Edgar Filing: Hoegh LNG Partners LP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F/A

(Mark One)

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

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

For the fiscal year ended December 31, 2014

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

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)
Wessex House, 5th Floor
45 Reid Street
Hamilton, HM 12 Bermuda
(Address of principal executive offices)

Richard Tyrrell
Wessex House, 5th Floor
45 Reid Street
Hamilton, HM 12 Bermuda
Telephone: +441-295-6815
Facsimile: +441-295-6101

richard.tyrrell@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		Name of each exchange on which registered
Common units representing limited partner interests		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.

13,156,060 common units representing limited partner interests
13,156,060 subordinated 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 x 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 x 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. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer x

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

U.S. GAAP x	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 x No

EXPLANATORY NOTE

Höegh LNG Partners LP ( “we,” “our,” “us” or “the Partnership”)is filing this Annual Report on Form 20-F/A for the year ended December 31, 2014 (“this Amendment” or “this Form 20-F/A”) to amend its Annual Report on Form 20-F for the year ended December 31, 2014 that was filed with the Securities and Exchange Commission (“SEC”) on April 28, 2015 (the “Original Filing”).

Value added taxes (“VAT”), withholding taxes (“WHT”) and other

We announced in August 2015 that we were reviewing our accounting treatment for certain Indonesian value added tax (“VAT”) and Indonesian withholding tax (“WHT”) transactions for the years ended December 31, 2014 and 2013. All of the VAT and WHT restatement adjustments relate to our subsidiary, PT Hoegh LNG Lampung. In completing our review and reconciliation procedures during 2015, certain VAT balances recorded to our consolidated and combined carve-out balance sheet raised concerns about the appropriateness of the accounting treatment for VAT. Our review and reconciliation procedures were subsequently expanded to include WHT balances. In the course of our review, we also completed a detailed analysis to confirm that all VAT and WHT transactions had been properly reported to Indonesian tax authorities.

Errors in accounting treatment of VAT and WHT

In Indonesia, the general rule is that VAT paid on supplier invoices is creditable (“creditable VAT”) against VAT received on customer invoices in determining the net amount of VAT due to the Indonesian tax authorities. The proper accounting treatment for creditable VAT paid on supplier invoices is to record it as a receivable on the balance sheet since it reduces the VAT liability due to the tax authorities on VAT received for customer invoices. However, prior to the start-up of revenue generating activities, VAT on most supplier invoices is non-creditable (“non-creditable VAT”). As a result, non-creditable VAT paid to the tax authorities on supplier invoices cannot subsequently be credited against VAT received on customer invoices. The proper accounting is to record non-creditable VAT as part of the expense of the associated supplier invoices or to capitalize it as a component of the asset to which it relates. Non-creditable VAT was incorrectly recorded as a VAT receivable in our consolidated and combined carve-out balance sheets for the years ended December 31, 2014 and 2013. Non-creditable VAT should have been recorded as components of vessel operating expenses, construction contract expenses, administrative expenses, newbuilding (net investment in direct financing lease) or deferred debt issuance cost.

In addition, due to the understanding reached with the charterer releasing it from the obligation to pay the charter invoices for September and October 2014, a correction to expense the VAT associated with the invoices that were not payable from the charterer was required. Following PT Hoegh LNG Lampung’s inquiry process with the Indonesian tax authorities on the proper basis for applying VAT to the construction contract invoices related to the Tower Yoke Mooring System (“the Mooring”), an adjustment of approximately $6.2 million was recorded to increase the trade receivables from the charterer and VAT liabilities due to the Indonesian tax authorities on our consolidated and combined carve-out balance sheet.

In Indonesia, WHT is due to be paid on supplier invoices from foreign vendors providing services, goods and financing depending upon applicable tax treaties. The proper accounting treatment is to record WHT as an expense of the period, as other items, net, or a component of the capitalized asset (newbuilding (net investment in direct financing lease) or deferred debt issuance cost). Certain tax amounts are also required to be withheld by the charterer on payments of the time charter /customer invoices. Our accounting policy is to record our revenues net of taxes. WHT paid on supplier invoices and withheld on time charter invoices was incorrectly recorded to a liability account in the consolidated and combined carve-out balance sheet.

PT Hoegh LNG Lampung uses an external service provider to complete filings for VAT and WHT to the Indonesian tax authorities as a basis for settlement of its VAT and WHT liabilities. The accuracy of the filings submitted to the tax authorities is dependent on PT Hoegh LNG Lampung providing the external service provider with transaction information for the VAT and WHT computation. In the course of its review, we identified certain VAT and WHT amounts that had not been previously reported. Amendments to previous VAT and WHT filings have been made to the Indonesian tax authorities and the impact, including penalties imposed by the Indonesian tax authorities, recorded as part of the restatement adjustments.

Pursuant to the omnibus agreement with Höegh LNG Holdings Ltd. (“Höegh LNG”), we are indemnified by Höegh LNG for non-budgeted, non-creditable Indonesian VAT and non-budgeted Indonesian WHT, and any related impact on cash flow for the periods included in this Form 20-F/A and as further described in note 17 to the Partnership’s consolidated and combined carve-out financial statements. The Partnership filed a claim for, and received payment from Höegh LNG with respect to, indemnification with respect to non-budgeted VAT and WHT related to the restatement periods up to and including December 31, 2014 of approximately $1.2 million in the fourth quarter of 2015.

Related adjustments

As a consequence of the reimbursable nature of certain VAT and WHT expenses under PT Hoegh LNG Lampung’s time charter, related adjustments are required for revenue recognition as follows:

Related adjustments to revenues: Under terms of its time charter, PT Hoegh LNG Lampung is reimbursed by the charterer for Indonesian corporate income taxes, WHT on certain interest expenses, certain services and dividends and all Indonesian taxes, including VAT, related to the Mooring. During 2014, the charterer was invoiced for an estimate of the reimbursement of applicable taxes (the “Tax element”) which is subject to a final settlement pending an audit process to compare the invoiced Tax element to actual applicable taxes incurred. The revenue on the Tax element was recognized in our consolidated and combined carve-out income statements only to the extent that applicable taxes were identified as incurred during the applicable period. The remaining invoiced Tax element was deferred pending the completion of the audit process. As of November 30, 2015, the date of the filing of this Form 20-F/A, the final settlement of the Tax element has not been completed. As a result of identifying additional VAT related to the Mooring and WHT expenses recorded as part of the restatement, previously deferred revenues for the Tax element have been recognized as revenue in the restatement adjustments for the additional actual taxes incurred to the extent that such revenues are deemed fixed and determinable.

Pursuant to our omnibus agreement, we were indemnified by Höegh LNG for the hire rate, taxes and VAT payments not received under PT Hoegh LNG Lampung’s time charter for September and October 2014. We received indemnification payments from Höegh LNG in September and October 2014, respectively, for the September and October 2014 invoices not paid by the charterer of $6.5 million and $6.7 million, respectively. We originally recognized part of the payments from Höegh LNG for September and October 2014 as revenue, net of certain deferrals related to part of the tax element and VAT. As a result of identifying additional VAT and WHT expenses recorded as part of the restatement, restatement adjustments include recognition of previously deferred indemnification revenues of approximately $4.9 million. After the restatement adjustments, all of the indemnification payments for the September and October 2014 invoices have been recognized as revenue and there is no remaining deferred indemnification on our consolidated and combined carve-out balance sheet.

Adjustments to revenue that were associated with Indonesian VAT and WHT related to the Mooring have been included in the construction contract revenues. All other adjustments to revenue are included in the time charter revenues or other revenues. As a result of restating the total estimated construction contract expenses and revenues, the computation of the percentage of completion method has been restated.

Reclassification and tax adjustments: As we completed our review of the financial reporting for PT Hoegh LNG Lampung, we identified certain other corrections related to PT Hoegh LNG Lampung for 2014. The main correction was related to a reclassification between vessel operating expenses and administrative expenses. The correction recorded resulted in a decrease in vessel operating expenses and an offsetting increase in administrative expenses for the year ended December 31, 2014. In addition, when the Indonesian tax advisors completed the computation of the tax loss carryforward based upon the restated results for PT Hoegh LNG Lampung the for the year ended December 31, 2014, they altered the tax treatment of a component of the losses on derivative instruments compared with the original tax computation for the year ended December 31, 2014. The tax advisors had subsequently identified a private Indonesian tax ruling indicating that all of the gains and losses on derivative instruments were not tax deductible. As a result, we have re-evaluated the recognition of the deferred tax asset and associated valuation allowance recorded as a component of other comprehensive income in equity related to the derivative instrument. The net impact of the restatement adjustment increased the deferred tax asset and the income tax benefit recorded to other comprehensive income by $0.1 million.

Indirect adjustments related to VAT and WHT

In addition to the related adjustments described above, the restatement adjustments related to VAT and WHT impacted the capitalized cost of PT Hoegh LNG Lampung’s newbuilding (net investment in direct financing lease) and deferred debt issuance cost related to the Lampung facility and the basis for computing the revenue for the direct financing lease and amortization of debt issuance cost. The lease element of PT Hoegh LNG Lampung’s time charter is accounted for as a direct financing lease. As a result of the restatement adjustments described above, the effective interest rate method was recalculated for the revenue for the direct financing lease and for the amortization of the deferred debt issuance cost. The changes in accounting for the resulting amortization of the direct financing lease and the deferred debt issuance cost do not affect or our cash flows or liquidity.

As a result of the conclusions above described above, we are restating in this Form 20-F/A our historical consolidated and combined carve-out balance sheets as of December 31, 2014 and 2013, our consolidated and combined carve-out statements of income, comprehensive income, changes in partners’ capital/owners equity and cash flows for the years ended December 31, 2014 and 2013 and our selected financial data as of and for the year ended December 31, 2014 and 2013. There is no effect related to these items impacting the year ended December 31, 2012 or to the total equity at the beginning of the earliest period presented.

The following table presents the effect of the restatement on our previously reported net income (loss) and total equity as of the date and for the periods shown:

	Net income (loss)									Total equity
(in thousands of U.S. dollars)	August 12 to December 31, 2014			January 1 to August 12, 2014			Year ended December 31, 2013			As of December 31, 2014			As of December 31, 2013
	(Post-IPO)			(Pre-IPO)			(Pre-IPO)
As previously reported	$	13,195			(10,786	)		40,527			237,440		$	(48,035	)
Adjustments:
VAT, WHT and other		75			(1,065	)		(61	)		(957	)		(61	)
Indirect adjustments		(15	)		(90	)		—			(105	)		—
As restated	$	13,255			(11,941	)		40,466			236,378		$	(48,096	)

The following table presents the effect of the restatement on our previously reported comprehensive income the periods shown:

	Year ended December 31, 2014
				Adjustments
(in thousands of U.S. dollars, except per unit amounts)	As reported			VAT, WHT and other			Indirect adjustments			As restated
Net income	$	2,409			(990	)		(105	)	$	1,314
Unrealized losses on cash flow hedge		(10,159	)		—			—			(10,159	)
Income tax benefit		1,890			94			—			1,984
Other comprehensive income		(8,269	)		94			—			(8,175	)
Comprehensive income (loss)	$	(5,860	)		(896	)		(105	)	$	(6,861	)

	Year ended December 31, 2013
			Adjustments
(in thousands of U.S. dollars, except per unit amounts)	As reported		VAT, WHT and other			Indirect adjustments		As restated
Net income	$	40,527		(61	)		—	$	40,466
Unrealized losses on cash flow hedge		—		—			—		—
Income tax benefit		—		—			—		—
Other comprehensive income		—		—			—		—
Comprehensive income (loss)	$	40,527		(61	)		—	$	40,466

Note 2 d. of the notes to the consolidated and combined carve-out financial statements included in this Form 20-F/A reflects the line item adjustments as a result of the restatement to our consolidated and combined carve-out financial statements and provides additional information about this restatement.

In addition, Exhibit 15.1 filed with this Form 20-F/A, which contains the condensed financial information of our parent company, Höegh LNG Partners LP, as of December 31, 2014 and for the period April 1-December 31, 2014, has been restated. Note 2 of the notes to such condensed financial information reflects the changes as a result of the restatement to the condensed financial information of Höegh LNG Partners LP.

Management also has determined that there were control deficiencies relating to the preparation of Indonesia VAT and WHT documentation and the accounting for Indonesia VAT and WHT which gave rise in part to this restatement and constituted a material weakness in our internal control over financial reporting. The material weakness, and our process for remediation thereof, are further described in Item 15. “Controls and Procedures.”

We are restating portions of Items 3,4, 5,7,15,18 and 19 for the information affected by the restated financial statements in this Form 20-F/A. Other Items in this Form 20-F/A are included for the convenience of the reader only and have not been updated from the Original Filing.

Except for the restated information described above, this Form 20-F/A continues to present information as of the date of the Original Filing. Other events occurring after the filing of the Original Filing or other disclosures necessary to reflect subsequent events have been or will be addressed in other reports filed with or furnished to the SEC subsequent to the date of the Original Filing. This Form 20-F/A includes currently-dated certifications from our Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, the dual-dated report of our independent registered public accounting firm, a restated Exhibit 15.1 as described above and the letter agreement, dated August 12, 2015, which supplements the omnibus agreement and relates to the restatement. The changes we have made are a result of and reflect the restatement described herein; no other information in the Original Filing has been updated.

Since this Form 20-F/A restates all of the financial information for the 2013 and 2014, we do not intend to amend our previously furnished reports on Form 6-K for periods ended prior to December 31, 2014. As a result, you should not rely on prior filings, but should rely upon the restated consolidated and combined carve-out financial statements, reports of our independent registered public accounting firm and related financial information for 2013 and 2014 contained in this Form 20-F/A.

HÖEGH LNG PARTNERS LP

INDEX TO FORM 20-F

	Presentation of Information in this Report	4
	Forward-Looking Statements	5

Part I		7
Item 1.	Identity of Directors, Senior Management and Advisers	7
Item 2.	Offer Statistics and Expected Timetable	7
Item 3.	Key Information	7
A.	Selected Financial Data (Restated)	7
B.	Capitalization and Indebtedness	12
C.	Reasons for the Offer and Use of Proceeds	12
D.	Risk Factors (Restated)	12
Item 4.	Information on the Partnership	44
A.	History and Development of the Partnership	44
B.	Business Overview (Restated)	44
C.	Organizational Structure	82
D.	Property, Plants and Equipment	83
Item 4A.	Unresolved Staff Comments	84
Item 5.	Operating and Financial Review and Prospects (Restated)	84
A.	Operating Results (Restated)	95
B.	Liquidity and Capital Resources (Restated)	114
C.	Research and Development, Patents and Licenses, Etc.	126
D.	Trend Information	126
E.	Off-Balance Sheet Arrangements	126
F.	Tabular Disclosure of Contractual Obligations	126
G.	Safe Harbor	127
Item 6.	Directors, Senior Management and Employees	127
A.	Directors and Senior Management	127
B.	Compensation	129
C.	Board Practices	132
D.	Employees	133
E.	Unit Ownership	133
Item 7.	Major Unitholders and Related Party Transactions	134
A.	Major Unitholders	134
B.	Related Party Transactions (Restated)	135
C.	Interests of Experts and Counsel	147
Item 8.	Financial Information	147
A.	Consolidated Statements and Other Financial Information	147
B.	Significant Changes	150
Item 9.	The Offer and Listing	151
A.	Offer and Listing Details	151
B.	Plan of Distribution	151
C.	Markets	151
D.	Selling Unitholders	151
E.	Dilution	151
F.	Expenses of the Issue	151
Item 10.	Additional Information	151
A.	Share Capital	152
B.	Memorandum and Articles of Association	152
C.	Material Contracts	152
D.	Exchange Controls	154
E.	Taxation	154

F.	Dividends and Paying Agents	162
G.	Statement by Experts	162
H.	Documents on Display	163
I.	Subsidiary Information	163
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	163
Item 12.	Description of Securities Other than Equity Securities	164

Part II		165
Item 13.	Defaults, Dividend Arrearages and Delinquencies	165
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	165
Item 15.	Controls and Procedures (Restated)	165
Item 16A.	Audit Committee Financial Expert	167
Item 16B.	Code of Ethics	167
Item 16C.	Principal Accountant Fees and Services	167
Item 16D.	Exemptions from the Listing Standards for Audit Committees	168
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	168
Item 16F.	Change in Registrants’ Certifying Accountant	169
Item 16G.	Corporate Governance	169
Item 16H.	Mine Safety Disclosure	170

Part III		171
Item 17.	Financial Statements	171
Item 18.	Financial Statements (Restated)	171
Item 19.	Exhibits (Restated)	171

SIGNATURE		176
Index to Financial Statements of Höegh LNG Partners LP and SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd (Restated).		F-1

PRESENTATION OF INFORMATION IN THIS REPORT

This annual report on Form 20-F for the year ended December 31, 2014 (this “Annual Report”) should be read in conjunction with the consolidated and combined carve-out 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 UK” refer to Hoegh LNG Services Ltd, a wholly owned subsidiary of our operating company. 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 “PT Hoegh” refer to PT Hoegh LNG Lampung, the owner of the PGN FSRU Lampung. 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 initial fleet, the GDF Suez Neptune and the GDF Suez Cape Ann, respectively. References in this Annual Report to “GDF Suez” refer to GDF Suez LNG Supply SA , a subsidiary of GDF Suez S.A. References in this Annual Report to “PGN” refer to PT PGN LNG Indonesia, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk.

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 “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 Hoegh 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 Hoegh LNG Asia Pte. Ltd., a wholly owned subsidiary of Höegh LNG. References in this Annual Report to “Höegh Shipping” refer to Hoegh 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.

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,” “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:

FSRU and LNG carrier market trends, including hire rates and factors affecting supply and demand;

our anticipated growth strategies;

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

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;

changes in our operating expenses, including drydocking and insurance costs;

our ability to make cash distributions on the units and the amount of any borrowings that may be necessary to make such distributions;

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

the future financial condition of our existing or future customers;

our ability to 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 maintain long-term relationships with our customers;

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

our ability to purchase vessels from Höegh LNG in the future, including the FSRU Independence and Höegh LNG’s two FSRU newbuildings or other FSRUs or LNG carriers;

our continued ability to enter into long-term, fixed-rate charters;

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

expected pursuit of strategic opportunities, including the acquisition of vessels;

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

timely acceptance of our vessels by their charterers;

termination dates and extensions of charters;

the expected 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;

expected demand in the FSRU sector and in the LNG shipping sector in general and the demand for FSRUs and LNG carriers in particular;

availability of skilled labor, vessel crews and management;

our incremental 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 agreements;

the anticipated taxation of the Partnership and distributions to its unitholders;

estimated future maintenance and replacement capital expenditures;

our ability to retain key employees;

customers’ increasing emphasis on environmental and safety concerns;

potential liability from any pending or future litigation;

potential disruption of shipping routes due to accidents, political events, piracy or acts by terrorists;

future sales of our common units in the public market;

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

our ability to successfully remediate any material weaknesses in our internal control over financial reporting and our 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.

PART I

Item 1.

Identity of Directors, Senior Management and Advisers

The information included in Item 1 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

Item 2.

Offer Statistics and Expected Timetable

The information included in Item 2 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

Item 3.

Key Information

Except for the information included in “Item 3.A. Selected Financial Data” and additional disclosures provided in “Item 3.D. Risk Factors — Risks Inherent in Our Business — We face risks relating to our ineffective internal control over financial reporting” and “Item 3.D. Risk Factors — Risks Inherent in an Investment in Us — We are an ‘emerging growth company’ and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investor,” Item 3 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Selected Financial Data (Restated)

The following table presents, in each case for the years and as of the dates indicated, our selected consolidated and combined carve-out financial and operating data, which includes, for periods prior to the closing of our initial public offering (“IPO”) on August 12, 2014, selected consolidated and combined carve-out financial and operating data of the Partnership and its subsidiaries that had interests in the PGN FSRU Lampung and the joint ventures that own the GDF Suez Neptune and the GDF Suez Cape Ann. The transfer of these equity interests and related loans and promissory notes by Hoegh LNG to the Partnership in connection with the IPO was recorded at Höegh LNG’s consolidated book values.

Two of the vessels in our initial fleet (the GDF Suez Neptune and the GDF Suez Cape Ann) are owned by our joint ventures, each of which is owned 50% by us. Under applicable accounting rules, 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 and combined carve-out financial statements. We derive cash flows from the operations of these two joint ventures from principal and 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, 2014, 2013 and 2012, Majority held FSRUs included the PGN FSRU Lampung and construction contract revenue and expenses of the mooring related to PGN FSRU Lampung (“the Mooring”) under construction. The Mooring project was completed in the fourth quarter of 2014. As of December 31, 2014, 2013 and 2012, Joint venture FSRUs included two 50%-owned FSRUs, the GDF Suez Neptune and the GDF Suez Cape Ann. We measure our segment profit based on segment EBITDA. Segment EBITDA is reconciled to net income for each segment in the segment table below. The accounting policies applied to the segments are the same as those applied in the consolidated and combined carve-out financial statements, except that Joint venture FSRUs are presented under the proportional consolidation method for the segment reporting and under the equity method in our consolidated and combined carve-out financial statements. 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.

You should read the following selected financial and operating data in conjunction with “Item 5. Operating and Financial Review and Prospects” and our consolidated and combined carve-out financial statements the combined financial statements of the two joint ventures that own the GDF Suez Neptune and the GDF Suez Cape Ann and the related notes thereto included elsewhere in this Annual Report. The financial information included in this Annual Report may not be indicative of our future results of operations, financial condition and cash flows.

Our financial position, results of operations and cash flows could differ from those that would have resulted if we operated autonomously or as an entity independent of Höegh LNG in the periods prior to our IPO for which historical financial and operating data are presented below, and such data may not be indicative of our future operating results or financial performance.

The information presented in the following table and related footnotes has been adjusted to reflect the restatement of our financial results which is described in the Explanatory Note above. A reconciliation of our previously reported consolidated and combined carve-out financial statements to our restated consolidated and combined carve-out financial statements as of December 31, 2013 and 2014 and for the years ended December 31, 2013 and 2014 is included in note 2.d. of the notes to our consolidated and combined carve-out financial statements.

	Year Ended December 31,
(in thousands of U.S. dollars, except per unit, information and fleet data)	2014			2013			2012
	(Restated)			(Restated)
Statement of Income Data:
Time charter revenues	$	22,227		$	—		$	—
Construction contract revenues		51,868			51,062			5,512
Other revenue		474			511			—
Total revenues		74,569			51,573			5,512
Voyage expenses		(1,139	)		—			—
Vessel operating expenses		(6,197	)		—			—
Construction contract expenses		(38,570	)		(43,958	)		(5,512	)
Administrative expenses		(12,566	)		(8,043	)		(3,185	)
Depreciation and amortization		(1,317	)		(8	)		—
Total operating expenses		(59,789	)		(52,009	)		(8,697	)
Equity in earnings of joint ventures		(5,330	)		40,228			5,007
Operating income		9,450			39,792			1,822
Interest income		4,959			2,122			2,481
Interest expense		(9,665	)		(352	)		(114	)
Loss on derivative financial instrument		(161	)		—			—
Other items, net		(2,788	)		(1,096	)		(1	)
Income before tax		1,795			40,466			4,188
Income tax expense		(481	)		—			—
Net income	$	1,314			40,466		$	4,188
Earnings per unit:
Common unit public (basic and diluted)	$	0.50		$	—		$	—
Common unit Höegh LNG (basic and diluted)	$	0.50		$	—		$	—
Subordinated units (basic and diluted)	$	0.50		$	—		$	—
Cash distributions declared and paid per unit	$	0.52		$	—		$	—
Balance Sheet Data (at end of period):
Assets:
Cash and cash equivalents	$	30,477		$	108		$	100
Restricted cash		37,119			10,700			10,700
Demand note due from owner		143,241			—
Current portion of advances to joint ventures		6,665			7,112			6,675
Long term advances to joint ventures		12,287			17,398			21,996
Newbuilding		—			122,572			86,067
Net investment in direct financing lease		295,363			—			—
Total assets		563,548			228,624			135,125
Liabilities and equity:
Accumulated losses of joint ventures		59,630			54,300			94,528
Amount, loans and promissory notes due to owners and affiliates		6,486			208,637			91,585
Long term debt		193,271			—			—
Owner's equity		—			(48,096	)		(53,229	)
Total Partners' capital		244,553			—			—
Total liabilities and equity	$	563,548		$	228,624		$	135,125
Cash Flow Data:
Net cash provided by (used in) operating activities	$	27,976		$	(41,217	)	$	(7,635	)
Net cash used in investing activities		(292,199	)		(30,781	)		(61,709	)
Net cash provided by financing activities		294,592			72,006			69,444
Fleet data:
Number of vessels		3			2			2
Average age (in years)		3.5			3.9			2.9
Average charter length remaining excluding options (in years)		16.7			16.1			17.1
Average charter length remaining including options (in years)		24.9			26.1			27.1
Other Financial Data:
Segment EBITDA(1)	$	48,931		$	31,919		$	29,239
Adjusted EBITDA(1)	$	50,272		$	31,919		$	29,239
Capital expenditures:
Expenditures for vessels and equipment		172,324			36,590			58,138
Selected Segment Data:
Joint venture FSRUs (proportionate consolidation)(2)
Segment Statement of Income Data:
Time charter revenues	$	41,319			41,110		$	41,076
Segment EBITDA (1)		32,834			32,347			32,424
Operating income	$	23,686			23,294		$	23,364
Segment Balance Sheet Data (at end of year):
Vessels, net of accumulated depreciation	$	279,670			286,460		$	294,993
Total assets	$	300,327			307,335		$	315,566
Segment Capital expenditures:
Expenditures for vessels & equipment	$	2,434			522		$	1,435

	(1)	Please read “—Non-GAAP Financial Measures” below
	(2)	Please read “Item 5. Operating and Financial Review and Prospects” below and note 4 of our consolidated and combined carve-out financial statements for information on the basis of presentation for the Joint venture FSRUs segment

Non-GAAP Financial Measures

Segment EBITDA and Adjusted EBITDA. EBITDA is defined as earnings before interest, depreciation and amortization and taxes. Segment EBITDA is defined as earnings before interest, depreciation and amortization, taxes and other financial items. Other financial items consist of gains and losses on derivative instruments and other items, net (including foreign exchange gains and losses and withholding tax on interest expenses). Adjusted EBITDA is defined as earnings before interest, depreciation and amortization, taxes, other financial items and cash collections on direct financial lease investments. Cash collections on direct finance lease investments consist of the difference between the payments under the time charter and the revenues recognized as a financial lease (representing the repayment of the principal recorded as a receivable). Segment EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and external users of financial statements, such as our lenders, to assess our financial and operating performance. We believe that Segment EBITDA assists our management and investors by increasing the comparability of our performance from period to period and against the performance of other companies in our industry that provide Segment EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest, other financial items, depreciation and amortization and taxes, 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. We believe that including Segment EBITDA as a financial and operating measure benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength in assessing whether to continue to hold common units. We believe Adjusted EBITDA benefits investors in comparing our results to other investment alternatives that account for time charters as operating leases rather than financial leases.

Segment EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with U.S. GAAP. Segment EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income, and these measures may vary among other companies. Therefore, Segment EBITDA and Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following tables reconcile Segment EBITDA and Adjusted EBITDA for each of the segments to net income (loss), the comparable U.S. GAAP financial measure, for the periods presented:

	Year ended December 31, 2014
(in thousands of U.S. dollars)	Majority held FSRUs		Joint venture FSRUs (proportional consolidation)			Other			Total Segment reporting			Consolidated & combined carve-out reporting
	(Restated)					(Restated)			(Restated)			(Restated)
Reconciliation to net income (loss)
Net income (loss)	$	8,375		(5,330	)		(1,731	)		1,314		$	1,314
Interest income		—		—			(4,959	)		(4,959	)		(4,959	)
Interest expense, net		9,198		17,121			467			26,786			9,665
Depreciation and amortization		1,317		9,148			—			10,465			1,317
Income tax (benefit) expense		505		—			(24	)		481			481
Equity in earnings of JVs: Interest (income) expense, net		—		—			—			—			17,121
Equity in earnings of JVs: Depreciation and amortization		—		—			—			—			9,148
Other financial items ⁽¹⁾		2,915		11,895			34			14,844			2,949
Equity in earnings of JVs: Other financial items ⁽¹⁾		—		—			—			—			11,895
Segment EBITDA		22,310		32,834			(6,213	)		48,931			48,931
Cash collection/ principal payment on direct financing lease		1,341		—			—			1,341			1,341
Adjusted EBITDA	$	23,651		32,834			(6,213	)		50,272		$	50,272

	Year ended December 31, 2013
(in thousands of U.S. dollars)	Majority held FSRUs		Joint venture FSRUs (proportional consolidation)			Other			Total Segment reporting			Consolidated & combined carve-out reporting
	(Restated)					(Restated)			(Restated)			(Restated)
Reconciliation to net income (loss)
Net income (loss)	$	1,669		40,228			(1,431	)		40,466		$	40,466
Interest income		—		—			(2,122	)		(2,122	)		(2,122	)
Interest expense, net		352		18,085			—			18,437			352
Depreciation and amortization		8		9,053			—			9,061			8
Income tax (benefit) expense		—		—			—			—			—
Equity in earnings of JVs: Interest (income) expense, net		—		—			—			—			18,085
Equity in earnings of JVs: Depreciation and amortization		—		—			—			—			9,053
Other financial items ⁽¹⁾		1,096		(35,019	)		—			(33,923	)		1,096
Equity in earnings of JVs: Other financial items ⁽¹⁾		—		—			—			—			(35,019	)
Segment EBITDA		3,125		32,347			(3,553	)		31,919			31,919
Cash collection/ principal payment on direct financing lease		—		—			—			—			—
Adjusted EBITDA	$	3,125		32,347			(3,553	)		31,919		$	31,919

	Year ended December 31, 2012
(in thousands of U.S. dollars)	Majority held FSRUs			Joint venture FSRUs (proportional consolidation)			Other			Total Segment reporting			Consolidated & combined carve-out reporting
Reconciliation to net income (loss)
Net income (loss)	$	(2,487	)		5,007			1,668			4,188		$	4,188
Interest income		—			(1	)		(2,481	)		(2,482	)		(2,481	)
Interest expense, net		114			19,033			—			19,147			118
Depreciation and amortization		—			9,060			—			9,060			—
Income tax (benefit) expense		—			—			—			—			—
Equity in earnings of JVs: Interest (income) expense, net		—			—			—			—			19,033
Equity in earnings of JVs: Depreciation and amortization		—			—			—			—			9,060
Other financial items ⁽¹⁾		1			(675	)		—			(674	)		1
Equity in earnings of JVs: Other financial items ⁽¹⁾		—			—			—			—			(675	)
Segment EBITDA		(2,372	)		32,424			(813	)		29,239			29,239
Cash collection/ principal payment on direct financing lease		—			—			—			—			—
Adjusted EBITDA	$	(2,372	)		32,424			(813	)		29,239		$	29,239

(1)

Other financial items consist of gains and losses on derivative instruments and other items, net including foreign exchange gains or losses and withholding tax on interest changes.

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors (Restated)

Some of the following risks relate principally to the industry in which we operate and to our business in general. Other risks relate principally to the securities market and to ownership of our common units. The occurrence of any of the events described in this section could significantly and negatively affect our business, financial condition, operating results or cash available for distribution or the trading price of our common units.

Risks Inherent in Our Business

Our initial fleet consists of only three vessels. 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 initial fleet consists of three 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. 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—GDF Suez Neptune Time Charter—Termination” and “Item 4.B. Business Overview—Vessel Time Charters—PGN FSRU Lampung Time Charter—Termination.” We may be unable to charter the applicable vessel on terms as favorable to us as those of the terminated charter.

We are dependent on GDF Suez and PGN as the sole customers for our vessels. A deterioration of the financial viability of GDF Suez or PGN or our relationship with either GDF Suez or PGN, or the loss of either GDF Suez or PGN 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, 2014, 2013 and 2012, PGN accounted for all of the revenues in our consolidated and combined carve-out income statements and GDF Suez accounted for all of the revenues of our joint ventures from which we derived all of our equity in earnings of joint ventures. A deterioration in the financial viability of GDF Suez or PGN or the loss of either GDF Suez or PGN 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 because of its financial inability, disagreements with us or our joint venture partners or otherwise;

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 prolonged periods of off-hire; (ii) with respect to the GDF Suez Neptune and the GDF Suez Cape Ann , 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;

with respect to the GDF Suez Neptune and the GDF Suez Cape Ann , GDF Suez exercising its right to terminate the charter without cause at any time following the fourth and sixth years, respectively, of the charters’ effectiveness, in which case GDF Suez will be obligated to pay the vessel owner a previously agreed upon termination fee based on the date such charter is terminated;

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

with respect to the PGN FSRU Lampung, PGN exercising its option to purchase the vessel; or

a prolonged force majeure event or a declaration of war in any location that materially interrupts the performance of the time charter.

