adopting the new standard. The cumulative effect includes allowances for expected credit losses recognized of $0.1 million (related to the net investment in financing lease) and $0.06 million (related to trade receivables). Refer to note 4.

For the year ended December 31, 2020, there was no change in the allowance for expected credit losses following the cumulative effect of adopting the new standard.

On January 1, 2020, the Partnership adopted FASB's revised guidance for Intangibles - Goodwill and Other: Simplifying the test for Goodwill Impairment, which simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The adoption of the standard did not have an impact on the consolidated financial statements.

Recently issued accounting pronouncements

In December 2019, FASB issued revised guidance for Income Taxes – Simplifying the Accounting for Income Taxes. The revised guidance eliminates certain exceptions to the guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance is effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted in interim or annual periods for which public business entities have not yet issued financial statements. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements and related disclosures. The Partnership implemented the revised guidance on January 1, 2021.

In March 2020, FASB issued final guidance for Reference Rate Reform to provide temporary optional expedients and exceptions to the guidance in US GAAP on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. For all types of hedging relationships, the guidance allows an entity to change the reference rate and other critical terms related to reference rate reform without having to dedesignate the relationship. The guidance is effective upon issuance through December 31, 2022. The Partnership is evaluating the impact of this revised guidance on its consolidated financial statements for the expected transitions from LIBOR to alternative reference rates. In January 2021 FASB issued an update to the guidance from 2020 to clarify its scope.

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Description of business (Tables)

12 Months Ended

Dec. 31, 2020

Description of business

Schedule of entities

The following table lists the entities included in these consolidated financial statements and their purpose as of December 31, 2020.

	Jurisdiction of
	Incorporation
Name	or Registration	Purpose
Höegh LNG Partners LP	Marshall Islands	Holding Company
Höegh LNG Partners Operating LLC (100% owned)	Marshall Islands	Holding Company
Hoegh LNG Services Ltd (100% owned)	United Kingdom	Administration Services Company
Hoegh LNG Lampung Pte. Ltd. (100% owned)	Singapore	Owns 49% of PT Hoegh LNG Lampung
PT Hoegh LNG Lampung (49% owned) (1)	Indonesia	Owns PGN FSRU Lampung
SRV Joint Gas Ltd. (50% owned) (2)	Cayman Islands	Owns Neptune
SRV Joint Gas Two Ltd. (50% owned) (2)	Cayman Islands	Owns Cape Ann
Hoegh LNG Cyprus Limited (100% owned)	Cyprus	Owns Höegh Gallant
Hoegh LNG Cyprus Limited Egypt Branch (100% owned)	Egypt	Branch of Hoegh LNG Cyprus Limited
Höegh LNG Colombia Holding Ltd. (100% owned)	Cayman Islands	Owns 100% of Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S.
Höegh LNG FSRU IV Ltd. (100% indirectly owned)	Cayman Islands	Owns Höegh Grace
Höegh LNG Colombia S.A.S. (100% indirectly owned)	Colombia	Operating Company

(1) PT Hoegh LNG Lampung is a variable interest entity, which is controlled by Hoegh LNG Lampung Pte. Ltd. and is, therefore, 100% consolidated in the consolidated financial statements.

(2) The remaining 50% interest in each joint venture is owned by Mitsui O.S.K. Lines, Ltd. and Tokyo LNG Tanker Co.

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Significant accounting policies (Tables)

12 Months Ended

Dec. 31, 2020

Significant accounting policies

Schedule of contract related intangibles and their useful lives

	Useful life
Intangible category	(Years)
Above market time charter Höegh Gallant	3.4
Option for time charter extension Höegh Gallant	5.3
Above market time charter Höegh Grace	9.5

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Segment information (Tables)

12 Months Ended

Dec. 31, 2020

Segment information

Schedule of results of segments

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	143,095	43,572	—	186,667	(43,572)	(1)	$	143,095
Total revenues		143,095	43,572	—	186,667				143,095
Operating expenses		(27,462)	(9,452)	(6,350)	(43,264)	9,452	(1)		(33,812)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,420	(1)		6,420
Segment EBITDA		115,633	34,120	(6,350)	143,403
Depreciation, amortization and impairment		(20,937)	(9,965)	—	(30,902)	9,965	(1)		(20,937)
Operating income (loss)		94,696	24,155	(6,350)	112,501				94,766
Gain (loss) on derivative instruments		—	(6,073)	—	(6,073)	6,073	(1)		—
Other financial income (expense), net		(9,072)	(11,662)	(16,985)	(37,719)	11,662	(1)		(26,057)
Income (loss) before tax		85,624	6,420	(23,335)	68,709	—			68,709
Income tax expense		(5,564)	—	—	(5,564)	—			(5,564)
Net income (loss)	$	80,060	6,420	(23,335)	63,145	—		$	63,145
Preferred unitholders’ interest in net income		—	—	—	—	14,802	(2)		14,802
Limited partners’ interest in net income (loss)	$	80,060	6,420	(23,335)	63,145	(14,802)	(2)	$	48,343

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

	As of December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	619,620	242,226	—	861,846	(242,226)	(1)	$	619,620
Net investment in financing lease		274,257	—	—	274,257	—			274,257
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	4,153	4,153	—			4,153
Total assets		969,278	267,003	12,532	1,248,813	(267,003)	(1)		981,810
Accumulated earnings of joint ventures		—	—	50	50	9,640	(1)		9,690
Expenditures for vessels & equipment		8	75	—	83	(75)	(2)		8
Expenditures for drydocking		—	2	—	2	(2)	(2)		—
Principal repayment financing lease		4,551	—	—	4,551	—			4,551
Amortization of above market contract	$	3,052	—	—	3,052	—		$	3,052

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	145,321	42,433	—	187,754	(42,433)	(1)	$	145,321
Other revenue		115	—	—	115		(1)		115
Total revenues		145,436	42,433	—	187,869				145,436
Operating expenses (2)		(34,266)	(9,044)	(6,465)	(49,775)	9,044	(1)		(40,731)
Equity in earnings (losses) of joint ventures		—	—	—	—	6,078	(1)		6,078
Segment EBITDA		111,170	33,389	(6,465)	138,094
Depreciation, amortization and impairment		(21,477)	(10,030)	—	(31,507)	10,030	(1)		(21,477)
Operating income (loss)		89,693	23,359	(6,465)	106,587				89,306
Gain (loss) on debt extinguishment		1,030	—	—	1,030		(1)		1,030
Gain (loss) on derivative instruments		—	(5,209)	—	(5,209)	5,209	(1)		—
Other financial income (expense), net		(12,511)	(12,072)	(17,809)	(42,392)	12,072	(1)		(30,320)
Income (loss) before tax		78,212	6,078	(24,274)	60,016	—			60,016
Income tax expense		(7,278)	—	3	(7,275)	—			(7,275)
Net income (loss)	$	70,934	6,078	(24,271)	52,741	—		$	52,741
Preferred unitholders’ interest in net income		—	—	—	—	13,850	(3)		13,850
Limited partners’ interest in net income (loss)	$	70,934	6,078	(24,271)	52,741	(13,850)	(3)	$	38,891

(1) Eliminations reverse each of the income statement line items of the proportional amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs net income (loss) to Equity in earnings (losses) of joint ventures.

(2) The Partnership's Indonesian subsidiary was assessed a property tax and penalties of $3.0 million by the Indonesian authorities for the period from 2015 through 2019. The retroactive assessment was as a result of the issuance of a new regulation in 2019, defining FSRUs as subject to the existing Indonesian property tax law. The property tax and penalties were recorded as a component of vessel operating expenses.

(3) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

	As of December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Vessels, net of accumulated depreciation	$	640,431	252,789	—	893,220	(252,789)	(1)	$	640,431
Net investment in financing lease		278,904	—	—	278,904	—			278,904
Goodwill		251	—	—	251	—			251
Advances to joint ventures		—	—	3,831	3,831	—			3,831
Total assets		996,201	284,174	16,599	1,296,974	(284,174)	(1)		1,012,800
Accumulated earnings of joint ventures		—	—	50	50	3,220	(1)		3,270
Expenditures for vessels & equipment		211	195	—	406	(195)	(2)		211
Expenditures for drydocking		3,107	913	—	4,020	(913)	(2)		3,107
Impairment/retirement of equipment		—	(75)	—	(75)	75	(2)		—
Principal repayment financing lease		4,168	—	—	4,168	—			4,168
Amortization of above market contract	$	3,631	—	—	3,631	—		$	3,631

(1) Eliminates the proportional share of the Joint venture FSRUs’ Vessels, net of accumulated depreciation, and Total assets and reflects the Partnership’s share of net assets (assets less liabilities) of the Joint venture FSRUs as Accumulated earnings of joint ventures.

(2) Eliminates the Joint venture FSRUs’ Expenditures for vessels & equipment and drydocking to reflect the consolidated expenditures of the Partnership.

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment			Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations		reporting
Time charter revenues	$	144,952	43,169	—	188,121	(43,169)	(1)	$	144,952
Other revenue		1,609	—	—	1,609		(1)		1,609
Total revenues		146,561	43,169	—	173,846				146,561
Operating expenses		(27,294)	(10,932)	(5,817)	(44,043)	10,932	(1)		(33,111)
Equity in earnings (losses) of joint ventures		—	—	—	—	17,938	(1)		17,938
Segment EBITDA		119,267	32,237	(5,817)	145,687
Depreciation and amortization		(21,146)	(9,725)	—	(30,871)	9,725	(1)		(21,146)
Operating income (loss)		98,121	22,512	(5,817)	114,816				110,242
Gain (loss) on derivative instruments		4,681	8,496	—	13,177	(8,496)	(1)		4,681
Other financial income (expense), net		(26,381)	(13,070)	(2,615)	(42,066)	13,070	(1)		(28,996)
Income (loss) before tax		76,421	17,938	(8,432)	85,927	—			85,927
Income tax benefit (expense)		(8,253)	—	(52)	(8,305)	—			(8,305)
Net income (loss)	$	68,168	17,938	(8,484)	77,622	—		$	77,622
Preferred unitholders’ interest in net income		—	—	—	—	12,303	(2)		12,303
Limited partners’ interest in net income (loss)	$	68,168	17,938	(8,484)	77,622	(12,303)	(2)	$	65,319

(1) Eliminations reverse each of the income statement line items of the proportional consolidation amounts for Joint venture FSRUs and record the Partnership’s share of the Joint venture FSRUs’ net income (loss) to Equity in earnings (loss) of joint ventures.

(2) Allocates the preferred unitholders’ interest in net income to the preferred unitholders.

Schedule of total revenues from the customers

For the years ended December 31, 2020, 2019 and 2018, the percentage of consolidated total revenues from the following customers accounted for over 10% of the Partnership’s consolidated total revenues:

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019		2018
PT PGN LNG Indonesia	33	%	33	%	33	%
Höegh LNG	30	%	31	%	31	%
Sociedad Portuaria El Cayao S.A. E.S.P.	37	%	36	%	36	%

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Time charter revenues and related contract balances (Tables)

12 Months Ended

Dec. 31, 2020

Time charter revenues and related contract balances

Summary of disaggregated revenue

The following tables summarize the disaggregated revenue of the Partnership by segment for the twelve months ended December 31, 2020, 2019 and 2018:

	Year ended December 31, 2020
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	87,948	25,760	—	113,708	(25,760)	$	87,948
Time charter service revenues, excluding amortization		58,199	15,098	—	73,297	(15,098)		58,199
Amortization of above market contract intangibles		(3,052)	—	—	(3,052)	—		(3,052)
Amortization of deferred revenue for modifications & drydock		—	2,714	—	2,714	(2,714)		—
Total revenues (4)	$	143,095	43,572	—	186,667	(43,572)	$	143,095

	Year ended December 31, 2019
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization (2)	$	88,889	25,690	—	114,579	(25,690)	$	88,889
Time charter service revenues, excluding amortization		60,063	14,095	—	74,158	(14,095)		60,063
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,648	—	2,648	(2,648)		—
Other revenue (3)		115	—	—	115	—		115
Total revenues (4)	$	145,436	42,433	—	187,869	(42,433)	$	145,436

	Year ended December 31, 2018
			Joint venture
	Majority		FSRUs		Total
	held		(proportional		Segment		Consolidated
(in thousands of U.S. dollars)	FSRUs		consolidation)	Other	reporting	Eliminations (1)	reporting
Lease revenues, excluding amortization	$	89,215	25,690	—	114,905	(25,690)	$	89,215
Time charter service revenues, excluding amortization		59,368	15,078	—	74,446	(15,078)		59,368
Amortization of above market contract intangibles		(3,631)	—	—	(3,631)	—		(3,631)
Amortization of deferred revenue for modifications & drydock		—	2,401	—	2,401	(2,401)		—
Other revenue (3)		1,609	—	—	1,609	—		1,609
Total revenues (4)	$	146,561	43,169	—	189,730	(43,169)	$	146,561

(1) Eliminations reverse the proportional amounts of revenue for Joint venture FSRUs to reflect the consolidated revenues included in the consolidated income statement. The Partnership’s share of the Joint venture FSRUs revenues is included in Equity in earnings (losses) of joint ventures on the consolidated income statement.

(2) The financing lease revenues comprise about one-fourth of the total lease revenues for the years ended December 31, 2020 and 2019.

(3) Other revenue consists of insurance proceeds received for prior period claims related to repairs under the Mooring warranty and for repairs for the Höegh Gallant. The Partnership was indemnified by Höegh LNG for the cost of the repairs related to the Mooring, subject to repayment to the extent recovered from insurance proceeds. Refer to notes 3 and 17.

(4) Payments made by the charterer directly to the tax authorities on behalf of the subsidiaries for advance collection of income taxes or final income tax is recorded as a component of total revenues and is disclosed separately in the consolidated statement of cash flows.