For further details regarding termination of our charters, please read “Item 4. B. Business Overview—Vessel Time Charters—GDF Suez Neptune Time Charter—Termination” and “Item 4. B. Business Overview—Vessel Time Charters—PGN FSRU Lampung Time Charter—Termination.” 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.

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.

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.

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 businesses.

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 the minimum quarterly distribution on our common units.

We may not have sufficient cash from operations to pay the minimum quarterly distribution of $0.3375 per unit on 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 are dependent on our operations and the cash distributions and operations of our joint ventures, each of which may fluctuate based on the risks described in this section, 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 and insurance;

the continued availability of natural gas production, liquefaction and regasification facilities;

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 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 unscheduled off-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 and restrictions on distributions contained in our and our joint ventures’ current and future debt instruments;

fluctuations in interest rates;

fluctuations in working capital needs;

variable tax rates;

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 and payments to our general partner.

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.

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 distribute all of our available cash (as defined in our partnership agreement) 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 substantial majority 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 substantial majority of our income from our 50% equity interests in our joint ventures that own the GDF Suez Neptune and the GDF Suez 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 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 GDF Suez Neptune and the GDF Suez Cape Ann are Mitsui O.S.K. Lines, Ltd (“MOL”) and Tokyo LNG Tanker Co., Ltd (“TLT”), who 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 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;

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 of our vessels could be more expensive and time consuming than we anticipate, which could adversely affect our cash available for distribution.

The drydocking of our vessels could require us to expend capital if the vessels are drydocked for longer than the allowable period under the time charters. Although each of our time charters requires 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. 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 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.

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 the minimum quarterly distribution to unitholders, which could have a material adverse effect on our ability to make cash 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, cost-savings 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.

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.

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

Our growth strategy focuses on expansion in the floating storage and regasification sector and the 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 and the continued increase in natural gas production from unconventional sources in regions such as North America. Accordingly, our growth depends on continued growth in world and regional demand for LNG, FSRUs, 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 the production levels of low-cost natural gas in domestic, natural gas-consuming markets, which could further depress prices for natural gas in those markets and make LNG uneconomical;

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

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

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

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

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

negative global or regional economic or political conditions, 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.

PGN has the option to purchase the PGN FSRU Lampung beginning in June 2018. If PGN exercises this option, it could have a material adverse effect on our operating cash flows and our ability to make cash distributions to our unitholders.

PGN has the option to purchase the PGN FSRU Lampung beginning in June 2018, at a price specified in the time charter. Any compensation we receive for the purchase of the PGN FSRU Lampung may not adequately compensate us for the loss of the vessel and related time charter. If PGN exercises this option, it would significantly reduce the size of our fleet, and we may be 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 PGN FSRU Lampung time charter. 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—Termination.”

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

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

worldwide demand for natural gas;

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 in gas importing and consuming countries.

Seasonality in demand, peak-load demand, and other short-term factors such as pipeline gas disruptions and maintenance schedules of utilities affect charters of less than two years and rates. 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, 2014 we had total debt of $212.3 million and our joint ventures’ debt was $522.1 million, of which 50% is our share. In addition, we have the ability to incur additional debt, and we will have the ability to borrow an additional $85 million under our sponsor credit facility, subject to certain limitations. If we acquire additional vessels or businesses, our consolidated debt may significantly increase. We may incur additional debt under this or future credit facilities. Our joint ventures’ credit facilities will mature in 2022 and require an aggregate principal repayment of approximately $330 million, of which 50% is our share. A portion of the credit facility secured by the PGN FSRU Lampung will mature in 2021 and require that an aggregate principal amount of $16.5 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. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt—Lampung 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 effect any of these remedies on satisfactory terms, or at all.

We lent $140 million of the net proceeds of our IPO to Höegh LNG pursuant to a demand note and Höegh LNG has entered into a revolving credit facility to provide us with liquidity, and, as a result of these transactions, we will be exposed to the credit risk of Höegh LNG and other risks that could impact our liquidity.

Upon consummation of the IPO, we lent $140 million to Höegh LNG pursuant to a demand note and entered into a three-year, $85 million revolving credit facility with Höegh LNG as our lender to be used to fund our general partnership purposes, including working capital and distributions. This revolving credit facility provides our primary source of liquidity other than our cash from operations distributed to us by our subsidiaries and joint ventures and payments made to us under our shareholder loans. Höegh LNG’s ability to make loans under the revolving credit facility and to repay the demand note on demand, may be affected by events beyond our and their 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 and the demand note may be impaired. If we make demand on the demand note, or if we request a borrowing under the revolving credit facility, Höegh LNG may not have, or be able to obtain, sufficient funds to repay the demand note or 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, or Höegh LNG is unable to repay the demand note upon demand, our financial condition, results of operations and ability to make cash distributions to our unitholders could be materially adversely affected.

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;

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, maintaining minimum book equity ratio and ensuring that available cash flows exceeds interest and principal payable for a nine-month test period. Please read “Item 5. B. Liquidity and Capital Resources—Borrowing Activities—Long-term Debt—Lampung Facility.”

Our joint ventures’ and Höegh LNG’s 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, in some cases, guaranteed by Höegh LNG, and if we or they, as applicable, 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.

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.

Furthermore, our financing arrangements require 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 make dividend distributions out of profits or, in certain instances, share premium or distributable capital reserves resulting from contributed capital reserves. Höegh Lampung is subject to Singapore laws and may make dividend distributions only out of profits. Dividends may only be paid by PT Hoegh if its retained earnings are positive under Indonesian law. As of December 31, 2014, PT Hoegh had negative retained earnings and therefore could not make dividend payments to us under Indonesia law. However, subject to meeting a debt service ratio of 1:20:1:00, PT Hoegh 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 meeting operating requirements as defined by the Lampung 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 PT Hoegh’s existing financing agreement, and certain other events occurring at Höegh LNG, could result in cross-defaults or defaults under PT Hoegh’s existing credit facility, which could have a material adverse effect on us.

Höegh LNG guarantees the obligations of PT Hoegh, a company incorporated under the laws of the Republic of Indonesia and the owner of the PGN FSRU Lampung, under PT Hoegh’s existing credit facility. Pursuant to the terms of the PT Hoegh credit 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 PT Hoegh credit facility. Furthermore, among other things, a default by Höegh LNG on certain of its indebtedness or the occurrence of certain other adverse events at Höegh LNG may cause a default under the PT Hoegh credit facility. Any one of these events could result in the acceleration of the maturity of the PT Hoegh credit facility and the lenders thereunder 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 Hoegh might not have sufficient funds or other assets to satisfy all of its obligations, 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.”

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;

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.

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.

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

FSRU and 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 expect 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. Many of these competitors have significantly greater financial resources and larger fleets than do we or Höegh LNG. 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 may 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.

We may have more difficulty entering into long-term time charters in the future if an active short-term market for FSRUs develops or the spot LNG transportation market for LNG carriers continues to develop.

One of our principal strategies is to enter into additional FSRU and LNG carrier time charters of five or more years. If a market for short-term time charters for FSRUs develops, we may have increased difficulty entering into long-term time charters upon expiration or early termination of the time charters for the FSRUs in our initial fleet or for any vessels that we acquire in the future. As a result, our cash flows may be less stable.

In the LNG carrier market, awards of LNG carrier time charters have historically been for five or more years, though the use of spot voyages and short-term time charters has grown in the past few years. This may impact our ability to identify attractive acquisition candidates in the LNG carrier market.

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 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.

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 beyond our contracted newbuildings, 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.

Hire rates for FSRUs are not readily available and may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings and ability to make cash distributions to our unitholders may decline.

Hire rates for FSRUs are not readily available and may fluctuate over time as a result of changes in the supply demand balance relating to current and future FSRU and capacity. This supply demand relationship largely depends on a number of factors outside our control. The LNG market is closely connected to world natural gas prices and energy markets, which we cannot predict. A substantial or extended decline in natural gas prices could adversely affect our ability to recharter our vessels at acceptable rates or to acquire and profitably operate new FSRUs. Our ability from time to time to charter or re-charter any vessel at attractive rates will depend on, among other things, the prevailing economic conditions in the LNG industry. Hire rates for newbuilding FSRUs are correlated with the price of FSRU newbuildings. Hire rates at a time when we may be seeking a new charter may be lower than the hire rates at which our vessels are currently chartered. If rates are lower when we are seeking a new charter, our earnings and ability to make cash distributions to our unitholders may decline.

Vessel values may fluctuate substantially, and, if these values are lower at a time when we are attempting to dispose of vessels, we may incur a loss.

Vessel values 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

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 her, we may seek to dispose of her. Our inability to dispose of a vessel at a reasonable value could result in a loss on her 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.

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 sponsor credit facility; or

maintain satisfactory relationships with suppliers and other third parties.

In addition, all our vessels are subject to a ship management agreement or sub-technical support agreements with Höegh LNG Management. Our joint ventures’ vessels are subject to commercial and administration management agreements with Höegh Norway, and the PGN FSRU Lampung is subject to a technical information and services agreement with Höegh Norway, a master spare parts supply agreement with Höegh Asia and a master maintenance agreement with Höegh Shipping. Pursuant to the commercial and administration management agreements, Höegh LNG Management provides significant commercial and technical management services with respect to the GDF Suez Neptune and the GDF Suez Cape Ann. Pursuant to the technical information and services agreement, the master spare parts supply agreement and the master maintenance agreement, Höegh Norway, Höegh Asia and Höegh Shipping provide significant commercial, administration and support services with respect to the PGN FSRU Lampung. In addition, pursuant to an administrative services agreement among us, our operating company and Höegh UK and an administrative services agreement between our operating company and Leif Höegh UK, Höegh UK and Leif Höegh UK provide us and our operating company with certain administrative, financial and other support services. Höegh UK subcontracts some of these services to Höegh Norway and Leif Höegh UK pursuant to separate administrative services agreements. 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;

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 environmental damage, 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.

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

Our operating expenses 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, while we do not bear the cost of fuel (bunkers) under our time charters, 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 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 employ technically skilled staff and crew, they will not be able to adequately staff our vessels. 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 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, our revenue has been generated in U.S. Dollars, but we incur a minority of our operating expenses in other currencies. Fluctuations in exchange rates could affect our cash flows and operating results. If the U.S. Dollar weakens significantly, we would be required to convert more U.S. Dollars to other currencies to satisfy our obligations, which would cause us to have less cash available for distribution.

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 and the Gulf of Aden off the coast of Somalia. 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, such as the October 2002 attack on the m.v. Limburg and the July 2010 attack allegedly by Al-Qaeda on the m. Star, both very large crude carriers not related to us, 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 could be exposed to political, governmental and economic instability that could harm our operations.

Economic, political and governmental conditions in the countries where we are engaged in business or where our vessels are registered could affect our operations. Any disruption caused by these factors could harm our business. In particular, we derive a substantial portion of our revenues from shipping and regasifying LNG from politically unstable regions. Past political conflicts in these regions have included attacks on ships and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Future hostilities or other political instability 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 Brazil, the United States or other countries against countries in the Middle East, Southeast Asia or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could also harm our business and ability to make cash distributions to our unitholders.

The LNG transportation, storage and regasification industry is subject to substantial environmental and other regulations, which may significantly limit our operations or 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 impacts to the environment from their operations. 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. Additional laws and regulations may be adopted that could limit our ability to do business or further increase costs, which could harm our business. In addition, failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of operations. We may become subject to additional laws and regulations if we enter new markets or trades.

These requirements can affect the resale value or useful lives of our vessels, require a reduction in cargo capacity, 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.

The design, construction and operation of FSRUs and interconnecting pipelines and the transportation of LNG are subject to governmental approvals and permits. 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.

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 (the “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 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. 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 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.

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, including the 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. Clean Air Act of 1970, as amended. In some cases, these laws and regulations require us to obtain 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. 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, may increase our overall cost of business. 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 affected by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, and the handling and disposal of hazardous substances and wastes. These regulations include OPA 90, the CWA, the U.S. Maritime Transportation Security Act of 2002 and 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”).

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 expect to incur substantial expenses in complying with these laws and regulation, including expenses for vessel modifications and changes in operating procedures.

These 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, national and foreign 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 or property 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 and civil penalties, criminal sanctions or the suspension or termination of our operations, including, in certain instances, seizure or detention of our vessels.

Further changes to existing environmental legislation that is 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. The United States has recently enacted legislation and regulations that require more stringent controls of air and water emissions from oceangoing vessels. Such legislation or regulations may require additional capital expenditures or operating expenses (such as increased costs for low-sulfur fuel) in order for us to maintain our vessels’ compliance with international and/or national regulations.

Climate change and greenhouse gas restrictions 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 emission from vessel emissions. 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 Kyoto Protocol to the United Nations Framework Convention on Climate Change (the “Kyoto Protocol”) for now, a new treaty may be adopted in the future that includes restrictions on shipping emissions. 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.

Adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also have an effect on demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business that we cannot predict with certainty at this time.

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.

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 GDF Suez Neptune or the GDF Suez 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 GL, compliant with the ISM Code and “in class.”

As part of the certification process, a vessel must undergo annual surveys, renewal surveys, intermediate surveys and special surveys. In lieu of a special survey, a vessel’s machinery may be on a continuous survey cycle, under which the machinery would be surveyed periodically over a five-year period. Each of the vessels in our initial fleet is on a planned maintenance system approval, and as such the classification society attends onboard once every year to verify that the maintenance of the equipment onboard is done correctly. For each of the GDF Suez Neptune and the GDF Suez Cape Ann, a renewal survey is conducted every five years and an intermediate survey is conducted every 30 months after a renewal survey. During the first 15 years of operation, the vessels have an approved 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 drydocked both at each renewal survey and each intermediate survey, resulting in drydocking approximately every five years or pursuant to charterer’s requirements every 30 months. We do not anticipate drydocking the PGN FSRU Lampung for at least 20 years as certain inspections can be done without drydocking.

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.

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 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 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 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 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 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 common units. Additionally, some investors may decide to divest their interest, or not to invest, in our common units simply because we may do business with companies that do business in sanctioned countries. Investor perception of the value of our common 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 face risks relating to our ineffective internal control over financial reporting.

As a result of our review of our internal control over financial reporting in connection with the preparation of this Form 20-F/A, we identified a combination of control deficiencies related to the accounting treatment for certain Indonesian VAT and WHT transactions for the year ended December 31, 2014, which together constituted a material weakness in our internal control of financial reporting. In addition, management has concluded, based primarily on the identification of the material weakness, that our disclosure controls and procedures were not effective at December 31, 2014. See “Item 15. Controls and Procedures.” We have not yet remediated our material weakness. If we are unable to successfully remediate this material weakness in a timely manner, or if in the future we are unable to maintain effective internal controls and disclosure controls, investors may lose confidence in our reported financial information, which could lead to a decline in the price of our common units, limit our ability to access the capital markets in the future, and require us to incur additional costs to improve our internal control and disclosure control systems and procedures. Further, if lenders lose confidence in the reliability of our financial statements, it could have a material adverse effect on our ability to fund our operations.

Because of an exemption for newly public companies, our management will not be required to make its first annual assessment of our internal control over financial reporting until our annual report for the year ending December 31, 2015. Our efforts to develop and maintain effective internal controls and disclosure controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under the Sarbanes-Oxley Act of 2002.

Risks Inherent in an Investment in Us

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. 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. Please read “Item 7.B. Related Party Transactions—Omnibus Agreement—Noncompetition.”

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 and subordinated 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.

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.

Höegh LNG owns approximately 16.1% of our common units and all of our subordinated units, which represent an aggregate approximate 58.0% 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;

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 reduced 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 will over time be elected by common unitholders, our general partner will likely have substantial influence on decisions made by our board of directors.

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

Our sole existing officer 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 is expected to devote the substantial majority of his time to our business, he may, from time to time, participate in business development activities for Höegh LNG that are linked to developing opportunities for us.

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 would 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, our joint ventures pay fees for services provided to them by Höegh LNG Management, and our joint ventures reimburse Höegh LNG Management for all expenses they incur on our behalf. These fees and expenses include all costs and expenses incurred in providing certain crewing and technical management services to our joint ventures. In addition, pursuant to a technical information and services agreement, we reimburse Höegh Norway for expenses Höegh Norway incurs pursuant to the technical support agreement that it is party to with Höegh LNG Management.

In addition, pursuant to an administrative services agreement among us, our operating company and Höegh UK and an administrative services agreement between our operating company and Leif Höegh UK, Höegh UK and Leif Höegh provide us and our operating company with certain administrative, financial and other support services. We reimburse Höegh UK and Leif Höegh UK for their reasonable costs and expenses incurred in connection with the provision of these services. In addition, under our administrative services agreement with Höegh UK, we pay Höegh UK a service fee equal to 5.0% of its costs and expenses incurred in connection with providing services to us.

Pursuant to the above-mentioned administrative services agreement with Höegh UK, Höegh UK subcontracts to Höegh Norway and Leif Höegh UK certain administrative services provided to us pursuant to administrative services agreements with Höegh Norway and Leif Höegh UK. Höegh UK reimburses Höegh Norway and Leif Höegh UK for reasonable costs and expenses incurred in connection with the provision of these services. In addition, Höegh UK pays Höegh Norway (and, with respect to certain services, Leif Höegh UK) a service fee equal to 5.0% of the costs and expenses incurred in connection with providing services.

For a description of the ship management agreements, the sub-technical support agreement and the administrative services agreements, please read “Item 7.B. Related Party Transactions.” The fees and expenses payable pursuant to the ship management agreements, the technical support agreement and the administrative services agreements 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, Höegh UK, Leif Höegh UK 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 and subordinated units voting together as a single class is required to remove the general partner. Höegh LNG owns approximately 58.0% of the outstanding common and subordinated units. Additionally, during the term of the SRV Joint Gas shareholders’ agreement, Höegh LNG has agreed to continue to own common units and subordinated units representing a greater than 25% limited partner interest in us in the aggregate.

If our general partner is removed without “cause” during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units, any existing arrearages on the common units will be extinguished, and Höegh LNG will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Any conversion of the incentive distribution rights would be dilutive to existing unitholders. Furthermore, any cash payment in lieu of such conversion could be prohibitively expensive. “Cause” is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor business decisions, such as charges of poor management of our business by the directors appointed by our general partner, so the removal of our general partner because of the unitholders’ dissatisfaction with the general partner’s decisions in this regard would most likely result in the termination of the subordination period.

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.

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, subordinated or other equity securities owned by them or to include those securities in registration statements that we may file for ourselves or other unitholders. Höegh LNG owns 2,116,060 common units and 13,156,060 subordinated 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.

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.

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 it uniform with the Delaware Revised Uniform Partnership Act and, so long as it does not conflict with the Marshall Islands Act or decisions of the Marshall Islands courts, the non-statutory law (“case law”) of the State of Delaware is adopted as the law of the Marshall Islands. 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 and subordinated 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 there are no subordinated units outstanding and 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.

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, without your approval, which would dilute your ownership interests.

We may, without the approval of our unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. 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;

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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.

Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3375 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

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

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. Our board of directors may establish reserves for distributions on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. 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.

Our general partner has a limited call right that may require you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

Höegh LNG, which owns and controls of our general partner, owns approximately 16.1% of our common units. At the end of the subordination period, assuming no additional issuances of common units, and the conversion of our subordinated units into common units, Höegh LNG will own approximately 58.0% 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, except for those contractual obligations of the Partnership that are expressly made without recourse to our general partner. 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 common 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 common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common 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 you if the distribution would cause 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, to 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.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies.” These provisions include an exemption from the auditor attestation requirement in the assessment of the emerging growth company’s internal control over financial reporting and an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to our auditor’s report in which the auditor would be required to provide additional information about the audit and our financial statements. For as long as we take advantage of the reduced reporting obligations, the information that we provide unitholders may be different than information provided by other public companies. We cannot predict if investors will find our common units less attractive because we may rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our unit price may be more volatile. Furthermore, if we fail to successfully remediate the material weakness in our internal control of financial reporting as described in “Item 15. Controls and Procedures” or to maintain an effective system of internal controls and disclosure controls in the future, we may not be able to accurately report our financial results or prevent fraud. Please read “—Risks Related to Our Business—We face risks relating to our ineffective internal control over financial reporting.”

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. Please read “Item 4.B. Business Overview—Taxation of the Partnership.”

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. 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 our initial taxable year, and we expect that we will not be treated as a PFIC for the current or any future taxable year. We expect that more than 25.0% of our gross income for our current taxable year and each future year was or will be nonpassive income, and more than 50.0% of the average value of our assets for each such year 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. 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 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, or 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, and the opinion of our counsel is not binding on the IRS or any court. 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 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 (“Treasury Regulations”). U.S. source gross transportation consists of 50.0% of the gross shipping income that a 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.

We believe that we 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 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 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 35% net income tax in the United States (and the after-tax earnings attributable to such income may be subject to an additional 30% 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 the United Kingdom and 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 intend to 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 common units. However, because we are organized as a limited partnership, there is a risk in some jurisdictions, including the United Kingdom and 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 may 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 the United Kingdom or 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 United Kingdom and Norway, will be largely a question of fact to be determined through an analysis of contractual arrangements, including the sub-technical support agreement that Höegh Norway has entered into with Höegh LNG Management, the ship management agreements that our joint ventures have entered into with Höegh LNG Management, the administrative service agreement we have entered into with our operating company and Höegh UK, the administrative service agreement our operating company has entered into with Leif Höegh UK and the administrative service agreements Höegh UK has entered into with Höegh Norway and with Leif Höegh UK, 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 the United Kingdom, 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.

Item 4.

Information on the Partnership

Except for the description of the tax element of the hire rate under the PGN FSRU Lampung time charter included under “Item 4.B. Business Overview – PGN FSRU Lampung Time Charter – Hire Rate” and “Taxation of the Partnership – Indonesian Taxation,” Item 4 of the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing

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.

At the closing of our initial public offering (“IPO”) in August 2014, Höegh LNG contributed interests in our initial fleet of FSRUs to us. Our initial fleet consists of three modern FSRUs that operate under long-term charters with major energy companies or utilities.

Our initial fleet consists of interests in the following vessels:

a 50% interest in the GDF Suez Neptune , an FSRU built in 2009 that is currently operating under a time charter with GDF Suez, a subsidiary of GDF Suez S.A., a French publicly listed, government-backed, electric utility company, and the leading LNG importer in Europe in 2012, that expires in 2029, with an option to extend for up to two additional periods of five years each;

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

a 100% economic interest in the PGN FSRU Lampung , an FSRU built in 2014 that is currently operating under a time charter with PGN, a subsidiary of an Indonesian publicly listed, government-controlled, gas and energy company that constructs gas pipelines and infrastructure and distributes and transmits natural gas to industrial, commercial and household users. 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.

We were formed on April 28, 2014 as a Marshall Islands limited partnership and have our principal executive offices at Wessex House, 5th Floor, 45 Reid Street, Hamilton, Bermuda.

Capital Expenditures

Our capital expenditures amounted to $172.2 million, $36.5 million and $58.1 million for the years ended December 31, 2014, 2013 and 2012 respectively. The capital expenditures are mainly related to the PGN FSRU Lampung which was delivered from the shipyard in April 2014, after being under construction during 2013 and 2012.

Business Overview (Restated)

General

We own and operate floating storage and regasification units (“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 by making accretive acquisitions of FSRUs, LNG carriers and other LNG infrastructure assets with long-term charters.

We intend to leverage our relationship with Höegh LNG to make accretive acquisitions of FSRUs, LNG carriers and other LNG infrastructure assets with long-term charters from Höegh LNG and third parties. Pursuant to the omnibus agreement we have entered into with Höegh LNG, we have a right to purchase from Höegh LNG any FSRU or LNG carrier operating under a charter of five or more years. 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, for 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:

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.

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 from 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. This has made FSRU technology flexible in |terms of being generic and able to meet different market needs and finding solutions to 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 facilitate 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 terminals, 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 (Oslo Børs symbol: HLNG) . 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 four operators of FSRUs in the world. 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 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.

Business Strategies

Our primary business objective is to increase quarterly distributions per unit over time by executing the following strategies:

Focus on FSRU Newbuilding Acquisitions. We intend to acquire newbuilding FSRUs on long-term charters, rather than FSRUs based on retrofitted, first-generation LNG carriers. We believe newbuilding vessels offer the greatest flexibility. 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. In addition, Höegh LNG has strong customer relationships deriving from its ability to work alongside customers on their vessel design needs. Moreover, Höegh LNG pursues a strategy of maintaining one or more uncontracted newbuilding vessels on order so it can provide its customers an FSRU with minimum lead time. 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 and Accretive 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 and accretive acquisitions. Pursuant to the omnibus agreement that we have entered into with Höegh LNG, we have the right to purchase all or a portion of Höegh LNG’s interests in the Independence, as well as other FSRUs or LNG carriers under a charter of five or more years. 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 four FSRU owners and operators in the world, 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 or that the business strategies discussed above will increase our quarterly distributions. For further discussion of the risks that we face, please read “Item 3.D. Risk Factors.”

Our Fleet

Our Initial Fleet

Upon the closing of the IPO, Höegh LNG contributed to us our initial fleet consisting of interests in the following vessels:

a 50% interest in the GDF Suez Neptune , an FSRU built in 2009 that is currently operating under a time charter with GDF Suez that expires in 2029, 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 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.

Both the GDF Suez Neptune and the GDF Suez 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 Hoegh Shareholders’ Agreement.”

The following table provides information about our three FSRUs:

FSRU

Our

Economic

Interest

Capacity

(cbm)

Maximum

Send-out

Capacity

(MMscf/d)

Current

Location of

Operations

Charter

Commencement

Charterer

Charter

Expiration

Charter

Extension

Option

Periods

GDF Suez Neptune

145,000

750

Trinidad/ Spain/United States

November 2009

GDF Suez

2029

Five years plus five years

GDF Suez Cape Ann

145,000

750

China

June 2010

GDF Suez

2030

Five years plus five years

PGN FSRU Lampung

100

170,000

360

Indonesia

July 2014

PGN

2034

Five or 10 years(1)

(1)

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

As of December 31, 2014, the GDF Suez Neptune, the GDF Suez Cape Ann and the PGN FSRU Lampung were approximately 5.2 years old, 4.6 years old and 0.8 years old, respectively. FSRUs are generally designed to have a lifespan of approximately 40 years.

The GDF Suez Neptune was intended to be used as a floating LNG import terminal in Boston. However, she has been used as an LNG carrier, delivering LNG primarily from Trinidad to Boston and Barcelona, Spain. GDF Suez would like to utilize the GDF Suez Neptune as a stationary FSRU in Uruguay, which requires modification. The modification work is being carried out in connection with the GDF Suez Neptune’s scheduled drydocking. The work commenced at the beginning of March 2015 and ended April 11, 2015. The charterer will reimburse us for the drydocking and modification. The vessel remained on hire during the modification. Since November 2013, the GDF Suez Cape Ann has been employed as China’s first FSRU, located in Tianjin outside Beijing. At the time of construction, both the GDF Suez Neptune and the GDF Suez Cape Ann were the most advanced FSRUs ever built in terms of regasification technology, power generation and thermal insulation. In addition, the vessels received the “Green Passport” from Det Norske Veritas GL certifying the environmental considerations taken when constructing, operating and ultimately when disposing of the vessel. Each vessel has a storage capacity of 145,000 cbm of LNG and a maximum send-out capacity of 750 million standard cubic feet per day (“MMscf/d”) of regasified LNG.

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 and located approximately 16 kilometers offshore. The PGN FSRU Lampung has a storage capacity of 170,000 cbm of LNG and a maximum send-out capacity of 360 MMscf/d of regasified LNG via subsea and onshore pipelines connecting to the existing grid in south Sumatra.

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

Additional Newbuilding FSRUs

Pursuant to the omnibus agreement we have entered into with Höegh LNG, we have the right to purchase all or a portion of Höegh LNG’s interests in an additional newbuilding FSRU, the Independence, which was constructed by Hyundai Heavy Industries Co., Ltd. (“HHI”) and was delivered to Höegh LNG from the shipyard in May 2014. In the fourth quarter of 2014, the Independence started operations under a time charter that expires in 2024 with AB Klaipèdos Nafta (“ABKN”). We have the right to purchase all or a portion of Höegh LNG’s interests in the Independence within 24 months after acceptance of such vessel by her charterer, subject to reaching an agreement with Höegh LNG regarding the purchase price and other terms in accordance with the provisions of the omnibus agreement and any rights ABKN has under the related time charter. We may exercise this option at one or more times during such 24-month period.

The Independence is located in the port of Klaipeda and provides Lithuania with the ability to diversify its gas supply by giving it access to the world market for LNG. The Independence is moored adjacent to a purpose-built jetty and has a storage capacity of 170,000 cbm of LNG and a maximum send-out capacity of 384 MMscf/d of regasified LNG via one pipeline connecting to the existing grid in Lithuania.

On November 3, 2014, Höegh LNG signed a contract with the government owned Egyptian Natural Gas Holding Company (“Egas”) for the supply of an FSRU as an LNG import terminal at Ain Sokhna port, located on the Red Sea in Egypt. The FSRU Höegh Gallant will be employed for this contract. The project is scheduled for the start of operations during the second quarter of 2015. The Höegh Gallant was delivered from the shipyard in early November 2014 and employed as an LNG carrier until mid-January 2015 when it entered the shipyard for minor modifications required for the Egas contract. The Höegh Gallant has a storage capacity of 170,000 cbm of LNG and a maximum send-out capacity of 550 MMscf/d of regasified LNG.

On November 1, 2014, Höegh LNG signed a contract with Sociedad Portuaria El Cayao S.A.E.S.P (“SPEC”) for the supply of an FSRU as a new LNG import terminal in Cartagena, on the Atlantic coast of Colombia. The FSRU contract is for up to twenty years, but includes options for SPEC to reduce the term to five, ten or fifteen years. SPEC will confirm the initial contract term before start of operations, which is expected mid-2016. Höegh LNG plans to employ the Höegh Grace for the project. The Höegh Grace will have storage capacity of 170,000 cbm of LNG and a maximum send-out capacity of 500 MMscf/d of regasified LNG.

Pursuant to the terms of the omnibus agreement, we will have the right to purchase the Höegh Gallant and the Höegh Grace following acceptance by the respective charterer of the related FSRU subject to reaching an agreement with Hoegh LNG regarding the purchase price. There can be no assurance that we will purchase any of these additional newbuilding FSRUs.

The following table provides information about the additional newbuilding FSRUs that we will have the right to purchase from Höegh LNG pursuant to the omnibus agreement:

FSRU

Capacity

(cbm)

Maximum

Send-Out

Capacity

(MMscf/d)

Location of

Operations

Charter

Commencement

Charterer

Charter

Expiration

Charter

Extension

Option

Periods

Independence

170,000

384

Lithuania

Fourth Quarter of 2014

ABKN

2024

n/a

Höegh Gallant

170,000

550

Egypt

Second Quarter of 2015

Egas

2020

n/a

Höegh Grace

170,000

500

Colombia

Mid-2016(1)

SPEC

(2)

n/a

(1)

Expected charter commencement.

(2)

Charter is for up to twenty years, but includes options for SPEC to reduce the term to five, ten or fifteen years.

If Höegh LNG secures a charter of five or more years for one additional newbuilding FSRU, Hull no. 2552, that is also currently being constructed by HHI and is scheduled for delivery to Höegh LNG from the shipyard in the first quarter of 2017, we will have the right to purchase the FSRU from Höegh LNG following acceptance by the charterer pursuant to the omnibus agreement subject to reaching an agreement with Hoegh LNG regarding the purchase price. Hull no. 2552 will have storage capacity of 170,000 cbm of LNG and a maximum send-out capacity of 750 MMscf/d of regasified LNG.

Technical Specifications

Each FSRU in our initial fleet, as well as the Independence, the Höegh Gallant and the Höegh Grace, has or will have 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 GDF Suez Neptune and the GDF Suez 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 Independence is equipped for quay-side mooring. The Höegh Gallant and the Höegh Grace will be equipped for quay-side mooring as well.

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 Independence, the Höegh Gallant and the Höegh Grace have a high-pressure manifold on the side, to connect to the loading arm on the purpose-built jetties. The GDF Suez Cape Ann and GDF Suez Neptune have an STL buoy system, but have also been retrofitted with high-pressure gas manifold on the side, which can be connected to an onshore terminal.

Each of the Independence, the Höegh Gallant and the Höegh Grace is or will be equipped with the same reinforced membrane-type cargo containment system as our current fleet.

Each of the GDF Suez Neptune and the GDF Suez 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. The Independence is equipped to operate using a regasification system that is closed-loop, open-loop or a combination of closed-loop and open-loop, i.e. any mix of seawater and steam heating.

Each of the GDF Suez Neptune , the GDF Suez Cape Ann, the Independence, the Höegh Gallant and the Höegh Grace is or will be capable of operating as a conventional LNG carrier.

Customers

For the years ended December 31, 2014, 2013 and 2012, total revenues in the consolidated and combined carve-out statements of income are from PGN, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk, an Indonesian publicly listed, government-controlled, gas and energy company that constructs gas pipelines and infrastructure and distributes and transmits natural gas to industrial, commercial and household users. GDF Suez accounted for 100% of our joint ventures’ time charter revenues for the years ended December 31, 2014, 2013 and 2012. GDF Suez is a subsidiary of GDF Suez S.A., a French publicly listed, government-backed, electric utility company.

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).

GDF Suez Neptune Time Charter

Initial Term; Extensions

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

Performance Standards

Under the GDF Suez 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. 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 GDF Suez Neptune time charter, hire is payable to the vessel owner monthly, in advance in U.S. Dollars. The hire rate under the GDF Suez 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.

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 GDF Suez 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 GDF Suez exercises its option to extend the GDF Suez 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 GDF Suez Neptune 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:

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.

Ship Management and Maintenance

Under the GDF Suez 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 GDF Suez 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, after the fourth anniversary of the delivery date of the vessel, 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 “GDF 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 GDF 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 GDF Charterer’s Group, as applicable. Additionally, if any personal property of the GDF 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 GDF 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 she 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, 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 GDF Suez 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

GDF Suez entered into a subcharter with GLNS SA (“GLNS”), a joint venture of GDF Suez and Marubeni Corporation, pursuant to which GDF Suez and SRV Joint Gas Ltd. amended the GDF Suez Neptune time charter in February 2015. Such amendments apply only during the term of the subcharter.

In connection with the subcharter, the charterer has agreed to reimburse the vessel owner for the costs of modifying the GDF Suez Neptune for the subcharter and, the charterer will after the expiration of the subcharter, reimburse the costs of reinstating the vessel in order for her to be in every way fitted for service under the charter, during which times the vessel will be on-hire (so long as the time for the modification does not exceed an agreed-upon drydocking allowance). The charterer is also required to compensate the vessel owner for time spent and costs and expenses incurred in connection with the subcharter and arrange for the importation, stay and exportation into and from Uruguay of the GDF Suez Neptune and any materials or equipment needed for the vessel owner’s performance of the subcharter. The charterer will indemnify the vessel owner for (i) costs, claims or losses that the vessel owner incurs as a consequence of the subcharter, except that the vessel owner’s liability for any tortious act (which includes negligence) to any third party will be treated in the same manner as under the original charter, and for (ii) any Uruguayan tax implications. During the term of the subcharter and while the vessel is not on a voyage as an LNG carrier, certain amendments to the time charter apply, including the following:

the charterer will provide port and marine facilities capable of receiving the vessel and berths and places that the vessel can safely reach and return from;

in lieu of the off-hire provision, hire will be reduced proportionately to the extent the vessel does not achieve the specified discharge rate of regasified LNG;

the maintenance provisions and allowances differ;

a right of charterer to change the manager of the GDF Suez Neptune if the average commercial availability of the regasification system falls below certain thresholds;

performance standards different from those described above under “—Performance Standards,” pursuant to which the vessel owner undertakes to ensure that the vessel consumes no more than a specified amount of fuel oil, delivers the nominated discharge rate in accordance with the daily curve agreed with the charterer, is capable of regasifying LNG in a closed-loop heating mode at a specified pressure and temperature and regasifies and discharges her cargo at neither less nor more than a specified LNG discharge rate; and

with respect to indemnification, the definition of the “GDF Charterer’s Group” includes GLNS.

GDF Suez Cape Ann Time Charter

Initial Term; Extensions

The GDF Suez Cape Ann time charter commenced upon acceptance of the vessel by the charterer in June 2010. The initial term of the GDF Suez Cape Ann time charter is 20 years. GDF Suez has the option to extend the time charter for up to two additional periods of five years each. Since November 2013, the GDF Suez Cape Ann has been operating as an FSRU pursuant to a subcharter between GDF Suez and CNOOC Tianjin LNG Limited Company (“CNOOC TLNG”) and will do so for a period of three to five years.

GDF Suez entered into a subcharter with CNOOC TLNG, pursuant to which GDF Suez and SRV Joint Gas Two Ltd. amended the GDF Suez Cape Ann time charter in June 2012 and November 2013. Such amendments apply only during the term of the subcharter. Additionally, GDF Suez, CNOOC TLNG, CNOOC and SRV Joint Gas Two Ltd. entered into ancillary agreements, pursuant to which they allocated responsibility for liabilities associated with their activities at the Tianjin LNG terminal.

When the subcharter with CNOOC TLNG is not in effect, the terms of the GDF Suez Cape Ann time charter are substantially similar to those of the GDF Suez Neptune time charter while not under its subcharter with GLNS.

Subcharter Provisions

In connection with the subcharter, the charterer reimbursed the vessel owner for the costs of modifying the GDF Suez Cape Ann to an FSRU and, the charterer will after the expiration of the subcharter, reimburse the costs of reinstating the vessel in order for her to be in every way fitted for service under the charter, during which times the vessel will be on-hire. The charterer is also required to compensate the vessel owner for time spent and costs and expenses incurred in connection with the subcharter and arrange for the importation, stay and exportation into and from China of the GDF Suez Cape Ann and any materials or equipment needed for the vessel owner’s performance of the subcharter. The charterer will indemnify the vessel owner for costs, claims or losses that the vessel owner incurs as a consequence of the subcharter, except if such costs, claims or losses resulted directly from the vessel owner’s material failure to comply with the time charter, and for any Chinese tax implications.

During the term of the subcharter and while the vessel is not on a voyage as an LNG carrier, certain amendments to the time charter apply, including the following:

additional crew requirements, with the charterer responsible for providing and paying for any Chinese master, officer or crew required to be onboard;

the charterer will provide port and marine facilities capable of receiving the vessel and berths and places that the vessel can safely reach and return from;

in lieu of the off-hire provision, hire will be reduced proportionately to the extent the vessel does not achieve the minimum discharge rate of regasified LNG;

the maintenance provisions and allowances differ;

performance standards different from those described under “— GDF Suez Neptune Time Charter—Performance Standards,” pursuant to which the vessel owner undertakes to ensure that the vessel consumes no more than a specified amount of fuel oil, delivers the nominated discharge rate in accordance with the daily curve agreed with the charterer, is capable of regasifying LNG in a closed-loop heating mode at a specified pressure and temperature and regasifies and discharges her cargo at not less than a regasified LNG discharge rate; and

with respect to indemnification, the definition of the “GDF Charterer’s Group” includes CNOOC TLNG.

Guarantee

Pursuant to the GDF Suez 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 the services of the PGN FSRU Lampung, which is moored at the Mooring owned by PGN 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 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 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 may exercise its option to extend the time charter for a subsequent five years.

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:

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;

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

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

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 advance 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, 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 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 regasificiation 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.”

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.

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 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 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. While we currently believe that it is unlikely that the purchase option will be exercised and we believe that the compensation we would receive upon any exercise by PGN of its purchase option would adequately compensate us for the loss of the PGN FSRU Lampung , there can be no assurance that any proceeds payable to us upon exercise of the option would adequately compensate us for the loss of the PGN FSRU Lampung. If PGN exercises its option to purchase the PGN FSRU Lampung, we will attempt to acquire a replacement vessel with the proceeds from such exercise. However, we may be unable to acquire a suitable replacement vessel, because, among other things that are beyond our control, there may be no replacement vessels 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, or the purchase price of a replacement vessel at the time we identify such replacement vessel may be greater than the proceeds we receive from the exercise of the option. In addition, the hire rate of any replacement vessel we are able to acquire may be lower than the hire rate under the charter. Our inability to find a suitable replacement vessel or the chartering of a replacement vessel at a lower hire rate would have a material adverse effect on our cash flow and on our ability to make cash distributions to our unitholders. Please read “Item 3. D. Risk Factors—Risks Inherent in Our Business—PGN has the option to purchase the PGN FSRU Lampung beginning June 2018. If PGN exercises this 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 Hoegh of all its obligations and liabilities under the time charter.

Shareholder Agreements

We hold our interests in two vessels in our initial fleet through the following joint ventures:

SRV Joint Gas Ltd. (owner of the GDF Suez 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 GDF Suez 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.

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

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

SRV Joint Gas Shareholders’ Agreement

Both SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. (collectively, 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 substantial majority 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;

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 GDF Suez Neptune or the GDF Suez Cape Ann , as applicable, or any other financing exceeding $5,000,000;

investments exceeding $2,500,000 for an 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 GDF Suez Neptune or the GDF Suez 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 and subordinated units representing a greater than 25% limited partner interest in us in the aggregate. In addition, Höegh LNG 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 Hoegh Shareholders’ Agreement

We own a 100% equity interest in Höegh Lampung, which owns a 49% equity interest in PT Hoegh (the owner of the PGN FSRU Lampung). PT Bahtera, an Indonesian company established in February 2013, owns the remaining 51% equity interest in PT Hoegh 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 Hoegh shareholders’ agreement”) and the PT Hoegh shareholder loan, we have a 100% economic interest in the PGN FSRU Lampung.

The board of directors of PT Hoegh manages PT Hoegh, whereas the board of commissioners of PT Hoegh supervise the operation and management of PT Hoegh. 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 Hoegh shareholders’ agreement if (i) a quorum is not present at a meeting of the board of directors of PT Hoegh, the board of commissioners of PT Hoegh 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 Hoegh, the board of commissioners of PT Hoegh and/or the shareholders of PT Hoegh 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 Hoegh 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 Hoegh 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 Hoegh shareholders’ agreement, PT Imeco Inter Sarana has guaranteed the performance and obligations of PT Bahtera. Furthermore, pursuant to the PT Hoegh 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 Hoegh, a failure by PT Hoegh to pay tax, a dispute, litigation or arbitration relating to PT Hoegh and all costs, losses, liabilities and claims relating to the PGN FSRU Lampung as a result of environmental damage.

The PT Hoegh shareholders’ agreement terminates when:

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

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

Höegh Lampung requires the other shareholders to dissolve PT Hoegh. 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 Hoegh 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 Hoegh. In connection with this loan, as security, PT Bahtera collaterally assigned its equity interest and any dividends it may receive from PT Hoegh to Höegh Lampung for as long as amounts remain outstanding. As a result of the above and the PT Hoegh shareholders’ agreement, we will be entitled to all of the net cash flows from PT Hoegh, after the payment of management, agency and local representation fees.

Employees

Other than our Chief Executive Officer and Chief Financial Officer, we do not have any employees and rely on the key employees of Höegh Norway and Leif Höegh UK who perform services for us pursuant to the administrative services agreements. Höegh Norway and Höegh LNG Management also provide commercial and technical management services to our fleet pursuant to ship management agreements, a sub-technical support agreement and commercial and administration management agreements. 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 and LNG carrier industries include BW Maritime Pte. Ltd., Dynagas LNG Partners LP, Excelerate Energy L.P., Exmar NV, GasLog Ltd., GasLog Partners LP, Golar LNG Limited, Golar LNG Partners LP, MOL, OLT and Teekay LNG Partners L.P.

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 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 hold 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 and 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

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 December 31, 2014, entities in the Höegh LNG group employed approximately 475 seafarers who serve on our and Höegh LNG’s vessels, of whom approximately 410 are employees and 65 are in a crew pool. Norwegian employees are employed by Höegh LNG Management and non-Norwegian/Scandinavian employees, except Indonesian seafarers, are employed by Höegh Maritime Management. The Indonesian seafarers are employed by PT Hoegh. Höegh LNG Management and Höegh Maritime Management will employ and train additional seagoing staff 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.

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.

We have obtained hull and machinery insurance on all our vessels against marine and war 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 a mutual 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.

Our current protection and indemnity insurance coverage for pollution is limited to $3.07 billion for all liabilities, except for pollution, which is limited to $1 billion per vessel per incident. We are a member of the Gard P&I Club, which is one of the 13 P&I clubs that comprises the International Group. Members of the International Group 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. P&I clubs provide the basic layer of insurance, which is currently $9 million. For members of the International Group, the International Group provides the next layer of insurance, covering liability between $9 million and $30 million. For liabilities above $30 million, the International Group 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 clubs’ 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, loss of hire and protection and indemnity have confirmed that they will consider the FSRUs as vessels for the purpose of providing insurance.

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.

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 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, 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 certification to the ISO 14001 Environmental Standard, 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 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 policy setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies. Höegh LNG Management holds a Document of Compliance under the ISM Code for operation of the GDF Suez Neptune and the GDF Suez Cape Ann, and PT Hoegh holds a Document of Compliance under the ISM Code for operation of the PGN FSRU Lampung . All Documents of Compliance meet the standards set by 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 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 regulation 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 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.

In March 2006, the IMO amended Annex I to the MARPOL Convention, including a new regulation relating to oil fuel tank protection, which became effective August 1, 2007. The new regulation 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 proposed by the United States, Norway and other IMO member states to Annex VI took effect that require progressively stricter limitations on sulfur emissions from ships. In Emission Control Areas (“ECAs”), limitations on sulfur emissions require that fuels contain no more than 1% sulfur. As of January 1, 2012, fuel used to power ships may not contain more than 3.5% sulfur. This cap has begun to decrease progressively and will continue to do so until it reaches 0.5% by January 1, 2020. 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 in any European Union country. Annex VI Regulation 14, which came into effect on January 1, 2015, set the same 0.1% sulfur limit in the Baltic Sea, North Sea, North America, and United States Caribbean Sea ECAs. Our FSRUs have achieved compliance through use of gas boil-off and low sulfur marine diesel oil in their diesel generators and boilers. The amendments also establish new stringent standards for emissions of nitrogen oxides from new marine engines, depending on their date of installation.

Pursuant to further amendments adopted in April 2014, the Tier III Annex VI requirements for nitrogen oxides will apply to certain new-build vessels with marine diesel engines that are constructed on or after January 1, 2016, and that operate in the North American or United States Caribbean Sea ECAs. The amendments are expected to enter into force on September 1, 2015.

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, to be replaced in time with a requirement for treatment. The BWM Convention will not become effective until 12 months after it has been adopted by 30 states, the combined merchant fleets of which represent not less than 35% of the gross tonnage of the world’s merchant shipping. Though this standard has not been met, the IMO has passed a resolution encouraging the ratification of the BWM Convention and calling upon those countries that have already ratified to encourage the installation of ballast water management systems (“BWMS”) on new ships. As referenced below, the U.S. Coast Guard issued new ballast water management rules on March 23, 2012, and the U.S. Environmental Protection Agency (the “EPA”) issued a new Vessel General Permit in March 2013 that contains numeric technology-based ballast water effluent limitations that will apply to certain commercial vessels with ballast water tanks. Under the requirements of the BWM Convention for units with ballast water capacity more than 5,000 cbm that were constructed in 2011 or before, ballast water management exchange or treatment will be accepted until 2016. From 2016 (or not later than the first renewal date of the International Oil Pollution Prevention Certificate after 2016), only ballast water treatment will be accepted by the BWM Convention. Installation of ballast water treatment systems will be needed on the GDF Suez Neptune and the GDF Suez Cape Ann . Given that ballast water treatment technologies are still at the developmental stage, at this time the additional costs of complying with these rules are unclear, but current estimates suggest that additional costs are not likely to be material.

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.

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.

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.

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 compound coatings to prevent the attachment of mollusks and other sea life to the hulls of vessels after September 1, 2003. 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 altered or replaced. We have obtained Anti-fouling System Certificates for all of our vessels, and we do not believe that maintaining such certificates will have an adverse financial impact on the operation of our vessels.

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 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. 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

loss of subsistence use of natural resources.

Effective as of July 31, 2009, the U.S. Coast Guard adjusted the limits of OPA 90 liability to the greater of $2,000 per gross ton or $17.088 million 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). These limits of liability do not apply, however, 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. This limit is subject to possible adjustment for inflation. 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 similar liability regime 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.

In response to the BP Deepwater Horizon oil spill, the U.S. Congress is currently considering a number of bills that could potentially increase or even eliminate the limits of liability under OPA 90. Compliance with any new requirements of OPA 90 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 require 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”), incorporates the current U.S. Coast Guard requirements for ballast water management, as well as supplemental ballast water requirements, and includes 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 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.

U.S. Ballast Water Regulation

In the United States, two federal agencies regulate ballast water discharges, the EPA, through the VGP, and the U.S. Coast Guard, through approved BWMS. On March 28, 2013, the EPA published a new VGP to replace the existing VGP when it expired in December 2013. The new 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 new 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 has 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 are subject to the ballast water numeric effluent limitations immediately upon the effective date of the new VGP.

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 no more than 10 living organisms per milliliter for organisms between 10 and 50 micrometers in size. For organisms larger than 50 micrometers, the discharge can have 10 living organisms per cbm of discharge. The U.S. Coast Guard will review the practicability of implementing a more stringent ballast water discharge standard and publish the results no later than January 1, 2016. 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. If U.S. Coast Guard-type approved technologies are not available by a vessel’s compliance date, the vessel may request an extension to the deadline from the U.S. Coast Guard.

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. The emission standards apply in two stages: near-term standards for newly-built engines apply from 2011, and long-term standards requiring an 80% reduction in nitrogen dioxides will apply from 2016. Aligned with the Annex VI Regulation 14 requirements, beginning in January 2015, the EPA emission standards also limit sulfur content in fuel used in Category 3 marine vessels operating in the North America ECA to 1,000 ppm (or 0.1% sulfur by mass). Compliance with these standards may cause us to incur costs to install control equipment on our vessels in the future.

Regulation of Greenhouse Gas Emissions

In February 2005, the Kyoto Protocol entered into force. Pursuant to the Kyoto Protocol, adopting countries are required to implement national programs to reduce emissions of greenhouse gases. In December 2009, more than 27 nations, including the United States and China, signed the Copenhagen Accord, which includes a nonbinding commitment to reduce greenhouse gas emissions. The IMO is evaluating various mandatory measures to reduce greenhouse gas emissions from international shipping, which may include market-based instruments or a carbon tax. The European Commission is currently considering possible European action to introduce monitoring, reporting and verification of greenhouse gas emissions from maritime transport as a first step towards measures to reduce these emissions.

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. These new 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. The implementation of the EEDI and the SEEMP standards could cause us to incur additional compliance costs. The IMO is also considering 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 its potential impact on our operations at this time.

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 recently been considered in 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.

Other federal and state laws and regulations relating to the control of greenhouse gas emissions may come into effect, including climate change initiatives that have been considered in 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 to succeed the Kyoto Protocol, 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. After 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.

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. 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. 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.

China Environmental Regulation of FSRUs

Effective June 1, 2011, the Ministry of Transport of the People’s Republic of China (the “PRC”) promulgated regulations on Ship-Induced Marine Pollution Emergency Preparation and Response Management (the “Emergency Response Regulations 2011”) together with the Detailed Rules on the implementation of the Ship-Induced Pollution Response Agreement Regime issued by the Marine Safety Administration (the “MSA”) of the PRC. In addition, the Prevention and Control of Marine Pollution from Ships were implemented in 2010, which requires operators of (i) any ship carrying polluting and hazardous cargoes in bulk or (ii) any other ships above 10,000 gross tons to enter into a Ship Pollution Response Agreement with a pollution clean-up company approved by the MSA prior to the vessel entering any PRC port. Under the Emergency Response Regulations 2011, operators are liable for all costs and expenses for any pollution and must be paid or secured with a financial guarantee before the vessel leaves the port.

While we believe we are in compliance with these regulations and have a Ship Pollution Response Agreement in place for our vessels, we cannot predict whether any accidental pollution may occur, whether it will cause us to incur costs and/or penalties or what the amount of any such costs or penalties may be.

Uruguay Environmental Regulation of FSRUs

Uruguayan Law N˚ 16.688 establishes a regime for the prevention and pollution of the waters of Uruguay, which provides for strict, joint and several liability of owners of vessels that cause pollution for any damages, cleanup costs, and fines for violations. In addition, the Hidrovia countries (Brazil, Bolivia, Paraguay, Argentina, and Uruguay) are working towards standardizing all requirements and regulations for the prevention, reduction, and control of pollution from vessels in the Hidrovia Region by developing an adapted version of MARPOL, called the RIOCON convention. Moreover, additional conventions, laws, and regulations may be adopted that could materially impact our ability to manage our vessels located in Uruguayan waters.

Uruguay recently created new oil spill response requirements under Disposicion Maritimia N˚ 149 that establishes rules governing all vessels entering a Uruguayan port or anchoring in Uruguayan waters. Among these requirements, vessel owners must contract with a Uruguayan Coast Guard approved oil spill response organization (“OSRO”) at least 24 hours before entering a Uruguayan port. A certificate of coverage and evidence of P&I coverage must be submitted to the local authorities for all applicable vessels. The regulation generally applies to all tank vessels or barges and vessels engaged in exploration or exploitation of resources in the Uruguayan Exclusive Economic Zone. The regulation was to take effect on February 20, 2015, but has been delayed pending certain clarifications with the OSROs.

While we believe we will be able to comply with these laws and regulations, the adoption of additional international treaties or conventions, as well as national and local laws or regulations, could subject us to material liabilities, materially impact our ability to operate in Uruguayan waters, or materially increase our costs of operation.

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.

Taxation of the Partnership

The following are discussions of the material tax considerations applicable to us under U.S., United Kingdom, Marshall Islands, Norway, Singapore and Indonesia law, respectively. This discussion is 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 will not be subject to U.S. federal income tax, and gross income generated from such activities in the United States generally will be subject to U.S. federal income tax on a net basis plus a branch profits tax. 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”) will be 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”) will be considered to be 100.0% derived from sources within the United States and generally will be subject to U.S. federal income tax on a net basis plus a branch profits tax. 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 will not be 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, all 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 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.

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 (which we refer to as 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, 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

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 requirements for the Section 883 Exemption, and we expect that we will continue to satisfy such requirements for all future taxable years. First, we are organized under the 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 are expected to earn. 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 either the Publicly Traded Test or the Qualified Shareholder Stock Ownership Test and we satisfy certain substantiation, reporting and other requirements.

Our common units are traded only on the New York Stock Exchange, which is considered to be an established securities market. Although the matter is not free from doubt, based upon our current and expected cash flow and distributions on our outstanding equity interests, we believe that our common units represent more than 50.0% of the total value of all of our outstanding equity interests and therefore our equity interests should be “primarily traded” on an established securities market for purposes of the Publicly Traded Test.

In addition, we believe that we satisfied the listing and trading volume requirements described previously for 2014 and we expect that we will continue to satisfy such requirements for all future taxable years. 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 2014, 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, 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.

In the event we are not able to satisfy the Publicly Traded Test for a taxable year, we may be able to satisfy the Qualified Shareholder Stock Ownership Test for that year provided Höegh LNG owns more than 50.0% of the value of our outstanding equity interests for more than half of the days in such year, Höegh LNG itself met the Publicly Traded Test for such year and Höegh LNG provided us with certain information that we need in order to claim the benefits of the Qualified Shareholder Stock Ownership Test. Based on representations made by Höegh LNG with respect to its present share ownership, exchange-traded shares and trading volumes, we believe Höegh LNG presently meets the Publicly Traded Test, and Höegh LNG has agreed to provide the information referenced above. However, there can be no assurance that Höegh LNG will continue to meet the Publicly Traded Test or be able to provide the information we need to claim the benefits of the Section 883 Exemption under the Qualified Shareholder Ownership Test. Further, the relative values of our equity interests are uncertain and subject to change, and as a result Höegh LNG may not own more than 50.0% of the value of our outstanding equity interests for any future year. Consequently, there can be no assurance that we would meet the Qualified Shareholder Stock Ownership Test based upon the ownership by Höegh LNG of an indirect ownership interest in us.

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 (i.e., 50.0% 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 or is 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 will 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 treated as Effectively Connected Income.

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 (imposed at rates of up to 35.0%). In addition, a 30.0% branch profits tax could be imposed on 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 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. As a result, distributions by our operating subsidiaries and our controlled affiliates to us will not be subject to Marshall Islands taxation.

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 the 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.

United Kingdom Taxation

The following is a discussion of the material United Kingdom tax consequences applicable to us. This discussion is based upon existing legislation and current H.M. Revenue & Customs practice as of the date of this Annual Report. Changes in these authorities 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 United Kingdom tax considerations applicable to us.

Taxation of the Partnership and non-United Kingdom Incorporated Subsidiaries.

As we are a limited partnership and do not expect to be managed and controlled within the United Kingdom nor trade in the United Kingdom, we do not expect to be subject to taxation in the United Kingdom. While we and our operating company have entered into agreements with Höegh UK and Leif Höegh UK, companies incorporated and resident in the United Kingdom, for the provision of certain administrative services, we believe that the terms of these agreements will not result in us or our operating company being treated as being resident in the United Kingdom or having a permanent establishment or carrying on a trade in the United Kingdom. As a consequence, we expect that neither our profits nor the profits or our operating company will be subject to United Kingdom corporation tax. We do not currently anticipate that any of our other non-United Kingdom incorporated subsidiaries will be controlled or managed in the United Kingdom or have a permanent establishment or otherwise carry on a trade in the United Kingdom. Accordingly, we do not anticipate that any of our non-United Kingdom incorporated subsidiaries will be subject to United Kingdom corporation tax.

Taxation of United Kingdom Incorporated Subsidiaries.

Höegh UK is incorporated in the UK and we anticipate will be centrally managed and controlled in the United Kingdom and therefore will be regarded for the purposes of United Kingdom tax as being resident in the United Kingdom and liable to United Kingdom corporation tax on its worldwide income and chargeable gains. As of December 31, 2014, the generally applicable rate of United Kingdom corporation tax was 21.0% (reduced to 20% from April 1, 2015). Höegh UK (and any other UK resident subsidiaries which we acquire) will generally be liable to tax at this rate on their income, profits and gains after deducting expenses incurred wholly and exclusively for the purposes of the business being undertaken. There is currently no United Kingdom withholding tax on distributions made by UK resident companies (such as Höegh UK).

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.

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 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 Hoegh’s main business activity in Indonesia is to provide the lease, operation, and maintenance of the PGN FSRU Lampung to PGN. As PT Hoegh was established in Indonesia, it is a resident taxpayer. Under Law No. 36 Year 2008 regarding Income Tax (“Income Tax Law” or “ITL”), PT Hoegh is subject to Corporate Income Tax (“CIT”) of 25% on taxable income derived from the business activities performed. Therefore, any income generated by PT Hoegh from PGN in regards to the lease, operation, and maintenance of the PGN FSRU Lampung is subject to CIT of 25% (after deductions for allowable expenses in accordance with the ITL provisions). PT Hoegh’s income would include any gain derived from the sale of the Mooring to PGN, as governed by the LOM agreement.

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 5 years. Loss carry back is not permitted in Indonesia.

For tax purposes, costs incurred in relation to the acquisition of fixed assets are deductible (through depreciation) over a useful life of four to twenty years depending on the type of the fixed assets. In this regard, although the commercial useful life of a fixed asset is more than twenty years, such asset shall only be depreciated for a maximum of twenty years for tax purposes.

Depreciation commences in the month when expenditures are incurred. The annual 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 Hoegh will generate income outside of Indonesia.

Taxation of the Sales of the PGN FSRU Lampung to PGN

PGN was granted an option to purchase the PGN FSRU Lampung from PT Hoegh at specified prices as set out in the PGN FSRU Lampung Time Charter. Any gain arising from the sale of the FSRU (i.e. sales price less tax book value) will be subject to CIT at the rate of 25% to PT Hoegh Lampung.

Withholding Taxes (“WHT”)

PT Hoegh Lampung is required to withhold:

WHT under Article 23/26 of the ITL at the following rates:

2% on payments for rent, fees for technical, management and other services to another resident taxpayer;

15% on payments of dividends, interest and royalties to another resident taxpayer; and

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.

WHT under Article 4(2) of the ITL at the rate of 10% on domestic rentals of land and/or buildings and 3% to 6% on payments for domestic construction services.

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 Hoegh is required to withhold and remit EIT on monthly basis.

Value Added Tax (“VAT”)

Any fees charged by PT Hoegh for services provided to PGN 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 Hoegh 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 Hoegh. 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.

VAT of 10% would also be charged on the sale of the FSRU to PGN, if applicable.

Organizational Structure

We are a publicly traded limited partnership formed on April 28, 2014.

The diagram below depicts our simplified organizational and ownership structure.

We listed our common units on the New York Stock Exchange (“NYSE”) in August 2014 under the ticker symbol “HMLP.”

We were formed under the law of the Marshall Islands and maintain our principal executive headquarters at Wessex House, 5th Floor, 45 Reid Street, Hamilton HM12, Bermuda.

A full list of our significant operating and vessel-owning subsidiaries is included in Exhibit 8.1.

Property, Plant and Equipment

Other than the vessels in our initial fleet, we do not have any material property.

Item 4A.

Unresolved Staff Comments

Not applicable.

Item 5.

Operating and Financial Review and Prospects (Restated)

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 and combined carve-out financial statements and related notes of Höegh LNG Partners LP and the combined financial statements and related notes of our joint ventures owning the GDF Suez Neptune and the GDF Suez Cape Ann, each included elsewhere in this Annual Report. We account for our equity interests in our joint ventures owning the GDF Suez Neptune and the GDF Suez Cape Ann as equity method investments in our consolidated and combined carve-out financial statements. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information. Such financial statements, including related notes thereto, have been prepared in accordance with U.S. GAAP and are presented in U.S. Dollars. The information below has been adjusted solely to reflect the impact of the restatement on our financial results which is more fully described in note 2.d. of the notes of the consolidated and combined carve-out financial statements contained in this Form 20-F/A and to include the section entitled “Restatement of Previously Issued Financial Statements” below and does not reflect any subsequent information or events occurring after the date of the Original Filing or update any disclosure herein to reflect the passage of time since the date of the Original Filing.

The following discussion assumes that our business was operated as a separate entity prior to our IPO on August 12, 2014. The combined carve-out financial statements prior to our IPO have been carved out of the consolidated financial statements of Höegh LNG, which owned our interests in Höegh Lampung, PT Hoegh (the owner of the PGN FSRU Lampung and the Mooring) and our joint ventures, SRV Joint Gas Ltd. (the owner of the GDF Suez Neptune) and SRV Joint Gas Two Ltd. (the owner the GDF Suez Cape Ann). Prior to the closing of the IPO, Höegh LNG contributed to us all of its equity interests in and promissory notes due to it from each of the entities owning the GDF Suez Neptune, the GDF Suez Cape Ann and the PGN FSRU Lampung (the “initial fleet”).The transfer was recorded at Höegh LNG’s consolidated book values, as converted to U.S. GAAP.

Our financial position, results of operations and cash flows reflected in the consolidated combined carve-out financial statements include all expenses allocable to our business, but may not be indicative of those that would have been achieved had we operated as a separate public entity for all periods presented or of future results.

Restatement of Previously Issued Financial Statements

Please read note 2.d. of the notes to our consolidated and combined carve-out financial statements for a more detailed discussion of our restated results and the basis for them. The following table presents the effect of the restatement on the Partnership’s previously reported net income (loss) and total equity as of the date and for the periods shown:

	Net income (loss)									Total equity
(in thousands of U.S. dollars)	August 12 to December 31, 2014			January 1 to August 12, 2014			Year ended December 31, 2013			As of December 31, 2014			As of December 31, 2013
	(Post-IPO)			(Pre-IPO)			(Pre-IPO)
As previously reported	$	13,195			(10,786	)		40,527			237,440		$	(48,035	)
Adjustments:
VAT, WHT and other		75			(1,065	)		(61	)		(957	)		(61	)
Indirect adjustments		(15	)		(90	)		—			(105	)		—
As restated	$	13,255			(11,941	)		40,466			236,378		$	(48,096	)

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.

Our Fleet

Our initial fleet consists of interests in the following vessels:

a 50% interest in the GDF Suez Neptune, an FSRU built in 2009 that is currently operating under a time charter with GDF Suez, a subsidiary of GDF Suez S.A., a French publicly listed, government-backed, electric utility company, that expires in 2029, with an option to extend for up to two additional periods of five years each;

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

a 100% economic interest in the PGN FSRU Lampung, an FSRU built in 2014 that is currently operating under a time charter with PGN, a subsidiary of an Indonesian publicly listed, government-controlled, gas and energy company that constructs gas pipelines and infrastructure and distributes and transmits natural gas to industrial, commercial and household users, 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.

For a description of our joint ventures and our shareholder agreements, please read “Item 4.B. Business Overview—Shareholder Agreements.”