Schedule of consolidated receivables between lease and service components

The following table summarizes the allocation of consolidated receivables between lease and service components:

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Trade receivable for lease	$	2,608	$	2,898
Trade receivable for time charter services		1,506		2,133
Allowance for expected credit losses		(60)		—
Total trade receivable and amounts due from affiliates	$	4,054	$	5,031

Summary of contract assets, contract liabilities and refund liabilities to customers

The following table summarizes the consolidated contract assets, contract liabilities and refund liabilities to customers, as of December 31, 2020 and 2019:

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2020	$	279	$	(125)
Additions		—		(841)
Reduction for receivables recorded		(18)		—
Reduction for revenue recognized (excluding amortization)		—		10
Reduction for revenue recognized from previous years		—		48
Repayments of refund liabilities to charterer		—		17
Balance December 31, 2020	$	261	$	(891)

	Services related
	Contract		Refund liability
(in thousands of U.S. dollars)	asset		to charters
Balance January 1, 2019	$	—	$	(1,834)
Additions		279		(65)
Reduction for receivables recorded		—		89
Reduction for revenue recognized from previous years		—		497
Repayments of refund liabilities to charterer		—		1,188
Balance December 31, 2019	$	279	$	(125)

Summary of minimum contractual future revenues

As of December 31, 2020, the minimum contractual future revenues to be received under the time charters for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace during the next five years and thereafter are as follows:

(in thousands of U.S. dollars)	Service related		Lease related		Total
2021	$	32,369		90,441	$	122,810
2022		32,369		90,441		122,810
2023		32,369		90,441		122,810
2024		32,369		90,441		122,810
2025		27,091		77,717		104,808
Thereafter		96,683		286,467		383,150
Total - undiscounted	$	253,250		725,948	$	979,198
Operating lease			$	321,724
Financing lease				404,224
Discounting effect				(172,499)
Financing lease receivable			$	231,725

Summary of direct financing lease

	As of December 31,
(in thousands of U.S. dollars)	2020		2019
Minimum lease payments	$	589,074	$	589,074
Unguaranteed residual value		146,000		146,000
Unearned income		(440,345)		(440,345)
Initial direct cost, net		3,095		3,095
Net investment in financing lease at origination		297,824		297,824
Principal repayment and amortization		(23,471)		(18,920)
Allowance for credit loss		(96)		—
Net investment in financing lease at period end		274,257		278,904
Less: Current portion		(4,969)		(4,551)
Long term net investment in financing lease	$	269,288	$	274,353
Net investment in financing lease consists of:
Financing lease receivable	$	231,725	$	240,000
Unguaranteed residual value		42,532		38,904
Net investment in financing lease at period end	$	274,257	$	278,904

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Financial income (expense), net (Tables)

12 Months Ended

Dec. 31, 2020

Financial income (expense), net

Schedule of components of financial income (expense), net

The components of financial income (expense), net are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Interest income	$	605	947	$	725
Interest expense:
Interest expense		(22,003)	(24,950)		(26,077)
Commitment fees		(138)	(381)		(37)
Amortization of debt issuance cost and fair value of debt assumed		(2,289)	(2,361)		(700)
Total interest expense		(24,430)	(27,692)		(26,814)
Gain (loss) on debt extinguishment		—	1,030		—
Gain (loss) on derivative instruments		—	—		4,681
Other items, net:
Foreign exchange gain (loss)		444	(396)		(193)
Bank charges, fees and other		(276)	(297)		(143)
Withholding tax on interest expense and other		(2,400)	(2,882)		(2,571)
Total other items, net		(2,232)	(3,575)		(2,907)
Total financial income (expense), net	$	(26,057)	(29,290)	$	(24,315)

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Income tax (Tables)

12 Months Ended

Dec. 31, 2020

Income tax

Schedule of components of income tax expense

The components of income tax expense recognized in the consolidated statements of income are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Current tax (benefit) expense	$	3,832	4,126	$	4,759
Deferred tax (benefit) expense for
Change in temporary differences		1,335	3,341		3,290
Tax loss and tax credit carried forward		393	(196)		247
Change in valuation allowance		4	4		9
Total deferred tax (benefit) expense		1,732	3,149		3,546
Total income tax (benefit) expense	$	5,564	7,275	$	8,305

Deferred tax (benefit) expense recognized in the consolidated statements of comprehensive income as a component of other comprehensive income (“OCI”) are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Cash flow hedge derivative instruments	$	262	389	$	299
Deferred tax (benefit) expense recognized in OCI	$	262	389	$	299

Schedule of reconciliation of the income before tax at the statutory rate

The reconciliation of the income before tax at the statutory rate in the Marshall Islands to the actual income tax expense for each year is as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Income before tax	$	68,709	60,016	$	85,927
At applicable statutory tax rate
Amount computed at corporate tax of 0%		—	—		—
Foreign tax rate differences		4,972	5,425		7,513
Permanent differences:
Amended tax return: reinstatement of tax loss carryforward		—	—		—
Tax audit or amended tax return: change in uncertain tax position		385	558		(41)
Non-deductible interest expense		571	1,477		875
Non-deductible withholding tax		625	717		838
Non-deductible loss on derivatives		(114)	120		—
Tax exemptions		(13)	(13)		(36)
Non-deductible other financial items		(106)	194		116
Other non-deductible costs		(18)	45		63
Tax credits		(742)	(1,252)		(1,032)
Adjustment for valuation allowance		4	4		9
Tax expense (benefit) for year	$	5,564	7,275	$	8,305

Schedule of deferred income tax assets (liabilities)

Deferred income tax assets (liabilities) are summarized as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Deferred tax assets:
Accrued liabilities and other payables	$	124	$	235
Derivative instruments		422		565
Other equipment		8		9
Tax credits carried forward		1,421		1,818
Tax loss carryforward		32		57
Valuation allowance		(32)		(57)
Deferred tax liabilities:
Accrued interest income		(4,575)		(4,123)
Accrued liabilities and other payables		(400)		(385)
Financing lease		(11,328)		(10,451)
Deferred tax assets (liabilities), net	$	(14,328)	$	(12,332)

Schedule of changes in the unrecognized tax benefits

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Unrecognized tax benefits as of January 1,	$	(2,283)	(1,725)	$	(2,626)
Decrease related to prior year tax positions		—	—		434
Increase related to current year tax positions		(385)	(558)		(418)
Settlements		—	—		885
Unrecognized tax benefits as of December 31,	$	(2,668)	(2,283)	$	(1,725)

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Prepaid expenses and other receivables (Tables)

12 Months Ended

Dec. 31, 2020

Prepaid expenses and other receivables

Schedule of prepaid expenses

The components of prepaid expenses and other receivables are as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Prepaid expenses	$	2,140	$	752
Other receivables		1,743		1,782
Total other prepaid expenses and other receivables	$	3,883	$	2,534

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Investments in joint ventures (Tables)

12 Months Ended

Dec. 31, 2020

Schedule of Equity Method Investments [Line Items]

Schedule of equity method investments

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accumulated earnings of joint ventures	$	9,690	$	3,270

SRV Joint Gas Ltd and SRV Joint Gas Two Ltd [Member]

Schedule of Equity Method Investments [Line Items]

Schedule of financial statement information of joint ventures on aggregated basis

	Year ended
	December 31,
(in thousands of U.S. dollars)	2020			2019		2018
Time charter revenues	$	78,687		77,051		$	79,654
Other income		8,457		7,814			6,684
Total revenues		87,144		84,865			86,338
Operating expenses		(18,904)		(18,088)			(21,864)
Depreciation and amortization		(20,546)		(20,524)			(20,065)
Impairment of long-lived assets (1)		—		(149)			—
Operating income		47,694		46,104			44,409
Unrealized gain (loss) on derivative instruments		(12,146)		(10,418)			16,992
Other financial expense, net		(23,324)		(24,144)			(26,140)
Net income (loss)	$	12,224		11,542		$	35,261
Share of joint ventures owned		50	%	50	%		50	%
Share of joint ventures net income (loss) before eliminations		6,112		5,771			17,631
Eliminations		308		307			307
Equity in earnings (losses) of joint ventures	$	6,420		6,078		$	17,938

(1) At the completion of the class renewal survey of the Neptune, certain equipment was identified that was impaired.

	As of
	December 31,
(in thousands of U.S. dollars)	2020			2019
Cash and cash equivalents	$	13,455		$	17,897
Restricted cash		21,264			9,250
Other current assets		178			973
Total current assets		34,897			28,120
Restricted cash		14,656			34,650
Vessels, net of accumulated depreciation		499,318			521,060
Total long-term assets		513,974			555,710
Current portion of long-term debt		199,030			28,297
Amounts and loans due to owners and affiliates		7,278			629
Derivative instruments		14,687			13,089
Refund liabilities (1)		1,040			26,691
Other current liabilities		8,811			10,327
Total current liabilities		230,846			79,033
Long-term debt		176,385			375,091
Loans due to owners and affiliates		1,737			7,663
Derivative instruments		69,618			59,070
Other long-term liabilities		36,040			40,952
Total long-term liabilities		283,780			482,776
Net assets (liabilities)	$	34,245		$	22,021
Share of joint ventures owned		50	%		50	%
Share of joint ventures net assets (liabilities) before eliminations		17,123			11,011
Eliminations		(7,433)			(7,741)
Accumulated earnings (losses) of joint ventures	$	9,690		$	3,270

(1) Refund liabilities include the liability for the boil-off claim and other refundable amounts due to the charterer.

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Advances to joint ventures (Tables)

12 Months Ended

Dec. 31, 2020

Advances to joint ventures

Schedule of investments in and advances to affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Current portion of advances to joint ventures	$	3,284	$	—
Long-term advances to joint ventures		869		3,831
Advances/shareholder loans to joint ventures	$	4,153	$	3,831

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Vessels and other equipment (Tables)

12 Months Ended

Dec. 31, 2020

Vessels and other equipment

Schedule of vessels and other equipment

			Dry-
(in thousands of U.S. dollars)	Vessel		docking	Total
Historical cost December 31, 2018	$	706,715	6,667	$	713,382
Additions		183	3,107		3,290
Historical cost December 31, 2019		706,898	9,774		716,672
Depreciation for the year		(19,393)	(1,777)		(21,170)
Accumulated depreciation December 31, 2019		(70,264)	(5,977)		(76,241)
Vessels, net December 31, 2019		636,634	3,797		640,431
Historical cost December 31, 2019		706,898	9,774		716,672
Additions		8	—		8
Historical cost December 31, 2020		706,906	9,774		716,680
Depreciation for the year		(19,398)	(1,421)		(20,819)
Accumulated depreciation December 31, 2020		(89,662)	(7,398)		(97,060)
Vessels, net December 31, 2020	$	617,244	2,376	$	619,620

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Intangibles and goodwill (Tables)

12 Months Ended

Dec. 31, 2020

Intangibles and goodwill

Schedule of indefinite-lived intangible assets

			Option
	Above		for time
	market time		charter	Total
(in thousands of U.S. dollars)	charter		extension	Intangibles	Goodwill	Total
Historical cost December 31, 2018	$	22,760	8,000	30,760	251	$	31,011
Amortization for the year		(3,631)	—	(3,631)	—		(3,631)
Accumulated amortization, December 31, 2019		(13,903)	—	(13,903)	—		(13,903)
Intangibles and goodwill, December 31, 2019		8,857	8,000	16,857	251		17,108
Historical cost December 31, 2019		22,760	8,000	30,760	251		31,011
Additions		—	—	—	—		—
Historical cost December 31, 2020		22,760	8,000	30,760	251		31,011
Amortization for the year		(2,030)	(1,022)	(3,052)	—		(3,052)
Accumulated amortization, December 31, 2020		(15,933)	(1,022)	(16,955)	—		(16,955)
Intangibles and goodwill, December 31, 2020	$	6,827	6,978	13,805	251	$	14,056

Schedule of estimated future amortization expense

The following table presents estimated future amortization expense for the intangibles:

(in thousands of U.S. dollars)	Total
2021	$	2,755
2022		2,755
2023		2,755
2024		2,762
2025		2,116
2026 and thereafter	$	662

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Long-term debt (Tables)

12 Months Ended

Dec. 31, 2020

Schedule of long-term debt

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Lampung facility:
Export credit tranche	$	79,324	$	94,210
FSRU tranche		18,635		22,812
$385 million facility:
Commercial tranche		230,705		249,635
Export credit tranche		44,500		51,167
Revolving credit tranche		48,300		48,300
Outstanding principal		421,464		466,124
Lampung facility unamortized debt issuance cost		(2,999)		(4,309)
$385 million facility unamortized debt issuance costs		(3,876)		(4,854)
Total debt		414,589		456,961
Less: Current portion of long-term debt		(59,119)		(44,660)
Long-term debt	$	355,470	$	412,301

Schedule of outstanding principal on long-term debt

(in thousands of U.S. dollars)	Total
2021	$	123,557
2022		25,597
2023		25,597
2024		25,597
2025		25,597
2026 and thereafter		195,519
Total	$	421,464

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Accrued liabilities and payables (Tables)

12 Months Ended

Dec. 31, 2020

Accrued liabilities and payables

Schedule of accrued liabilities and payables

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Accrued operating and administrative expenses	$	3,042	$	3,314
Accrued property tax		—		3,033
Accrued interest		2,641		2,850
Current tax payable		469		818
Refund liabilities (note 4)		891		125
Lease liability (note 2 and note 10)		39		75
Other accruals and payables		150		949
Total accrued liabilities and other payables	$	7,232	$	11,164

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Related party transactions (Tables)

12 Months Ended

Dec. 31, 2020

Schedule of related party transactions

Amounts due from affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due from affiliates	$	3,639	$	4,296

Amounts due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Amounts due to owners and affiliates	$	2,600	$	2,513

Revolving credit facility due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2020		2019
Revolving credit facility due to owners and affiliates - non-current portion	$	18,465	$	8,792

Hoegh LNG and Subsidiaries [Member]

Schedule of related party transactions

As described in Related party agreements below, subsidiaries of Höegh LNG have provided administrative services to the Partnership and ship management and/or technical support services for the PGN FSRU Lampung, the Höegh Gallant and the Höegh Grace, as well as leasing the Höegh Gallant.

Related party amounts included in the consolidated statements of income for the years ended December 31, 2020, 2019 and 2018 or included in the consolidated balance sheets as of December 31, 2020 and 2019 are as follows:

(in thousands of U.S. dollars)	2020		2019	2018
Revenues
Time charter revenue Höegh Gallant (1)	$	45,274	47,173	$	47,108
Operating expenses
Vessel operating expenses (2)		(21,328)	(24,523)		(21,520)
Hours, travel expense and overhead (3) and Board of Directors’ fees (4)		(4,353)	(4,072)		(3,671)
Financial (income) expense
Interest income from joint ventures (5)		321	295		273
Interest expense and commitment fees to Höegh LNG (6)		(64)	(1,882)		(2,938)
Total	$	19,850	16,991	$	19,252

	As of
Balance sheet	December 31,
(in thousands of U.S. dollars)	2020		2019
Equity
Contribution from Höegh LNG (7)	$	11,850	$	—
Repayment of indemnification received from Höegh LNG (8)		—		(64)
Issuance of units for Board of Directors’ fees (4)		181		194
Other and contribution from owner (9)		109		485
Total	$	12,140	$	615

1) Time charter revenue Höegh Gallant: Subsidiaries of Höegh LNG, have leased the Höegh Gallant.

2) Vessel operating expenses: Subsidiaries of Höegh LNG provide ship management of vessels, including crews and the provision of all other services and supplies.

3) Hours, travel expenses and overhead: Subsidiaries of Höegh LNG provide management, accounting, bookkeeping and administrative support under administrative service agreements. These services are charges based upon the actual hours incurred for each individual as registered in the time-write system based on a rate which includes a provision for overhead and any associated travel expenses.

4) Board of Directors’ fees: Total Board of Directors’ fees were $571, $496 and $501 for the years ended December 31, 2020, 2019 and 2018, respectively. Part of the compensation is awarded as common units of the Partnership. Effective September 4, 2020, a total of 15,528 common units were awarded to non-employee directors as compensation of $162 for part of directors’ fees for 2020 under the Höegh LNG Partners LP Long Term Incentive Plan. Effective June 4, 2019 and June 6, 2018, a total of 11,180 and 11,050 common units, respectively, of the Partnership were awarded to non-employee directors as compensation of $194 and $200, respectively, for part of directors’ fees for 2019 and 2018. The awards were recorded as administrative expense and as an issuance of common units. Common units are recorded when issued.

5) Interest income from joint ventures: The Partnership and its joint venture partners have provided subordinated financing to the joint ventures as shareholder loans. Interest income for the Partnership’s shareholder loans to the joint ventures is recorded as interest income.

6) Interest expense and commitment fees to Höegh LNG and affiliates: Höegh LNG and its affiliates provided an $85 million revolving credit facility for general partnership purposes. The Partnership incurred a commitment fee on the undrawn balance until January 29, 2018 and an interest expense on the drawn balance.

7) Non-cash contribution from/distribution to Höegh LNG: As described under “Indemnification” below, on April 8, and December 11, 2020, the Partnership was indemnified by Höegh LNG for its share of the joint-ventures boil-off settlement payments by a reduction of $8.6 million and $3.3 million, respectively, on its outstanding balance on the $85 million revolving credit facility from Höegh LNG. These non-cash settlements, totaling $11.9 million, were recorded as an increase in equity.

8) Cash contribution from/distribution to Höegh LNG: As described under “Indemnifications” below, Höegh LNG made indemnification payments to the Partnership or received refunds of indemnification from the Partnership which were recorded as contributions or distributions to equity.

9) Other and contribution from owner: Höegh LNG granted share-based incentives to certain key employees whose services benefit the Partnership. Related expenses are recorded as administrative expenses and as a contribution from owner since the Partnership is not invoiced for this employee benefit. Effective March 26, 2020, March 21, 2019 and September 14, 2018, the Partnership granted or extended the terms for 8,100, 10,917 and 28,018 phantom units, respectively, to the Chief Executive Officer and Chief Financial Officer of the Partnership. Related expenses are recorded over the vesting period as an administrative expense and as increase in equity. On August 6, 2020, the Partnership announced that the Partnership’s Chief Executive Officer and Chief Financial Officer resigned, which resulted in 15,378 of the phantom units not vesting, resulting in a reduction in administration expense and equity for the forfeited units. The remaining 4,861 unvested phantom units will vest in 2021.

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2020

Financial Instruments

Schedule of estimated fair value and carrying value of assets and liabilities

The following table includes the estimated fair value and carrying value of those assets and liabilities that are measured at fair value on a recurring and non-recurring basis, as well as the estimated fair value of the financial instruments that are not accounted for at a fair value on a recurring basis. Trade payables and receivables for which the estimated fair values are equivalent to carrying values are not specified below.

		As of			As of
		December 31, 2020			December 31, 2019
		Carrying		Fair	Carrying	Fair
		amount		value	amount	value
		Asset		Asset	Asset	Asset
(in thousands of U.S. dollars)	Level	(Liability)		(Liability)	(Liability)	(Liability)
Recurring:
Cash and cash equivalents	1	$	31,770	31,770	39,126	$	39,126
Restricted cash	1		19,293	19,293	20,693		20,693
Derivative instruments	2		(26,475)	(26,475)	(14,935)		(14,935)
Other:
Amounts due from affiliate	2		3,639	3,639	4,296		4,296
Advances (shareholder loans) to joint ventures	2		4,153	4,305	3,831		4,029
Current amounts due to owners and affiliates	2		(2,600)	(2,600)	(2,513)		(2,513)
Lampung facility	2		(94,960)	(99,295)	(112,713)		(119,598)
$385 million facility	2		(319,629)	(323,342)	(344,248)		(352,219)
Revolving credit facility due to owners and affiliates	2	$	(18,465)	(16,987)	(8,792)	$	(8,717)

Summary of Financing receivables and net investment in financing lease

The following table contains a summary of the class of financial asset, year of origination and the method by which the credit quality is monitored on a quarterly basis:

Class		Credit Quality		As of December 31,
(in thousands of U.S. dollars)	Year	Indicator	Grade	2020		2019
Advances/shareholder loans to joint ventures	2006	Collection experience	Performing	$	4,153	$	3,831
Net investment in financing lease	2014	Credit Information	Performing	$	274,257	$	278,904

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Risk management and concentrations of risk (Tables)

12 Months Ended

Dec. 31, 2020

Risk management and concentrations of risk

Schedule of interest rate swap agreements

				Fair
				value			Fixed
	Interest			carrying			interest
	rate	Notional		amount			rate
(in thousands of U.S. dollars)	index	amount		liability		Term	(1)
LIBOR-based debt
Lampung interest rate swaps (2)	LIBOR	$	97,960	$	(5,680)	Sep 2026	2.800	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,560)	Jan 2026	2.941	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,197)	Oct 2025	2.838	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(5,111)	Jan 2026	2.735	%
$385 million facility swaps (2)	LIBOR	$	56,782	$	(4,927)	Jan 2026	2.650	%

1) Excludes the margins paid on the floating-rate debt.

2) All interest rate swaps are U.S. dollar denominated and the notional amount reduces quarterly from the effective date of the interest rate swaps.

Schedule of fair value of derivative instruments

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the consolidated balance sheets.

	Current		Long-term		Current		Long-term
	assets:		assets:		liabilities:		liabilities:
	derivative		derivative		derivative		derivative
(in thousands of U.S. dollars)	instruments		instruments		instruments		instruments
As of December 31, 2020
Interest rate swaps	$	—	$	—	$	(6,945)	$	(19,530)
As of December 31, 2019
Interest rate swaps	$	—	$	—	$	(2,907)	$	(12,028)

Schedule of effect of cash flow hedge accounting on the consolidated statement of income

The following effects of cash flow hedges relating to interest rate swaps are included in gain (loss) on derivative instruments in the consolidated statements of income for the years ended December 31, 2020 and 2019.

	Year ended
	December 31, 2020
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(5,849)	$	—
Amortization of amount excluded from hedge effectiveness		851		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(1,024)		262
Total gains (losses) on derivative instruments	$	(6,022)	$	262

	Year ended
	December 31, 2019
			Income tax
(in thousands of U.S. dollars)	Interest expense		benefit
Gain (loss) on interest rate swaps in cash flow hedging relationships:
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$	(956)	$	—
Amortization of amount excluded from hedge effectiveness		966		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		(987)		389
Settlement of cash flow hedge		199		—
Total gains (losses) on derivative instruments	$	(778)	$	389

The following effects of cash flow hedges relating to interest rate swaps are included in total gains (losses) on derivative instruments in the consolidated statements of income for the year ended December 31, 2018.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2018
Interest rate swaps:
Ineffective portion of cash flow hedge	$	(990)
Amortization of amount excluded from hedge effectiveness		2,969
Reclassification discontinued hedge from OCI		3,557
Reclassification from accumulated other comprehensive income		(855)
Unrealized gains (losses)		4,681
Realized gains (losses)		—
Total gains (losses) on derivative instruments	$	4,681

Schedule of effect of cash flow hedge accounting on accumulated OCI and earnings

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Effective portion of unrealized loss on cash flow hedge		(18,240)	—		(18,240)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		5,849	—		5,849		(5,849)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		1,024	(262)		762		(1,024)		262
Other comprehensive income for period		(11,367)	(262)		(11,629)
Accumulated OCI as of December 31, 2020	$	(29,486)	(86)	$	(29,572)
Gain (loss) reclassified to earnings						$	(6,873)	$	262

	Cash Flow Hedge
	Accumulated other comprehensive income					Earnings
	Before tax			Accumulated
	gains		Tax benefit	OCI:		Interest		Tax
(in thousands of U.S. dollars)	(losses)		(expense)	Net of tax		expense		benefit
Accumulated OCI as of December 31, 2018	$	(5,902)	565	$	(5,337)
Initial value of interest rate swap to be recognized in earnings on amortization approach		(625)	—		(625)
Effective portion of unrealized loss on cash flow hedge		(13,535)	—		(13,535)
Reclassification from accumulated other comprehensive income included in hedge effectiveness		956	—		956		(956)		—
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach		987	(389)		598		(987)		389
Other comprehensive income for period		(12,217)	(389)		(12,606)
Accumulated OCI as of December 31, 2019	$	(18,119)	176	$	(17,943)
Gain (loss) reclassified to earnings						$	(1,943)	$	389

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income and changes in accumulated OCI is as follows as of and for the year ended December 31, 2018.

	Cash Flow Hedge
	Before tax		Tax benefit		Accumulated
(in thousands of U.S. dollars)	gains (losses)		(expense)	Net of tax	OCI
Balance as of December 31, 2017	$	(3,612)	864	(2,748)	$	(2,748)
Effective portion of unrealized loss on cash flow hedge		412	—	412		412
Reclassification of amortization of cash flow hedge to earnings		855	(299)	556		556
Reclassification of discontinued cash flow hedge to earnings		(3,557)	—	(3,557)		(3,557)
Other comprehensive income for period		(2,290)	(299)	(2,589)		(2,589)
Balance as of December 31, 2018	$	(5,902)	565	(5,337)	$	(5,337)

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Supplemental cash flow information (Tables)

12 Months Ended

Dec. 31, 2020

Supplemental cash flow information

Schedule of supplemental cash flow information

	Year ended December 31,
(in thousands of U.S. dollars)	2020		2019	2018
Supplemental disclosure of non-cash investing activities
Non-cash expenditures for vessel and other equipment	$	—	—	$	(229)
Supplemental disclosure of non-cash financing activities
Non-cash indemnifications received	$	11,850	—	$	—

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Issuance of common units and Series A Preferred Units (Tables)

12 Months Ended

Dec. 31, 2020

Issuance of common units and Series A Preferred Units

Schedule of net proceeds for units issued

	Year ended
	December 31, 2020
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	—	3,231	$	3,231
Less: Commissions		—	(57)		(57)
Net proceeds for units issued	$	—	3,174	$	3,174

	Year ended December 31, 2019
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	1,042	13,298	$	14,340
Less: Commissions		(13)	(233)		(246)
Net proceeds for units issued	$	1,029	13,065	$	14,094

	Year ended December 31, 2018
			Series A
	Common		preferred
(in thousands of U.S. dollars)	units		units	Total
Gross proceeds for units issued	$	4,623	39,360	$	43,983
Less: Commissions		(60)	(701)		(761)
Net proceeds for units issued	$	4,563	38,659	$	43,222

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Common, subordinated and preferred units (Tables)

12 Months Ended

Dec. 31, 2020

Common, subordinated and preferred units

Schedule of movements in the number of units, subordinated units and preferred units

The following table shows the movements in the number of common units, subordinated units and preferred units during the years ended December 31, 2020, 2019 and 2018:

		Common		8.75%
	Common	Units		Series A
	Units	Höegh	Subordinated	Preferred
(in units)	Public	LNG	Units	Units
December 31, 2017	17,648,844	2,116,060	13,156,060	4,600,000
June 6, 2018; Awards to non-employee directors as compensation for directors' fees	8,840	—	—	—
July 5, 2018; Awards to non-employee directors as compensation for directors' fees	2,210	—	—	—
Units issued to staff at Höegh LNG during 2018	14,622	(14,622)	—	—
Phantom units issued to CEO/CFO during 2018	17,079	—	—	—
ATM program (from January 26, 2018 to December 31, 2018)	253,106	—	—	1,529,070
December 31, 2018	17,944,701	2,101,438	13,156,060	6,129,070
June 4, 2019; Awards to non-employee directors as compensation for directors' fees	8,944	—	—	—
July 16, 2019; Awards to non-employee directors as compensation for directors' fees	2,236	—	—	—
August 16, 2019; Subordinated units converted to common units	—	13,156,060	(13,156,060)	—
Phantom units issued to CEO/CFO during 2019	19,745	—	—	—
ATM program (from January 1, 2019 to December 31, 2019)	53,160	—	—	496,520
December 31, 2019	18,028,786	15,257,498	—	6,625,590
September 4, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
September 15, 2020; Awards to non-employee directors as compensation for directors' fees	7,764	—	—	—
October 23, 2020; Awards to non-employee directors as compensation for directors' fees	3,882	—	—	—
Phantom units issued to CEO/CFO during 2020	6,627	—	—	—
ATM program (from January 1, 2020 to December 31, 2020)	—	—	—	126,743
December 31, 2020	18,050,941	15,257,498	—	6,752,333

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Earning per unit and cash distributions (Tables)

12 Months Ended

Dec. 31, 2020

Earning per unit and cash distributions

Schedule of calculation of basic and diluted earnings per unit

	Year ended December 31,
(in thousands of U.S. dollars, except per unit numbers)	2020		2019		2018
Net income	$	63,145		52,741	$	77,622
Adjustment for:
Preferred unitholders’ interest in net income		14,802		13,850		12,303
Limited partners' interest in net income		48,343		38,891		65,319
Less: Dividends paid or to be paid (1)		(60,222)		(60,149)		(59,952)
Under (over) distributed earnings		(11,879)		(21,258)		5,367
Under (over) distributed earnings attributable to:
Common units public		(6,437)		(11,514)		2,900
Common units Höegh LNG		(5,442)		(3,211)		340
Subordinated units Höegh LNG (4)		—		(6,533)		2,127
	$	(11,879)		(21,258)	$	5,367
Basic weighted average units outstanding (in thousands)
Common units public		18,034		17,986		17,856
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Diluted weighted average units outstanding (in thousands)
Common units public		18,037		17,995		17,864
Common units Höegh LNG		15,257		7,039		2,101
Subordinated units Höegh LNG (4)		—		8,218		13,156
Basic and diluted earnings per unit (2):
Common unit public	$	1.40	$	1.12	$	1.93
Common unit Höegh LNG (3)	$	1.51	$	1.84	$	2.03
Subordinated unit Höegh LNG (3) (4)	$	—	$	0.70	$	2.03

(1) Includes all distributions paid or to be paid in relationship to the period, regardless of whether the declaration and payment dates were prior to the end of the period and is based the number of units outstanding at the period end.

(2) Effective March 26, 2020, granted 8,100 phantom units to the CEO/CFO of the Partnership, one-third of such phantom units vest as of November 30, 2021, 2022 and 2023, respectively. Effective March 21, 2019, granted 10,917 phantom units to the CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective March 23, 2018, the Partnership granted 14,584 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of November 30, 2019, 2020 and 2021, respectively. Effective June 3, 2016, the Partnership granted 21,500 phantom units to the then-serving CEO/CFO of the Partnership. One-third of such phantom units vest as of December 31, 2017, November 30, 2018 and November 30, 2019, respectively. On September 14, 2018, the plan was amended to extend the terms and conditions of such unvested units for the grants effective March 23, 2017 and June 3, 2016 of the then-serving CEO/CFO that resigned as CEO/CFO of the Partnership. The phantom units impact the diluted weighted average units outstanding. As a result of the resignation of the CEO/CFO of the Partnership in August 2020, a total of 15,378 of the unvested phantom units terminated.