Pursuant to the omnibus agreement we entered into with Höegh LNG, our general partner, and our operating company at the closing of our IPO, we have the right to purchase from Höegh LNG all or a portion of its interests in an additional newbuilding FSRU, the Independence, within 24 months after acceptance of such vessel by her charterer, subject to reaching an agreement with Höegh LNG regarding the purchase price and other terms in accordance with the provisions of the omnibus agreement and any rights ABKN has under the related time charter. We may exercise this option at one or more times during such 24-month period.

In addition, pursuant to the omnibus agreement, we have a right to purchase from Höegh LNG, any FSRU or LNG carrier operating under a charter of five years or more, in accordance with the provisions set forth in the omnibus agreement. In the fourth quarter of 2014, Höegh LNG secured charters of five or more years for two additional newbuilding FSRUs, the Höegh Gallant and the Höegh Grace and placed an order for an additional FSRU as follows:

On November 1, 2014, Höegh LNG signed a contract for a minimum term of five years with Sociedad Portuaria El Cayao S.A. E.S.P. (SPEC) to provide an FSRU (the Höegh Grace) to service a new LNG import terminal in Colombia. The contract is expected to commence in the middle of 2016.

On November 3, 2014, Höegh LNG signed a five-year contract with the government-owned EGAS of Egypt to provide the FSRU Höegh Gallant commencing in the first half of 2015.

In November 2014, Höegh LNG placed an order for an additional FSRU newbuilding (Hull no. 2552) to be constructed by HHI with an expected delivery in the first quarter of 2017. No charter has yet been agreed to with respect to this vessel.

We will have the right to purchase the Höegh Gallant, the Höegh Grace and, assuming a charter of five or more years is secured for Hull no. 2552, Hull no. 2552, from Höegh LNG upon acceptance of such vessels by their respective charterers pursuant to the terms of the omnibus agreement. However, there can be no assurance that we will acquire any vessels from Höegh LNG.

Our Charters

We and our joint ventures generate revenues by chartering the vessels in our initial fleet under long-term time charters. As of December 31, 2014, the average remaining term of the time charters for the vessels in our initial fleet was approximately 16.7 years, excluding the exercise of any options, and 24.9 years, assuming the exercise of all options.

Under our existing charters, the rate charged for the services of each vessel, which we call the “hire rate,” is paid monthly in advance or based on the terms of the charter. Under the time charters, hire payments may be reduced if the vessel does not perform to certain of her specifications, such as the amount of fuel consumed to power the vessel under normal circumstances exceeds a guaranteed amount.

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 GDF Suez Neptune and the GDF Suez 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.

Under the GDF Suez Neptune and GDF Suez Cape Ann time charters, a vessel generally will be deemed off-hire if she 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:

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.

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.

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 (as defined under “Item 4.B. Business Overview—Vessel Time Charters—Item 4.B. 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.”

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 three vessels in our initial fleet 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 select components of our statements of income in our consolidated and combined carve-out 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 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, 2014, 2013 and 2012, there was no income tax expense for our joint ventures. The equity in earnings 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 and combined carve-out 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 and combined carve-out financial statements.

Advances to Joint Ventures. Represents our share of the advances to our joint ventures (shareholder loans). Please read note 13 to our consolidated and combined carve-out financial statements.

Investment in (Accumulated Losses) of Joint Ventures. Represents 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 financial instrument liabilities on the combined balance sheets. As a result, the liabilities exceed 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. Please read note 16 to our audited historical consolidated and combined carve-out financial statements. The investment in (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 historical consolidated and combined carve-out balance sheet.

We derive cash flows from the operations of our joint ventures from interest and principal payments 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 principal and 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 quarterly payments include a payment of interest for the first month of the quarter and interest is accrued for the last two months of the quarter for repayment in the latter years of the loans The following provides a description of the impacts of our interests in our joint ventures on select components of our statement of cash flows in our consolidated and combined carve-out financial statements:

Cash Flows Provided by (Used in) Operating Activities. Receipt of cash payments for interest income on the shareholder loans is reflected in cash flows provided by (used in) operating activities. For the years ended December 31, 2014, 2013 and 2012, such payments amounted to $0.6 million, $0.7 million and $0.9 million, respectively. All other cash flows used in investing activities relate to our other activities.

Cash Flows Used in Investing Activities. Receipts from repayment of principal of advances to joint ventures represent principal repayments paid by our joint ventures to us on its shareholder loans. For the years ended December 31, 2014, 2013 and 2012, such payments amounted to $6.7 million, $5.5 million and $6.0 million, respectively. All other cash flows used in investing activities relate to our other activities.

Please read our consolidated and combined carve-out financial statements and the combined financial statements of our joint ventures included elsewhere in this Annual Report for more detailed information.

Historical Employment of Our Fleet

The following table describes the operations of the vessels in our fleet.

Vessel		Description of Historical Operations
GDF Suez Neptune		Delivered in November 2009. Has operated under a long-term time charter with GDF Suez, which commenced on delivery.
GDF Suez Cape Ann		Delivered in June 2010. Has operated under a long-term time charter with GDF Suez, which commenced on delivery.
PGN FSRU Lampung		Delivered in April 2014. Has operated under a long-term time charter with PGN, which commenced on July 21, 2014.

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 continues to change. Our historical results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries. For example, the PGN FSRU Lampung was delivered from the shipyard in April 2014 and commenced operations in July 2014 and, as such, has had limited historical operations. In addition, pursuant to the omnibus agreement, we will have the right to purchase from Höegh LNG any FSRU or LNG carrier operating under a charter of five or more years, and we will have the right to purchase from Höegh LNG all or a portion of its interests in the Independence, if her purchase price is agreed upon in accordance with the provisions of the omnibus agreement. Furthermore, we may grow through the acquisition in the future of additional vessels as part of our growth strategy.

We no longer own the Mooring and will not have construction contract revenue and expenses. Our historical results of operations include revenues and expenses related to the construction of the Mooring, an offshore installation that is used to moor the PGN FSRU Lampung. The construction of the Mooring was 100% complete in the fourth quarter of 2014 and the Mooring was transferred to the charterer. We do not expect to engage in the construction of moorings in the next few years. Höegh LNG may deliver mooring solutions prior to us acquiring FSRUs under the omnibus agreement. However, when time charters expire on existing vessels or if we acquire vessels from third parties, we may offer construction of moorings to new charterers.

Upon completion of the IPO, we have increased interest income. At the closing of the IPO, we lent $140 million to Höegh LNG in exchange for a note bearing interest at a rate of 5.88% per annum, which is repayable on demand or which we can elect to utilize as part of the purchase consideration in the event we purchase all or a portion of Höegh LNG’s interests in the Independence or another FSRU or LNG carrier operating under a charter of five or more years. Interest income attributable to the note is included in our consolidated and combined carve-out financial statements subsequent to the IPO and will continue until the demand note is utilized or repaid.

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 interest rate swap contracts that impact our equity in earnings for our joint ventures and were entered into by our joint ventures. On March 17, 2014, we entered into interest rate swap contracts related to the Lampung facility (as defined below). The interest rate swaps are designated as cash flow hedges for accounting purposes, however, certain amortization and the ineffective portion of the hedge impacts the results of operations. Refer to note 18 of our consolidated and combined carve-out financial statements. We may enter into additional (i) 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 reflect allocated administrative costs that may not be indicative of future administrative costs. The administrative costs included in our historical results of operations prior to the IPO have been determined by allocating certain of Höegh LNG’s administrative costs, after deducting costs directly charged to Höegh LNG’s subsidiaries for services provided by the administrative staff, to us principally based on the size of our fleet (including newbuildings) in relation to the size of Höegh LNG’s fleet (including newbuildings). These allocated costs may not be indicative of our future administrative costs. In connection with the IPO, we and our operating company have entered into an administrative services agreement with Höegh UK and our operating company has entered into an administrative services agreement with Leif Höegh UK, pursuant to which Höegh UK and Leif Höegh UK provide us and our operating company with certain administrative services. Höegh UK also subcontracts certain of the administrative services provided under its administrative services agreement to Höegh Norway and Leif Höegh UK. Subsequent to the IPO, we reimburse Höegh UK and Leif Höegh UK, and Höegh UK reimburses Höegh Norway and Leif Höegh UK, for the reasonable costs and expenses incurred in connection with the provision of the services under such administrative services agreements. In addition, Höegh UK pays to Höegh Norway (and, with respect to certain services, Leif Höegh UK) a service fee in U.S. Dollars equal to 5.0% of the costs and expenses incurred in connection with providing services.

We will incur additional general and administrative expense as a publicly traded limited partnership. Subsequent to our IPO in August 2014, we began to incur costs of being a publicly traded partnership as part of our general and administrative expenses. These costs include costs for implementing internal controls, preparing SEC filings including associated auditor and legal fees, holding the unitholder meetings, travelling for investor relations meetings, registrar and transfer agent fees, and incremental director and officer liability insurance costs and directors’ compensation.

Our results of operations are affected by accounting for the PGN FSRU Lampung time charter as a direct financing lease. When the PGN FSRU Lampung began operating under her charter, we recorded a receivable (net investment in direct 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 the vessel is reclassified to the net investment in direct financing lease on the balance sheet, there is no charge for depreciation expense.

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;

our ability to acquire additional vessels, including the Independence;

the levels of demand for FSRU, LNG carrier services and other LNG infrastructure;

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 and foreign currency swap contracts;

foreign currency exchange gains and losses;

our access to capital required to acquire additional vessels and/or to implement our business strategy;

increases in crewing and insurance costs;

the level of debt and the related interest expense; and

the level of any distribution on our common units.

Please read “Item 3.D. Risk Factors” for a discussion of certain risks inherent in our business.

Important Financial and Operational Terms and Concepts

We use a variety of financial and operational terms and concepts when analyzing our and our joint ventures’ performance. These include the following:

Time Charter Revenues. Revenues include fees for the right to use FSRUs for a stated period of time that meet the criteria for lease accounting, in addition to providing a time charter service element. Time charter revenues consist of charter hire payments under time charters, fees for providing time charter services, fees for reimbursement for actual vessel operating expenses, certain tax elements and drydocking costs borne by the charterer on a pass-through basis, as well as fees for the reimbursement of certain vessel modifications or other costs borne by the charterer. The lease element of time charters that are accounted for as operating leases and any upfront payments for amounts reimbursed by the charterer are recognized on a straight-line basis over the term of the charter. The lease element of time charters that are accounted for as direct financing leases is recognized over the charter term using the effective interest rate method and is included in time charter revenues. The PGN FSRU Lampung time charter is accounted for as a financial lease. Under a direct financing lease, we record a receivable (called a net investment in direct financing lease) and remove the related FSRU from our balance sheet. The lease element of time charter payments is split between revenues and the repayment of part of the receivable. The revenues are recorded so there is a constant rate of return on the net investment. As a result, the revenue shows a declining profile over time as more of the time charter payments are treated as a repayment of the receivable. However, the cash flows from time charters are not impacted by the accounting treatment. In addition, since the FSRU is removed from the balance sheet, there is no charge for depreciation expense. Revenues for the lease element of time charters are not recognized for days the FSRUs are off-hire.

Fees for providing time charter services and reimbursements for actual vessel operating expenses or other costs are recognized as revenues as services are performed or the actual costs are incurred. Revenues for the time charter services element are not recognized for days that the FSRUs are off-hire.

Upfront payments of fees for reimbursement of drydocking costs are recognized on a straight-line basis over the period to the next drydocking.

Under time charters, revenue is not recognized during days a vessel is off-hire. Under time charters, we are responsible for providing the crewing and other services related to the vessel’s operations, the cost of which is included in the daily hire rate, except when off-hire. Revenues are affected by hire rates and the number of days a vessel operates.

Voyage Expenses. Under our time charters, the charterer typically pays the voyage expenses. We, as vessel owner, are responsible for any voyage expenses incurred during periods of off-hire under the time charter.

Vessel Operating Expenses. Vessel operating expenses include crewing, repairs and maintenance, insurance, stores, lube oil, communication expenses and management fees. Vessel operating expenses are paid by the vessel owner under time charters and are recognized when incurred.

Off-hire. Under our time charters, when the vessel is off-hire, or not available for service, the customer generally is not required to pay the hire rate, and the vessel owner is responsible for all costs. Prolonged off-hire may lead to a termination of the time charter. A vessel generally will be deemed off-hire if there is a loss of time due to, among other things, operational deficiencies; unscheduled drydocking for repairs, maintenance or inspection that exceeds a specified period; equipment breakdowns; delays due to accidents, crewing strikes, certain vessel detentions or similar problems; or the vessel owner’s failure to maintain the vessel in compliance with her specifications and contractual standards or to provide the required crew. 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. 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.

Drydocking. We must periodically have surveys, class renewals and drydocks of our vessels for inspection, repairs and maintenance and any modifications required to comply with industry certification or governmental requirements. For each of the GDF Suez Neptune and the GDF Suez Cape Ann after the modifications and first drydock completed in 2012 and 2015, respectively, the vessels are on an approved extended drydock interval. However, the class survey intervals are unchanged. The intermediate survey is carried out after 2.5 years and then every 5 years thereafter. A class renewal survey is conducted every five years. During the first 15 years of operation, the vessels have an approved extended drydock interval which allows them to be drydocked every 7.5 years. After the vessel reaches 15 years old, it must be drydocked every 5 years. Subject to the charterers’ requirements for Condition Assessment Programme (CAP), the drydocking schedule may be changed to every immediate and class renewals, which would require drydocking every 2.5 years. GDF Suez has subchartered the GDF Suez Cape Ann, which resulted in some modifications to the vessel. As a result, certain drydocking procedures were completed at the same time and in advance of the normally scheduled drydocking. As a result, the next scheduled drydocking for the GDF Suez Cape Ann is in 2017. The GDF Suez Neptune started modification and drydocking procedures in March 2015 which were completed in April 2015. The GDF Suez Neptune remained on hire during the drydocking. As a result, the next drydocking for the GDF Suez Neptune is expected to be in 2022. We do not anticipate drydocking the PGN FSRU Lampung for at least 20 years as certain inspections can be done without drydocking. Each of our time charters requires 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. For vessels operating on time charters, we capitalize the costs directly associated with the classification and regulatory requirements for inspection of the vessels or improving the vessel’s operating efficiency, functionality or safety during drydocking. We expense costs related to routine repairs and maintenance performed during drydocking or as otherwise incurred. The number of drydockings undertaken in a given period and the nature of the work performed determine the level of drydocking expenditures.

Depreciation and Amortization. Depreciation on vessels and equipment is calculated on a straight-line basis over an estimated useful life of 35 years. Drydocking cost is amortized on a straight-line basis over the period until the next planned drydocking takes place. For vessels that are newly built or acquired, an element of the cost of the vessel is allocated initially to a drydock component and amortized on a straight-line basis over the period until the next planned drydocking. The estimated economic life for our newbuilding FSRUs is 40 years.

Impairment of Long-Lived Asset. Vessels, equipment and newbuildings subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group to be tested for possible impairment, we first compare the undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, an impairment charge is recognized to the extent that the carrying value exceeds its fair value.

Interest Income and Interest Expense. Interest income principally includes interest income on advances to our joint ventures and demand note from Höegh LNG. Interest expense (including amortization of debt issuance cost) principally relate to financing of the PGN FSRU Lampung and, prior to July 3, 2014, the construction contract expense for the Mooring.

Customers

For the years ended December 31, 2014, 2013 and 2012, total revenues in the consolidated and combined carve-out statements of income are from PGN, a subsidiary of PT Perusahaan Gas Negara (Persero) Tbk, an Indonesian publicly listed, government-controlled, gas and energy company that constructs gas pipelines and infrastructure and distributes and transmits natural gas to industrial, commercial and household users. With the commencement of the PGN FSRU Lampung time charter in July 2014, we also have time charter revenue from PGN. Revenues included as a component of equity in earnings of joint ventures are from GDF Suez and accounted for 100% of our joint ventures’ time charter revenues. GDF Suez is a subsidiary of GDF Suez S.A., a French publicly listed, government-backed, electric utility company.

Inflation and Cost Increases

Inflation has not had a significant impact on operating expenses, including crewing costs, for the GDF Suez Neptune and the GDF Suez Cape Ann. FSRUs are specialized vessels, and there has been demand for experienced crew, which has led to higher crew costs. The GDF Suez Neptune and the GDF Suez 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 and certain supplies. Indonesian inflation has ranged from approximately 3.5% to over 8.0% 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 annum 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 mitigate to some extent cost increases.

Insurance

Hull and Machinery Insurance. We have obtained hull and machinery insurance on all our vessels against marine and war 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.

Loss of Hire Insurance. 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. Protection and indemnity insurance, which covers our third-party legal liabilities in connection with our shipping or floating regasification activities, is provided by a mutual protection and indemnity association (a “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.

Our current protection and indemnity insurance coverage for pollution is limited to $3.07 billion for all liabilities, except for pollution, which is limited to $1 billion per vessel per incident. We are a member of the Gard P&I Club, which is one of the 13 P&I clubs that comprise the International Group of Protection and Indemnity Clubs (the “International Group”). Members of the International Group 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. P&I clubs provide the basic layer of insurance, which is currently $9 million. For members of the International Group, the International Group provides the next layer of insurance, covering liability between $9 million and $30 million. For liabilities above $30 million, the International Group 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 clubs’ 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, loss of hire and protection and indemnity have confirmed that they will consider the FSRUs as vessels for the purpose of providing insurance.

Environmental indemnifications. Under the omnibus agreement, Höegh LNG will 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. Liabilities resulting from a change in law are excluded from the environmental indemnity. There is an aggregate cap of $5.0 million on the amount of indemnity coverage provided by Höegh LNG for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Höegh LNG is liable for claims only to the extent such aggregate amount exceeds $500,000.

Other indemnifications. Under the omnibus agreement, Höegh LNG will also 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 arise 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 (refer to note 20 of our consolidated and combined carve-out financial statements);

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. The Partnership filed a claim for indemnification with respect to non-budgeted expenses (including repair costs) of $3.1 million and warranty provision of $2.0 million during the first quarter of 2015 (refer to note 20 of our consolidated and combined carve-out financial statements); 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 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. The Partnership filed a claim for indemnification with respect to non-budgeted value added tax and withholding tax related to the restatement periods up to and including December 31, 2014 of approximately $1.2 million in the fourth quarter of 2015. The indemnification payment was received from Höegh LNG in the fourth quarter of 2015 and recorded as a contribution to equity. Refer to note 2.d. of our consolidated and combined carve-out financial statements for additional information on the restatement adjustments related to value added tax and withholding tax.

Please refer to “A. Operating Results—Year Ended December 31, 2014 Compared with the Year ended December 31, 2013—PGN Claims including Delay Liquidated Damages and Indemnifications” for additional discussion.

A. Operating Results (Restated)

The following table summarizes our operating results for the years ended December 31, 2014, 2013 and 2012:

	Year Ended December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)			(Restated)
Statement of Income Data:
Time charter revenues	$	22,227		$	—		$	—
Construction contract revenues		51,868			51,062			5,512
Other revenue		474			511			—
Total revenues		74,569			51,573			5,512
Voyage expenses		(1,139	)		—			—
Vessel operating expenses		(6,197	)		—			—
Construction contract expenses		(38,570	)		(43,958	)		(5,512	)
Administrative expenses		(12,566	)		(8,043	)		(3,185	)
Depreciation and amortization		(1,317	)		(8	)		—
Total operating expenses		(59,789	)		(52,009	)		(8,697	)
Equity in earnings of joint ventures		(5,330	)		40,228			5,007
Operating income		9,450			39,792			1,822
Interest income		4,959			2,122			2,481
Interest expense		(9,665	)		(352	)		(114	)
Loss on derivative financial instrument		(161	)		—			—
Other items, net		(2,788	)		(1,096	)		(1	)
Income before tax		1,795			40,466			4,188
Income tax expense		(481	)		—			—
Net income	$	1,314			40,466		$	4,188

Significant Developments in 2014

The following sets forth highlights of our operations for the year ended December 31, 2014:

Total revenues were $74.6 million, including $22.2 million of time charter revenues, for the year ended December 31, 2014, compared to $51.6 million for the year ended December 31, 2013;

Operating income was $9.5 million for the year ended December 31, 2014, compared to $39.8 million for the year ended December 31, 2013; operating income was impacted by unrealized losses on derivative instruments on the Partnership’s share of equity in earnings of joint ventures for the year ended December 31, 2014 compared with gains for the year ended December 31, 2013;

Unrealized losses on derivative instruments were $11.9 million on the Partnership’s share of equity in earnings of joint ventures for the year ended December 31, 2014, compared with gains of $35.0 million for the year ended December 31, 2013;

Net income was $1.3 million for the year ended December 31, 2014, compared to $40.5 million for the year ended December 31, 2013; net income was also impacted by changes in the unrealized gains (losses) on derivative instruments on the Partnership’s share of equity in earnings of joint ventures between 2013 and 2014;

Acceptance by PGN was achieved on the PGN FSRU Lampung effective October 30, 2014 after commissioning delays:

Indemnity claims were made to Höegh LNG pursuant to the omnibus agreement for time charter payments for September and October 2014 invoices, warranty provisions for repairs and non-budgeted expenses.

Subsequent to the year ended December 31, 2014, an understanding was reached with PGN under which no delay liquidated damages will be payable. Due to this subsequent event, no delay liquidated damages are reflected in the construction contract expenses for the year ended December 31, 2014.

100% utilization was achieved on the PGN FSRU Lampung after the acceptance date and time charter payments received for November and December, 2014;

Received full payment from the charterer relating to the Mooring during the year ended December 31, 2014;

Made an early repayment of $7.9 million of long-term debt and fully funded the restricted cash balance of $15.2 million required under the Lampung facility;

100% utilization on joint venture vessels, the GDF Suez Neptune and the GDF Suez Cape Ann was achieved in 2013 and 2014

IPO closed on August 12, 2014, raising net proceeds of $203.5 million;

On September 24, 2014, we held our first annual meeting of unitholders at which four members of our board of directors were elected;

On November 14, 2014, we paid a pro rata $0.1834/unit distribution for the period from August 12, 2014 to September 30, 2014, equivalent to $0.3375 per unit per quarter and $1.35 per unit on an annualized basis; and

On February 13, 2015, we paid a $0.3375 per unit distribution with respect to the fourth quarter of 2014, equivalent to $1.35 per unit on an annualized basis.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013

Time Charter Revenues. The following table sets forth details of our time charter revenues for the years ended December 31, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
	(Restated)
Time charter revenues	$	22,227	$	—	$	22,227

Time charter revenues for year ended December 31, 2014 were $ 22.2 million, an increase of $22.2 million from the year ended December 31, 2013. The time charter hire payments for PGN FSRU Lampung began July 21, 2014 when the project was ready to begin commissioning. However, there were some technical problems with the regasification system of this vessel in September and October 2014. We have been indemnified for the amount payable for the September and October invoices by Höegh LNG. For additional discussion, refer to “—PGN Claims including Delay Liquidated Damages and Indemnifications” below and notes 2 d. and 20 of our consolidated and combined carve-out financial statements.

Time charter revenues consisted of the lease element of the time charter, accounted for as a direct financing lease using the effective interest rate method, as well as fees for providing time charter services, reimbursement for vessel operating expenses and value added and withholding taxes borne by the charterer.

Construction Contract Revenues and Related Expenses. The following table sets forth details of our construction contract revenues and construction contract expenses for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
	(Restated)			(Restated)
Construction contract revenues	$	51,868		$	51,062		$	806
Construction contract expenses	$	(38,570	)	$	(43,958	)	$	5,388
Recognized contract margin	$	13,298		$	7,104		$	6,194

Construction contract revenues for the year ended December 31, 2014 were $51.9 million, an increase of $0.8 million from $51.1 million for the year ended December 31, 2013. Construction contract expenses for the year ended December 31, 2014 were $38.6 million, a decrease of $5.4 million from $44.0 million for the year ended December 31, 2013. The recognized contract margin for the year ended December 31, 2014 was $13.3 million, an increase of $6.2 million from $7.1 million for the year ended December 31, 2013.

The Mooring is an offshore installation that is being used to moor the PGN FSRU Lampung to offload the gas into an offshore pipe that transports the gas to a land terminal for the charterer. The Mooring has been constructed in China, installed in Indonesia and was sold to the charterer. Revenue was recognized on the Mooring based upon the percentage of completion method under which construction contract revenue is recognized using the ratio of costs incurred to estimated total costs multiplied by the total estimated contract revenue to determine revenue. The increase in construction contract revenue is primarily due to progress towards completion of the project for the Mooring, which was 100% as of December 31, 2014, compared with 52% as of December 31, 2013. PGN formally accepted the PGN Lampung project effective October 30, 2014. During the second quarter of 2014, the initial 90% payment for the Mooring was received. During the fourth quarter of 2014, the final 10% payment for the Mooring was invoiced and received from PGN.

PGN issued invoices for delay liquidated damages of $7.1 million related to claims from PGN on the project for the year end December 31, 2014. Subsequent to the year ended December 31, 2014, an understanding with PGN has been reached under which no delay liquidated damages will be payable. Due to this subsequent event, no delay liquated damages are reflected in the construction contract expenses for the year ended December 31, 2014. Refer to “—PGN Claims including Delay Liquidated Damages and Indemnifications” below and notes 20 and 23 of the consolidated and combined carve-out financial statements.

A warranty provision of $2.0 million has been recorded for the year ended December 31, 2014 as part of the construction contract expenses. In ramping up operations, a technical issue was identified associated with the Mooring that requires attention. The technical issue requires replacement of equipment and repairs under our warranties for the functionality of the Mooring to PGN. The warranty provision represents our best estimate of cost to obtain replacement parts and install them. Under the omnibus agreement, all costs incurred for repairs under the warranty will be indemnified by Höegh LNG. For additional discussion, refer to “—PGN Claims including Delay Liquidated Damages and Indemnifications” below and note 20 of our consolidated and combined carve-out financial statements.

Other Revenue. The following table sets forth details of our other revenue for the years ended December 31, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
	(Restated)
Other revenue	$	474	$	511	$	(37	)

Other revenue for the year ended December 31, 2014 was $0.5 million, compared with $0.5 million from the year ended December 31, 2014. Other revenue includes incidental revenues prior to the start of the time charter for the PGN FSRU Lampung.

Voyage and Vessel Operating Expenses. The following table sets forth details of our voyage and vessel operating expenses for the years ended December 31, 2014 and 2013:

						Positive
	Year ended December 31,					(negative)
(in thousands of U.S. dollars)	2014			2013		variance
	(Restated)
Voyage expenses	$	(1,139	)	$	—	$	(1,139	)
Vessel operating expenses	$	(6,197	)	$	—	$	(6,197	)

Voyage expenses for the year ended December 31, 2014 were $1.1 million, an increase of $1.1 million from year ended December 31, 2013. Voyage expenses are typically paid directly by the charterer. Certain bunker fuel and use of LNG during the commissioning and testing of PGN FSRU Lampung were borne by us. In addition, LNG quantities used in running our generators during the period where we had problems with the regasification system were for our own account. As a result, the voyage expenses are not expected to be recurring costs. However, if the vessel is off-hire, voyage expenses, principally fuel, may also be incurred and would be paid by us.

Vessel operating expenses for year ended December 31, 2014 were $6.2 million, an increase of $6.2 million from the year ended December 31, 2014. This reflects operating cost from the start of the time charter as well as crew training costs and certain expenses of the start-up of the time charter hire period beginning July 21, 2014.

Administrative Expenses. The following table sets forth details of our administrative expenses for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
	(Restated)
Administrative expenses	$	(12,566	)	$	(8,043	)	$	(4,523	)

Administrative expenses for the year ended December 31, 2014 were $12.6 million, an increase of $4.5 million from $8.1 million for the year ended December 31, 2013. The major reasons for the increase were expenses incurred in preparation for the IPO, higher public company cost and higher activity related to the PGN FSRU Lampung.

Administrative expenses related to the corporate costs of the Partnership were $6.2 million for the year ended December 31, 2014, an increase of $2.7 million from $3.5 million for the year ended December 31, 2013. Expenses of $3.5 million were incurred principally related to audit fees, legal fees and other charges of ours incurred by Höegh LNG’s staff working on preparation for the IPO, an increase of $1.1 million from $2.4 million for the year ended December 31, 2013. Approximately $0.2 million relates to fees in establishing the new legal structure in conjunction with the IPO during 2014. The remaining increase in administrative expense of approximately $1.4 million relates to higher costs of being a public company and includes charges for preparation of external reporting, legal fees, audit fees, travel costs and consulting fees on implementation of internal controls under Sarbanes-Oxley.

Administrative expenses related to the PGN FSRU Lampung for the year ended December 31, 2014 were $6.4 million, an increase of $1.9 million from $4.5 million for the year ended December 31, 2013. The higher costs reflect greater required resources and other expenses in the ramp up phase of operations.

Depreciation and Amortization. The following table sets forth details of our depreciation and amortization for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2,013			variance
Depreciation and amortization	$	(1,317	)	$	(8	)	$	(1,309	)

Depreciation and amortization for the year ended December 31, 2014 related to the PGN FSRU Lampung and for office and IT equipment. In the middle of May 2014, the PGN FSRU Lampung was deemed substantially complete to begin the commissioning under the time charter. The newbuilding was transferred on the balance sheet to vessels until such time as the time charter commenced when the vessel was transferred on the balance sheet to net investment in direct financing lease. However, due to delays unconnected to us and minor damage to the FSRU by a tugboat during the pipeline installation, the time charter hire did not commence until July 21, 2014. As a result, the vessel was depreciated until the start of the direct financing lease. The depreciation expense for the PGN FSRU Lampung for the year ended December 31, 2014 was $1.3 million. The remaining depreciation of $0.02 million relates to office and IT equipment, an increase of $0.01 million for the year ended December 31, 2013.

Total Operating Expenses. The following table sets forth details of our total operating expenses for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2,013			variance
	(Restated)			(Restated)
Total operating expenses	$	(59,789	)	$	(52,009	)	$	(7,780	)

Total operating expenses for the year ended December 31, 2014 were $59.8 million, an increase of $7.8 million from $52.0 million for the year ended December 31, 2013. Excluding construction contract expenses, the total operating expenses were $21.2 million, an increase of $13.1 million from $8.1 million for the year ended December 31, 2013. The increase was due to higher voyage expenses and vessel operating expenses totaling $7.4 million due to the start of operations of the PGN FSRU Lampung, an increase of $4.5 million in administrative expenses reflecting the ramp up of the PGN FSRU Lampung, costs incurred to complete the IPO and higher public company costs and higher depreciation due to the delay in the commissioning of PGN FSRU Lampung.

Equity in Earnings (Losses) of Joint Ventures. The following table sets forth details of our equity in earnings of joint ventures for the years ended December 30, 2014 and 2013:

						Positive
	Year ended December 31,					(negative)
(in thousands of U.S. dollars)	2014			2,013		variance
Equity in (losses) earnings of joint ventures	$	(5,330	)	$	40,228	$	(45,558	)

Equity in losses of joint ventures for the year ended December 31, 2014 was $5.3 million, a decrease of $45.5 million from equity in earnings of $40.2 million for the year ended December 31, 2013. The reason for the decrease was an unrealized loss on derivative financial instruments in our joint ventures in the year ended December 31, 2014, compared with an unrealized gain in the year ended December 30, 2013.

Our share of our joint ventures’ operating income was $23.7 million for the year ended December 31, 2014, compared with $23.3 million for the year ended December 31, 2013. Our share of other income (expense), net, principally consisting of interest expense, was $17.1 million for the year ended December 31, 2014, a reduction of $1.0 million from $18.1 million for the year ended December 31, 2013. The reduction was mainly due to lower interest expense due to repayment of principal on debt between the years.

Our share of unrealized loss on derivative financial instruments was $11.9 million for the year ended December 31, 2014, a decrease of $46.9 million compared to unrealized gain on derivative financial instruments of $35.0 million for the year ended December 31, 2013. The variance in the unrealized gains and losses on derivative financial instruments is the reason for the decline in our equity in earnings of joint ventures for the year ended December 31, 2014 compared to the year ended December 31, 2013. The joint ventures utilize interest rate swap contracts to exchange a receipt of floating interest for a payment of fixed interest 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. Historically, the joint ventures have accumulated unrealized losses on the interest rate swaps due to declining interest rates, which has resulted in liabilities for derivative financial instruments and an accumulated deficit in equity on their balance sheets.

There was no accrued income tax expense for the years ended December 31, 2014 and 2013. Our joint ventures did not pay any dividends for the year ended December 31, 2014 and 2013.

Operating Income. The following table sets forth details of our operating income for the years ended December 31, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
	(Restated)		(Restated)
Operating income	$	9,450	$	39,792	$	(30,342	)

Operating income for the year ended December 31, 2014 was $9.5 million, a decrease of $30.3 million from the operating income of $39.8 million for the year ended December 31, 2013. The decrease in operating income was impacted by the decrease in the equity in earnings (losses) of joint ventures of $45.6 million as a result of the unrealized loss on derivatives for the year ended December 31, 2014 compared with an unrealized gain for the year ended December 31, 2013. This decrease was partially offset by the increase in recognized contract margin on the Mooring of $6.2 million, higher time charter revenues of $22.2 million due to the start-up of the PGN FSRU Lampung less the higher operating expenses of $13.1 million.