(3) Includes total amounts attributable to incentive distributions rights of $1,598, $1,597 and $1,591 for the years ended December 31, 2020, 2019 and 2018, respectively. For the year ended December 31, 2020 the full amount was attributable to common units owned by Höegh LNG. For the years ended December 31, 2019 and 2018, respectively, $908 and $219 was attributed to common units owned by Höegh LNG and $688 and $1,372 was attributed to subordinated units owned by Höegh LNG.

(4) On August 16, 2019, all subordinated units converted into common units on a one-for-one basis.

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Description of business - Entities (Details)	12 Months Ended
	Dec. 31, 2020
Hoegh LNG Partners LP [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Marshall Islands
Purpose	Holding Company
Hoegh LNG Partners Operating LLC [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Marshall Islands
Purpose	Holding Company
Hoegh LNG Services Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	United Kingdom
Purpose	Administration Services Company
Hoegh LNG Lampung Pte. Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Singapore
Purpose	Owns 49% of PT Hoegh LNG Lampung
PT Hoegh LNG Lampung [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Indonesia
Purpose	Owns PGN FSRU Lampung
SRV Joint Gas Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Cayman Islands
Purpose	Owns Neptune
SRV Joint Gas Two Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Cayman Islands
Purpose	Owns Cape Ann
Hoegh LNG Cyprus Limited [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Cyprus
Purpose	Owns Höegh Gallant
Hoegh LNG Cyprus Limited Egypt Branch [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Egypt
Purpose	Branch of Hoegh LNG Cyprus Limited
Hoegh LNG Colombia Holding Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Cayman Islands
Purpose	Owns 100% of Höegh LNG FSRU IV Ltd. and Höegh LNG Colombia S.A.S.
Hoegh LNG FSRU IV Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Cayman Islands
Purpose	Owns Höegh Grace
Hoegh LNG Colombia S A S [Member]
Condensed Financial Statements, Captions [Line Items]
Jurisdiction of Incorporation or Registration	Colombia
Purpose	Operating Company

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Description of business - Additional information (Details) - USD ($) $ in Millions						1 Months Ended	12 Months Ended
	Dec. 01, 2017	Oct. 05, 2017	Jan. 03, 2017	Oct. 01, 2015	Aug. 12, 2014	Aug. 28, 2014	Dec. 31, 2020	Dec. 31, 2016	Oct. 18, 2019	Jan. 26, 2018
Condensed Financial Statements, Captions [Line Items]
Maximum Offering Amount									$ 120.0	$ 120.0
Subordinated Unit [Member]
Condensed Financial Statements, Captions [Line Items]
Limited Partners' Capital Account, Units Issued					13,156,060
Hoegh LNG Holdings Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Percentage of incentive distribution rights					100.00%
Percentage of Partnership Interest					58.00%
Limited Partners' Capital Account, Units Issued					2,116,060
Hoegh LNG Partners LP [Member] | Series A Preferred Stock [Member]
Condensed Financial Statements, Captions [Line Items]
Preferred Stock, Dividend Rate, Percentage		8.75%
Proceeds from Issuance of Preferred Limited Partners Units		$ 110.9
Limited Partners' Capital Account, Units Issued		4,600,000
Hoegh LNG Lampung Pte. Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							100.00%
Mitsui O.S.K. Lines, Ltd. and Tokyo LNG Tanker Co. [Member]
Condensed Financial Statements, Captions [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Hoegh LNG FSRU IV Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Non Cancellable Lease Expiration Term								10 years
Lease Expiration Term								10 years
Lease Initial Term								20 years
Hoegh LNG FSRU IV Ltd [Member] | Maximum [Member]
Condensed Financial Statements, Captions [Line Items]
Lease Expiration Term								15 years
Hoegh LNG FSRU IV Ltd [Member] | Minimum [Member]
Condensed Financial Statements, Captions [Line Items]
Lease Expiration Term								10 years
Hoegh LNG FSRU III Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				100.00%
SRV Joint Gas Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Sociedad Portuaria El Cayao [Member]
Condensed Financial Statements, Captions [Line Items]
Ownership Interest By Private Equity Investors								49.00%
Sociedad Portuaria El Cayao [Member] | Promigas S.A. ESP [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								51.00%
Hoegh Lng Colombia Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								51.00%
Hoegh LNG Colombia Holding Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.00%		51.00%
Underwritten Public Offering [Member]
Condensed Financial Statements, Captions [Line Items]
Limited Partners' Capital Account, Units Issued								6,588,389
Partners' Capital Account, Public Sale of Units Net of Offering Costs								$ 111.5
Subsidiaries [Member] | Hoegh LNG Holdings Ltd [Member]
Condensed Financial Statements, Captions [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						100.00%
IPO [Member]
Condensed Financial Statements, Captions [Line Items]
Exercise Of Option, Additional Common Units					1,440,000
Limited Partners' Capital Account, Units Issued					11,040,000
Partners' Capital Account, Public Sale of Units Net of Offering Costs					$ 203.5

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Significant accounting policies (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Jan. 01, 2020
Significant Accounting Policies [Line Items]
Allowance for credit loss	$ 96
Allowance for Credit Loss on Trade Receivables and Amount Due from Affiliates	$ 60
Accounting Standards Update 2016-02 [Member]
Significant Accounting Policies [Line Items]
Cumulative Effect on Retained Earnings, Net of Tax		$ 160
Allowance for credit loss		100
Allowance for Credit Loss on Trade Receivables and Amount Due from Affiliates		$ 60

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Significant accounting policies - Additional information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Jan. 03, 2017
Significant Accounting Policies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 385.0
Vessels [Member]
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	35 years
$385 million facility [Member]
Significant Accounting Policies [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 385.0
SRV Joint Gas Two Ltd [Member]
Significant Accounting Policies [Line Items]
Advances to Affiliate	0.9	$ 0.8
SRV Joint Gas Two Ltd [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Significant Accounting Policies [Line Items]
Net liabilities	$ 4.2	0.7
Hoegh Grace [Member]
Significant Accounting Policies [Line Items]
Non-Cancellable Charter Period	10 years
SRV Joint Gas Ltd [Member]
Significant Accounting Policies [Line Items]
Advances to Affiliate	$ 3.3	3.0
SRV Joint Gas Ltd [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Significant Accounting Policies [Line Items]
Net liabilities	5.5	2.6
PT Hoegh LNG Lampung [Member]
Significant Accounting Policies [Line Items]
Restricted Net Assets	$ 179.9	$ 169.8
Initial Charter Hire Period	20 years
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	100.00%
Statutory Reserve on Paid Up Capital Percentage	20.00%
Hoegh LNG Cyprus Limited [Member]
Significant Accounting Policies [Line Items]
Restricted Net Assets	$ 0.0
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	100.00%
Hoegh Lng Colombia Ltd [Member]
Significant Accounting Policies [Line Items]
Restricted Net Assets	$ 0.0
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	100.00%
Hoegh Grace entities [Member]
Significant Accounting Policies [Line Items]
Non-Cancellable Charter Period	10 years
Business Acquisition, Percentage of Voting Interests Acquired			51.00%
Hoegh Gallant [Member]
Significant Accounting Policies [Line Items]
Initial Charter Hire Period	5 years
Above Market Leases [Member] | Hoegh Grace entities [Member]
Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life	9 years 6 months
Above Market Leases [Member] | Hoegh Gallant [Member]
Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years 4 months 24 days
Option for time charter extension [Member] | Hoegh Gallant [Member]
Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life	5 years 3 months 18 days

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Segment information - Results for the segments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Time charter revenues	$ 143,095	$ 145,321	$ 144,952
Other revenue	0	115	1,609
Total revenues	143,095	145,436	146,561
Operating expenses	(33,812)	(40,731)	(33,111)
Equity in earnings (losses) of joint ventures	6,420	6,078	17,938
Depreciation, Depletion and Amortization	(20,937)	(21,477)	(21,146)
Operating income (loss)	94,766	89,306	110,242
Gain (loss) on debt extinguishment	0	1,030	0
Gain (loss) on derivative instruments	0	0	4,681
Other financial income (expense), net	(26,057)	(30,320)	(28,996)
Income (loss) before tax	68,709	60,016	85,927
Income tax benefit (expense)	(5,564)	(7,275)	(8,305)
Net income (loss)	63,145	52,741	77,622
Preferred unitholders' interest in net income	14,802	13,850	12,303
Limited partners' interest in net income (loss)	48,343	38,891	65,319
Vessels, net of accumulated depreciation	619,620	640,431
Net investment in financing lease	274,257	278,904
Goodwill	251	251	251
Advances to joint ventures	4,153	3,831
Total assets	981,810	1,012,800
Accumulated earnings of joint ventures	9,690	3,270
Expenditures for vessels & equipment	8	211
Expenditures for drydocking	0	3,107
Impairment/retirement of equipment		0
Principal repayment direct financing lease	4,551	4,168
Amortization of above market & contract extension	3,052	3,631	3,631
Majority held FSRUs [Member]
Time charter revenues	143,095	145,321	144,952
Other revenue		115	1,609
Total revenues	143,095	145,436	146,561
Operating expenses	(27,462)	(34,266)	(27,294)
Equity in earnings (losses) of joint ventures	0	0
Segment EBITDA	115,633	111,170	119,267
Depreciation, Depletion and Amortization	(20,937)	(21,477)	(21,146)
Operating income (loss)	94,696	89,693	98,121
Gain (loss) on debt extinguishment		1,030
Gain (loss) on derivative instruments	0	0	4,681
Other financial income (expense), net	(9,072)	(12,511)	(26,381)
Income (loss) before tax	85,624	78,212	76,421
Income tax benefit (expense)	(5,564)	(7,278)	(8,253)
Net income (loss)	80,060	70,934	68,168
Preferred unitholders' interest in net income	0	0
Limited partners' interest in net income (loss)	80,060	70,934	68,168
Vessels, net of accumulated depreciation	619,620	640,431
Net investment in financing lease	274,257	278,904
Goodwill	251	251
Advances to joint ventures	0	0
Total assets	969,278	996,201
Accumulated earnings of joint ventures	0	0
Expenditures for vessels & equipment	8	211
Expenditures for drydocking	0	3,107
Impairment/retirement of equipment		0
Principal repayment direct financing lease	4,551	4,168
Amortization of above market & contract extension	3,052	3,631	3,631
Joint venture FSRUs [Member]
Time charter revenues	43,572	42,433	43,169
Other revenue		0
Total revenues	43,572	42,433	43,169
Operating expenses	(9,452)	(9,044)	(10,932)
Equity in earnings (losses) of joint ventures	0	0
Segment EBITDA	34,120	33,389	32,237
Depreciation, Depletion and Amortization	(9,965)	(10,030)	(9,725)
Operating income (loss)	24,155	23,359	22,512
Gain (loss) on debt extinguishment		0
Gain (loss) on derivative instruments	(6,073)	(5,209)	8,496
Other financial income (expense), net	(11,662)	(12,072)	(13,070)
Income (loss) before tax	6,420	6,078	17,938
Income tax benefit (expense)	0	0
Net income (loss)	6,420	6,078	17,938
Preferred unitholders' interest in net income	0	0
Limited partners' interest in net income (loss)	6,420	6,078	17,938
Vessels, net of accumulated depreciation	242,226	252,789
Net investment in financing lease	0	0
Goodwill	0	0
Advances to joint ventures	0	0
Total assets	267,003	284,174
Accumulated earnings of joint ventures	0	0
Expenditures for vessels & equipment	75	195
Expenditures for drydocking	2	913
Impairment/retirement of equipment		(75)
Principal repayment direct financing lease	0	0
Amortization of above market & contract extension	0	0
Other Segments [Member]
Time charter revenues	0	0
Other revenue		0
Total revenues	0	0
Operating expenses	(6,350)	(6,465)	(5,817)
Equity in earnings (losses) of joint ventures	0	0
Segment EBITDA	(6,350)	(6,465)	(5,817)
Depreciation, Depletion and Amortization	0	0
Operating income (loss)	(6,350)	(6,465)	(5,817)
Gain (loss) on debt extinguishment		0
Gain (loss) on derivative instruments	0	0
Other financial income (expense), net	(16,985)	(17,809)	(2,615)
Income (loss) before tax	(23,335)	(24,274)	(8,432)
Income tax benefit (expense)	0	3	(52)
Net income (loss)	(23,335)	(24,271)	(8,484)
Preferred unitholders' interest in net income	0	0
Limited partners' interest in net income (loss)	(23,335)	(24,271)	(8,484)
Vessels, net of accumulated depreciation	0	0
Net investment in financing lease	0	0
Goodwill	0	0
Advances to joint ventures	4,153	3,831
Total assets	12,532	16,599
Accumulated earnings of joint ventures	50	50
Expenditures for vessels & equipment	0	0
Expenditures for drydocking	0	0
Impairment/retirement of equipment		0
Principal repayment direct financing lease	0	0
Amortization of above market & contract extension	0	0
Total Segment Reporting [Member]
Time charter revenues	186,667	187,754	188,121
Other revenue		115	1,609
Total revenues	186,667	187,869	173,846
Operating expenses	(43,264)	(49,775)	(44,043)
Equity in earnings (losses) of joint ventures	0	0
Segment EBITDA	143,403	138,094	145,687
Depreciation, Depletion and Amortization	(30,902)	(31,507)	(30,871)
Operating income (loss)	112,501	106,587	114,816
Gain (loss) on debt extinguishment		1,030
Gain (loss) on derivative instruments	(6,073)	(5,209)	13,177
Other financial income (expense), net	(37,719)	(42,392)	(42,066)
Income (loss) before tax	68,709	60,016	85,927
Income tax benefit (expense)	(5,564)	(7,275)	(8,305)
Net income (loss)	63,145	52,741	77,622
Preferred unitholders' interest in net income	0	0
Limited partners' interest in net income (loss)	63,145	52,741	77,622
Vessels, net of accumulated depreciation	861,846	893,220
Net investment in financing lease	274,257	278,904
Goodwill	251	251
Advances to joint ventures	4,153	3,831
Total assets	1,248,813	1,296,974
Accumulated earnings of joint ventures	50	50
Expenditures for vessels & equipment	83	406
Expenditures for drydocking	2	4,020
Impairment/retirement of equipment		(75)
Principal repayment direct financing lease	4,551	4,168
Amortization of above market & contract extension	3,052	3,631
Eliminations [Member]
Time charter revenues	(43,572)	(42,433)	(43,169)
Other revenue		0
Total revenues	(43,572)	(42,433)	(43,169)
Operating expenses	9,452	9,044	10,932
Equity in earnings (losses) of joint ventures	6,420	6,078	17,938
Depreciation, Depletion and Amortization	9,965	10,030	9,725
Gain (loss) on derivative instruments	6,073	5,209	(8,496)
Other financial income (expense), net	11,662	12,072	13,070
Income (loss) before tax	0	0
Income tax benefit (expense)	0	0
Net income (loss)	0	0
Preferred unitholders' interest in net income	14,802	13,850	12,303
Limited partners' interest in net income (loss)	(14,802)	(13,850)	$ (12,303)
Vessels, net of accumulated depreciation	(242,226)	(252,789)
Net investment in financing lease	0	0
Goodwill	0	0
Advances to joint ventures	0	0
Total assets	(267,003)	(284,174)
Accumulated earnings of joint ventures	9,640	3,220
Expenditures for vessels & equipment	(75)	(195)
Expenditures for drydocking	(2)	(913)
Impairment/retirement of equipment		75
Principal repayment direct financing lease	0	0
Amortization of above market & contract extension	$ 0	$ 0

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Segment information - Percentage of consolidated total revenues (Details) - Sales Revenue, Net [Member]	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
PT PGN LNG Indonesia [Member]
Percentage of Revenue	33.00%	33.00%	33.00%
Hoegh LNG Egypt LLC [Member]
Percentage of Revenue	30.00%	31.00%	31.00%
Sociedad Portuaria El Cayao [Member]
Percentage of Revenue	37.00%	36.00%	36.00%

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Segment information - Additional information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) segment	May 28, 2019 USD ($)	Jan. 29, 2018 USD ($)
Number of Operating Segments | segment	2
Line of Credit Facility, Maximum Borrowing Capacity	$ 385.0
Revolving credit facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity	85.0
Revolving credit facility [Member] | Hoegh LNG [Member]
Line of Credit Facility, Maximum Borrowing Capacity		$ 85.0	$ 85.0
$385 million facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 385.0
Neptune and the Cape Ann
Equity Method Investment, Ownership Percentage	50.00%

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Time charter revenues and related contract balances - Disaggregated revenue by segment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lease revenues, excluding amortization	$ 87,948	$ 88,889	$ 89,215
Time charter service revenues, excluding amortization	58,199	60,063	59,368
Amortization of above market contract intangibles	(3,052)	(3,631)	(3,631)
Amortization of deferred revenue for modifications & drydock	0	0
Other revenue	0	115	1,609
Total revenues	143,095	145,436	146,561
Total segment reporting [Member]
Lease revenues, excluding amortization	113,708	114,579	114,905
Time charter service revenues, excluding amortization	73,297	74,158	74,446
Amortization of above market contract intangibles	(3,052)	(3,631)	(3,631)
Amortization of deferred revenue for modifications & drydock	2,714	2,648	2,401
Other revenue		115	1,609
Total revenues	186,667	187,869	189,730
Majority held FSRUs [Member]
Lease revenues, excluding amortization	87,948	88,889	89,215
Time charter service revenues, excluding amortization	58,199	60,063	59,368
Amortization of above market contract intangibles	(3,052)	(3,631)	(3,631)
Amortization of deferred revenue for modifications & drydock	0	0
Other revenue		115	1,609
Total revenues	143,095	145,436	146,561
Joint venture FSRUs [Member]
Lease revenues, excluding amortization	25,760	25,690	25,690
Time charter service revenues, excluding amortization	15,098	14,095	15,078
Amortization of above market contract intangibles	0	0
Amortization of deferred revenue for modifications & drydock	2,714	2,648	2,401
Other revenue		0
Total revenues	43,572	42,433	43,169
Other Segments [Member]
Lease revenues, excluding amortization	0	0
Time charter service revenues, excluding amortization	0	0
Amortization of above market contract intangibles	0	0
Amortization of deferred revenue for modifications & drydock	0	0
Other revenue		0
Total revenues	0	0
Eliminations [Member]
Lease revenues, excluding amortization	(25,760)	(25,690)	(25,690)
Time charter service revenues, excluding amortization	(15,098)	(14,095)	(15,078)
Amortization of above market contract intangibles	0	0
Amortization of deferred revenue for modifications & drydock	(2,714)	(2,648)	(2,401)
Other revenue		0
Total revenues	$ (43,572)	$ (42,433)	$ (43,169)

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Time charter revenues and related contract balances - Allocation of consolidated receivables between lease and service (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Trade receivable for lease	$ 2,608	$ 2,898
Trade receivable for time charter services	1,506	2,133
Allowance for expected credit losses	(60)
Total trade receivable and amounts due from affiliates	$ 4,054	$ 5,031

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Time charter revenues and related contract balances - Consolidated contract assets, contract liabilities and refund liabilities (Details) - Time Charter Services [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Beginning Balance	$ 279
Additions		$ 279
Reduction for receivables recorded	(18)
Ending Balance	261	279
Beginning balance	(125)	(1,834)
Additions	(841)	(65)
Reduction for receivables recorded		89
Reduction for revenue recognized (excluding amortization)	10
Reduction for revenue recognized from previous years	48	497
Repayments of refund liabilities to charterer		1,101
Repayments of refund liabilities to charterer	17	1,188
Ending balance	$ (891)	$ (125)

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Time charter revenues and related contract balances - Minimum contractual future revenues (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Time charter revenues and related contract balances
2021	$ 32,369
2022	32,369
2023	32,369
2024	32,369
2025	27,091
Thereafter	96,683
Total	253,250
2021	90,441
2022	90,441
2023	90,441
2024	90,441
2025	77,717
Thereafter	286,467
Total - undiscounted	725,948
Operating lease	321,724
Direct financing lease	404,224
Discounting effect	(172,499)
Financing lease	231,725	$ 240,000
2021	122,810
2022	122,810
2023	122,810
2024	122,810
2025	104,808
Thereafter	383,150
Total	$ 979,198

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Time charter revenues and related contract balances - Direct financing lease receivable and unguaranteed residual value (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Direct financing lease
Minimum lease payments	$ 589,074	$ 589,074
Unguaranteed residual value	146,000	146,000
Unearned income	(440,345)	(440,345)
Initial direct cost, net	3,095	3,095
Net investment in financing lease	297,824	297,824
Principal repayment and amortization	(23,471)	(18,920)
Allowance for credit loss	(96)
Net investment in financing lease at period end	274,257	278,904
Less: Current portion	(4,969)	(4,551)
Net investment in financing lease consists of:
Financing lease receivable	231,725	240,000
Unguaranteed residual value	42,532	38,904
Net investment in financing lease at period end	$ 274,257	$ 278,904

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Time charter revenues and net investment in direct financing lease - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Hoegh LNG FRSU III Ltd [Member]
Capital Leased Assets [Line Items]
Business Combinations Charter Out One Vessel To Predefined Hire Rate	90.00%
Hoegh Gallant [Member]
Capital Leased Assets [Line Items]
Lease Expiration Year	2020
Lease Expiration Term	5 years
Charter period	5 years
PGN FSRU Lampung [Member]
Capital Leased Assets [Line Items]
Lease Expiration Year	2034
Lease Expiration Term	20 years
Hoegh Grace [Member]
Capital Leased Assets [Line Items]
Lease Expiration Year	2036
Lease Expiration Term	20 years
Non Cancellable Lease Expiration Term	10 years
Hoegh LNG FSRU IV Ltd [Member]
Capital Leased Assets [Line Items]
Lease Initial Term	20 years
Maximum [Member] | Hoegh Grace [Member]
Capital Leased Assets [Line Items]
Lease Initial Term	20 years
Maximum [Member] | Hoegh LNG FSRU IV Ltd [Member]
Capital Leased Assets [Line Items]
Lease Expiration Term	15 years
Minimum [Member] | Hoegh Grace [Member]
Capital Leased Assets [Line Items]
Lease Initial Term	15 years
Minimum [Member] | Hoegh LNG FSRU IV Ltd [Member]
Capital Leased Assets [Line Items]
Lease Expiration Term	10 years
Time Charter Services [Member]
Capital Leased Assets [Line Items]
Reduction for revenue recognized from previous years	$ 48	$ 497
Repayments of refund liabilities to charterer		$ 1,101

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Financial income (expense), net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Interest income	$ 605	$ 947	$ 725
Interest expense:
Interest expense	(22,003)	(24,950)	(26,077)
Commitment fees	(138)	(381)	(37)
Amortization of debt issuance cost and fair value of debt assumed	(2,289)	(2,361)	(700)
Total interest expense	(24,430)	(27,692)	(26,814)
Gain (loss) on debt extinguishment	0	1,030	0
Other items, net:
Foreign exchange gain (loss)	444	(396)	(193)
Bank charges, fees and other	(276)	(297)	(143)
Withholding tax on interest expense and other	(2,400)	(2,882)	(2,571)
Total other items, net	(2,232)	(3,575)	(2,907)
Total financial income (expense), net	(26,057)	$ (29,290)	$ (24,315)
Debt Instrument, Financial Covenants	$ 385,000

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Income tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current tax (benefit) expense	$ 3,832	$ 4,126	$ 4,759
Income before tax	68,709	60,016	85,927
Deferred tax (benefit) expense for
Change in temporary differences	1,335	3,341	3,290
Tax loss and tax credit carried forward	393	(196)	247
Change in valuation allowance	4	4	9
Total deferred tax (benefit) expense	1,732	3,149	3,546
Total income tax (benefit) expense	$ 5,564	$ 7,275	$ 8,305

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Income tax - Deferred tax (benefit) expense recognized in OCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flow hedge derivative instruments	$ 262	$ 389	$ 299
Other Comprehensive Income (Loss), Tax, Total	$ 262	$ 389	$ 299

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Income tax - Reconciliation of the income before tax at the statutory rate (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income tax
Income (loss) before tax	$ 68,709	$ 60,016	$ 85,927
At applicable statutory tax rate
Amount computed at corporate tax of 0%	0	0	0
Foreign tax rate differences	4,972	5,425	7,513
Permanent differences:
Amended tax return: reinstatement of tax loss carryforward	0	0	0
Tax audit or amended tax return: change in uncertain tax position	385	558	(41)
Non-deductible interest expense	571	1,477	875
Non-deductible withholding tax	(114)	120	0
Non-deductible loss on derivatives	625	717	838
Tax exemptions	(13)	(13)	(36)
Non-deductible other financial items	(106)	194	116
Other non-deductible costs	(18)	45	63
Tax credits	(742)	(1,252)	(1,032)
Adjustment for valuation allowance	4	4	9
Income Tax Expense (Benefit), Total	$ 5,564	$ 7,275	$ 8,305

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Income tax - Deferred income tax assets (liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Accrued liabilities and other payables	$ 124	$ 235
Derivative instruments	422	565
Other equipment	8	9
Tax credits carried forward	1,421	1,818
Tax loss carryforward	32	57
Valuation allowance	(32)	(57)
Deferred tax liabilities:
Accrued interest income	(4,575)	(4,123)
Accrued liabilities and other payables	(400)	(385)
Financing lease	(11,328)	(10,451)
Deferred tax assets (liabilities), net	$ (14,328)	$ (12,332)

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Income tax - Changes in the unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Unrecognized tax benefits as of January 1,	$ (2,283)	$ (1,725)	$ (2,626)
Decrease related to prior year tax positions	0	0	434
Increase related to current year tax positions	(385)	(558)	(418)
Settlements	0	0	885
Unrecognized tax benefits as of December 31,	$ (2,668)	$ (2,283)	$ (1,725)

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Income tax - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Tax Credit Carryforward, Amount				$ 1,486
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	$ 4	$ 4	$ 9
Unrecognized Tax Benefits	2,668	2,283	1,725	2,626
Reduction to the uncertain tax position			434
Increases in uncertain tax positions	385	558	418
Amended tax return: reinstatement of tax loss carryforward	0	0	885
Other Noncash Income Tax Expense	867	867	852
Accrued Income Taxes, Noncurrent	2,668	2,283
Reversal of uncertain tax position				$ 2,228
Income Tax Expense (Benefit)	$ 5,564	$ 7,275	$ 8,305
Colombia
Income tax subject to examination year	2017
Indonesia
Income tax subject to examination year	2016
Income Tax Examination Year Concluded Audit	2013
Income Tax Examination Year Concluded Audit One	2014
SINGAPORE
Income tax subject to examination year	2016
Tax Credit Carry forward Expiring In 2020 And 2023 [Member]
Tax Credit Carryforward, Amount	$ 256
Tax Credit Carryforward Expiring In 2020 [Member]
Tax Credit Carryforward, Amount	$ 430
Tax Credit Carryforward, Year of Expiration	2021
Tax Credit Carryforward Expiring In 2021 [Member]
Tax Credit Carryforward, Amount	$ 991
Tax Credit Carryforward, Year of Expiration	2022

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Prepaid expenses and other receivables (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Prepaid expenses	$ 2,140	$ 752
Other receivables	1,743	1,782
Total other prepaid expenses and other receivables	$ 3,883	$ 2,534

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Investments in joint ventures (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Accumulated earnings of joint ventures	$ 9,690	$ 3,270

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Investments in joint ventures - Combined joint ventures on an aggregated basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Time charter revenues	$ 143,095	$ 145,321	$ 144,952
Other income	0	115	1,609
Total revenues	143,095	145,436	146,561
Operating expenses	(33,812)	(40,731)	(33,111)
Depreciation, amortization and impairment	(20,937)	(21,477)	(21,146)
Impairment of long-lived assets		0
Operating income	94,766	89,306	110,242
Unrealized gain (loss) on derivative instruments	0	0	4,681
Income (loss) before tax	68,709	60,016	85,927
Net income (loss)	63,145	52,741	77,622
Equity in (earnings) losses of joint ventures	6,420	6,078	17,938
Cash and cash equivalents	31,770	39,126	26,326	$ 22,679
Restricted cash	7,198	8,066	6,003	6,962
Total current assets	55,158	59,771
Restricted cash	12,095	12,627	13,125	$ 13,640
Vessels, net of accumulated depreciation	619,620	640,431
Total long-term assets	926,652	953,029
Current portion of long-term debt	59,119	44,660
Derivative instruments	6,945	2,907
Refund liabilities	891	125
Total current liabilities	77,808	63,253
Long-term debt	355,470	412,301
Derivative instruments	19,530	12,028
Other long-term liabilities	124	84
Total long-term liabilities	410,687	448,037
Srv Joint Gas Limited And Srv Joint Gas Two Limited [Member]
Time charter revenues	78,687	77,051	79,654
Other income	8,457	7,814	6,684
Total revenues	87,144	84,865	86,338
Operating expenses	(18,904)	(18,088)	(21,864)
Depreciation, amortization and impairment	(20,546)	(20,524)	(20,065)
Impairment of long-lived assets		(149)
Operating income	47,694	46,104	44,409
Unrealized gain (loss) on derivative instruments	(12,146)	(10,418)	16,992
Other financial expense, net	(23,324)	(24,144)	(26,140)
Net income (loss)	$ 12,224	$ 11,542	$ 35,261
Share of joint ventures owned	50.00%	50.00%	50.00%
Share of joint ventures net income (loss) before eliminations	$ 6,112	$ 5,771	$ 17,631
Eliminations	308	307	307
Equity in (earnings) losses of joint ventures	6,420	6,078	$ 17,938
Cash and cash equivalents	13,455	17,897
Restricted cash	21,264	9,250
Other current assets	178	973
Total current assets	34,897	28,120
Restricted cash	14,656	34,650
Vessels, net of accumulated depreciation	499,318	521,060
Total long-term assets	513,974	555,710
Current portion of long-term debt	199,030	28,297
Amounts and loans due to owners and affiliates	7,278	629
Derivative instruments	14,687	13,089
Refund liabilities	1,040	26,691
Other current liabilities	8,811	10,327
Total current liabilities	230,846	79,033
Long-term debt	176,385	375,091
Loans due to owners and affiliates	1,737	7,663
Derivative instruments	69,618	59,070
Other long-term liabilities	36,040	40,952
Total long-term liabilities	283,780	482,776
Net assets (liabilities)	34,245	22,021
Share of joint ventures net assets (liabilities) before eliminations	17,123	11,011
Eliminations	(7,433)	(7,741)
Accumulated earnings (losses) of joint ventures	$ 9,690	$ 3,270