Interest Income. The following table sets forth details of our interest income for the years ended December 31, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
Interest income	$	4,959	$	2,122	$	2,837

Interest income for the year ended December 31, 2014 was $5.0 million, an increase of $2.8 million from $2.2 million for the year ended December 31, 2013. Interest income of $3.3 million related to the demand note due from Höegh LNG and $1.7 million related to interest accrued on the advances to our joint ventures for the year ended December 31, 2014. For the year ended December 31, 2013, the entire balance related to interest accrued on the advances to our joint ventures. The decrease in interest income from joint ventures is due to repayment by our joint ventures of a portion of the principal due under the shareholder loans between the periods. The interest rate under the shareholder loans is a fixed rate of 8.0% per year. We lent $140 million to Höegh LNG from net proceeds of the IPO pursuant to a demand note. The note is repayable on demand or we can elect to utilize the note as part of the purchase consideration in the event all or a portion of Höegh LNG’s interests in the FSRU, Independence, are purchased by the Partnership. The note bears interest at a rate of 5.88% per annum.

100

Interest Expense. The following table sets forth details of our interest expense for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
	(Restated)
Interest expense	$	(9,163	)	$	(6,110	)	$	(3,053	)
Commitment fees		(1,587	)		(2,162	)		575
Amortization of debt issuance cost		(4,362	)		(379	)		(3,983	)
Capitalized interest		5,447			8,299			(2,852	)
Total interest expense	$	(9,665	)	$	(352	)	$	(9,313	)

Interest expense for the year ended December 31, 2014 was $9.7 million, an increase of $9.3 million from $0.4 million for the year ended December 31, 2013. Interest expense consists of the interest incurred, commitment fees and amortization of debt issuance cost less the interest capitalized for the period.

The interest incurred of $9.2 million for the year ended December 31, 2014 increased by $3.1 million compared to $6.1 million for the year ended December 31, 2013, principally due to higher outstanding loan balances. During 2013, loans and promissory notes due to owners and affiliates financed the construction of the PGN FSRU Lampung and the construction contract expenses of the Mooring. On March 4, 2014 and April 8, 2014, we drew $96 million and $161.1 million, respectively, on the Lampung facility. Following the drawdown of the external debt, $48.5 million was repaid on a promissory note to owners and affiliates. In July 3, 2014, the full principal amount of $32.1 million on the Mooring tranche and accrued interest was repaid. As of December 29, 2014, an early repayment of $7.9 million on the other tranches of the Lampung facility occurred and the regularly scheduled quarterly repayment began.

Commitment fees of $1.6 million and $2.2 million for the years ended December 31, 2014 and 2013, respectively, were incurred on principally on the Lampung facility for undrawn balances. Although $12.1 million of the Lampung facility was not drawn, the last date for drawdowns expired in 2014. There will not be further commitment fees on the Lampung facility except fees related to the letter of credit facility which expired February 16, 2015.

For the years ended December 31, 2014 and 2013, the amortization of debt issuance cost was $4.4 million and $0.4 million, respectively. The increase of $4.0 million related to the start of amortization on the Lampung facility. The deferred debt issuance cost associated with the Mooring tranche of the Lampung facility was fully amortized by the repayment date of July 3, 2014 resulting in a $1.7 million amortization charge for the year ended December 31, 2014. In addition, there was an early repayment of $7.9 million on the facility which resulted in a write down of debt issuance cost of approximately $0.5 million.

Capitalized interest for the year ended December 31, 2014 was $5.4 million, a decrease of $2.9 million from $8.3 million the year ended December 31, 2013. For the year ended December 31, 2013, the PGN FSRU Lampung and the Mooring were under construction for the entire period and most interest incurred qualified for capitalization. Capitalization of interest ceased in the middle of May, 2014 when the PGN FSRU Lampung and the Mooring were substantially complete.

Gain (Loss) on Derivative Financial Instruments. The following table sets forth details of our gain/loss on derivative financial instruments for the years ended December 31, 2014 and 2013:

						Positive
	Year ended December 31,					(negative)
(in thousands of U.S. dollars)	2014			2,013		variance
Loss on derivative financial instruments	$	(161	)	$	—	$	(161	)

101

Loss on derivative financial instruments for the year ended December 31, 2014 was $0.2 million, an increase of $0.2 million the year ended December 31, 2014. This loss was primarily due to the ineffective portion of the hedge of the interest rate swaps and amortization of the amount excluded from hedge effectiveness related to the Lampung facility. The interest rate swaps are designated as cash flow hedges of the variable interest payments on the Lampung facility and the effective portion of the changes in fair value of the hedges are recorded in other comprehensive income.

Other Items, Net. The following table sets forth details of our other items for the years ended December 31, 2014 and 2013:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
	(Restated)			(Restated)
Other items, net	$	(2,788	)	$	(1,096	)	$	(1,692	)

Other items, net for the year ended December 31, 2014 was $2.8 million, an increase of $1.7 million from $1.1 million for the year ended December 31, 2013. This is primarily due to withholding tax that is payable on interest expense to parties outside of Singapore and Indonesia. The reason for the increase in withholding taxes is primarily a result of the establishment of PT Hoegh and Hoegh Lampung as of October 1, 2013. Such withholding taxes were only payable on interest expense for three months in 2013.

Income (Loss) Before Tax. The following table sets forth details of our income before tax for the years ended December 30, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
	(Restated)		(Restated)
Income before tax	$	1,795	$	40,466	$	(38,671	)

Income before tax for the year ended December 31, 2014 was $1.8 million, a decrease of $38.7 million from $40.5 million for the year ended December 31, 2013. The decrease was largely due to the decrease in the equity in earnings (losses) of joint ventures of $45.5 million.

Income Tax Expense. The following table sets forth details of our income tax expense for the years ended December 31, 2014 and 2013:

						Positive
	Year ended December 31,					(negative)
(in thousands of U.S. dollars)	2014			2013		variance
	(Restated)
Income tax expense	$	(481	)	$	—	$	(481	)

Income tax expense for the year ended December 31, 2014 was $0.5 million, an increase of $0.5 million compared with the year ended December 31, 2013. We are not subject to Marshall Islands income taxes. However, we are subject to tax for earnings in Indonesia and Singapore starting in the fourth quarter of 2013 and the UK starting in the third quarter of 2014. For the year ended December 31, 2014, the income taxes expense primarily related to Hoegh Lampung, our Singapore subsidiary, mainly as a result of internal interest income. For the year ended December 31, 2014, PT Hoegh which is incorporated in Indonesia, incurred a tax loss. The tax loss carryforward of $1.3million expires in 2019.

A deferred tax benefit of $2.0 million, net of valuation allowance of $0.4 million, related to the unrealized losses on interest rate swaps accounted for as a cash flow hedge was recorded as a component of other comprehensive income in the consolidated and combined carve-out statements of comprehensive income for the year ended December 31, 2014.

102

A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that some or all of the benefit will not be realized. Given the lack of historical operations in Indonesia, management of the Partnership concluded a valuation allowance should be established to reduce the deferred tax assets on temporary differences and the tax loss carryforward for PT Hoegh to the amount deemed more-likely-than-not of realization. A component of the deferred tax asset relates to the cash flow hedge of the interest rate swap. Management concluded that approximately $2.0 million of the deferred tax asset was more-likely-than-not to be realized over the 11 year term of the swap and recognized a deferred tax asset for that amount. Deferred tax expenses for the change in the valuation allowance of $1.5 million and $0.4 million were recorded to income tax expense in the consolidated and combined statement of income and consolidated and combined statement of comprehensive income, respectively, for the year ended December 31, 2014.

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. In 2013, a tax loss was incurred in Indonesia principally due to unrealized losses on foreign exchange that does not impact the income statement prepared in the functional currency of U.S. dollars. In 2014, the Indonesia authorities have approved the change of currency for tax reporting to U.S. dollars. Under existing tax law, it is not clear if the prior year tax loss carryforward from foreign exchange losses can be utilized when the tax reporting currency is subsequently changed. Due to the uncertainty of this tax position, a provision was recognized for the year ended December 31, 2013 and the resulting unrecognized tax benefit was $2.6 million. There was no change in the unrecognized tax benefits as of December 31, 2014.

Pursuant to the terms of the PGN FSRU Lampung time charter, we will be reimbursed, as a component of time charter revenues, for current income taxes arising in Indonesia related to time charter activities.

Net Income. The following table sets forth details of our net income for the years ended December 31, 2014 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2014		2013		variance
	(Restated)		(Restated)
Net income	$	1,314	$	40,466	$	(39,152	)

As a result of the foregoing, net income for the year ended December 31, 2014 was $1.3 million, a decrease of $39.2 million compared with net income of $40.5 million the year ended December 31, 2013.

PGN Claims Including Delay Liquidated Damages and Indemnifications

Following certain delays unconnected to us and minor damage to the PGN FSRU Lampung by a tugboat during the pipeline installation, the time charter hire on the PGN FSRU Lampung commenced July 21, 2014 for the start of commissioning. During the commissioning to test the PGN FSRU Lampung project (including the Mooring) and the pipeline functionality, problems were identified on August 29, 2014 with the regasification system of the FSRU. This required that parts of the regasification system were disassembled and transferred to shore for repair under the provision of the warranties for the vessel. The equipment was reinstalled and all commissioning completed to allow us to deliver the Certificate of Acceptance to PGN. PGN formally accepted and signed the Certificate of Acceptance dated October 30, 2014.

Our subsidiary had commitments to pay a day rate for delay liquidated damages to PGN up to a maximum amount of $10.7 million if the PGN FSRU Lampung was not connected to the Mooring and ready to deliver LNG by the scheduled arrival date or acceptance was not achieved by the scheduled delivery date.

PGN had concerns about requirements under the time charter contract to pay hire rates for periods the regasification system was not functioning and issued invoices for $7.1 million for delay liquidated damages for amounts PGN believed it had claims due to delays in the scheduled arrival date and the acceptance date. PGN did not pay its time charter hire for September or October 2014. Delay liquidated damages cease on the date of the Certificate of Acceptance of October 30, 2014. We had included potential delay liquidated damages due to PGN in its project contingency as part of estimated total construction contract costs for the Mooring (as the first deliverable under the contract) as the basis for computing the percentage of completion.

103

We are indemnified under the omnibus agreement by Höegh LNG for delay liquidated damages. We filed indemnification claims for the delay liquidated damages invoiced from PGN for $7.1 million and recorded this amount to construction contract expenses for claims for the months of September and October 2014. The amounts were to be paid to us by Höegh LNG prior to any delay liquidated damages being paid to PGN.

We are also indemnified by Höegh LNG for any hire rate payments not received 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. We filed indemnification claims for the September and October 2014 invoices not paid by PGN of $6.5 million and $6.7 million, respectively, and received payments from Höegh LNG in September and October, respectively. Indemnification for hire rate payments is accounted for consistent with the accounting policies for loss of hire insurance, and is recognized when the proceeds are received. Therefore, we recognized the payments from Höegh LNG for September and October 2014 as revenue, including additional revenues recognized of $4.9 million due to the restatement adjustments. Refer to notes 2.d, 17 and 20 to the consolidated and combined carve-out financial statements.

Our subsidiary is jointly and severally liable for the delay liquidated damages of the pipeline contractor to the extent the pipeline contractor fails to perform. Similarly, the pipeline contractor is jointly and severally liable for our subsidiary’s delay liquidated damages. Our maximum exposure for the pipeline contractor’s delay liquidated damages is approximately $11.5 million. Further, our subsidiary and the pipeline contractor have an agreement to cover the other party’s delay liquidated damages to the extent caused by the other party’s scope of work. As of December 31, 2014, we had not received any claims from PGN or the pipeline contractor related to the contractor’s delay liquidated damages. We are indemnified by Höegh LNG for any potential delay liquidated damages, net of any recoveries, arising for or from claims of the pipeline contractor.

Subsequent to December 31, 2014, an understanding with PGN, the pipeline contractor and our subsidiary has been reached. As a result, PGN will not pay the time charter hire for September or October 2014, our subsidiary will not pay the delay liquidated damages, our subsidiary is released from joint and several liability for the pipeline contractor’s delay liquidated damages, the pipeline contractor is released from joint and several liability for our subsidiary’s delay liquidated damages and neither our subsidiary nor the pipeline contractor cover the other party’s delay liquidated damages to the extent caused by the other party’s scope of work. Due to this subsequent event, no delay liquidated damages are reflected in the construction contract expenses for the year ended December 31, 2014. Refer to notes 6 and 20 to the consolidated and combined carve-out financial statements. Because our subsidiary will not pay any delay liquidated damages to PGN, we will not receive any related indemnification from Höegh LNG.

Additionally, a warranty allowance of $2.0 million was recorded to construction contract expenses for replacement of equipment parts for the year ended December 31, 2014. The replacement parts are expected to be installed in 2015 and 2016. Accordingly, we filed indemnification claims for the warranty allowance of $2.0 million. The amount will be paid to us by Höegh LNG when costs are incurred for the warranty. When the funding for the indemnification is received from Höegh LNG, the amount will be recorded as a contribution to equity. Refer to notes 2 and 20 to the consolidated and combined carve-out financial statements.

We are indemnified by Höegh LNG for non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project prior to the date of acceptance. In the first quarter of 2015, we filed indemnification claims for non-budgeted expenses and costs of $3.1 million related to the year ended December 31, 2014. Höegh LNG paid us for this amount by March 31, 2015. The amount is recorded as a contribution to equity in the first quarter of 2015. For additional information, refer to notes 2 and 20 in our consolidated and combined carve-out financial statements.

We are also indemnified by Höegh LNG 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. The Partnership filed a claim for indemnification with respect to non-budgeted value added tax and withholding tax related to the restatement periods up to and including December 31, 2014 of approximately $1.2 million in the fourth quarter of 2015. The indemnification payment was received from Höegh LNG in the fourth quarter of 2015 and recorded as a contribution to equity. Refer to note 2.d. of our consolidated and combined carve-out financial statements for additional information on the restatement adjustments related to value added tax and withholding tax.

104

Segments

We have two segments, which are the “Majority held FSRUs” and the “Joint venture FSRUs.” In addition, unallocated corporate costs that are considered to benefit the entire organization and interest income from advances to our joint ventures and the demand note from Höegh LNG are included in “Other.”

For the year ended December 31, 2014, Majority held FSRUs included the direct financing lease related to the PGN FSRU Lampung and construction contract revenue and expenses of the Mooring. The Mooring was constructed on behalf of, and was sold to, PGN using the percentage of completion method of accounting. The Mooring project was completed as of December 31, 2014. For the year ended December 31, 2013, Majority held FSRUs includes a newbuilding, the PGN FSRU Lampung, and construction contract revenues and expenses of the Mooring under construction.

As of December 31, 2014 and 2013, Joint venture FSRUs include two 50% owned FSRUs, the GDF Suez Neptune and the GDF Suez Cape Ann, that operate under long term time charters with one charterer, GDF Suez.

We measure our segment profit based on Segment EBITDA. Segment EBITDA is reconciled to operating income and net income for each segment in the segment tables 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.

Majority Held FSRUs. The following table sets forth details of segment results for the Majority held FSRUs for the years ended December 31, 2014 and 2013:

	Years ended						Positive
Majority Held FSRUs	December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
	(Restated)			(Restated)
Time charter revenues	$	22,227		$	—		$	22,227
Construction contract revenues		51,868			51,062			806
Other revenues		474			511			(37	)
Total revenues		74,569			51,573			22,996
Voyage & vessel operating expenses		(7,336	)		—			(7,336	)
Construction contract expense		(38,570	)		(43,958	)		5,388
Administrative expenses		(6,353	)		(4,490	)		(1,863	)
Segment EBITDA		22,310			3,125			19,185
Depreciation and amortization		(1,317	)		(8	)		(1,309	)
Operating income (loss)		20,993			3,117			17,876
Financial income (expense), net		(12,113	)		(1,448	)		(10,665	)
Income (loss) before tax		8,880			1,669			7,211
Income tax expense		(505	)		—			(505	)
Net income (loss)	$	8,375		$	1,669		$	6,706

105

Total revenues for the year ended December 31, 2014 were $74.6 million, an increase of $23.0million from $51.6 million for the year ended December 31, 2013. The main reason for the increase was due to time charter revenues for PGN FSRU Lampung, which began July 21, 2014 when the project was ready to begin commissioning.

As discussed in more detail above, the construction contact revenues increased by $0.8 million for the year ended December 31, 2014 compared with the year ended December 31, 2013 and reflected the completion of the Mooring project. Construction contract expenses for the year ended December 31, 2014, which included $2.0 million for a warranty allowance, decreased by $5.4 million compared with the year ended December 31, 2013. The recognized project margin was for the year ended December 31, 2014 was $13.3 million compared with $7.1 million for the year ended December 31, 2013.

Voyage expenses and vessel operating expenses for the year ended December 31, 2014 were $7.3 million, an increase of $7.3 million from the year ended December 31, 2013. As discussed in more detail above, this reflects the start up of the time charter hire period beginning July 21, 2014 as well as certain bunker usage during the commissioning and testing of PGN FSRU Lampung.

Administrative expenses for the year ended December 31, 2014 were $6.4 million, an increase of $1.9 million from $4.5 million for the year ended December 31, 2013. The higher costs reflect greater required resources and other expenses in the ramp up phase of operations for the PGN FSRU Lampung.

Segment EBITDA for the year ended December 31, 2014 was $22.3 million, an increase of $19.2 million compared to $3.1 million for the year ended December 31, 2013. The increase was due mainly to the start of operations of PGN FSRU Lampung on July 21, 2014.

Joint Venture FSRUs the following table sets forth details of segment results for the Joint venture FSRUs for the years ended December 31, 2014 and 2013:

	Years ended						Positive
Joint Venture FSRUs	December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
Time charter revenues	$	41,319		$	41,110		$	209
Vessel operating expenses		(7,514	)		(7,702	)		188
Administrative expenses		(971	)		(1,061	)		90
Segment EBITDA		32,834			32,347			487
Depreciation and amortization		(9,148	)		(9,053	)		(95	)
Operating income		23,686			23,294			392
Gain (loss) on derivative instruments		(11,879	)		35,038			(46,917	)
Other income (expense), net		(17,137	)		(18,104	)		967
Net income (loss)	$	(5,330	)	$	40,228		$	(45,558	)

The segment results for the Joint venture FSRUs are presented using the proportional consolidation method (which differs from the equity method used in the consolidated and combined carve-out financial statements).

Total time charter revenues were $41.3 million and $41.1 million for the years ended December 31, 2014 and 2013, respectively. Revenues for time charter payments, including fees for reimbursement of operating expenses, were $40.1 million and $40.3 million for the years ended December 31, 2014 and 2013, respectively. The decrease in revenues for time charter payments in 2014 was due to the decrease in fees for reimbursement of vessel operating expenses. The remaining revenues principally related to the amortization of deferred revenues for upfront payments for modifications and drydocking payments from the charterer.

106

Vessel operating expenses for the year ended December 31, 2014 were $7.5 million, a decrease of $0.2 million compared to $7.7 million for the year ended December 31, 2013.

Administrative expenses for the year ended December 31, 2014 declined slightly compared with the year ended December 31, 2013.

Segment EBITDA was $32.8 million for the year ended December 31, 2014 compared with $32.3 million for the year ended December 31, 2013.

Other. The following table sets forth details of other results of Other for the years ended December 31, 2014 and 2013:

	Years ended						Positive
Other	December 31,						(negative)
(in thousands of U.S. dollars)	2014			2013			variance
		(Restated)
Administrative expenses	$	(6,213	)	$	(3,553	)	$	(2,660	)
Segment EBITDA		(6,213	)		(3,553	)		(2,660	)
Operating income (loss)		(6,213	)		(3,553	)		(2,660	)
Interest income		4,458			2,122			2,336
Income (loss) before tax		(1,755	)		(1,431	)		(324	)
Income tax expense		24			—			24
Net income (loss)	$	(1,731	)	$	(1,431	)	$	(300	)

Administrative expenses and Segment EBITDA for the year ended December 31, 2014 for each was $6.2 million, an increase of $2.6 million from $3.6 million for the year ended December 31, 2013. Expenses of $3.5 million were incurred principally related to audit fees, legal fees and other charges of ours incurred by Höegh LNG’s staff working on preparation for the IPO, an increase of $1.1 million from $2.4 million for the year ended December 31, 2013. Approximately $0.2 million relates to fees in establishing the new legal structure in conjunction with the IPO during 2014. The remaining negative variance of approximately $1.4 million relates to higher costs of being a public company and includes charges for preparation of external reporting, legal fees, audit fees, travel costs and consulting fees on implementation of internal controls under Sarbanes-Oxley.

Interest income, which is not part of the segment measure of profits, is related to the interest accrued on the advances to our joint ventures for the years ended December 31, 2014 and 2013 and interest income on the demand note due from Höegh LNG from the closing of the IPO on August 12, 2014.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012

Construction Contract Revenue and Related Expenses. The following table sets forth details of our construction contract revenues and construction contract expenses for the years ended December 31, 2013 and 2012:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
	(Restated)
Construction contract revenues	$	51,062		$	5,512		$	45,550
Construction contract expenses		(43,958	)		(5,512	)		(38,446	)
Recognized contract margin	$	7,104		$	—		$	7,104

Construction contract revenues for the year ended December 31, 2013 were $51.1 million, an increase of $45.6 million from $5.5 million for the year ended December 31, 2012. Construction contract expenses for the year ended December 31, 2013 were $43.9 million, an increase of 38.4 million from $5.5 million for the year ended December 31, 2012.

107

Revenue was recognized on the Mooring based upon the percentage of completion method under which construction contract revenue was recognized using the ratio of costs incurred to estimated total costs multiplied by the total estimated contract revenue to determine revenue. The increase in construction contract revenue was primarily due to progress towards completion of the project for the Mooring, which was estimated to be 52% as of December 31, 2013 compared with 6.0% for the year ended December 31, 2012. As of December 31, 2012, the initial stages of the contract had recently commenced and sufficient information was not available to estimate profit on the project with a reasonable level of certainty. Therefore, the amount of construction contract revenue recognized for the year ended December 31, 2012 was equal to the cost incurred, and no margin was recognized. As of December 31, 2013, a margin proportional to the percentage completion was recognized.

Other Revenue. The following table sets forth details of our other revenue for the years ended December 31, 2013 and 2012:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
Other revenue	$	511	$	—	$	511

Other revenue for the year ended December 31, 2013 was $0.5 million, an increase of $0.5 million from the year ended December 31, 2012. Other revenue includes incidental revenues prior to the start of the time charter for the PGN FSRU Lampung.

Administrative Expenses. The following table sets forth details of our administrative expenses for the years ended December 31, 2013 and 2012:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
Administrative expenses	$	(8,043	)	$	(3,185	)	$	(4,858	)

Administrative expenses for the year ended December 31, 2013 were $8.0 million, an increase of $4.8 million from $3.2 million for the year ended December 31, 2012. The major reasons for the increase were expenses incurred in preparation for the IPO and higher activity related to the PGN FSRU Lampung, the Mooring and preparation for the start of operations. Expenses of $2.4 million incurred for the IPO principally related to audit fees, legal fees and charges for hours incurred by Höegh LNG’s staff working on preparation for the IPO.

Depreciation and Amortization. The following table sets forth details of our depreciation and amortization for the years ended December 31, 2013 and 2012:

						Positive
	Year ended December 31,					(negative)
(in thousands of U.S. dollars)	2013			2012		variance
Depreciation and amortization	$	(8	)	$	—	$	(8	)

Depreciation and amortization for the year ended December 31, 2013 for office and IT equipment related to the start-up of operations. There were no corresponding charges for the year ended December 31, 2012.

108

Total Operating Expenses. The following table sets forth details of our total operating expenses for the years ended December 31, 2013 and 2012:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
	(Restated)
Total operating expenses	$	(52,009	)	$	(8,697	)	$	(43,312	)

Total operating expenses for the year ended December 31, 2013 were $52.0 million, an increase of $43.3 million from $8.7 million for the year ended December 31, 2012 due to an increase in construction contract and administrative expenses.

Equity in Earnings of Joint Ventures. The following table sets forth details of our equity in earnings of joint ventures for the years ended December 31, 2013 and 2012:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
Equity in earnings of joint ventures	$	40,228	$	5,007	$	35,221

Equity in earnings of joint ventures for the year ended December 31, 2013 was $40.2 million, an increase of $35.2 million from $5.0 million for the year ended December 31, 2012. The primary reason for the increase was higher unrealized gains on derivative instruments in 2013 than in 2012.

Our share of our joint ventures’ operating income was $23.3 million for the year ended December 31, 2013, compared with $23.4 million for the year ended December 31, 2012. Other financial expenses, net were $18.1 million for the year ended December 31, 2013, a reduction of $1.0 million from $19.1 million for the year ended December 31, 2012. The reduction was mainly due to lower interest expense due to repayment of principal on debt during 2013.

Our share of unrealized gains on derivative instruments was $35.0 million for the year ended December 31, 2013 as compared to unrealized gains on derivative instruments of $0.7 million for the year ended December 31, 2012 explaining most of the increase in our equity in earnings of joint ventures for 2013 compared to 2012. The joint ventures utilized interest rate swap contracts to exchange a receipt of floating interest for a payment of fixed interest 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. Historically, the joint ventures have accumulated unrealized losses on the interest rate swap due to declining interest rates, which has resulted in liabilities for derivative financial instruments and an accumulated deficit in equity on their balance sheets. Increasing interest rates during 2013 and 2012 have resulted in unrealized gains, which have reduced the liabilities for derivative financial instruments and the accumulated deficit in equity on their balance sheets. There was no income tax expense for the years ended December 31, 2013 and 2012. Our joint ventures did not pay any dividends for the years ended December 31, 2013 and 2012.

Operating Income. The following table sets forth details of our operating income for the years ended December 31, 2013 and 2012:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
	(Restated)
Operating income	$	39,792	$	1,822	$	37,970

Operating income for the year ended December 31, 2013 was $39.8 million, an increase of $38.0 million from $1.8 million for the year ended December 31, 2012. The increase in operating income was primarily due to the increase in the equity in earnings of joint ventures of $35.2 million and the margin on the construction contract for the Mooring of $7.1 million, which was partially offset by the negative impact of higher administrative expenses.

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Interest Income. The following table sets forth details of our interest income for the years ended December 31, 2012 and 2013:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
Interest income	$	2,122	$	2,482	$	(360	)

Interest income for the year ended December 31, 2013 was $2.1 million, a decrease of $0.4 million from $2.5 million for the year ended December 31, 2012. Interest income is related to the interest accrued on the advances to our joint ventures. The decrease in interest income is due to repayment by our joint ventures of a portion of the principal due under the shareholder loans during 2013. The interest rate is a fixed rate of 8.0% per year based upon the shareholder loans.

Interest Expense. The following table sets forth details of our interest expense for the years ended December 31, 2013 and 2012:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
Interest expense	$	(6,110	)	$	(3,769	)	$	(2,341	)
Commitment fees		(2,162	)		(1,729	)		(433	)
Amortization of debt issuance cost		(379	)		(379	)		—
Capitalized interest		8,299			5,763			2,536
Total interest expense	$	(352	)	$	(114	)	$	(238	)

Interest expense for the year ended December 31, 2013 was $0.4 million, an increase of $0.3 million from $0.1 million for the year ended December 31, 2012. Interest expense consists of the interest incurred, commitment fees and amortization of debt issuance cost less the interest capitalized for the period. The interest incurred increased from $3.7 million for the year ended December 31, 2012 to $6.1 million for the year ended December 31, 2013 principally due to higher outstanding loan balances. Loans and promissory notes due to owners and affiliates have financed the construction of the PGN FSRU Lampung and the construction contract expenses of the Mooring. Commitment fees were for the year ended December 31, 2013 were $2.2 million, an increase of $0.5 million from $1.7 million for the year ended December 31, 2012. Most of the interest incurred was capitalized as part of the newbuilding or included in the construction contract expense for the Mooring. Capitalized interest was $8.3 million for the year ended December 31, 2013 compared with $5.8 million for the year ended December 31, 2012.

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Other Items, Net. The following table sets forth details of our other items for the years ended December 31, 2013 and 2012:

							Positive
	Year ended December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
	(Restated)
Other items, net	$	(1,096	)	$	(1	)	$	(1,095	)

Other items, net for the year ended December 31, 2013 was $1.1 million, primarily due to withholding tax that is payable on interest expense for 2013 to parties outside of Indonesia.

Income before Tax. The following table sets forth details of our income before tax for the years ended December 31, 2013 and 2012:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
	(Restated)
Income before tax	$	40,466	$	4,188	$	36,278

Income before tax for the year ended December 31, 2013 was $40.5 million, an increase of $36.3 million from $4.2 million for the year ended December 31, 2012. The increase was largely due to the increase in the equity in earnings of joint ventures of $35.2 million and the margin on the construction contract of $7.1 million, which was partially offset by higher administrative expenses of $4.9 million.

Income Tax Expense. There was no income tax expense for the years ended December 31, 2013 and 2012. We are not subject to Marshall Islands corporate income taxes. However, we are subject to tax for earnings in Indonesia and Singapore starting in the fourth quarter of 2013.

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. In 2013, we incurred a tax loss as a result of unrealized foreign exchange losses in local currency used for reporting taxes for PT Hoegh that has the U.S. dollar as its functional currency. In 2014, the Indonesia authorities have approved the change of currency for tax reporting to U.S. dollars. Under existing tax law, it is not clear if the prior year tax loss carryforward from foreign exchange losses can be utilized when the tax reporting currency is subsequently changed. Due to uncertainty of this tax position, a provision was recognized and the resulting unrecognized tax benefit was $2.6 million.

A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that some or all of the benefit will not be realized. Given the lack of historical operations, we concluded a valuation allowance should be established to reduce the other deferred tax assets to amount more-likely-than-not of being realized. As a result, we did not recognize a deferred tax benefit in the income statement for the year ended December 31, 2013.

For the year ended December 31, 2012, none of our activities were in jurisdictions subject to tax.

Net Income. The following table sets forth details of our net income for the years ended December 31, 2013 and 2012:

					Positive
	Year ended December 31,				(negative)
(in thousands of U.S. dollars)	2013		2012		variance
	(Restated)
Net income	$	40,466	$	4,188	$	36,278

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As a result of the foregoing, net income for the year ended December 31, 2013 was $40.5 million, an increase of $36.3 million compared with the year ended December 31, 2012.

Segments

As of and for the years ended December 31, 2013 and 2012, Majority held FSRUs included the newbuilding, the PGN FSRU Lampung, and construction contract revenue and expenses of the Mooring under construction being constructed on behalf of PGN using the percentage of completion method of accounting.

As of December 31, 2013 and 2012, joint venture FSRUs included two 50.0%-owned FSRUs, the GDF Suez Neptune and the GDF Suez Cape Ann, each of which operates under a long-term time charter with GDF Suez.

The accounting policies applied to the segments are the same as those applied in the consolidated and combined carve-out financial statements, except that Joint venture FSRUs are presented under the proportional consolidation method for the segment reporting and under the equity method for the consolidated and combined carve-out financial statements. 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.

Majority Held FSRUs. The following table sets forth details of segment results for the Majority held FSRUs for the years ended December 31, 2013 and 2012:

	Years ended						Positive
Majority Held FSRUs	December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
	(Restated)
Construction contract revenues	$	51,062		$	5,512		$	45,550
Other revenues		511			—			511
Total revenues		51,573			5,512			46,061
Construction contract expense		(43,958	)		(5,512	)		(38,446	)
Administrative expenses		(4,490	)		(2,372	)		(2,118	)
Segment EBITDA		3,125			(2,372	)		5,497
Depreciation and amortization		(8	)		—			(8	)
Operating income (loss)		3,117			(2,372	)		5,489
Financial income (expense), net		(1,448	)		(115	)		(1,333	)
Income (loss) before tax		1,669			(2,487	)		4,156
Net income (loss)	$	1,669		$	(2,487	)	$	4,156

Total revenues for the year ended December 31, 2013 were $51.6 million, an increase of $46.1 million from $5.5 million for the year ended December 31, 2012. As discussed in more detail above, the main reason for the increase was higher construction contract revenue for the year ended December 31, 2013 reflecting 52% project completion compared with 6% for the year ended December 31, 2012.

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Administrative expenses for the year ended December 31, 2013 were $4.5 million, an increase of $2.1 million from $2.4 million for the year ended December 31, 2012. Higher expenses were due to higher activity related to the PGN FSRU Lampung, the Mooring and preparation for the start of operations.