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Investments in joint ventures - Additional Information (Details)	Dec. 31, 2020
SRV Joint Gas Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
SRV Joint Gas Two Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

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Advances to joint ventures (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Advances to Joint Ventures [Line Items]
Advances to joint ventures	$ 3,284	$ 0
Long-term advances/shareholder loans to joint ventures	869	3,831
Advances/shareholder loans to joint ventures	$ 4,153	$ 3,831
Shareholder [Member]
Advances to Joint Ventures [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.00%

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Advances to joint ventures - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Advances to Joint Ventures [Line Items]
Due from joint ventures	$ 4,153	$ 3,831
Debt service coverage ratio	1.20%
SRV Joint Gas Ltd [Member]
Advances to Joint Ventures [Line Items]
Due from joint ventures	$ 3,300	3,000
SRV Joint Gas Two Ltd [Member]
Advances to Joint Ventures [Line Items]
Due from joint ventures	$ 900	$ 800
Shareholder [Member]
Advances to Joint Ventures [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.00%

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Vessels and other equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Beginning Balance, Historical Cost	$ 716,672	$ 713,382
Additions	8	3,290
Ending Balance, Historical Cost	716,680	716,672
Depreciation for the year	(20,819)	(21,170)
Accumulated depreciation	(97,060)	(76,241)
Vessel, net	619,620	640,431
Vessel [Member]
Beginning Balance, Historical Cost	706,898	706,715
Additions	8	183
Ending Balance, Historical Cost	706,906	706,898
Depreciation for the year	(19,398)	(19,393)
Accumulated depreciation	(89,662)	(70,264)
Vessel, net	617,244	636,634
Dry Docking [Member]
Beginning Balance, Historical Cost	9,774	6,667
Additions	0	3,107
Ending Balance, Historical Cost	9,774	9,774
Depreciation for the year	(1,421)	(1,777)
Accumulated depreciation	(7,398)	(5,977)
Vessel, net	$ 2,376	$ 3,797

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Vessels and other equipment - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Lease, Right-of-Use Asset	$ 61	$ 91
Operating Lease, Liability	61	91
Property, Plant and Equipment, Gross	716,680	716,672	$ 713,382
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	97,060	76,241
Depreciation	$ 20,819	$ 21,170
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating Lease, Right-of-Use Asset	Operating Lease, Right-of-Use Asset
Operating Lease, Liability, Statement of Financial Position [Extensible List]	Operating Lease, Liability	Operating Lease, Liability
Equipment [Member]
Property, Plant and Equipment, Gross	$ 308	$ 845
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	260	679
Depreciation	$ 118	$ 307	$ 159

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Intangibles and goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Historical cost, Beginning balance	$ 30,760	$ 30,760
Amortization for the year	(3,052)	(3,631)
Accumulated amortization			$ (16,955)	$ (13,903)
Historical cost, Ending balance	30,760	30,760
Intangibles and goodwill			13,805	16,857
Goodwill, Beginning Balance	251	251
Goodwill, Ending Balance	251	251
Intangibles and goodwill	251	251	251	251
Historical cost, Beginning balance	17,108	31,011
Accumulated amortization			(16,955)	(13,903)
Amortization for the year	(3,052)	(3,631)
Historical cost, Ending balance	14,056	17,108
Option for time charter extension [Member]
Historical cost, Beginning balance	8,000	8,000
Amortization for the year	(1,022)
Accumulated amortization			(1,022)
Historical cost, Ending balance	8,000	8,000
Intangibles and goodwill			6,978	8,000
Above Market Time Charter [Member]
Historical cost, Beginning balance	22,760	22,760
Amortization for the year	(2,030)	(3,631)
Accumulated amortization			(15,933)	(13,903)
Historical cost, Ending balance	$ 22,760	$ 22,760
Intangibles and goodwill			$ 6,827	$ 8,857

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Intangibles and goodwill - Estimated future amortization expense (Details) $ in Thousands	Dec. 31, 2020 USD ($)
2021	$ 2,755
2022	2,755
2023	2,755
2024	2,762
2025	2,116
2026 and thereafter	$ 662

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Long-term debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Outstanding principal	$ 421,464	$ 466,124
Total debt	414,589	456,961
Less: Current portion of long-term debt	(59,119)	(44,660)
Long-term debt	355,470	412,301
Lampung facility [Member]
Debt Instrument [Line Items]
Unamortized debt issuance cost	(2,999)	(4,309)
$385 million facility [Member]
Debt Instrument [Line Items]
Unamortized debt issuance cost	(3,876)	(4,854)
Export credit tranche [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Outstanding principal	79,324	94,210
Export credit tranche [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Outstanding principal	44,500	51,167
FSRU tranche [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Outstanding principal	18,635	22,812
Commercial tranche [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Outstanding principal	230,705	249,635
Revolving credit facility [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Outstanding principal	$ 48,300	$ 48,300

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Long-term debt - Principal on long-term debt outstanding (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
2021	$ 123,557
2022	25,597
2023	25,597
2024	25,597
2025	25,597
2026 and thereafter	195,519
Total	$ 421,464	$ 466,124

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Long-term debt - Additional information (Details) - USD ($) $ in Thousands					1 Months Ended	12 Months Ended
	Oct. 23, 2020	Aug. 07, 2020	Apr. 24, 2020	Aug. 12, 2019	Jan. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 29, 2019	Sep. 30, 2013
Debt Instrument [Line Items]
Loan Covenant Security Maintenance Percentage to Loans Outstanding						125.00%
Line of Credit Facility, Maximum Borrowing Capacity						$ 385,000
Repayment of revolving credit facility due to owners and affiliates						0	$ 34,000	$ 17,500
Revolving credit due to owners and affiliates repayment				$ 34,000
Payments of arrangement fees						$ 0	$ 5,797	$ 0
Lampung facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate						4.70%	6.20%
Gallant And Grace facility
Debt Instrument [Line Items]
Repayment of revolving credit facility due to owners and affiliates					$ 303,200
Repayments of Accrued interest					1,600
$385 million facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									$ 320,000
Repayment of revolving credit facility due to owners and affiliates					303,200
Repayments of Accrued interest					1,600
Payments of arrangement fees					5,500
Remaining proceeds used for general partnership purposes					9,600
Export credit tranche [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis						The interest rate for the export credit tranche is LIBOR plus a margin of 2.3%.
Line of Credit Facility, Frequency of Payments						The export credit tranche is repayable in quarterly installments over 12 years
Debt Instrument, Basis Spread on Variable Rate						2.30%
Export credit tranche [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Future repayment upon maturity of commercial tranche					$ 9,500
FSRU tranche [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis						The FSRU tranche has an interest rate of LIBOR plus a margin of 3.4%.
Line of Credit Facility, Frequency of Payments						The FSRU tranche is repayable quarterly over 7 years
Debt Instrument, Balloon Payment						$ 15,500
Debt Instrument, Basis Spread on Variable Rate						3.40%
Commercial tranche [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate						3.40%	4.70%
Secured Debt [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description						The primary financial covenants under the Lampung facility are as follows: Borrower must maintain a minimum debt service coverage ratio of 1.10 to 1.00 for the preceding nine-month period tested on each quarterly repayment date; Guarantor's book equity must be greater than the higher of (i) $200 million and (ii) 25% of total assets; and Guarantor's free liquid assets (cash and cash equivalents or available draws on credit facilities) must be greater than $20 million.
Term Loan Facility [Member] | Lampung facility [Member]
Debt Instrument [Line Items]
Secured Debt										$ 299,000
385 million facility
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis					LIBOR plus a margin of 2.30%
Line of Credit Facility, Frequency of Payments					The commercial tranche is repayable quarterly with a final balloon payment of $136.1
Debt Instrument, Basis Spread on Variable Rate					2.30%
Debt Instrument, Covenant Description						The primary financial covenants under the $385 million facility are as follows: The Partnership must maintain Consolidated book equity (excluding hedge reserves and mark to market value of derivatives) equal to the greater of 25% of total assets, and $150 million Consolidated working capital (current assets, excluding intercompany receivables and marked-to-market value of any financial derivative, less current liabilities, excluding intercompany payables, marked-to-market value of any financial derivative and the current portion of long-term debt) shall at all time be greater than zero Minimum liquidity (cash and cash equivalents and available draws under a bank credit facility for a term of more than 12 months) equal to the greater of $15 million, and $2.5 million multiplied by the number of vessels owned or leased by the Partnership (prorated for partial ownership), subject to a cap of $20 million ratio of combined EBITDA for the Vessel Owners to debt service (principal repayments, guarantee commission, commitment fees and interest expense) for the preceding twelve months of a minimum of 115%.
Line of Credit Facility, Maximum Borrowing Capacity					$ 385,000	$ 385,000
Amount drew					$ 320,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					1.60%
Revolving credit facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate						3.60%	6.60%
Line of Credit Facility, Maximum Borrowing Capacity						$ 85,000
Amount drew	$ 10,700	$ 6,600	$ 4,500
Revolving credit facility [Member] | $385 million facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity									$ 63,000
Amount drew				$ 48,300
Revolving Credit Facility Due To Owners And Affiliates [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 85,000
Hegh Gallant [Member] | Export credit tranche [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					3.98%
Hegh Grace [Member] | Export credit tranche [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					3.88%

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Accrued liabilities and payables (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accrued liabilities and payables
Accrued operating and administrative expenses	$ 3,042	$ 3,314
Accrued property tax		3,033
Accrued interest	2,641	2,850
Current tax payable	469	818
Refund liabilities	891	125
Lease liability	39	75
Other accruals and payables	150	949
Total accrued liabilities and other payables	$ 7,232	$ 11,164
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Lease liability	Lease liability

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Related party transactions - Statement of income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues
Time charter revenue Hoegh Gallant	$ 143,095	$ 145,321	$ 144,952
Operating expenses
Vessel operating expenses	(24,072)	(30,870)	(24,195)
Interest income from joint ventures	605	947	725
Interest expense and commitment fees to Hoegh LNG	(24,430)	(27,692)	(26,814)
Total	63,145	52,741	77,622
Hoegh Gallant [Member]
Revenues
Time charter revenue Hoegh Gallant	45,274	47,173	47,108
Hoegh LNG and Subsidiaries [Member]
Operating expenses
Vessel operating expenses	(21,328)	(24,523)	(21,520)
Hours, travel expense and overhead and Board of Directors' fees	(4,353)	(4,072)	(3,671)
Interest income from joint ventures	321	295	273
Interest expense and commitment fees to Hoegh LNG	(64)	(1,882)	(2,938)
Total	$ 19,850	$ 16,991	$ 19,252

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Related party transactions - Balance sheet (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Contribution from Hegh LNG	$ 11,850
Repayment of indemnifications received from Hoegh LNG	0	$ (64)	$ (2,353)
Issuance of units for Board of Directors' fees	181	194	$ 200
Other and contribution from owner	109	485
Equity: Total	12,140	615
Director [Member]
Related Party Transaction [Line Items]
Issuance of units for Board of Directors' fees	181	194
Hoegh LNG and Subsidiaries [Member]
Related Party Transaction [Line Items]
Contribution from Hegh LNG	11,850
Repayment of indemnifications received from Hoegh LNG	$ 0	$ (64)

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Related party transactions - Receivables and payables from related parties (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Amounts due from affiliates	$ 3,639	$ 4,296
Amounts due to owners and affiliates	$ 2,600	$ 2,513

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Related party transactions - Revolving credit facility (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Revolving credit facility due to owners and affiliates - non-current portion	$ 18,465	$ 8,792