Construction contract expense increased by $38.5 million for the year ended December 31, 2013 compared with the year ended December 31, 2012 due to progress on the Mooring construction project.

Segment EBITDA for the year ended December 31, 2013 was $3.1 million, an increase of $5.5 million from the loss of $2.4 million for the year ended December 31, 2012 as a result of recognition of the contract margin on the percentage of completion for 2013 and no margin in 2012.

Joint Venture FSRUs. The following table sets forth details of segment results for the Joint venture FSRUs for the years ended December 31, 2013 and 2012:

	Years ended						Positive
Joint Venture FSRUs	December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
Time charter revenues	$	41,110		$	41,076		$	34
Vessel operating expenses		(7,702	)		(7,525	)		(178	)
Administrative expenses		(1,061	)		(1,127	)		66
Segment EBITDA		32,347			32,424			(77	)
Depreciation and amortization		(9,053	)		(9,060	)		7
Operating income		23,294			23,364			(70	)
Gain on derivative instruments		35,038			693			34,345
Other income (expense), net		(18,104	)		(19,050	)		946
Net income (loss)	$	40,228		$	5,007		$	35,221

Total time charter revenues were $41.1 million and $41.1 million for the years ended December 31, 2013 and 2012, respectively. Revenues for time charter payments, including fees for reimbursement of operating expenses, were $40.3 million and $40.2 million for the years ended December 31, 2013 and 2012, respectively. The increase in revenues for time charter payments in 2013 was due to the increase in fees for reimbursement of vessel operating expenses. The remaining revenues principally related to the amortization of deferred revenues for upfront payments for modifications and drydocking payments from the charterer.

Vessel operating expenses for the year ended December 31, 2013 were $7.7 million, an increase of $0.2 million, compared to $7.5 million for the year ended December 31, 2012 due to slightly higher cost for salary and other cost increases.

Administrative expenses for the year ended December 31, 2013 declined slightly compared with the year ended December 31, 2012. As a result of GDF Suez’s decision to subcharter the GDF Suez Cape Ann, additional administrative hours were incurred. The decline in administrative expenses in 2013 compared with 2012 was primarily related to more administrative hours incurred on the subcharter project in 2012 than in 2013.

Segment EBITDA was $32.3 million for the year ended December 31, 2013 compared with $32.4 million for the year ended December 31, 2012.

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Other. The following table sets forth details of other results of Other for the years ended December 31, 2013 and 2012:

	Years ended						Positive
Other	December 31,						(negative)
(in thousands of U.S. dollars)	2013			2012			variance
Administrative expenses	$	(3,553	)	$	(813	)	$	(2,740	)
Segment EBITDA		(3,553	)		(813	)		(2,740	)
Operating income (loss)		(3,553	)		(813	)		(2,740	)
Interest income		2,122			2,481			(359	)
Income (loss) before tax		(1,431	)		1,668			(3,099	)
Income tax expense		—			—			—
Net income (loss)	$	(1,431	)	$	1,668		$	(3,099	)

Administrative expenses and Segment EBITDA for the year ended December 31, 2013 for each was $3.6 million, an increase of $2.7 million from $0.8 million for the year ended December 31, 2012. Other includes unallocated corporate costs. The major reason for the increase was expenses of $2.4 million incurred in preparation for the IPO for the year ended December 31, 2013. Expenses incurred for the IPO principally related to audit fees, legal fees and charges for hours incurred working on preparation for the IPO.

Interest income, which is not part of the segment measure of profits, is related to the interest accrued on the advances to our joint ventures.

Liquidity and Capital Resources (Restated)

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 utilization of the demand note due from Höegh LNG, 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 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 working capital, including drydocking, and maintaining cash reserves against fluctuations in operating cash flows.

Our sources of liquidity include cash balances, the $140 million demand note due from Höegh LNG, cash flows from our operations, interest and repayment of principal from our advances to our joint ventures and our undrawn balance under the $85 million sponsor credit facility. Cash and cash equivalents are denominated primarily in U.S. dollars. We do not currently use derivative financial instruments for other purposes than managing interest rate risks. The advances to our joint ventures (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. 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; 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 Hoegh Lampung may only be paid out of profits under Singapore law. Dividends from PT Höegh may only be paid if the retained earnings are positive under Indonesian law and requirements are fulfilled under the Lampung facility. As of December 31, 2014, PT Hoegh has negative retained earnings and therefore cannot make dividend payments under Indonesia law. However, subject to meeting a debt service ratio of 1:20:1:00, PT Hoegh 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 meeting operating requirements as defined by the Lampung facility.

Our joint ventures have a commitment to fund the drydocking and the modifications of the GDF Suez Neptune during 2015. Under the terms of the time charter, GDF Suez will fund the both the drydocking and modifications.

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As of December 31, 2014, we do not have material commitments for capital expenditures for the rest of our current business. Our expected expenditures for our current business include funding repairs and replacement parts of approximately $2.0 million for the Mooring. This expenditure is indemnified by Höegh LNG under the omnibus agreement. Therefore, the funding for this expenditure will be provided by Höegh LNG.

We believe our cash flows from operations, including distributions to us from PT Hoegh as payment of intercompany interest and/or intercompany debt, and repayment of principal from our advances to our joint ventures 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. In connection with the IPO, we entered into an $85 million sponsor credit facility with Höegh LNG, which we believe will provide us with adequate liquidity to fund our distributions given our expected level of debt amortization. The $140 million demand note due from Höegh LNG is repayable on demand or we can elect to utilize it as part of the purchase consideration in the event we purchase all or a portion of Höegh LNG’s interests in the Independence or another FSRU under a charter of five or more years.

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 upon external financing sources, including bank borrowings and the issuance of debt and equity securities, to fund acquisitions and other expansion capital expenditures.

We have not made use of derivative instruments for currency risk management purposes. On March 17, 2014, we entered into interest rate swap contracts for the Lampung facility. As of December 31, 2014, we had outstanding interest rate swap agreements for a total notional amount of $212.3 million to hedge against the interest rate risks of our long-term debt under the Lampung facility. We apply hedge accounting for these interest rate swaps. We receive interest based on three month US dollar LIBOR and pay a fixed rate of 2.8%. The swaps amortize over 12 years to match the outstanding balance of the Lampung facility. Refer to “Item 5.F. Tabular Disclosure of Contractual Obligations.” The carrying value of the liability for derivative financial instruments was $9.2 million as of December 31, 2014. There were no similar outstanding instruments as of December 31, 2013. In addition, our joint ventures have utilized interest rate swap contracts that are not designated as hedges for accounting purposes. Please read note 19 to our consolidated and combined carve-out financial statements. For information about our joint ventures’ derivative instruments, please read note 13 to our joint ventures’ combined financial statements.

As of December 31, 2014, the Partnership had cash and cash equivalents of $30.5 million and an undrawn sponsor credit facility of $85 million. Current restricted cash for operating obligations of the PGN FSRU Lampung was $21.9 million and long-term restricted cash required under the Lampung facility was $15.2 million as of December 31, 2014. The Partnership has an interest-bearing demand note due from Höegh LNG of $140.0 million. The Partnership’s total long-term debt was $212.3 million as of December 31, 2014, repayable in quarterly installments of $4.8 million.

On November 14, 2014, the Partnership paid its first cash distribution of $4.8 million to its unitholders for the prorated $0.1834 per unit distribution declared for the period from August 12, 2014 to September 30, 2014, which is equivalent to $0.3375 per unit per quarter.

As of December 31, 2014, our total current assets exceeded total current liabilities by $167 million. We believe our current resources, including the sponsor credit facility, are sufficient to meet our working capital requirements for our current business for the next twelve months.

For information regarding estimated maintenance and replacement capital expenditures, impacting our cash distributions, please read “Item 8.A. Consolidated Statements and Other Financial Information—Estimated Maintenance and Replacement Capital Expenditures.”

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Cash Flows

Cash Flows for the years ended December 31, 2014 and 2013

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)	2014			2013
	(Restated)			(Restated)
Net cash provided by (used in) operating activities	$	27,976		$	(41,217	)
Net cash used in investing activities		(292,199	)		(30,781	)
Net cash provided by financing activities		294,592			72,006
Increase (decrease) in cash and cash equivalents		30,369			8
Cash and cash equivalents, beginning of period		108			100
Cash and cash equivalents, end of period	$	30,477		$	108

Net Cash Provided by (Used in) Operating Activities

Net cash provided by operating activities was $27.9 million for the year ended December 31, 2014 compared with net cash used in operating activities of $41.2 million for the year ended December 31, 2013. Cash flows from operating activities reflect that the full Mooring payment was received and the time charter hire commenced for the PGN FSRU Lampung during the year ended December 31, 2014. In addition, cash of $26.3 million was used to pay the tax authorities for a refundable value tax on the import of the PGN FSRU Lampung into Indonesia. For the year ended December 31, 2013, the reason for the increased cash used in operating activities was because the PGN FSRU Lampung had not been delivered or started operations and high construction contract expenses were being incurred on the Mooring.

Net Cash Used in Investing Activities

Net cash used in investing activities was $292.2 million and $30.8 million for the years ended December 31, 2014 and 2013, respectively. Net cash used in investing activities increased by $261.4 million in 2014 compared with 2013 primarily due to expenditures for the newbuilding, the PGN FSRU Lampung and the demand note lent to Höegh LNG. Expenditures for the newbuilding increased by $134.6 million as the result of the final 60% payment and payments for change orders due to the delivery of the PGN FSRU Lampung. This was partially offset by cash provided by the $1.1 million increase in principal payments on advances to joint ventures, the receipt of principal payment on the direct financing lease of $1.3 million and the release of restricted cash for a letter of credit of $10.7 million during the year ended December 31, 2014. Following the closing of the IPO, we lent $140.0 million to Höegh LNG pursuant to an interest-bearing demand note from the net proceeds.

Net Cash Provided by Financing Activities

Net cash provided by financing activities was $294.6 million and $72.0 million for the years ended December 31, 2014 and 2013, respectively.

Net cash provided by financing activities during the year ended December 31, 2014 was impacted by the closing of the Partnership’s IPO and the application of the net proceeds. We received net proceeds from the IPO, after deduction for the underwriters’ discounts and expenses of the offering, of $203.5 million. We distributed $43.5 million in cash from the net proceeds to Höegh LNG. We kept $20.0 million of the IPO proceeds for general partnership purposes.

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We received proceeds of $10.8 million from amounts, loans and promissory notes due to owners and affiliates during the year ended December 31, 2014. In addition, we drew $257.1 million on the Lampung facility that was used for payments for the contractual commitments for the PGN FSRU Lampung and the Mooring construction contract expenses. We also paid $8.0 million in debt issuance cost related to the facility. Part of the proceeds of the debt and cash flows from operations was used to repay $74.6 million of amounts, loans and promissory notes from owners and affiliates. Following the first Mooring payment, the full Mooring tranche of $32.1 million was repaid on July 3, 2014. Following the final Mooring payment, an early repayment of $7.9 million was made on the Lampung facility and quarterly repayments commenced on December 29, 2014. In total, we repaid $44.8 million of long-term debt for the year ended December 31, 2014. As a result of the early repayment on long-term debt, a cash settlement of $1.1 million was made to reduce the amount of the interest rate swaps that are accounted for as cash flow hedges of the variable interest rate debt to match the outstanding debt balance. The restricted cash required by the Lampung facility of $15.2 million was also fully funded. Net distributions to the owner were $11.2 million.

On the import of the PGN FSRU Lampung into Indonesia during 2014, we obtained funding from PGN of $26.3 million to pay for the refundable value added tax on import. Refer to “Net Cash Provided by (Used in) Operating Activities” above.

During the fourth quarter of 2014, we paid our first cash distribution of $4.8 million to our unitholders for the prorated $0.1834 per unit distribution declared for the period from August 12, 2014 to September 30, 2014, which is equivalent to $0.3375 per unit per quarter.

During the year ended December 31, 2013, most of the funding was provided by $116.7 million drawn on amounts, loans and promissory notes from owners and affiliates. Debt issuance cost of $9.4 million was paid related to the Lampung facility and there were net distributions to the owner of $35.3 million.

As a result of the foregoing, cash and cash equivalents increased by $30.4 million for the year ended December 31, 2014 and by eight thousand dollars for the year ended December 31, 2013.

Cash Flows of for the years ended December 31, 2013 and 2012

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)	2013			2012
	(Restated)
Net cash used in operating activities	$	(41,217	)	$	(7,635	)
Net cash used in investing activities		(30,781	)		(61,709	)
Net cash provided by financing activities		72,006			69,444
Increase (decrease) in cash and cash equivalents		8			100
Cash and cash equivalents, beginning of period		100			—
Cash and cash equivalents, end of period	$	108		$	100

Net cash used in operating activities was $41.2 million and $7.6 million for the years ended December 31, 2013 and 2012, respectively. Cash flows from operating activities reflect that the PGN FSRU Lampung had not yet been delivered or started operations for either period. The increase in cash used in operating activities of $34.5 million for the year ended December 31, 2013 compared to 2012 is principally due to higher construction contract expenses for the Mooring under the percentage of completion method. In addition, administrative expenses increased in 2013 compared to 2012 principally due to the costs incurred in preparation for the IPO.

Net Cash Used in Investing Activities

Net cash used in investing activities was $30.8 million and $61.7 million for the years ended December 31, 2013 and 2012, respectively. Net cash used in investing activities decreased by approximately $30.9 million for the year ended December 31, 2013 mainly due to fewer scheduled shipbuilding contract payments in 2013 than in 2012. Under the terms of the shipbuilding contract, we paid 10.0%, 20.0% and 10.0% of the contract price in 2011, 2012 and 2013, respectively, based on milestones in the construction. The final 60.0% payment and any payment for change orders were due in the second quarter of 2014 at delivery of the PGN FSRU Lampung. In addition, in 2012 there was an increase in restricted cash of $10.0 million.

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Net Cash Provided by Financing Activities

Net cash provided by financing activities was $72.0 million for the year ended December 31, 2013 compared with $69.4 million for the comparable period of 2012.

During 2013 and 2012, the financing for construction of the PGN FSRU Lampung and the construction contract expenses of the Mooring were principally provided by loans and promissory notes from owners and affiliates. Proceeds from lending from owners and affiliates were $116.7 million and $61.7 million for the years ended December 31, 2013 and 2012, respectively. Further, the PGN FSRU Lampung and the Mooring were not historically owned by a separate legal entity or organized as a discrete unit until late in 2013. Therefore, no separate cash operating accounts existed. As a result, certain cash flows from financing activities are reflected as contributions from or distributions to the owner, net in the consolidated and combined carve-out statement of cash flows and the consolidated and combined carve-out statement of equity. The net distributions to the owner were $35.3 million for the year ended December 31, 2013 and the net contributions from the owner were $7.8 million for the year ended December 31, 2012.

As a result of the foregoing, cash and cash equivalents increased by $8,000 and $100,000 for the year ended December 31, 2013 and 2012, respectively.

Borrowing Activities

Loans and Promissory Notes Due to Owners and Affiliates

The following table sets forth our loans and promissory notes due to owners and affiliates as of December 31, 2014:

(in thousands of U.S. Dollars)	As of December 31, 2014
$85.0 million Revolving credit facility due to Höegh LNG Ltd.	$	467
Loans and promissory notes due to owners and affiliates	$	467

In connection with the IPO, we entered into an $85 million sponsor credit facility with Höegh LNG. No amounts have been drawn under the facility. The balance as of December 31, 2014 included in the table above reflects the accrued commitment fee.

Included in the combined carve-out equity as of August 12, 2014, were amounts related to promissory notes and related accrued interest due to Höegh LNG. Höegh LNG’s receivables for the promissory notes and related accrued interest of the Partnership’s subsidiaries were contributed to the Partnership in connection with the IPO. Refer to notes 2a and 3 in the consolidated and combined carve-out financial statements for additional discussion of the contribution. As a result, the liabilities of the Partnership’s subsidiaries are eliminated in consolidation since they are no longer external liabilities to the Partnership as of December 31, 2014.

Sponsor Credit Facility with Höegh LNG

The $85 million sponsor credit facility with Höegh LNG is available for three years, unless otherwise terminated due to an event of default. Interest on drawn amounts is payable quarterly at LIBOR plus a margin of 4.0%. Additionally, we are required to pay a 1.4% annual commitment fee, payable quarterly, to Höegh LNG on undrawn available amounts under the sponsor credit facility. Drawings on the sponsor 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.

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The sponsor 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, 2014 and 2013:

	As of December 31,
(in thousands of U.S. dollars)	2014			2013
Lampung facility:
$ 178.6 million Export credit tranche	$	168,640		$	—
$ 58.5 million FSRU tranche		43,693			—
$ 61.9 million Mooring tranche		—			—
Total debt		212,333			—
Less: Current portion of long-term debt		(19,062	)		—
Long-term debt	$	193,271		$	—

Refer to “Item 5.F. Tabular Disclosure of Contractual Obligations” and note 14 in the consolidated and combined carve-out financial statements for the maturity profile of the debt.

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Lampung Facility

In September 2013, PT Hoegh entered into a secured $299 million term loan facility and $10.7 million standby letter of credit 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. The $10.7 million standby letter of credit facility supports guarantees to PGN for delivery obligations of the PGN FSRU Lampung and Mooring under the lease, operation and maintenance agreement. Höegh LNG is the guarantor for the 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 letter of credit facility was undrawn as of December 31, 2014 and 2013.

On March 4, 2014, PT Hoegh drew $96 million of the Lampung facility, of which $28.4 million, $32.1 million and $35.5 million were drawn on the FSRU tranche, the Mooring tranche and the export credit tranche, respectively. On April 8, 2014, PT Hoegh drew $161.1 million of the Lampung facility, of which $18.0 million and $143.1 million were drawn on the FSRU tranche and export credit tranche, respectively. On July 3, 2014, the full principal amount of $32.1 million on the Mooring tranche and accrued interest was repaid. The final available commitment on the FSRU tranche of $12.1 million was never drawn. On December 29, 2014, PT Hoegh made an early repayment of $7.9 million, of which $1.6 million and $6.3 million was repaid on the FSRU tranche and the Export credit tranche, respectively. The quarterly repayments due under the Lampung facility began on December 29, 2014. As of December 31, 2013, the Lampung facility was undrawn.

The FSRU tranche of $58.5 million has an interest rate of LIBOR plus a margin of 3.4%. The interest rate for the export credit tranche of $178.6 million is LIBOR plus a margin of 2.3%. The first repayment of the both tranches occurred on December 29, 2014. The FSRU tranche is repayable quarterly over 7 years with a final balloon payment of $16.5 million. 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 Mooring tranche of $61.9 million bore interest at a rate equal to LIBOR plus a margin of 2.5%. The Mooring tranche was fully repaid on July 3, 2014.

Commitment fees were 1.4%, 0.9% and 1.0% of the undrawn portions of the FSRU tranche, the export credit tranche and the Mooring tranche, respectively.

The primary financial covenants under the Lampung facility are as follows:

PT Hoegh must maintain a minimum debt service coverage ratio of 1.10:1.00 for the preceding nine-month period tested beginning from the second quarterly repayment date of the export credit tranche and on each quarterly repayment date thereafter;

Höegh LNG’s book equity must be greater than the higher of (i) $200 million and (ii) 25.0% of total assets; and

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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, 2014, the guarantor was in compliance with the financial covenants. The covenant for the borrower is effective from March 2015. The borrower was in compliance with the financial covenants as of March 31, 2015.

Höegh LNG, as guarantor, has issued the following guarantees related to the Lampung facility: (a) an unconditional and irrevocable on-demand guarantee for all amounts due under the financing agreements, to be released after the date falling 180 days after acceptance of the PGN FSRU Lampung under the time charter subject to the relevant terms and conditions being met; (b) 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; (c) an unconditional and irrevocable on-demand guarantee for PT Hoegh’s obligation to ensure the required balance is in the debt service reserve account on the eighth repayment date (or such earlier date as is applicable if an event of default occurs); (d) 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 (e) 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 and all project accounts and the shares in PT Hoegh and Höegh Lampung are pledged in favor of the bank syndicate and the export credit agent.

The Lampung facility contains customary covenants that limit, among other things, the ability of PT Hoegh 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;

failure to comply with the financial or insurance covenants;

cross-default to other indebtedness held by Höegh LNG or PT Hoegh;

bankruptcy and other insolvency events at Höegh LNG or PT Hoegh;

occurrence of certain litigation events at Höegh LNG or PT Hoegh;

the occurrence of a material adverse effect in respect of Höegh LNG, PT Hoegh or the charterer;

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breach of O&M agreement by O&M operator;

termination or breach of the charter; and

cross-default to certain material project contracts.

Joint Ventures Debt

The debt of our joint ventures is not consolidated on our consolidated and combined carve-out financial statements, but it is included as a component in “Investment in and advances to joint ventures” on our combined carve-out 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, 2014, our 50.0% share of the outstanding balance was $19.5 million. The shareholder loans are due not later than the 12th anniversary of the delivery date of each FSRU. The GDF Suez Neptune and the GDF Suez 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 have financed part of the construction of the vessels and operating expenses until the delivery and commencement of operations of the GDF Suez Neptune and the GDF Suez 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 include a payment of interest for the first month of the quarter and a repayment of principal. Interest is accrued for the last two months of the quarter for repayment in the latter years of the loans. Since the shareholder loans are subordinated to long-term bank debt, the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt.

Neptune Facility. In December 2007, our joint venture owning the GDF Suez 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 GDF Suez Neptune (the “Neptune facility”). As of December 31, 2014, our 50.0% share of the outstanding balance was $128.8 million. The Neptune facility is secured with a first priority mortgage of the GDF Suez 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 $165 million, of which $82.5 million is our share, due in April 2022. The Neptune facility bears interest at a rate equal to three month LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swap contracts to the borrower, which are not reflected in the LIBOR rate for the facility.

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 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.

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The Neptune facility identifies various events that may trigger mandatory reduction, prepayment and cancellation of the facility, including total loss or sale of the GDF Suez Neptune. The Neptune 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.

Cape Ann Facility. In December 2007, our joint venture owning the GDF Suez 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 GDF Suez Cape Ann (the “Cape Ann facility”). As of December 31, 2014, our 50.0% share of the outstanding balance was $132.3 million. The Cape Ann facility is secured with a first priority mortgage of the GDF Suez 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 $165 million, of which $82.5 million is our share, due in October 2022. The Cape Ann facility bears interest at a rate equal to three month LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swap contracts to the borrower, which are not reflected in the LIBOR rate for the facility.

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 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 GDF Suez Cape Ann. The Cape Ann 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.

Critical Accounting Estimates

The preparation of our consolidated and combined carve-out financial statements and of the combined financial statements of our joint ventures in accordance with U.S. GAAP requires that management make estimates and assumptions affecting the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a discussion of the accounting policies applied by us that are considered to involve a higher degree of judgment in their application. Please read note 2 to the consolidated and combined carve-out financial statements and the combined financial statements of our joint ventures included elsewhere in this Annual Report.

Time Charter Revenue Recognition

Revenue arrangements include the right to use FSRUs for a stated period of time that meet the criteria for lease accounting, in addition to providing a time charter service element. The lease element of time charters that are accounted for as operating leases and any upfront payments for amounts reimbursed by the charterer are recognized on a straight-line basis over the term of the charter. The lease element of time charters that are accounted for as direct financing leases is recognized over the charter term using the effective interest rate method and is included in time charter revenues. Direct financing leases are reflected on the balance sheets as net investments in direct financing leases. The PGN FSRU Lampung time charter is accounted for as a financial lease.

Evaluation of whether a time charter should be accounted for as an operating or financial lease requires use of judgment. Our evaluations of each time charter requires 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 operating or financial leases. Operating leases recognize revenues on a straight-line basis as time charters are paid while financial leases use the effective interest method. Under the effective interest method, part of the payment is reflected as a repayment of the net investment in the direct financing lease (receivable). As a result, the revenue component of a direct financial lease shows a declining profile over time. However, the cash flows from time charters are not impacted by the accounting treatment applied.

Our time charters may include provisions for the charterer to make upfront payments for fees for certain vessel modifications, drydocking costs, other additions to equipment or spare parts or estimates for certain reimbursable costs or taxes.

Fees for modifications or other additions to equipment are deferred and amortized over the shorter of the remaining charter period or the useful life of the additions. Payments of fees for reimbursement of drydocking costs are recognized on a straight-line basis over the period to the next drydocking. Reimbursements for estimated costs, which may be subject to repayment provisions, are initially deferred and only recognized as revenue when the actual costs are incurred and the revenues are deemed to be fixed and determinable.

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Construction Contract Revenue and Related Expenses

Revenue on construction contracts are recognized under the percentage of completion method using the ratio of costs incurred to estimated total costs. It is our judgment that until a construction contract reaches at least 25.0% completion, there may be insufficient information to determine the estimated profit with a reasonable level of certainty to recognize a margin on the contract. Revenue from contract change orders, if any, is recognized when the owner has agreed to the change order in writing. Provisions are recognized in the consolidated and combined carve-out financial statements of income for the full amount of estimated losses on uncompleted contracts whenever evidence indicates that the estimated total cost of a contract exceeds its estimated total revenue. All contract costs, including those associated with change orders, are recorded as incurred, and revisions to estimated total costs are reflected as soon as the obligation to perform is determined. Contract costs consist of direct costs on contracts, including labor and materials and amounts payable to subcontractors and interest.

The accuracy of our revenue and recognition of a margin in a given period is dependent on the accuracy of our estimates of the cost to complete each project. The main factors that can contribute to changes in estimates of contract cost include: a) the accuracy of the estimated costs in tendering the original bid at a fixed price, b) higher costs due to weather and other delays (including resulting delay liquidated damages) and c) subcontractor performance issues (including costs of warranty work, if any). These factors may cause fluctuations in the profit margin on the construction contract between periods. As the percentage of completion method relies on the substantial use of estimates, estimates may be revised throughout the life of a construction contract. The construction cost incurred and estimates to complete on construction contracts are reviewed, at a minimum, on a quarterly basis, as well as when information becomes available that would necessitate a review of the current estimate. Adjustments to estimates for a contract’s estimated costs at completion and estimated profit or loss often are required as experience is gained, and as more information is obtained, even though the scope of work required under the contract may not change. The impact of such changes to estimates is made on a cumulative basis in the period when such information has become known. Delays in delivery can result in delay liquidated damages that would be payable by us to our charterer.

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 Financial Instruments

Under our risk management policies, we currently use of derivative financial instruments to manage interest rate risk. For interest rate swaps that are designated as cash flow hedges for accounting purposes, the changes in the fair value of the interest rate swaps are recorded in other comprehensive income (OCI) for that portion that is effective. Amounts included in accumulated OCI are reclassified to earnings in the consolidated combined carve-out statement of income when the hedged transaction is reflected in the statement of income. Ineffective portions of the cash flow hedges and amortization of amounts excluded form hedge effectiveness are recognized in statement of income as they occur or on a systematic basis, respectively. To qualify as a cash flow hedge, an assessment of whether the interest rate swap designated as a hedging instrument is highly effective in offsetting changes in the cash flows of hedged items must be assessed at the designation date and over the life of the instrument. If a hedge is no longer highly effective, hedge accounting is discontinued on a prospective basis. Changes in fair value of interest rate swaps that are not designated as cash flow hedges for accounting purposes are recognized in the consolidated and combined carve-out 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 the our credit worthiness given the level of collateral provided and the credit worthiness of the counterparty to the derivative. Determining credit worthiness is highly subjective and requires significant judgment.

Recent Accounting Pronouncements

There are no recent accounting pronouncements, the adoption of which had a material impact on the consolidated and combined financial statements in the current year.

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In May 2014, a new accounting standard, Revenue from Contracts with Customers, was issued by the Financial Accounting Standards Board. Under the new standard, revenue for most contracts with customers will be recognized when promised goods or services are transferred to customers in an amount that reflects consideration that the entity expects to be entitled, subject to certain limitations. The scope of this guidance does not apply to leases, financial instruments, guarantees and certain non-monetary transactions. The standard is effective for annual periods beginning after December 15, 2016 and early adoption is not permitted. The Partnership is currently assessing the impact the adoption this standard will have on the consolidated and combined carve-out financial statements.

Research and Development, Patents and Licenses, Etc.

Not applicable.

Trend Information

Outlook and Trends

Our FSRUs operate under long-term fixed rate contracts. Therefore, we believe our results of operations are not impacted by seasonality or short term fluctuations in FSRU charter rates or LNG prices. We believe lower LNG prices will positively impact demand for the commodity and, as a result, the infrastructure necessary for its import. Pakistan, Egypt, Jordan, Poland and Uruguay are expected to emerge as new sources of LNG demand in 2015. All such countries, except Poland, are expected to utilize FSRUs. We believe that attractive LNG pricing and adoption of FSRU technology will result in new FSRU projects that may become potential opportunities for us in the future.

Pursuant to the omnibus agreement, the Partnership has the right to purchase from Höegh LNG all or a portion of its interests in the FSRU Independence within 24 months after the acceptance of the vessel by her charterer, subject to reaching an agreement with Höegh LNG regarding the purchase price and other terms in accordance with the provisions of the omnibus agreement. Höegh LNG is also obligated to offer to the Partnership any FSRU or LNG carrier operating under a charter of five or more years.

As discussed at “Item 5. Operating and Financial Review and Prospects—Overview—Our Fleet,” the Independence began operating under its time charter in November 2014. In addition, in the fourth quarter of 2014, Höegh LNG entered into time charter agreements of five years or more for the Höegh Grace and the Höegh Gallant, which are scheduled to commence in mid-2016 and the second quarter of 2015, respectively. We believe these developments may provide opportunities for us to acquire additional vessels. However, there can be no assurance that we will acquire any vessels from Höegh LNG.

Off-Balance Sheet Arrangements

As of December 31, 2014, there were no off-balance sheet arrangements.

Tabular Disclosure of Contractual Obligations

The following table sets forth our contractual obligations as of December 31, 2014:

	Payments Due by Period
(in thousands of U.S. dollars)	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
Long term debt	$	212,333		19,062		38,124		38,124	$	117,023
Interest commitments on long-term debt and interest rate swaps(1)		60,483		10,853		18,551		14,440		16,639
Other long-term liabilities(2)		24,524		2,318		22,206		—		—
Total	$	297,340		32,233		78,881		52,564	$	133,662

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(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 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.

(2)

Our consolidated and combined carve-out 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. The current portion of the advance of $2.3 million is included in our consolidated and combined carve-out balance sheet as accrued liabilities and other payables which is reflected in the table above.

Safe Harbor

Please read “Forward-Looking Statements.”

Item 6.

Directors, Senior Management and Employees

The information included in Item 6 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

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 Agreements. Please read “Item 7. B. Related Party Transactions—Administrative Services Agreements.”

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 Wessex House, 5th Floor, 45 Reid Street, Hamilton, HM12, Bermuda.

Name	Age	Position
Sveinung Støhle	56	Chairman of the Board of Directors
Steffen Føreid	46	Director
Claibourne Harris	65	Director, Member of the Audit Committee, Member of the Conflicts Committee
Morten W. Høegh	41	Director
Andrew Jamieson	67	Director, Member of the Audit Committee
Robert Shaw	59	Director, Member of the Audit Committee, Member of the Conflicts Committee
David Spivak	47	Director, Member of the Audit Committee, Member of the Conflicts Committee
Richard Tyrrell	41	Chief Executive Officer and Chief Financial Officer

Sveinung Støhle has served as our director and chairman of our board of directors since April 2014. Since 2005, Mr. Støhle has served as the President and Chief Executive Officer of Höegh LNG through his employment with Höegh Norway. He has more than 25 years of experience in 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.

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Steffen Føreid has served as our director since April 2014. Since 2010, Mr. Føreid has served as the Chief Financial Officer of Höegh LNG. From 2008 to 2010, Mr. Føreid was the Chief Financial Officer of and an advisor to Grenland Group ASA. From 2002 to 2007, Mr. Føreid held various positions at a corporate restructuring of Kværner ASA, including Executive Vice President during a management buy-out of Kværner ASA and Vice President of Group Business Development at Aker Kværner ASA. From 1996 to 2001, Mr. Føreid worked within Corporate and Investment Banking at JPMorgan Chase & Co. Mr. Føreid has a Master of Science in Finance from the University of Fribourg in Switzerland.

Claiborne Harris has served as our director since May 2014. Since May 2013, Mr. Harris has been a member of Gunung Bonito LLC, which provides energy advisory services and LNG consulting. From October 2012 to April 2013, Mr. Harris served as a consultant to GDF Suez Energy North America, advising the President and Chief Executive Officer. From January 2006 to September 2012, he was President and Chief Executive Officer of GDF Suez Gas North America, which was responsible for GDF Suez Energy North America’s natural gas activities. From December 2002 to December 2006, Mr. Harris served as President and Chief Executive Officer of Suez Global LNG, which developed and managed LNG shipping assets. Prior to joining Suez Global LNG, Mr. Harris held various positions at Tractebel LNG Ltd., Enron, VICO Indonesia and UNOCAL. Mr. Harris holds a Bachelor of Science Geology from the University of Oklahoma.

Morten W. Høegh has served as our director since April 2014. Since 2006, Mr. Høegh has served as the Chairman of Höegh LNG, and 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 the Chairman of Höegh Eiendom AS and, until October 2014, was a director of Hector Rail AB. He is a director and member of the Executive Committee of Gard P&I (Bermuda) Ltd. He also serves as the Chairman of the UK committee of DNV GL. From 1998 to 2000, Mr. Høegh worked as an investment banker with Morgan Stanley. He has a Master in Business Administration from Harvard Business School and a Master of Science in Ocean Systems Management and a Bachelor of Science in Ocean Engineering from the Massachusetts Institute of Technology. He also is a graduate of the Military Russian Program at the Norwegian Defense Intelligence and Security School.

Andrew Jamieson has served as our director since April 2014. 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. Since 2005, 2010 and 2012, Mr. Jamieson has served as a director and chairman of Woodside Petroleum Ltd, Velocys PLC and Seven Energy International, respectively. Mr. Jamieson holds a Ph.D. degree from Glasgow University and is a Fellow of both the Institute of Chemical Engineers and the Royal Academy of Engineering.

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. 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. Since 2013, Mr. Shaw has been a managing director of Sea Trade Holdings Inc. and its subsidiaries. Mr. Shaw also is the chairman of the board of the Carnegie Council for Ethics in International Affairs and a board member 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. Mr. Spivak is currently the Managing Director of Brockstreet Consulting, a strategic business and financial consulting firm he founded in 2013. 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 serving as a Managing Director in the Investment Banking and Equity Capital Markets Divisions, as well as serving as the Canadian Head of Global Capital Structuring. From 2005 to 2009, Mr. Spivak was head of Citigroup’s shipping equity franchise in New York. Prior to joining Citigroup, 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 also is a Certified Public Accountant (inactive) and member of the TSX Listings Advisory Committee.

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Richard Tyrrell joined Leif Höegh UK in January 2014 in readiness to serve as the Chief Executive Officer and Chief Financial Officer of us and Höegh UK. Prior to joining Leif Höegh UK, Mr. Tyrrell served as a Managing Director in the energy team of Perella Weinberg Partners, a global, independent advisory and asset management firm, from June 2009 until January 2014. From 2008 to February 2009, Mr. Tyrrell was an investment professional with Morgan Stanley Infrastructure, an infrastructure investment and management platform with $4 billion under management, where he evaluated principal investment opportunities. From 2003 to 2008, Mr. Tyrrell worked for various departments of Morgan Stanley’s Investment Banking Division, including its Global Energy and Utilities Group and its United Kingdom Mergers and Acquisitions Group. From 1994 to 2000, Mr. Tyrrell served as a technical manager and field engineer for Schlumberger Limited in Australia and Southeast Asia. Mr. Tyrrell has a Master of Business Administration from Harvard Business School and an undergraduate degree in Mechanical Engineering from the Imperial College of Science, Technology and Medicine.

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 Hoegh, 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 the sub-technical support agreement that it is party to with Höegh LNG Management. Our joint ventures reimburse Höegh LNG Management for expenses incurred pursuant to the ship management agreements to which they are party to with Höegh LNG Management. Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Support Agreement.” Our subsidiary, Höegh UK also reimburses each of Leif Höegh UK and Höegh Norway for expenses pursuant to administrative services agreements. Please read “Item 7.B. Related Party Transactions—Administrative Services Agreements.”

Executive Compensation

We have not paid any compensation to our directors or our Chief Executive Officer and Chief Financial Officer nor accrued any obligations with respect to management incentive or retirement benefits for our directors and our Chief Executive Officer and Chief Financial Officer prior to our IPO. Pursuant to the administrative services agreement that we and our operating company entered into with Höegh UK, Richard Tyrrell, as an officer of Höegh UK, provides executive officer functions for our benefit. Mr. Tyrrell is 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 our administrative services agreement with Höegh UK, we paid $1.2 million for the year ended December 31, 2014, including $0.6 million for provision of services to Höegh UK from Höegh Norway under the Höegh UK Administrative Services Agreement, under which Höegh UK has subcontracted provision of certain services to Höegh Norway. Höegh UK compensated Richard Tyrrell.

In connection with the IPO, Mr. Tyrrell entered into an employment agreement with Leif Höegh UK dated December 4, 2013 and effective on January 15, 2014, which was assigned from Leif Höegh UK to Höegh UK subsequent to the closing of our IPO. Pursuant to the employment agreement, Mr. Tyrrell serves as Höegh UK’s Chief Executive Officer and Chief Financial Officer and is based in London. His annualized base salary is GBP 300,000. In addition, the employment agreement also provides for a discretionary annual bonus (as determined by Höegh UK), participation in other employment benefits in which other senior executives of Höegh UK participate, 25 working days of paid vacation per year (plus public holidays), and up to 12 weeks of paid sick leave per year. Mr. Tyrrell’s employment may be terminated on three months’ prior written notice by either Mr. Tyrrell or Höegh UK. In addition, Mr. Tyrrell’s employment agreement provides Höegh UK with the option to make a payment in lieu of notice. Höegh UK may also terminate the employment agreement with immediate effect upon certain specified “cause” events. The employment agreement includes post-termination restrictive covenants prohibiting Mr. Tyrrell from competing or soliciting customers or employees for a period of six months after the termination of his employment.

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Compensation of Directors

Our officers who also serve as our directors did not receive additional compensation for their service as directors. Non-management directors receive compensation for attending meetings of our board of directors, as well as committee meetings. Non-management directors each receive a director fee of $50,000 per year. Chairpersons of the audit and conflicts committees each receive a committee fee of $10,000 per year, and other committee members receive a committee fee of $5,000 per year. 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.

For the year ended December 31, 2014, we did not pay cash compensation to our directors. Director fees are paid annually and will be paid in 2015.

2014 Long-Term Incentive Plan

In connection with our initial public offering, we adopted the Höegh LNG Partners LP 2013 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. During the year ended December 31, 2014, we granted no awards under the LTIP.

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.

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.

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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.

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.

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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.

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-today activities consistent with the policies and procedures adopted by our board of directors.

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 Støhle, Steffen Føreid and Claibourne Harris were appointed by our general partner and will serve for terms as determined by our general partner. Morten W. Høegh, Andrew Jamieson, David Spivak and Robert Shaw were elected by our common unitholders on September 24, 2014, and are divided into four classes serving staggered terms. Andrew Jamieson was elected by our common unitholders on September 24, 2014 as the Class I elected director and will serve until our annual meeting of unitholders in 2015. Robert Shaw was designated as the Class II elected director and will serve until our annual meeting of unitholders in 2016. David Spivak was designated as our Class III elected director and will serve until our annual meeting of unitholders in 2017. Morten W. Høegh was designated as our Class IV elected director and will serve until our annual meeting of unitholders in 2018. 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.

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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.

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, Mr. Harris, Mr. Jamieson, Mr. Shaw and Mr. Spivak. Each of Mr. Harris, Mr. Jamieson, Mr. Shaw and Mr. Spivak satisfies the independence standards required for audit committee members of the SEC and the NYSE. Mr. Spivak qualifies as an “audit committee expert” 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 Mr. Harris, Mr. Shaw and Mr. Spivak.

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.”

Employees

Employees of Höegh LNG’s affiliates provide administrative services to us pursuant to the administrative services agreements. 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, a sub-technical support agreement and commercial and administration management agreements. A total crew of approximately 160 people is employed by Höegh LNG’s subsidiaries to operate our FSRUs.

Unit Ownership

Please read “Item 7.A. Major Unitholders.”

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Item 7.

Major Unitholders and Related Party Transactions

Except for certain information below in “Item 7.B. Related Party Transactions – Omnibus Agreement – Indemnification,” and “Item 7.B. Related Party Transactions – Other Related Party Transactions” the information included in Item 7 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Major Unitholders

The following table sets forth the beneficial ownership of our common units and subordinated units as of April 23, 2015, by each of our directors and executive officers and each person that we know to beneficially own more than 5% of our outstanding common or subordinated units:

	Common Units Beneficially Owned					Subordinated Units Beneficially Owned					Percentage of Total Common and Subordinated Units Beneficially
Name of Beneficial Owner	Number		Percent			Number		Percent			Owned
Höegh LNG Holding Ltd.(1)		2,116,060		16.1	%		13,156,060		100	%		58.0	%
Clearbridge Investments, LLC(2)		738,500		5.6	%		—		—			2.8	%
FMR LLC(3)		778,655		5.9	%		—		—			3.0	%
Goldman Sachs Asset Management(4)		2,330,485		17.7	%		—		—			8.9	%
Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne(5)		1,433,935		10.9	%		—		—			5.4	%
Oceanic Investment Management Limited(6)		1,048,900		8.0	%		—		—			4.0	%
Sveinung Støhle (Chairman of the Board of Directors)		*		*			—		—			*
Steffen Føreid (Director)		*		*			—		—			*
Claiborne Harris (Director)		*		*			—		—			*
Morten W. Høegh (Director)(7)		352,500		2.7	%		—		—
Andrew Jamieson (Director)		*		*			—		—			*
Robert Shaw (Director)		*		*			—		—			*
David Spivak (Director)		*		*			—		—			*
Richard Tyrell (Chief Financial Officer and Chief Financial Officer)		*		*			—		—			*
All directors and executive officers as a group (8 persons)		388,500		3.0	%		—		—			1.5	%

* 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 a 44.4% ownership interest. Leif Höegh & Co. Ltd. is indirectly controlled by Leif O. Høegh and a family trust under which Morten Høegh, one of our directors, is the primary beneficiary.
	(2)	This information is based on the Schedule 13G filed by Clearbridge Investments, LLC on February 17, 2015.
	(3)	This information is based on the Schedule 13G filed by FMR LLC on February 13, 2015.
	(4)	Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC (collectively, “Goldman Sachs Asset Management”) have shared voting power and shared dispositive power as to 2,330,485 units. This information is based on the Schedule 13G filed by Goldman Sachs Asset Management on September 10, 2014.
	(5)	Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power as to 644,647 units and shared dispositive power as to 1,433,935 units. This information is based on the Schedule 13G/A filed by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne on February 10, 2015.

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	(6)	Oceanic Hedge Fund, Oceanic Opportunities Master Fund, L.P., Oceanic CL Fund LP, Tufton Oceanic (Isle of Man) Limited, Oceanic Opportunities GP Limited, Oceanic CL GP Limited, Cato Brahde and Oceanic Investment Management Limited (collectively, “Oceanic Investment Management Limited”) each have shared voting power and shared dispositive power of up to 1,048,900 units. This information is based on the Schedule 13G filed by Oceanic Investment Management Limited on September 3, 2014.
	(7)	Morten W. Høegh may be deemed to have shared beneficial ownership of 352,500 common units through direct and indirect ownership interests in Leif Höegh & Co Ltd. and Aequitas Investments Ltd. Morten W. Høegh has an indirect minority ownership and voting interest in Fraternitas AS, which beneficially owns 50,000 common units. If the common units owned by Fraternitas AS were deemed to be beneficially owned by Mr. Høegh, then he would share beneficial ownership of a total of 402,500 common units, or 3.1% of the common units issued and outstanding as of April 23, 2015.

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.” Höegh LNG also exercises influence over the Partnership through its ownership of all of our subordinated units. At the end of the subordination period, assuming no additional issuances of common units and the conversion of our subordinated units into common units, Höegh LNG will own approximately 58.0% of our common units.

Related Party Transactions (Restated)

As a result of our relationships with Höegh LNG and its affiliates, we, our general partner 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 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 into or were party to since January 1, 2014 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.

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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.

Contribution, Purchase and Sale Agreement

On August 8, 2014, in connection with the closing of our IPO, we entered into a contribution, purchase and sale agreement with Höegh LNG that effected the transfer of the ownership interests in the entities that owned the vessels in our initial fleet and related shareholder loans, promissory notes and accrued interest and the use of the net proceeds of our IPO. Please refer to note 3 to our consolidated and combined carve-out financial statements for additional information.

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

(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;

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(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:

(1)

prevent us from owning, operating or chartering any Non-Five-Year Vessel that was previously a Five-Year Vessel while owned by us;

(2)

prevent us or any of our subsidiaries from 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)

prevent us or any of our subsidiaries from 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

(4)

prevent us or any of our subsidiaries from 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.

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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 time that is the later of the date of the change of control and the date on which all of our outstanding subordinated units have converted to common units. 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.

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.

Independence Purchase Option

Under the omnibus agreement, we have the right to purchase from Höegh LNG all or a portion of its interests in the Independence at a purchase price to be agreed upon by us and Höegh LNG at any time within 24 months after Höegh LNG notifies our board of directors of her acceptance by her charterer. We may exercise this option at one or more times during such 24-month period. If we and Höegh LNG are unable to agree upon the fair market value of the Independence, the fair market value will be determined by a mutually acceptable investment banking firm, ship broker or other expert advisor, and we will have the right, but not the obligation, to purchase the vessel at such price.

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 Independence purchase option will terminate immediately.

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 a 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 time that is the later of the date of the change of control and the date on which all of our outstanding subordinated units have converted to common units. 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.

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Indemnification

Under the omnibus agreement, Höegh LNG indemnifies us after the closing of the IPO for a period of five years 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. Liabilities resulting from a change in law after the closing of the IPO are excluded from the environmental indemnity. There is an aggregate cap of $5.0 million on the amount of indemnity coverage provided by Höegh LNG for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Höegh LNG is liable for claims only to the extent such aggregate amount exceeds $500,000.

Höegh LNG also indemnifies us for losses:

related to certain defects in title to the assets contributed or sold to us and any failure to obtain, prior to the time they were contributed to us, certain consents and permits necessary to conduct our business, which liabilities arise within three years after August 12, 2014;

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;

in the event that we do not receive hire rate payments under the PGN FSRU Lampung time charter for the period commencing on the closing date of our IPO through the earlier of (i) the date of acceptance of the PGN FSRU Lampung or (ii) the termination of such 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 related tower yoke mooring system) occurring prior to the date of acceptance of the PGN FSRU Lampung pursuant to the time charter; and

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.

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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.

Administrative Services Agreements

Höegh UK Administrative Services Agreement

In connection with the IPO, we and our operating company entered into an administrative services agreement with Höegh UK, pursuant to which Höegh UK will provide us and our operating company certain administrative services. The agreement has an initial term of five years. The services provided under the Höegh UK Administrative Services Agreement will be provided in a diligent manner, as we or our operating company may reasonably direct.

The Höegh UK Administrative Services Agreement may be terminated prior to the end of its term 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 Höegh UK Administrative Services Agreement may also be terminated solely by Höegh UK 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.

Under the Höegh UK Administrative Services Agreement, Richard Tyrrell, as an officer of Höegh UK, provides executive officer functions for our benefit. Mr. Tyrrell is responsible for providing advice and recommendations to us, subject to the direction of our board of directors. Our board of directors has the ability to terminate the arrangement with Höegh UK regarding the provision of executive officer services to us with respect to Mr. Tyrrell at any time in its sole discretion.

The administrative services provided by Höegh UK to us include:

commercial management services: assisting with our commercial management and the execution of our business strategies and investment decisions, although Höegh UK will not make any strategic or investment decisions;

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, arranging meetings for our common unitholders pursuant to our partnership agreement, arranging the provision of IT services, providing all administrative services required for subsequent debt and equity financings and attending to all other administrative matters necessary to ensure the professional management of our business;

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banking and financial services: providing cash management including assistance with preparation of budgets, overseeing banking services and bank accounts, providing assistance and support with our capitalization, financing and future offerings, negotiating and arranging for hedging arrangements and monitoring and maintaining compliance with loan and credit terms;

advisory services: assisting in complying with U.S. and other applicable securities laws;

client and investor relations: providing advisory, clerical and investor relations services to assist and support us in our communications with our common unitholders; and

assisting with the integration of any acquired businesses.

The administrative services provided by Höegh UK to our operating company include:

advising on cash management and services;

arranging for the preparation and provision of accounting information; and

providing advice on financing and other agreements into which the operating company is considering entering.

Each month, we and our operating company reimburse Höegh UK for its reasonable costs and expenses incurred in connection with the provision of the services under the Höegh UK Administrative Services Agreement. In addition, Höegh UK receive a service fee in U.S. Dollars equal to 5.0% of the costs and expenses incurred by them in connection with providing services. Amounts payable by us or our operating company must be paid promptly upon receipt of an invoice for such costs, expenses and supporting detail that may be reasonably required. Our operating company reimbursed Höegh UK approximately $1.2 million in total under the Höegh UK Administrative Services Agreement for the year ended December 31, 2014.

Under the Höegh UK Administrative Services Agreement, we and our operating company indemnify Höegh UK 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 the subcontractor or its officers, employees and agents.

Höegh Norway Administrative Services Agreement

Under the Höegh UK Administrative Services Agreement, Höegh UK is permitted to subcontract to Höegh Norway certain of the above-mentioned administrative services provided to us pursuant to an administrative services agreement with Höegh Norway. This agreement has an initial term of five years. The services provided under the Höegh Norway Administrative Services Agreement, as amended, will be provided in a diligent manner, as Höegh UK may reasonably direct. The Höegh Norway Administrative Services Agreement may be terminated by Höegh UK for any reason in its sole discretion upon 90 days’ written notice. The Höegh Norway 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;

an order is made to wind up the Partnership;

a final judgment, order or decree that materially and adversely affects the ability of us, our operating company or Höegh UK to perform the agreement is obtained or entered and not vacated, discharged or stayed; or

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we, our operating company or Höegh UK make or makes a general assignment for the benefit of creditors, file a petition in bankruptcy or for liquidation or commence any reorganization proceedings.

The administrative services provided by Höegh Norway to Höegh UK 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.

Each month, Höegh UK reimburses Höegh Norway for its reasonable costs and expenses incurred in connection with the provision of the services under the Höegh Norway Administrative Services Agreement. In addition Höegh Norway receives a service fee in U.S. Dollars equal to 3.0% of the costs and expenses incurred by them in connection with providing services. Amounts payable by Höegh UK must be paid promptly upon receipt of an invoice for such costs, expenses and supporting detail that may be reasonably required. Höegh UK reimbursed Höegh Norway approximately $0.6 million in total under the Höegh Norway Administrative Services Agreement for the year ended December 31, 2014

Under the Höegh Norway Administrative Services Agreement, Höegh UK will indemnify Höegh Norway 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 the subcontractor or its officers, employees and agents.

Leif Höegh UK Administrative Service Agreements

Our operating company and Höegh UK have entered into administrative services agreements with Leif Höegh UK, pursuant to which Leif Höegh UK will provide certain administrative services for an indefinite term. The services provided under the Leif Höegh UK Administrative Services Agreements will be rendered using the competence and control systems used for similar third-party services performed for and by Leif Höegh UK. Each of the Leif Höegh UK Administrative Services Agreements may be terminated by either party thereto upon three months’ notice.

The administrative services provided by Leif Höegh UK to Höegh UK include:

administration and payroll services;

provision of office facilities; and

secretarial services.

Höegh UK reimburses Leif Höegh UK for its reasonable costs and expenses incurred in connection with its administrative services agreement with Höegh UK. In addition, Leif Höegh UK receives a services fee equal to 5% of the costs and expenses of secretarial services under the agreement. Höegh UK reimbursed Leif Höegh UK approximately $0.1 million in total under this administrative services agreement for the year ended December 31, 2014.

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Leif Höegh UK occasionally performs certain administrative services directly for our operating company, for which it is reimbursed for its reasonable costs and expenses.

Joint Venture 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. or 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

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%. 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 and crewing of the vessels, each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. has entered into a ship management agreement with Höegh LNG Management, and Höegh Norway entered into a sub-technical support agreement with Höegh LNG Management for the technical management of the PGN FSRU Lampung . Each of these agreements provides that Höegh LNG Management must use its best endeavors to provide technical services, including but not limited to the following:

crew management: 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: providing competent personnel to 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.

For the ship management agreements between Höegh LNG Management and each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., either party may terminate upon 90 days’ notice. The sub-technical support agreement between Höegh LNG Management and Höegh Norway for the PGN FSRU Lampung terminates 90 days (or as otherwise agreed) after either party gives notice. Additionally, each of these 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.

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Höegh LNG Management was paid an annual management fee of approximately $672,000, $672,000 and $424,000 under the ship management agreements or sub-technical support agreement with each of SRV Joint Gas Ltd., SRV Joint Gas Two Ltd. and Höegh Norway, respectively, for the year ended December 31, 2014. 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 agreement 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. If a claim is the sole result of the negligence, gross negligence or willful default of Höegh LNG Management or its employees, agents and subcontractors, then Höegh LNG Management is liable in an amount up to 10 times the annual management fee.

Technical Information and Services Agreement

PT Hoegh entered into a technical information and services agreement with Höegh Norway, pursuant to which Höegh Norway provides PT Hoegh 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 Hoegh 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 Hoegh 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 Hoegh 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 Hoegh 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 Hoegh include:

commercial support, including:

assisting in identifying suppliers, liaising with off-shore suppliers of goods and services, assisting in identifying insurance providers; and

assisting in identifying insurance providers; and

assisting in negotiations and reviewing contracts and insurance policies;

technical support and advice, including in relation to:

identification, assessment and resolution of technical issues;

information technology;

health, safety and the environment; and

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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.

Each month, PT Hoegh 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. PT Hoegh paid Höegh Norway approximately $0.02 million total under the technical information and services agreement for the year ended December 31, 2014.

Under the technical information and services agreement, PT Hoegh 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 Hoegh’s issued share capital or any of PT Hoegh’s officers, directors, employees, agents, representatives, advisors and contractors and (iii) loss of or damage to property owned or under the custody of PT Hoegh or any party listed above in section (ii) of this paragraph.

Master Spare Parts Supply Agreement

PT Hoegh 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 Hoegh. PT Hoegh, 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 Hoegh 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 Hoegh no more than 14 days after receipt of such invoice.

Master Maintenance Agreement

PT Hoegh and Höegh Shipping entered into a master maintenance agreement, pursuant to which Höegh Shipping provides certain maintenance services to PT Hoegh. PT Hoegh, 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 Hoegh 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 Hoegh no more than 14 days after receipt of such invoice.

Sponsor Credit Facility with Höegh LNG

In connection with the closing of the IPO, we entered into a $85 million revolving credit facility with Höegh LNG, to be used to fund acquisitions and our working capital requirements. The sponsor credit facility is for a term of three years and is unsecured. Interest on drawn amounts is payable quarterly at LIBOR plus a margin of 4.0%. Additionally, we pay a 1.4% quarterly commitment fee to Hoegh LNG on undrawn available amounts under the sponsor credit facility.

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For a more detailed description of this credit facility, please read “Item 5.B —Liquidity and Capital Resources—Borrowing Activities—Sponsor Credit Facility with Höegh LNG.”

Demand Note

At the closing of the IPO, we lent $140 million to Höegh LNG, which is repayable on demand or which we can elect to utilize as part of the purchase consideration in the event we purchase all or a portion of Höegh LNG’s interests in the Independence. The note bears interest at a rate of 5.88% per annum.

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.

Other Related Party Transactions

Our activities were an integrated part of Höegh LNG until the closing of the IPO on August 12, 2014 and for each of the years ended December 31, 2013 and 2012. We entered into several agreements with Höegh LNG for the provision of services. As such, Höegh LNG has provided general and corporate management services to us. As described in note 2 to our consolidated and combined carve-out financial statements, certain administrative expenses have been included in the historical combined carve-out financial statements based on actual hours incurred. In addition, management has allocated remaining administrative expenses and Höegh LNG management’s share based payment costs based on the number of vessels, newbuildings and business development projects of Höegh LNG prior to the closing of the IPO. A subsidiary of Höegh LNG has provided the building supervision of the PGN FSRU Lampung and the Mooring and ship management for PGN FSRU Lampung.

Amounts included in the consolidated and combined carve-out statements of income for the years ended December 31, 2014, 2013 and 2012 or capitalized in the consolidated and combined carve-out balance sheets as of December 31, 2014 and 2013 are as follows:

Statement of income:	Year ended December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)
Revenues
Time charter revenues indemnified by Höegh LNG	$	13,269		$	—		$	—
Operating expenses
Vessel operating and administrative expenses(1)		(12,036	)		(6,348	)		(2,357	)
Construction contract expenses		(1,451	)		(3,738	)		(691	)
Interest income from joint ventures and demand note		4,959			2,122			2,481
Interest expense and commitment fees from Höegh LNG		(998	)		(352	)		(114	)
Total income (expense), net	$	(3,743	)	$	(8,316	)	$	(681	)

Balance sheet	As of December 31,
(in thousands of U.S. dollars)	2014		2013
Newbuilding
Newbuilding supervision cost	$	1,228	$	4,935
Interest expense capitalized from Höegh LNG		1,464		4,579
Total	$	2,692	$	9,514

146

(1)

Includes a fee of approximately $21,000 for the Technical Information and Services Agreement with Höegh LNG and a fee of approximately $423,000 for the Sub-Technical Support Agreement with Höegh Norway.

Our trade liabilities and shareholder loans to Höegh LNG and affiliates were $6.5 million and $208.6 million for the years ended December 31, 2014 and 2013, respectively. The weighted average interest rates on the outstanding balances on the shareholder loans were 4.48% and 4.29% for the years ended December 31, 2014 and 2013, respectively.

Distributions to Höegh LNG

Since our IPO in August 2014, we have declared and paid quarterly distributions totaling $4.8 million, $2.8 million of which were paid to Höegh LNG for the year ended December 31, 2014.

Interests of Experts and Counsel

Not applicable.

Item 8.

Financial Information

The information included in Item 8 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

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. We are not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on 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:

147

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 substantial majority of our business is currently conducted through our joint ventures. Under the joint venture agreement that governs our joint ventures that own the GDF Suez Neptune and the GDF Suez 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. If our joint ventures are unable to make distributions to us, it could have a material 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. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of non-affiliated common unitholders. After the subordination period has ended, our partnership agreement can be amended with the approval of a majority of the outstanding common units. Höegh LNG owns approximately 16.1% of our common units and all of our subordinated units.

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.

Under Section 51 of the Marshall Islands Act, we may not make a distribution to unitholders if the distribution would cause 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, to 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 Hoegh 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 Hoegh has positive retained earnings. Hoegh Lampung, our subsidiary holding the ownership interest in PT Hoegh, 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 may be paid to the shareholders of any company except out of profits. As of December 31, 2014, PT Hoegh has negative retained earnings and therefore cannot make dividend payments under Indonesia law.

148

Our joint ventures for the GDF Suez Neptune and the GDF Suez 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 be paid out of profits or, if profits are insufficient to make a distribution and subject to the joint venture being solvent immediately following the date on which the distribution is made, out of share premium or distributable capital reserve resulting from contributed surplus paid into the joint venture.

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. Because under both our joint ventures’ time charters and the PGN FSRU Lampung time charter, the charterer reimburses our joint venture or us, as applicable, for anticipated drydocking expenses, these are excluded from maintenance capital expenditures.

Our initial estimated maintenance and replacement capital expenditure for us and our joint ventures is $10.2 million per year for future vessel replacement. The $10.2 million is based on assumptions regarding the remaining useful life of the vessels in our initial 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 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, or $1.35 per unit per year, prior to any distribution on the subordinated units to the extent we have sufficient cash on hand to pay the distribution, after establishment of cash reserves and payment of fees and expenses. There is no guarantee that we will pay the minimum quarterly distribution on the common units and subordinated 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.

During the year ended December 31, 2014, the aggregate amount of cash distributions paid was $4.8 million.

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On February 13, 2015, we paid a $0.3375 per unit distribution with respect to the fourth quarter of 2014, equivalent to $1.35 per unit on an annualized basis. The aggregate amount of the cash distributions paid was $8.9 million.

Subordination Period

During the subordination period applicable to the subordinated units currently held by Höegh LNG, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3375 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

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. Except for transfers of incentive distribution rights to an affiliate or another entity as part of a merger or consolidation with or into, or sale of substantially all of its assets to such entity, the approval of a majority of our common units (excluding common units held by our general partner and its affiliates), voting separately as a class, generally is required for a transfer of the incentive distribution rights to a third party prior to June 30, 2019. 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
Minimum Quarterly Distribution	$0.3375		100.0	%		0	%
First Target Distribution	up to $0.388125		100.0	%		0	%
	above $0.388125
Second Target Distribution	up to $0.421875		85.0	%		15.0	%
	above $0.421875
Third Target Distribution	up to $0.50625		75.0	%		25.0	%
Thereafter	above $0.50625		50.0	%		50.0	%

Significant changes

Not applicable.

150

Item 9. The Offer and Listing

The information included in Item 9 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Offer and Listing Details

The high and low sales prices of our common units as reported by the NYSE, for the periods indicated, are as follows:

	High		Low
Year ended December 31, 2015(1)	$	23.97	$	17.80
Year ended December 31, 2014(2)		26.50		16.26
Second quarter 2015(3)		22.15		20.31
First quarter 2015		23.97		17.80
Fourth quarter 2014		24.73		16.26
Third quarter 2014(4)		26.50		21.75
Month ended April 30, 2015(3)		22.15		20.31
Month ended March 31, 2015		23.43		21.03
Month ended February 28, 2015		23.97		20.78
Month ended January 31, 2015		23.34		17.80
Month ended December 31, 2014		21.55		16.26
Month ended November 30, 2014		24.73		18.17
Month ended October 31, 2014		24.43		18.42

	(1)	For the period from January 1, 2015 through April 23, 2015.
	(2)	For the period from August 7, 2014 through December 31, 2014.
	(3)	For the period from April 1, 2015 through April 23, 2015.
	(4)	For the period from August 7, 2014 through September 30, 2014.

Plan of Distribution

Not applicable.

Markets

Our common units started trading on the NYSE under the symbol “HMLP” on August 8, 2014.

Selling Unitholders

Not applicable.

Dilution

Not applicable.

Expenses of the Issue

Not applicable.

Item 10. Additional Information

The information included in Item 10 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

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Share Capital

Not applicable.

Memorandum and Articles of Association

The information required to be disclosed under Item 10B is incorporated by reference to our Registration Statement on Form 8-A filed with the SEC on August 4, 2014.

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, each of which is included in the list of exhibits in “Item 19. Exhibits”:

(1)

Contribution, Purchase and Sale Agreement, dated August 8, 2014, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC. Please read “Item 7.B. Related Party Transactions—Contribution, Purchase and Sale Agreement.”

(2)

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.”

(3)

2014 Höegh LNG Partners LP Long-Term Incentive Plan

(4)

Höegh LNG Partners LP Non-Employee Director Compensation Plan

(5)

Employment Contract, dated November 26, 2013, between Leif Höegh (U.K.) Limited and Richard Tyrrell.

(6)

Administrative Services Agreement, dated July 2, 2014, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Hoegh LNG Services Ltd., as amended. Please read “Item 7.B. Related Party Transactions—Administrative Service Agreements–Höegh UK Administrative Service Agreement.”

(7)

Administrative Services Agreement, dated July 2, 2014, between Hoegh LNG Services Ltd and Höegh LNG AS, as amended. Please read “Item 7.B. Related Party Transactions—Administrative Service Agreements—Höegh Norway Administrative Service Agreement.”

(8)

Administrative Services Agreement, dated October 28, 2014, between Leif Hoegh (U.K.) Limited and Höegh LNG Partners Operating LLC. “Item 7.B. Related Party Transactions—Administrative Service Agreements—Leif Höegh UK Administrative Service Agreements.”

(9)

Administrative Services Agreement, dated October 28, 2014, between Leif Hoegh (U.K.) Limited and Hoegh LNG Services Ltd. Please read “Item 7.B. Related Party Transactions—Administrative Service Agreements—Leif Höegh UK Administrative Service Agreements.”

(10)

Commercial Management and Administration Management Agreement, dated November 24, 2009, between SRV Joint Gas Ltd. and Höegh LNG AS (GDF Suez Neptune). Please read “Item 7.B. Related Party Transactions—Joint Venture Commercial and Administration Agreements.”

(11)

Commercial Management and Administration Management Agreement, dated May 19, 2010, between SRV Joint Gas Two Ltd. and Höegh LNG AS (GDF Suez Cape Ann). Please read “Item 7.B. Related Party Transactions—Joint Venture Commercial and Administration Agreements.”

(12)

Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Ltd. and Höegh LNG Fleet Management AS (GDF Suez Neptune). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

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(13)

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 (GDF Suez Cape Ann). Please read “Item 7.B. Related Party Transactions—Ship Management Agreements and Sub-Technical Agreements.”

(14)

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.”

(15)

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.”

(16)

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.”

(17)

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.”