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Related party transactions - Additional Information (Details) $ in Thousands																	1 Months Ended			12 Months Ended
	Dec. 11, 2020 USD ($)	Oct. 23, 2020 USD ($)	Sep. 04, 2020 shares	Aug. 07, 2020 USD ($)	Aug. 06, 2020 shares	Apr. 24, 2020 USD ($)	Apr. 08, 2020 USD ($)	Mar. 26, 2020 shares	Jun. 04, 2019 shares	May 28, 2019 USD ($)	Mar. 21, 2019 shares	Sep. 14, 2018 shares	Jun. 06, 2018 shares	Dec. 31, 2017	Jan. 03, 2017	Jun. 03, 2016 shares	Mar. 21, 2019 shares	Mar. 23, 2018 shares	Aug. 31, 2014 USD ($)	Dec. 31, 2021	Dec. 31, 2020 USD ($) claim shares	Dec. 31, 2019 USD ($) claim	Dec. 31, 2018 USD ($) claim	Jan. 29, 2018 USD ($)
Related Party Transaction [Line Items]
Revolving Credit Due To Owners And Affiliates																					$ 18,465	$ 8,792
Aggregate borrowing capacity																					$ 385,000
Indemnification claims filed or received | claim																					0	0	0
Distribution Made to Limited Partner, Cash Distributions Paid																					$ 74,886	$ 73,804	$ 72,497
Partners' Capital Account, Unit-based Compensation																					181	194	200
Repayment of Indemnifications Received From Hoegh Lng																					0	64	2,353
Director [Member]
Related Party Transaction [Line Items]
Total Board of Directors' fees																					571	496	501
Partners' Capital Account, Unit-based Compensation																					$ 181	194
Chief Executive Officer Chief Financial Officer [Member] | Phantom Units [Member]
Related Party Transaction [Line Items]
Units granted | shares								8,100			10,917	28,018				21,500	10,917	14,584
Unvested units forfeited | shares					15,378
Unvested units | shares																					4,861
Hoegh LNG [Member]
Related Party Transaction [Line Items]
Indemnification Under the Omnibus Agreement																							900
Reduction of loan	$ 3,300						$ 8,600														$ 11,900
Insurance recoveries																						100	2,400
Percentage Of Ownership Interest In Acquisition														49.00%	51.00%
indemnification received from HoeghLng																					300
Hoegh LNG and Subsidiaries [Member]
Related Party Transaction [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid																					28,500	28,400	28,200
LP Long Term Incentive Plan [Member] | Director [Member]
Related Party Transaction [Line Items]
Partners' Capital Account, Units, Unit-based Compensation | shares			15,528						11,180				11,050
Partners' Capital Account, Unit-based Compensation																					$ 162	$ 194	200
EgyptCo [Member]
Related Party Transaction [Line Items]
Indemnification Under Technical Issues																							$ 500
Revolving credit facility [Member]
Related Party Transaction [Line Items]
Debt, Weighted Average Interest Rate																					3.60%	6.60%
Revolving Credit Due To Owners And Affiliates																								$ 85,000
Aggregate borrowing capacity																					$ 85,000
Amount drawn		$ 10,700		$ 6,600		$ 4,500
Revolving credit facility [Member] | Hoegh LNG [Member]
Related Party Transaction [Line Items]
Debt Instrument, Basis Spread on Variable Rate																						1.40%
Revolving Credit Due To Owners And Affiliates																			$ 85,000
Aggregate borrowing capacity										$ 85,000														$ 85,000
Reduction of loan	$ 3,300						$ 8,600
Non-cash settlements, increase in equity																					$ 11,900
Line of Credit Facility Original Expiration Date																			Jan. 01, 2020
Line of Credit Facility, Expiration Date										Jan. 01, 2023
Revolving Credit Facility Maturing At 2020 [Member] | Hoegh LNG [Member]
Related Party Transaction [Line Items]
Debt Instrument, Basis Spread on Variable Rate																					3.00%
Revolving Credit Facility Maturing at 2021 and Thereafter [Member] | Hoegh LNG [Member]
Related Party Transaction [Line Items]
Debt Instrument, Basis Spread on Variable Rate																				4.00%

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Financial Instruments - Estimated fair value and carrying value (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial covenants	$ 385,000
Cash and cash equivalents	31,770	$ 39,126		$ 26,326	$ 22,679
Amounts due from affiliate	3,639	4,296
Advances (shareholder loans) to joint ventures	4,153	3,831
Current amounts due to owners and affiliates	(2,600)	(2,513)
Long-term Debt	(414,589)	(456,961)
$385 million facility	(385,000)
Revolving credit facility due to owners and affiliates	(18,465)	(8,792)
385 million facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial covenants	385,000
$385 million facility	(385,000)		$ (385,000)
Recurring [Member] | Carrying amount | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	31,770	39,126
Restricted cash	19,293	20,693
Recurring [Member] | Carrying amount | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	(26,475)	(14,935)
Recurring [Member] | Fair value | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	31,770	39,126
Restricted cash	19,293	20,693
Recurring [Member] | Fair value | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	(26,475)	(14,935)
Other [Member] | Carrying amount | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amounts due from affiliate	3,639	4,296
Advances (shareholder loans) to joint ventures	4,153	3,831
Current amounts due to owners and affiliates	(2,600)	(2,513)
Revolving credit facility due to owners and affiliates	(18,465)	(8,792)
Other [Member] | Carrying amount | Fair Value, Inputs, Level 2 [Member] | Lampung facility [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	(94,960)	(112,713)
Other [Member] | Carrying amount | Fair Value, Inputs, Level 2 [Member] | 385 million facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
$385 million facility	(319,629)	(344,248)
Other [Member] | Fair value | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amounts due from affiliate	3,639	4,296
Advances (shareholder loans) to joint ventures	4,305	4,029
Current amounts due to owners and affiliates	(2,600)	(2,513)
Revolving credit facility due to owners and affiliates	(16,987)	(8,717)
Other [Member] | Fair value | Fair Value, Inputs, Level 2 [Member] | Lampung facility [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	(99,295)	(119,598)
Other [Member] | Fair value | Fair Value, Inputs, Level 2 [Member] | 385 million facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ (323,342)	$ (352,219)

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Financial Instruments - Financing receivables and net investment in financing lease (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Financing Receivable, Recorded Investment [Line Items]
Advances/ loans to joint ventures	$ 4,153	$ 3,831
Net investment in financing lease	274,257	278,904
Payment activity [Member] | Performing Financial Instruments [Member]
Financing Receivable, Recorded Investment [Line Items]
Advances/ loans to joint ventures	4,153	3,831
Net investment in financing lease	$ 274,257	$ 278,904

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Risk management and concentrations of risk - Interest rate swap agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)
2.941% Interest Rate [Member]
Derivative [Line Items]
Derivative, Interest rate index	LIBOR
Derivative, Notional amount	$ 56,782
Derivative Liability, Fair Value carrying amount assets	$ (5,560)
Derivative, Term	Jan 2026
Derivative, Fixed interest rate	2.941%
2.838% Interest Rate [Member]
Derivative [Line Items]
Derivative, Interest rate index	LIBOR
Derivative, Notional amount	$ 56,782
Derivative Liability, Fair Value carrying amount assets	$ (5,197)
Derivative, Term	Oct 2025
Derivative, Fixed interest rate	2.838%
2.735% Interest Rate [Member]
Derivative [Line Items]
Derivative, Interest rate index	LIBOR
Derivative, Notional amount	$ 56,782
Derivative Liability, Fair Value carrying amount assets	$ (5,111)
Derivative, Term	Jan 2026
Derivative, Fixed interest rate	2.735%
2.650% Interest Rate [Member]
Derivative [Line Items]
Derivative, Interest rate index	LIBOR
Derivative, Notional amount	$ 56,782
Derivative Liability, Fair Value carrying amount assets	$ (4,927)
Derivative, Term	Jan 2026
Derivative, Fixed interest rate	2.65%
Lampung [Member]
Derivative [Line Items]
Derivative, Interest rate index	LIBOR
Derivative, Notional amount	$ 97,960
Derivative Liability, Fair Value carrying amount assets	$ (5,680)
Derivative, Term	Sep 2026
Derivative, Fixed interest rate	2.80%

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Risk management and concentrations of risk - Fair value of derivative instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Derivative Liability, Current	$ (6,945)	$ (2,907)
Derivative Liability, Noncurrent	(19,530)	(12,028)
Interest rate swap [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Current	0	0
Derivative Asset, Noncurrent	0	0
Derivative Liability, Current	(6,945)	(2,907)
Derivative Liability, Noncurrent	$ (19,530)	$ (12,028)

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Risk management and concentrations of risk - Cash flow hedge accounting (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification from accumulated other comprehensive income included in hedge effectiveness	$ 5,849	$ 956	$ 855
Reclassification of amortization of cash flow hedge to earnings, Tax benefit (expense)	0	0	(299)
Initial value of interest rate swap to be recognized in earnings on amortization approach, Tax benefit (expense)	0	0
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach	1,024	987	$ (3,557)
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, tax	262	389
Total gains (losses) on derivative instruments, tax	262	389
Interest Expense [Member]
Reclassification from accumulated other comprehensive income included in hedge effectiveness	(5,849)	(956)
Initial value of interest rate swap to be recognized in earnings on amortization approach, Tax benefit (expense)	851	966
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach	(1,024)	(987)
Settlement of cash flow hedge		199
Total gains (losses) on derivative instruments	$ (6,022)	$ (778)

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Risk management and concentrations of risk - Cash flow hedges relating to interest rate swaps are included in total gains (losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Total gains (losses) on derivative instruments	$ 0	$ 0	$ 4,681
Realized Gains Losses [Member]
Total gains (losses) on derivative instruments			0
Unrealized Gains Losses [Member]
Total gains (losses) on derivative instruments			4,681
Interest rate swap [Member]
Ineffective portion of cash flow hedge			(990)
Amortization of amount excluded from hedge effectiveness			2,969
Reclassification discontinued hedge from OCI			3,557
Reclassification from accumulated other comprehensive income			$ (855)

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Risk management and concentrations of risk - Effect of cash flow hedge accounting on accumulated OCI and earnings (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Beginning Balance, Before tax gains (losses)		$ (18,119)	$ (5,902)	$ (3,612)
Initial value of interest rate swap to be recognized in earnings on amortization approach, before tax gains (losses)			(625)
Effective portion of unrealized loss on cash flow hedge, Before tax gains (losses)		(18,240)	(13,535)	412
Reclassification from accumulated other comprehensive income included in hedge effectiveness		5,849	956	855
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, Before tax gains (losses)		1,024	987	(3,557)
Other comprehensive income for period, Before tax gains (losses)		(11,367)	12,217	(2,290)
Ending Balance, Before tax gains (losses)	$ (3,612)	(29,486)	(18,119)	(5,902)
Beginning Balance, Tax benefit (expense)		176	565	864
Initial value of interest rate swap to be recognized in earnings on amortization approach, Tax benefit (expense)		0	0
Effective portion of unrealized loss on cash flow hedge, Tax benefit (expense)		0
Reclassification of amortization of cash flow hedge to earnings, Tax benefit (expense)		0	0	(299)
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, tax		(262)	(389)
Other comprehensive income for period, Tax benefit (expense)		(262)	(389)	(299)
Ending Balance, Tax benefit (expense)	864	(86)	176	565
Beginning Balance, Net of tax		(17,943)	(5,337)	(2,748)
Initial value of interest rate swap to be recognized in earnings on amortization approach, Net of tax			(625)
Effective portion of unrealized loss on cash flow hedge, Net of tax		(18,240)	(13,535)	412
Reclassification of amortization of cash flow hedge to earnings, Net of tax	(2,748)	(5,849)	956	(556)
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, Net of tax				(3,557)
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, Net of tax		762	598	(3,557)
Other comprehensive income for period, Net of tax		(11,629)	(12,606)	(2,589)
Ending Balance, Net of tax	$ (2,748)	(29,572)	(17,943)	$ (5,337)
Gain (loss) reclassified to earnings, tax		262	389
Interest Expense [Member]
Reclassification from accumulated other comprehensive income included in hedge effectiveness		(5,849)	(956)
Reclassification discontinued hedge and initial fair value from accumulated other comprehensive income based on amortization approach, Before tax gains (losses)		(1,024)	(987)
Gain (loss) reclassified to earnings		$ (6,873)	$ (1,943)

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Risk management and concentrations of risk - Additional Information (Details) - USD ($) $ in Millions			12 Months Ended
	Dec. 29, 2014	Mar. 17, 2014	Dec. 31, 2018	Dec. 31, 2020	Feb. 28, 2019	Jan. 01, 2017	Oct. 01, 2015
Debt Instrument, Financial Covenants				$ 385.0
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net				7.9
$385 million facility [Member]
Debt Instrument, Financial Covenants				$ 385.0
Derivative, Notional Amount			$ 130.0		$ 127.7
2.941% rate [Member]
Derivative, Notional Amount			65.0
2.838% rate [Member]
Derivative, Notional Amount			$ 65.0
2.650% Fixed interest [Member]
Derivative, Notional Amount					63.8
2.735% Fixed interest [Member]
Derivative, Notional Amount					$ 63.8
Grace [Member]
Derivative, Notional Amount						$ 164.0
Debt Instrument, Face Amount						$ 164.0
Grace [Member] | Maximum [Member]
Debt Instrument, Interest Rate, Stated Percentage						2.315%
Grace [Member] | Minimum [Member]
Debt Instrument, Interest Rate, Stated Percentage						2.305%
Hoegh Gallant [Member] | Maximum [Member]
Derivative, Notional Amount							$ 146.3
Derivative, Fixed Interest Rate							1.9145%
Hoegh Gallant [Member] | Minimum [Member]
Derivative, Notional Amount							$ 146.3
Derivative, Fixed Interest Rate							1.9105%
Lampung facility [Member]
Derivative, Notional Amount		$ 237.1
Derivative, Term of Contract		12 years
Derivative, Fixed Interest Rate		2.80%
Repayments of Secured Debt	$ 7.9
Interest rate swap [Member] | $385 million facility [Member]
Derivative, Term of Contract			7 years
Interest rate swap [Member] | Maximum [Member] | $385 million facility [Member]
Derivative, Fixed Interest Rate			2.838%		2.735%
Interest rate swap [Member] | Minimum [Member] | $385 million facility [Member]
Derivative, Fixed Interest Rate			2.941%		2.65%

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Commitments and contingencies (Details)				1 Months Ended		3 Months Ended	12 Months Ended
	Dec. 11, 2020 USD ($)	Apr. 08, 2020 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2020 USD ($)	Apr. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2020 USD ($) claim	Dec. 31, 2019 USD ($) claim	Dec. 31, 2018 USD ($) claim	Jan. 29, 2018 USD ($)	Dec. 31, 2017 USD ($)
Contractual Obligation				$ 600,000			$ 600,000
Income tax examination, year under examination							5 years
Unrecognized tax benefits for uncertain tax positions				2,668,000		$ 2,283,000	$ 2,668,000	$ 2,283,000	$ 1,725,000		$ 2,626,000
Exposure to property tax and penalties							$ 3,000,000.0
Annual Property Tax Payable						500,000
Indemnification claims filed or received | claim							0	0	0
Repayment of Indemnifications Received From Hoegh Lng							$ 0	$ 64,000	$ 2,353,000
Revolving credit facility due to owners and affiliates				18,465,000		$ 8,792,000	18,465,000	$ 8,792,000
Corporate Joint Venture [Member]
Loss Contingency, Liability associated with the Boil of Claim			$ 23,700,000	$ 23,700,000			$ 23,700,000
Revolving credit facility [Member]
Revolving credit facility due to owners and affiliates										$ 85,000,000
Hoegh LNG [Member]
Indemnifications Under Omnibus Agreement									900,000
Indemnification claims filed or received | claim							0	0
Repayment of Indemnifications Received From Hoegh Lng							$ 0	$ 100,000	2,400,000
Indemnification Payments Received									300,000
Losses incurred due to time charter									$ 500,000
Hoegh LNG [Member] | Corporate Joint Venture [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%	50.00%	50.00%		50.00%
Loss Contingency Accrual			$ 11,900,000	$ 11,900,000			$ 11,900,000
Settlement of boil-off claim				6,500,000	$ 17,200,000
Reduction of loan	$ 3,300,000	$ 8,600,000		3,300,000	$ 8,600,000		300,000
Hoegh LNG [Member] | Revolving credit facility [Member]
Revolving credit facility due to owners and affiliates				$ 85,000,000			$ 85,000,000

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Supplemental cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental disclosure of non-cash investing activities
Non-cash expenditures for vessel and other equipment	$ 0	$ 0	$ (229)
Supplemental disclosure of non-cash financing activities
Non-cash indemnifications received	$ 11,850	$ 0	$ 0

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Issuance of common units and Series A Preferred Units (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Gross proceeds for units issued	$ 3,231	$ 14,340	$ 43,983
Less: Commissions	(57)	(246)	(761)
Net proceeds for units issued	3,174	14,094	43,222
8.75% Series A Preferred Units [Member]
Gross proceeds for units issued	3,231	13,298	39,360
Less: Commissions	(57)	(233)	(701)
Net proceeds for units issued	3,174	13,065	38,659
Common units [Member]
Gross proceeds for units issued	0	1,042	4,623
Less: Commissions	0	(13)	(60)
Net proceeds for units issued	$ 0	$ 1,029	$ 4,563

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Issuance of common units and Series A Preferred Units - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended			36 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020
Compensation Paid to Agent				$ 1,100
Proceeds from Issuance of Common Limited Partners Units	$ 0	$ 1,029	$ 4,563
Agent [Member]
Sales Commissions	$ 100	$ 200	$ 800
Common Stock [Member]
Partners' Capital Account, Units, Sale of Units		53,160	253,106	306,266
Proceeds from Issuance of Preferred Limited Partners Units		$ 1,000	$ 4,600
Proceeds from Issuance of Common Limited Partners Units				$ 5,600
Average Gross Sales Price Per Share	$ 0	$ 19.60	$ 18.26
8.75% Series A Preferred Units [Member]
Partners' Capital Account, Units, Sale of Units	126,743	496,520	1,529,070	2,152,333
Proceeds from Issuance of Preferred Limited Partners Units	$ 3,200	$ 13,100	$ 38,700	$ 54,900
Average Gross Sales Price Per Share	$ 25.50	$ 26.79	$ 25.74

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Common, subordinated and preferred units - Movements (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Common units public [Member]
Common And Subordinated Units [Line Items]
Beginning Balance	18,028,786	17,944,701	17,648,844
Awards to non-employee directors as compensation for directors' fees	3,882	8,944	8,840
ATM program		53,160	253,106
Ending Balance	18,050,941	18,028,786	17,944,701
Common units public [Member] | Director [Member]
Common And Subordinated Units [Line Items]
Awards to non-employee directors as compensation for directors' fees	7,764	2,236	2,210
Common units public [Member] | Non-employee director [Member]
Common And Subordinated Units [Line Items]
Awards to non-employee directors as compensation for directors' fees	3,882
Common units Hegh LNG [Member]
Common And Subordinated Units [Line Items]
Beginning Balance	15,257,498	2,101,438	2,116,060
Subordinated units converted to common units		13,156,060
Ending Balance	15,257,498	15,257,498	2,101,438
Subordinated unit Hegh LNG [Member]
Common And Subordinated Units [Line Items]
Beginning Balance		13,156,060	13,156,060
Subordinated units converted to common units		(13,156,060)
Ending Balance			13,156,060
8.75% Series A Preferred Units [Member]
Common And Subordinated Units [Line Items]
Beginning Balance	6,625,590	6,129,070	4,600,000
ATM program	126,743	496,520	1,529,070
Ending Balance	6,752,333	6,625,590	6,129,070
Phantom Share Units (PSUs) [Member] | Common units public [Member]
Common And Subordinated Units [Line Items]
Phantom units issued	6,627	19,745	17,079
Units issued to staff at Hegh LNG [Member] | Common units public [Member]
Common And Subordinated Units [Line Items]
Units issued to staff at Hegh LNG			14,622
Units issued to staff at Hegh LNG [Member] | Common units Hegh LNG [Member]
Common And Subordinated Units [Line Items]
Units issued to staff at Hegh LNG			(14,622)

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Common, subordinated and preferred units - Additional information (Details)		12 Months Ended
	Oct. 05, 2022 $ / shares	Dec. 31, 2020 shares	Dec. 31, 2019 shares	Dec. 31, 2018 shares	Dec. 31, 2017 shares
Common units Hegh LNG [Member]
Common And Subordinated Units [Line Items]
Partners Capital Account, Units | shares		15,257,498	15,257,498	2,101,438	2,116,060
Subordinated Units Hoegh LNG [Member]
Common And Subordinated Units [Line Items]
Partners Capital Account, Units | shares		15,257,498	15,257,498	13,156,060
Stockholders' Equity Note, Stock Split, Conversion Ratio		1
Series A Preferred Stock [Member]
Common And Subordinated Units [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 25.00
Preferred Stock, Redemption Price Per Share	$ 25.00
Preferred stock distribution rate, Percentage	8.75%
Partners Capital Distribution Amount Per Unit	$ 2.1875

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Earning per unit and cash distributions - Calculation of basic and diluted earnings per unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income	$ 63,145	$ 52,741	$ 77,622
Adjustment for:
Preferred unitholders' interest in net income	14,802	13,850	12,303
Limited partners' interest in net income	48,343	38,891	65,319
Less: Dividends paid or to be paid	(60,222)	(60,149)	(59,952)
Under (over) distributed earnings attributable to:
Distributed Earnings	(11,879)	(21,258)	5,367
Common units public [Member]
Under (over) distributed earnings attributable to:
Distributed Earnings	$ (6,437)	$ (11,514)	$ 2,900
Basic weighted average units outstanding
Weighted Average Number of Shares Outstanding, Basic	18,034	17,986	17,856
Diluted weighted average units outstanding
Weighted Average Number of Shares Outstanding, Diluted	18,037	17,995	17,864
Earnings per unit:
Earnings Per Share, Basic and Diluted	$ 1.40	$ 1.12	$ 1.93
Common units Hegh LNG [Member]
Under (over) distributed earnings attributable to:
Distributed Earnings	$ (5,442)	$ (3,211)	$ 340
Basic weighted average units outstanding
Weighted Average Number of Shares Outstanding, Basic	15,257	7,039	2,101
Diluted weighted average units outstanding
Weighted Average Number of Shares Outstanding, Diluted	15,257	7,039	2,101
Earnings per unit:
Earnings Per Share, Basic and Diluted	$ 1.51	$ 1.84	$ 2.03
Subordinated unit Hegh LNG [Member]
Under (over) distributed earnings attributable to:
Distributed Earnings		$ (6,533)	$ 2,127
Basic weighted average units outstanding
Weighted Average Number of Shares Outstanding, Basic		8,218	13,156
Diluted weighted average units outstanding
Weighted Average Number of Shares Outstanding, Diluted		8,218	13,156
Earnings per unit:
Earnings Per Share, Basic and Diluted	$ 0	$ 0.70	$ 2.03

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Earning per unit and cash distributions - Additional information (Details) - USD ($) $ / shares in Units, $ in Thousands					1 Months Ended			12 Months Ended
	Mar. 26, 2020	Mar. 21, 2019	Sep. 14, 2018	Jun. 03, 2016	Aug. 31, 2020	Mar. 21, 2019	Mar. 23, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution								$ 1,598	$ 1,597	$ 1,591
Subordinated unit Hegh LNG [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution									688	1,372
Phantom Units [Member] | Chief Executive Officer Chief Financial Officer [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	8,100	10,917	28,018	21,500		10,917	14,584
Number of units terminated					15,378
Second Target Distribution [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution Per Unit								$ 0.421875
Distribution Percentage To All Unit Holders								85.00%
Distribution Percentage To Holders Of Incentive Distribution Rights								15.00%
Third Target Distribution [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution Per Unit								$ 0.50625
Distribution Percentage To All Unit Holders								75.00%
Distribution Percentage To Holders Of Incentive Distribution Rights								25.00%
After Target Distribution [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Percentage To All Unit Holders								50.00%
Distribution Percentage To Holders Of Incentive Distribution Rights								50.00%
Common units public [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution Per Unit								$ 0.388125
Distribution Percentage To Holders Of Incentive Distribution Rights								100.00%
Common units Hegh LNG [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Incentive Distribution Right Target Distribution									$ 908	$ 219

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Subsequent events (Details) - USD ($) $ / shares in Units, $ in Thousands			3 Months Ended		12 Months Ended
	Feb. 16, 2021	Feb. 12, 2021	Apr. 09, 2021	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid					$ 74,886	$ 73,804	$ 72,497
Common and Subordinated Stock [Member]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit				$ 1.76
Subsequent Event [Member] | Series A Preferred Stock [Member]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.546875
Distribution Made to Limited Partner, Cash Distributions Paid	$ 3,900
Subsequent Event [Member] | Series A Preferred Stock [Member] | ATM Program
Subsequent Event [Line Items]
Partners' Capital Account, Units, Sale of Units			336,992
Average Gross Sales Price Per Share			$ 25.12
Sales Commissions			$ 8,300
Subsequent Event [Member] | Common and Subordinated Stock [Member]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.44
Distribution Made to Limited Partner, Cash Distributions Paid		$ 15,100
Subsequent Event [Member] | Common and Subordinated Stock [Member] | ATM Program
Subsequent Event [Line Items]
Partners' Capital Account, Units, Sale of Units			52,603
Average Gross Sales Price Per Share			$ 15.75
Sales Commissions			$ 800

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Schedule I - CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Total revenues	$ 143,095	$ 145,436	$ 146,561
EXPENSES
Administrative expenses	(9,740)	(9,861)	(8,916)
Equity in earnings (losses) of joint ventures	6,420	6,078	17,938
Interest expense	(24,430)	(27,692)	(26,814)
Net income (loss)	63,145	52,741	77,622
Parent Company | Reportable Legal Entities
Total revenues	0	0	0
EXPENSES
Administrative expenses	(6,279)	(6,473)	(5,822)
Equity in earnings of subsidiaries	64,296	60,315	68,359
Equity in earnings (losses) of joint ventures	6,420	6,078	17,938
Interest income	15,983	11,205	93
Interest expense	(17,139)	(18,242)	(2,938)
Other items, net	(136)	(142)	(8)
Net income (loss)	63,145	52,741	77,622
Share of subsidiaries unrealized losses on cash flow hedges	(11,367)	(12,217)	(2,290)
Share of subsidiaries income tax benefit	(262)	(389)	(299)
Comprehensive income	$ 51,516	$ 40,135	$ 75,033

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Schedule I - CONSOLIDATED BALANCE SHEETS (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash	$ 31,770	$ 39,126	$ 26,326	$ 22,679
Prepaid expenses and other receivables	3,883	2,534
Total current assets	55,158	59,771
Long-term assets
Accumulated earnings of joint ventures	9,690	3,270
Total long-term assets	926,652	953,029
Total assets	981,810	1,012,800
Current liabilities
Current portion of long-term debt	59,119	44,660
Trade payables	467	533
Amounts due to owners and affiliates	2,600	2,513
Derivative instruments	6,945	2,907
Accrued liabilities and other payables	7,232	11,164
Total current liabilities	77,808	63,253
Long-term liabilities
Long-term debt	355,470	412,301
Loans due to owners and affiliates	18,465	8,792
Derivative instruments	19,530	12,028
Total long-term liabilities	410,687	448,037
Total liabilities	488,495	511,290
Total equity	493,315	501,510	$ 520,437	$ 474,659
Total liabilities and equity	981,810	1,012,800
Parent Company | Reportable Legal Entities
Current assets
Cash	2,058	6,934
Current portion of long-term loans to subsidiaries	26,717	25,597
Promissory note from subsidiaries	123,248	123,248
Prepaid expenses and other receivables	1,097	224
Total current assets	153,120	156,003
Long-term assets
Accumulated earnings of joint ventures	9,690	3,270
Loans to subsidiaries	237,489	260,636
Investments in subsidiaries	455,582	449,570
Total long-term assets	702,761	713,476
Total assets	855,881	869,479
Current liabilities
Current portion of long-term debt	25,597	25,597
Trade payables	86	52
Amounts due to owners and affiliates	732	398
Derivative instruments	4,699	1,821
Accrued liabilities and other payables	2,860	3,155
Total current liabilities	33,974	31,023
Long-term liabilities
Long-term debt	294,032	318,650
Loans due to owners and affiliates	18,465	8,792
Derivative instruments	16,095	9,504
Total long-term liabilities	328,592	336,946
Total liabilities	362,566	367,969
Total equity	493,315	501,510
Total liabilities and equity	$ 855,881	$ 869,479

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Schedule I - CONDENSED STATEMENT OF CASH FLOW (Details) - USD ($) $ in Thousands	12 Months Ended			36 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities	$ 85,825	$ 85,252	$ 91,681
INVESTING ACTIVITIES
Net cash provided by (used in) investing activities	(8)	(269)	3,067
FINANCING ACTIVITIES
Net proceeds from issuance of Series A Preferred Units	3,174	13,065	38,659
Net proceeds from issuance of common units	0	1,029	4,563
Proceeds from long-term debt	0	368,300	0
Repayment of long-term debt	(44,660)	(342,416)	(45,458)
Repayment of debt issuance cost	0	(5,797)	0
Repayment of amounts due to owners and affiliates	0	(34,000)	(17,500)
Proceeds from indemnifications received from Hoegh LNG	0	0	1,701
Repayment of indemnifications received from Hoegh LNG	0	(64)	(2,353)
Cash distributions to limited partners	(74,886)	(73,804)	(72,497)
Net cash provided by (used in) financing activities	(94,622)	(70,625)	(92,478)
Increase (decrease) in cash, cash equivalents and restricted cash	(8,805)	14,358	2,270
Cash, cash equivalents and restricted cash, beginning of period	59,819	45,454	43,281	$ 43,281
Cash, cash equivalents and restricted cash, end of period	51,063	59,819	45,454	51,063
Reportable Legal Entities | Parent Company
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities	48,656	33,130	42,401
INVESTING ACTIVITIES
Long-term loan due from subsidiaries	22,027	(286,133)	0
Net cash provided by (used in) investing activities	22,027	(286,133)	0
FINANCING ACTIVITIES
Net proceeds from issuance of Series A Preferred Units	3,174	13,065	38,659
Net proceeds from issuance of common units	0	1,029	4,563
Proceeds from long-term debt	0	368,300	0
Proceeds from loans due to owners and affiliates	21,750	3,500	5,400
Repayment of long-term debt	(25,597)	(19,198)	0
Repayment of debt issuance cost	0	(5,797)	0
Repayment of amounts due to owners and affiliates	0	(34,000)	(17,500)
Proceeds from indemnifications received from Hoegh LNG	0	0	1,701
Repayment of indemnifications received from Hoegh LNG	0	(64)	(2,535)
Cash distributions to limited partners	(74,886)	(73,804)	(72,497)
Net cash provided by (used in) financing activities	(75,559)	253,301	(42,209)
Increase (decrease) in cash, cash equivalents and restricted cash	(4,876)	(72)	374
Cash, cash equivalents and restricted cash, beginning of period	6,934	7,006	6,632	6,632
Cash, cash equivalents and restricted cash, end of period	$ 2,058	$ 6,934	$ 7,006	$ 2,058

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Schedule I - Dividends (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reportable Legal Entities | Parent Company
Proceeds from Dividends Received	$ 55.8	$ 42.4	$ 51.7