(18)

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. and GDF Suez LNG Supply SA (GDF Suez Neptune). Please read “Item 4.B. Business Overview—Vessel Time Charters—GDF Suez Neptune Time Charter.”

(19)

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. (GDF Suez Cape Ann). Please read “Item 4.B. Business Overview—Vessel Time Charters.”

(20)

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 Hoegh 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 Hoegh LNG Lampung (PGN FSRU Lampung). Please read “Item 4.B. Business Overview—Vessel Time Charters—PGN FSRU Lampung Time Charter.”

(21)

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.”

153

(22)

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.”

(23)

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.

(24)

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.

(25)

Amendment and Restatement Agreement, dated October 9, 2013, among Hoegh LNG Lampung Pte Ltd., PT Bahtera Daya Utama and PT Imeco Inter Sarana.

(26)

Revolving Loan Agreement, dated August 12, 2014, between Höegh LNG Partners LP and Höegh LNG Holdings Ltd. in the amount of $85,000,000. Please read “Item 7.B. Related Party Transactions—Sponsor Credit Facility with Höegh LNG.”

(27)

Demand Note, dated August 12, 2014, issued by Höegh LNG Holdings Ltd. in favor of Höegh LNG Partners LP in the amount of $140,000,000. Please read “Item 7.B. Related Party Transactions—Demand Note.”

(28)

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. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Neptune Facility.”

(29)

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. Please read “Item 5.B. Liquidity and Capital Resources—Borrowing Activities—Joint Ventures Debt—Cape Ann Facility.”

(30)

$299 Million Lampung Facility Agreement, dated September 12, 2013, between PT Hoegh 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.”

(31)

License Agreement, between Leif Höegh & Co. Ltd. and Höegh LNG Partners LP. Please read “Item 7.B. Related Party Transactions—License Agreement.”

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 holders of our securities.

Taxation

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, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership to vary substantially from the consequences described below.

154

The following discussion applies only to beneficial owners of common units that own the common 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 or former citizens or long-term residents of the United States), persons who will hold the units as part of a straddle, hedge, 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, the tax treatment of its partners generally will depend on the status of the partner and the activities of the limited partnership. If you are a partner in a partnership holding our common units, you should consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of our common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. The opinions and 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. 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.

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 directly be 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 that owns (actually or constructively) less than 10.0% of the value or voting power of our equity and 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 jurisdiction 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 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. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in its common units and thereafter as capital gain. U.S. Holders that are corporations generally will not be entitled to claim a dividends 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 generally will be treated as “passive category income” for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes.

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Dividends received with respect to our common 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” that is taxable to such U.S. Individual Holder at preferential capital gain tax rates provided that: (i) our common units are readily tradable on an established securities market in the United States (such as the NYSE on which our common units are traded); (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 for more than 60 days during the 121-day period beginning 60 days before the date on which the common units become ex-dividend (and has not entered into certain risk limiting transactions with respect to such common 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. In addition, the preferential tax rate on dividends does not apply to dividends received by a U.S. Individual Holder to the extent that the U.S. Individual Holder elects to treat such dividends as investment income that may be offset by investment expenses. There is no assurance that any dividends paid on our common 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 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 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. 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 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 will be treated as long-term capital loss to the extent of the amount of such dividend.

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Sale, Exchange or Other Disposition of Common 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 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 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 the 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.

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 units, either:

at least 75.0% of our gross income (including the gross income of our vessel-owning subsidiaries) for such taxable year consists of passive income (e.g., dividends, interest, capital gains and rents derived other than in the active conduct of a rental business); or

at least 50.0% of the average of the values of the assets held by us (including the assets of our vessel-owning joint ventures and subsidiaries) at the end of each quarter 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 should 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 our initial taxable year, and we expect that we will not be a PFIC for the current and any future taxable year. We expect 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. 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.

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Moreover, there are legal uncertainties in determining whether the income 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, and the opinion of our counsel is not binding on the IRS or any court. Thus, it is possible that the IRS or a court could disagree with this 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, 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 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, that 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 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 common 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. 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 will provide each U.S. Holder with the information necessary to make the QEF election described above.

Taxation of U.S. Holders Making a “Mark-to-Market” Election

If we were to be treated as a PFIC for any taxable year and, as we anticipate, our 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, 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 at the end of the taxable year over the holder’s adjusted tax basis in the common 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 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 would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our common units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units 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.

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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, 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 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 the common units) and (ii) any gain realized on the sale, exchange or other disposition of the units. These special rules would apply for all periods in which the Non-Electing Holder holds its common units, even if we ceased to be a PFIC. 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;

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 in the current year; 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.

U.S. Federal Income Taxation of Non-U.S. Holders

A beneficial owner of our common 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, you should consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of our common units.

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. 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% rate (or, if applicable, a lower treaty rate). However, distributions paid to a Non-U.S. Holder that is engaged in a U.S. trade or business may be exempt from taxation under an applicable income tax treaty if the income arising from the distribution is not attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder.

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 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). 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 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.

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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 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-BEN-E, W-8ECI 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.

U.S. Holders purchasing more than $100,000 of our common units generally will be required to file IRS Form 926 reporting that payment to us. For purposes of determining the total dollar value of common units purchased, units purchased by certain related parties (including family members) are included. Substantial penalties may be imposed upon a U.S. Holder that fails to comply with this reporting obligation. Each U.S. Holder should consult its own tax advisor as to the possible obligation to file IRS Form 926.

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 obligations, if any, under this legislation that would result from their purchase, ownership or disposition of our units.

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 in the Republic of the Marshall Islands.

Because we and our subsidiaries do not and do not expect to conduct business 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, and you will not be required by the Republic of the Marshall Islands to file a tax return relating to your ownership of common units.

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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, 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 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. 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. 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.

United Kingdom Tax Consequences

The following is a discussion of the material United Kingdom tax consequences that may be relevant to prospective unitholders who are persons not resident or not domiciled in the United Kingdom for taxation purposes and who do not acquire their units as part of a trade, profession or vocation carried on in the United Kingdom, which we refer to as “Non-UK Holders.”

Prospective unitholders who are resident or domiciled in the United Kingdom for taxation purposes, or who hold their units through a trade, profession or vocation in the United Kingdom are urged to consult their own tax advisors regarding the potential United Kingdom tax consequences to them of an investment in our common units and are responsible for filing their own UK tax returns and paying any applicable UK taxes (which may be due on amounts received by us but not distributed). The discussion that follows is based upon current United Kingdom tax law and what is understood to be the current practice of HM Revenue and Customs as at the date of this document, both of which are subject to change, possibly with retrospective effect.

Taxation of income and disposals. We expect to conduct our affairs so that Non-UK Holders should not be subject to United Kingdom income tax, capital gains tax or corporation tax on income or gains arising from the Partnership. Distributions may be made to Non-UK Holders without withholding or deduction for or on account of United Kingdom income tax.

Stamp taxes. No liability to United Kingdom stamp duty or stamp duty reserve tax should arise in connection with the issue of units to unitholders or the transfer of units in the Partnership.

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Singapore Tax Consequences

The following is a discussion of the material Singapore tax consequences that may be relevant to prospective unitholders. 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 unitholders.

Prospective unitholders who are persons not resident in Singapore for taxation purposes and who do not acquire their units as part of a trade, profession or vocation carried on in Singapore should not be subject to Singapore income tax, or corporate tax on income or gains arising from the Partnership.

Prospective unitholders who are resident in Singapore for taxation purposes, or who hold their units through a trade, profession or vocation in Singapore are urged to consult their own tax advisors regarding the potential Singapore tax consequences to them of an investment in our common units and are responsible for filing their own Singapore tax returns and paying any applicable Singapore taxes (which may be due on amounts received by us but not distributed).

No liability to Singapore stamp duty should arise in connection with the issue of units to unitholders or the transfer of units in the Partnership.

Indonesian Tax Consequences

Prospective unitholders who are persons not resident in Indonesia for taxation purposes should not be subject to Indonesian income tax, or corporate tax on income or gains arising from the Partnership.

Prospective unitholders who are resident in Indonesia for taxation purposes or have a permanent establishment in Indonesia are urged to consult their own tax advisors regarding the potential Indonesian tax consequences to them of an investment in our common units and are responsible for filing their own Indonesian tax returns and paying any applicable Indonesian taxes (which may be due on amounts received by us but not distributed).

No liability to Indonesian stamp duty should arise in connection with the issue of units to unitholders or the transfer of units in the Partnership.

EACH PROSPECTIVE UNITHOLDER IS URGED TO CONSULT ITS OWN TAX COUNSEL OR OTHER ADVISOR WITH REGARD TO THE LEGAL AND TAX CONSEQUENCES OF UNIT OWNERSHIP UNDER ITS PARTICULAR CIRCUMSTANCES.

Dividends and Paying Agents

Not applicable.

Statement by Experts

Not applicable.

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Documents on Display

Documents concerning us that are referred to in this Annual Report may be inspected at our offices at Wessex House, 5th Floor, 45 Reid Street, Hamilton, HM12, Bermuda. 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, free of charge, or from the SEC’s Public Reference Section at 100 F Street, NE, Washington, D.C. 20549, at prescribed rates. Further information on the operation of the SEC Public Reference Section may be obtained by calling the SEC at 1-800-SEC-0330.

Subsidiary Information

Not applicable.

Item 11. Quantitative and Qualitative Disclosures About Market Risk

The information included in Item 11 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

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, 2014, there are interest rate swap agreements on the Lampung floating rate debt that are designated as cash flow hedges for accounting purposes. The notional amounts of the designated interest rate swaps amortize over 12 years to match the outstanding principal on the Lampung facility. No derivative instruments were outstanding as of December 31, 2013. Please read note 14 to our consolidated and combined carve-out financial statements.

As of December 31, 2014, the following interest rate swap agreements were outstanding:

(in thousands of U.S. dollars)	Interest rate index	Notional amount		Fair value carrying amount liability			Term	Fixed interest rate(1)
LIBOR-based debt
Interest rate swaps (2)	LIBOR	$	212,333	$	(9,220	)	Sept 2026		2.8	%

	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.

Our joint ventures have utilized interest rate swap contracts as described in note 13 to our joint ventures’ combined financial statements.

Foreign Currency Risk

All revenues, financing, interest expenses from financing and most expenditures for our assets 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, 2014, 2013 and 2012, no derivative financial instruments have been used to manage foreign exchange risk.

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Credit risk

Concentration of Risk

Financial instruments, which potentially subject the Partnership to significant concentrations of risk, consist principally of cash and cash equivalents, restricted cash, trade receivables 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 counter parties. There is a single charterer 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. No allowance for doubtful accounts was recorded for the year ended December 31, 2014. 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 charter terminate prematurely, there could be delays in obtaining a new time charter and the rates could be lower depending upon the prevailing market conditions.

Item 12. Description of Securities Other than Equity Securities

The information included in Item 12 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

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PART II

Item 13. Defaults, Dividend Arrearages and Delinquencies

The information included in Item 13 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

As of December 31, 2014, 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

The information included in Item 14 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

In August 7, 2014, the Form F-1 relating to our IPO, SEC file number 333-197228, was declared effective. We closed our IPO on August 12, 2014, and issued and sold through the underwriters to the public 11,040,000 common units (including 1,440,000 common units sold pursuant to the underwriters’ option to purchase additional common units). We issued to Höegh LNG 2,116,060 common units and 13,156,060 subordinated units and 100% of the incentive distribution rights (“IDRs”), which will entitle Höegh LNG to increasing percentages of the cash we distribute in excess of $0.388125 per unit per quarter. We issued to Höegh LNG GP LLC, a wholly owned subsidiary of Höegh LNG, a non-economic general partner interest in us. Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC served as managing underwriters of our IPO. The common units were sold for $20.00 per unit resulting in gross proceeds of $220.8 million. The net proceeds of the offering were approximately $203.5 million. Net proceeds is after deduction of underwriters’ discounts, structuring fees and reimbursements and the incremental direct costs attributable to the IPO that were deferred and charged against the proceeds of the offering. We applied the net proceeds of the offering as follows: (i) $140 million to make a loan to Höegh LNG in exchange for a note bearing interest at a rate of 5.88% per annum, which is repayable on demand or which we can elect to utilize as part of the purchase consideration in the event we purchase all or a portion of Höegh LNG’s interests in the Independence , (ii) $20 million for general partnership purposes and (iii) the remainder of approximately $43.5 million to make a cash distribution to Höegh LNG.

Item 15. Controls and Procedures (Restated)

During 2015 we identified errors in the accounting for certain Indonesian value added tax (“VAT”) related to our subsidiary, PT Hoegh LNG Lampung. As a result, we initiated a review of these VAT transactions and balances for the years ended December 31, 2014 and 2013. We subsequently expanded the review to include Indonesian withholding tax (“WHT”) transactions and balances.

As a result of this review, we determined that our accounting for Indonesian VAT and WHT was incorrect. In addition, these accounting errors also affected recognition of certain revenue for reimbursable tax amounts, recognition of revenues for our direct financing lease and amortization of deferred debt issuance cost. To correct these errors, we have restated, in this Form 20-F/A, our historical consolidated and combined carve-out balance sheets as of December 31, 2014 and 2013, our consolidated and combined carve-out statements of income, comprehensive income, changes in partners’ capital/owners’ equity and cash flows for the years ended December 31, 2014 and 2013 and selected financial data as of and for the years ended December 31, 2014 and 2013.

As a result of the identified accounting errors, we identified a material weakness in our internal control over financial reporting which is described further below.

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Disclosure Controls and Procedures

In connection with the restatement, under the direction of our Chief Executive Officer and Chief Financial Officer, we re-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, 2014. We, including our Chief Executive Officer and Chief Financial Officer, have concluded based upon this re-evaluation and considering the material weakness in internal controls over financial reporting described below that, as of such date, our disclosure controls and procedures were not effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act was (i) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding such required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms. Following this conclusion, we have taken or plan to take the remedial actions set forth below in “Material Weakness and Remediation Plans.”

Management’s Annual Report on Internal Control over Financial Reporting

This Annual Report does not include a report of management on our internal control over financial reporting due to a transition period established by rules of the SEC for newly public companies.

Attestation Report of the Registered Public Accounting Firm

This Annual Report does not include an attestation report of the Partnership’s registered public accounting firm due to a transition period established by rules of the SEC for emerging growth companies.

Material Weakness and Remediation Plans

Our management is responsible for establishing and maintaining for us adequate internal control over financial reporting. Internal controls are designed to provide reasonable assurance as to 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 controls over financial reporting include 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 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.

In connection with the preparation of this Form 20-F/A, we have concluded that a material weakness existed in our internal control over financial reporting as of December 31, 2014 and we have made changes to our internal controls based on this conclusion. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Specifically, we identified a combination of control deficiencies related to the accounting treatment for certain Indonesian VAT and WHT transactions for the year ended December 31, 2014, which constituted a material weakness in our internal control of financial reporting. In particular, we did not have controls that were designed and implemented in order to:

Appropriately understand the Indonesian tax regulations, and the implications of such regulations on financial reporting,

ii)

Reconcile transaction information provided to our tax advisors to our accounting records, and

iii)

Reconcile the WHT and VAT amounts and payments included in filings made with the Indonesian tax authorities to recorded amounts in our accounting records.

166

Additionally we did not design and implement management oversight controls over Indonesian and foreign jurisdiction tax reporting relevant to our consolidated financial statements.

As a result of the errors in the accounting treatment for the VAT and WHT transactions for the year ended December 31, 2014, there was also a control deficiency in identifying qualifying reimbursable Indonesian taxes incurred as a basis for revenue recognition of the deferred revenue related to the tax element under PT Hoegh LNG Lampung’s time charter.

Remediation of material weakness in internal control over financial reporting

Subsequent to December 31, 2014, we have taken or are planning to take the remedial actions set forth below to address the combination of deficiencies resulting in a material weakness in our internal control over financial reporting related to our accounting treatment for certain Indonesian VAT and WHT transactions:

Continuing to improve the control environment through (i) engaging the services of a sufficient number of personnel to be employed by Höegh LNG appropriately qualified to perform controls over VAT and WHT in Indonesia, (ii) increasing the knowledge and experience of our internal control requirements through ongoing training and engaging the services of qualified personnel, and (iii) designing and implementing management oversight controls over accounting for Indonesian and other foreign jurisdiction taxes through engaging the services of a tax compliance officer to be employed by Höegh LNG;

Designing and implementing controls to ensure capture and recording of VAT and WHT transactions in our consolidated financial statements through monthly reconciliations of our accounting records to:

transaction information provided to our tax advisors, and

WHT and VAT amounts and payments included in filings with the Indonesian tax authorities

Updating and increasing local involvement with review of work performed by accounting personnel in relation to local tax requirements and tax requirements arising from commercial issues,

We believe the remediation measures described above will remediate the material weakness we have identified and strengthen our internal control over financial reporting. We are committed to continuing to improve our internal control processes and will continue to review our financial reporting controls and procedures. We expect that our remediation efforts, including design, implementation and testing of our remediation measures will continue through the end of 2015 and into 2016. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address control deficiencies or determine to modify certain of the remediation measures described above.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the period covered by this Form 20/F-A that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16A.

Audit Committee Financial Expert

The information included in Item 16A in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Our board of directors has determined that David Spivak qualifies as an audit committee financial expert and is independent under applicable NYSE and SEC standards.

Item 16B.

Code of Ethics

The information included in Item 16B in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing

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

The information included in Item 16C in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Our principal accountant for 2014 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 2014.

167

Fees Incurred by the Partnership for Ernst & Young AS’ Services

(In thousands of U.S. dollars)	2014		2013
Audit Fees	$	714	$	1,675
Audit-Related Fees		319		—
Tax Fees		—		—
All Other Fees		—		—
	$	1,033	$	1,675

Audit Fees

Audit fees for 2014 and 2013 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.

Audit-Related Fees

Audit-related fees for 2014 are the aggregate fees billed for professional services rendered by the principal accountant related to assurance work in connection with the comfort letter and review of the prospectus associated with our IPO in August 2014 that have not been reported under “—Audit Fees” above.

Item 16D.

Exemptions from the Listing Standards for Audit Committees

The information included in Item 16D in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The information included in Item 16E in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

168

Item 16F.

Change in Registrants’ Certifying Accountant

The information included in Item 16F in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing

Not applicable.

Item 16G.

Corporate Governance

The information included in Item 16G in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

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 Mr. Harris, 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.

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.

169

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

The information included in Item 16H in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

170

PART III

Item 17. Financial Statements

The information included in Item 17 in the Original Filing has not been updated for information or events occurring after the date of the Original Filing and has not been updated to reflect the passage of time since the date of the Original Filing.

Not applicable.

Item 18. Financial Statements (Restated)

The restated consolidated and combined carve-out financial statements of Höegh LNG Partners LP and schedule set forth on pages F-1 through F-54 and Exhibit 15.1 and the combined financial statements of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. set forth on pages F-55 through F-74, 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 (Restated)

The information included in Item 19 has been updated to indicate the exhibits filed with the Original Filing and to indicate the filing of a new Exhibit 4.32, but has not been otherwise updated for information or events occurring after the date of the Original Filing or to reflect the passage of time since the date of the Original Filing. Restated versions of Exhibits 12.1, 13.1, 15.1 and each of the XBRL exhibits have been filed as part of this 20-F/A.

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	First Amended and Restated Agreement of Limited Partnership of Höegh LNG Partners LP, dated August 12, 2014, between Höegh LNG GP LLC and Höegh LNG Holdings Ltd. (incorporated by reference to Exhibit 1.2 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.1	Contribution, Purchase and Sale Agreement, dated August 8, 2014, among Höegh LNG Holdings Ltd., Höegh LNG Ltd., Höegh LNG Partners LP, Höegh LNG GP LLC and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.1 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.2	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)

4.3	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)

4.4	Höegh LNG Partners LP Non-Employee Director Compensation Plan (incorporated by reference to Exhibit 10.4 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)

171

4.5	Employment Contract, dated November 26, 2013, between Leif Höegh (U.K.) Limited and Richard Tyrrell (incorporated by reference to Exhibit 10.5 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)

4.6	Administrative Services Agreement, dated July 2, 2014, among Höegh LNG Partners LP, Höegh LNG Partners Operating LLC and Hoegh LNG Services Ltd., as amended (incorporated by reference to Exhibit 4.6 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.7	Administrative Services Agreement, dated July 2, 2014, between Hoegh LNG Services Ltd and Höegh LNG AS, as amended (incorporated by reference to Exhibit 4.7 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.8	Commercial Management and Administration Management Agreement, dated November 24, 2009, between SRV Joint Gas Ltd. and Höegh LNG AS (GDF Suez Neptune) (incorporated by reference to Exhibit 10.8 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)

4.9	Commercial Management and Administration Management Agreement, dated May 19, 2010, between SRV Joint Gas Two Ltd. and Höegh LNG AS (GDF Suez 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)

4.10	Baltic and International Maritime Council Standard Ship Management Agreement, dated April 23, 2014, between SRV Joint Gas Ltd. and Höegh LNG Fleet Management AS (GDF Suez 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)

4.11	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 (GDF Suez 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)

4.12	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 (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†	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 (GDF Suez Neptune) (incorporated by reference to Exhibit 10.16 to the registrant’s Form F-1 Registration Statement (333-197228), filed on July 3, 2014)

172

4.16.1††	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 (GDF Suez Neptune) (incorporated by reference to Exhibit 4.16.1 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.16.2††	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 (GDF Suez Neptune) (incorporated by reference to Exhibit 4.16.2 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.16.3†	Amendment No. 3, dated April 23, 2014, to the SRV LNG Carrier Time Charterparty (GDF Suez 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)

4.17†	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 (GDF Suez 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)

4.17.1†	Amendment No. 3, dated April 23, 2014, to the SRV LNG Carrier Time Charterparty (GDF Suez 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)

4.18†	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 Hoegh 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 Hoegh 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)

173

Exhibit
Number	Description
4.19	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)

4.20	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)

4.21	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)

4.22	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)

4.23	Amendment and Restatement Agreement, dated October 9, 2013, among Hoegh 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)

4.24	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)

4.25	Demand Note, dated August 12, 2014, issued by Höegh LNG Holdings Ltd. in favor of Höegh LNG Partners LP in the amount of $140,000,000 (incorporated by reference to Exhibit 4.25 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.26	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)

4.27	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)

4.28	$299 Million Lampung Facility Agreement, dated September 12, 2013, between PT Hoegh 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)

4.29	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)

4.30	Administrative Services Agreement, dated October 28, 2014, between Leif Hoegh (U.K.) Limited and Höegh LNG Partners Operating LLC (incorporated by reference to Exhibit 4.30 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

174

4.31	Administrative Services Agreement, dated October 28, 2014, between Leif Hoegh (U.K.) Limited and Hoegh LNG Services Ltd. (incorporated by reference to Exhibit 4.31 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

4.32*	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

8.1	Subsidiaries of Höegh LNG Partners LP (incorporated by reference to Exhibit 8.1 to the registrant’s Annual Report on Form 20-F, filed on April 24, 2015)

12.1*	Rule 13a-14(a)/15d-14(a) Certification of the Principal Executive Officer and the Principal Financial Officer

13.1*	Certification under Section 906 of the Sarbanes-Oxley Act of 2002 of the Principal Executive Officer and the Principal Financial Officer

15.1*	Schedule I - Condensed Financial Information of Registrant (Restated)

101.INS*	XBRL Instance Document

101.SCH*	XBRL Taxonomy Extension Schema

101.CAL*	XBRL Taxonomy Extension Schema Calculation Linkbase

101.DEF*	XBRL Taxonomy Extension Schema Definition Linkbase

101.LAB*	XBRL Taxonomy Extension Schema Label Linkbase

101.PRE*	XBRL Taxonomy Extension Schema Presentation Linkbase

	*	Filed herewith.
	†	Certain portions have been omitted pursuant to a confidential treatment order. Omitted information has been filed separately with the SEC.
	††	Confidential treatment has been requested for portions of this exhibit. These portions have been omitted from the Annual Report and submitted separately to the Securities and Exchange Commission.

175

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

	By:	/s/ RICHARD TYRRELL
	Name:	Richard Tyrrell
	Title:	Chief Executive Officer and Chief Financial Officer

Date: November 30, 2015

176

INDEX TO THE FINANCIAL STATEMENTS

Höegh LNG Partners LP
Audited Consolidated and Combined Carve-Out Financial Statements
Report of Independent Registered Public Accounting Firm	F-2
Consolidated and Combined Carve-Out Statements of Income for the Years Ended December 31, 2014, 2013 and 2012	F-3
Consolidated and Combined Carve-Out Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	F-4
Consolidated and Combined Carve-Out Balance Sheets as of December 31, 2014 and 2013	F-5
Consolidated and Combined Carve-Out Statements of Changes In Partners’ Capital/Owner’s Equity for the Years Ended December 31, 2014, 2013 and 2012	F-7
Consolidated and Combined Carve-Out Statements of Cash Flows for the Year Ended December 31, 2014, 2013 and 2012	F-8
Notes to the Consolidated and Combined Carve-Out Financial Statements	F-10

SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd.
Audited Combined Financial Statements
Report of Independent Auditors	F-55
Combined Statements of Income for the Years Ended December 31, 2014, 2013 and 2012	F-56
Combined Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	F-57
Combined Balance Sheets as of December 31, 2014 and 2013	F-58
Combined Statements of Changes in Equity for the Years Ended December 31, 2014, 2013 and 2012	F-59
Combined Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F-60
Notes to the Combined Financial Statements	F-61

Exhibit 15.1 Schedule I - Condensed Financial Information of Registrant

Report of Independent Registered Public Accounting Firm

The Board of Directors of Höegh LNG Partners LP

We have audited the accompanying consolidated and combined carve-out balance sheets of Höegh LNG Partners LP as of December 31, 2014 and 2013, as described in Note 2 (a) and (b), and the related consolidated and combined carve-out statements of income, comprehensive income, changes in partners’ capital/owner’s equity, and cash flows for each of the three years in the period ended December 31, 2014. Our audit also included the financial statement schedule listed in the Index at Item 18. These consolidated and combined carve-out financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated and combined carve-out financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated and combined carve-out financial position of Höegh LNG Partners LP at December 31, 2014 and 2013, and the consolidated and combined carve-out results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ Ernst & Young AS
Oslo, Norway
April 24, 2015

except as to Note 2 d and Note 17, as to which the date is

November 30, 2015

F-2

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars, except per unit amounts)

		Restated - Note 2.d
	Notes	2014			2013			2012
REVENUES
Time charter revenues	5,17,20	$	22,227			—		$	—
Construction contract revenues	6,9,17		51,868			51,062			5,512
Other revenue			474			511			—
Total revenues	5		74,569			51,573			5,512
OPERATING EXPENSES
Voyage expenses			(1,139	)		—			—
Vessel operating expenses	17		(6,197	)		—			—
Construction contract expenses	6,9,20		(38,570	)		(43,958	)		(5,512	)
Administrative expenses			(12,566	)		(8,043	)		(3,185	)
Depreciation and amortization	12		(1,317	)		(8	)		—
Total operating expenses			(59,789	)		(52,009	)		(8,697	)
Equity in earnings (losses) of joint ventures	4,16		(5,330	)		40,228			5,007
Operating income	4		9,450			39,792			1,822
FINANCIAL INCOME (EXPENSES), NET
Interest income	17		4,959			2,122			2,481
Interest expense	17		(9,665	)		(352	)		(114	)
Loss on derivative financial instruments	19		(161	)		—			—
Other items, net			(2,788	)		(1,096	)		(1	)
Total financial income (expense), net	7		(7,655	)		674			2,366
Income before tax			1,795			40,466			4,188
Income tax expense	8		(481	)		—			—
Net income	4	$	1,314			40,466		$	4,188

Earnings per unit	22
Common unit public (basic and diluted)		$	0.50			—			—
Common unit Höegh LNG (basic and diluted)		$	0.50			—			—
Subordinated unit (basic and diluted)		$	0.50			—			—

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-3

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

		Restated - Note 2.d
	Notes	2014			2013		2012
Net income		$	1,314			40,466	$	4,188
Unrealized losses on cash flow hedge	19		(10,159	)		—		—
Income tax benefit	8,19		1,984			—		—
Other comprehensive income			(8,175	)		—		—
Comprehensive income (loss)		$	(6,861	)		40,466	$	4,188

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-4

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(in thousands of U.S. dollars)

		Restated - Note 2.d.
	Notes	2014		2013
ASSETS
Current assets
Cash and cash equivalents	18	$	30,477	$	108
Restricted cash	18		21,935		—
Trade receivables			6,189		—
Unbilled construction contract income	9		—		55,174
Demand note due from owner	17,18		143,241		—
Advances to joint ventures	13,18		6,665		7,112
Deferred debt issuance cost	10		2,574		2,725
Current portion of net investment in direct financing lease	5		2,894		—
Current deferred tax asset	8		343		—
Prepaid expenses and other receivables			564		705
Total current assets			214,882		65,824
Long-term assets
Restricted cash	18		15,184		10,700
Newbuildings	4,12,17		—		122,572
Other equipment			54		85
Advances to joint ventures	13,18		12,287		17,398
Deferred debt issuance cost	10		11,556		7,742
Deferred charges			—		3,912
Net investment in direct financing lease	5		292,469		—
Long-term deferred tax asset	8		1,667		391
Other long-term assets	11		15,449		—
Total long-term assets			348,666		162,800
Total assets		$	563,548	$	228,624

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-5

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(in thousands of U.S. dollars)

		Restated - Note 2.d.
	Notes	2014			2013
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	14,18	$	19,062		$	—
Trade payables			864			—
Amounts due to owners and affiliates	17,18		6,019			15,207
Loans and promissory notes due to owners and affiliates	2a,17,18		467			193,430
Value added and withholding tax liability			3,066			4,615
Derivative financial instruments	18,19		4,676			—
Current deferred tax liability	8		—			391
Accrued liabilities and other payables	15		13,365			7,843
Total current liabilities			47,519			221,486

Long-term liabilities
Accumulated losses of joint ventures	4,16		59,630			54,300
Long-term debt	14,18		193,271			—
Derivative financial instruments	18,19		4,544			—
Prepaid and deferred revenue			—			934
Other long-term liabilities	11		22,206			—
Total long-term liabilities			279,651			55,234
Total liabilities			327,170			276,720
EQUITY	2a,3
Owner's equity			—			(48,096	)
Common units public			207,004			—
Common units Höegh LNG			5,202			—
Subordinated units			32,347			—
Total Partners' capital			244,553			—
Accumulated other comprehensive income			(8,175	)		—
Total equity			236,378			(48,096	)
Total liabilities and equity		$	563,548		$	228,624

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-6

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF

CHANGES IN PARTNERS’ CAPITAL/OWNER’S EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

	Restated - Note 2.d
				Partners’ Capital
	Owner's Equity			Common Units Public			Common Units Höegh LNG			Sub- ordinated Units			Accumulated Other Comprehensive Income			Total Equity
Combined carve-out balance as of January 1, 2012	$	(65,196	)		—			—			—			—		$	(65,196	)
Carve-out net income		4,188			—			—			—			—			4,188
Carve-out distributions to owner, net		7,779			—			—			—			—			7,779
Combined carve-out balance as of December 31, 2012		(53,229	)		—			—			—			—			(53,229	)
Carve-out net income		40,466			—			—			—			—			40,466
Carve-out distributions to owner, net		(35,333	)		—			—			—			—			(35,333	)
Combined carve-out balance as of December 31, 2013		(48,096	)		—			—			—			—			(48,096	)
Carve-out net loss (January 1- August 12, 2014)		(11,941	)		—			—			—			—			(11,941	)
Other comprehensive loss		—			—			—			—			(5,900	)		(5,900	)
Conversion of promissory note to equity		101,500			—			—			—			—			101,500
Carve-out distributions to owner, net		(11,039	)		—			—			—			—			(11,039	)
Combined carve-out balance as of August 12, 2014		30,424			—			—			—			(5,900	)		24,524
Elimination of equity (note 2)		45,799			—			—			—			—			45,799
Allocation of partnership capital to unitholders August 12, 2014		(76,223	)		—			10,561			65,662			—			—
Net proceeds from IPO net of underwriters' discounts, fees and expenses of offering (note 3)		—			203,467			—			—			—			203,467
Cash distribution of initial public offering proceeds to Höegh LNG		—			—			(6,023	)		(37,444	)		—			(43,467	)
Post-initial public offering net income (note 3)		—			5,562			1,066			6,627			—			13,255
Cash distributions to unitholders		—			(2,025	)		(388	)		(2,413	)					(4,826	)
Other comprehensive loss		—			—			—			—			(2,275	)		(2,275	)
Distributions to owner, net		—			—			(14	)		(85	)		—			(99	)
Consolidated balance as of December 31, 2014	$	—			207,004			5,202			32,347			(8,175	)	$	236,378

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-7

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

	Restated - Note 2.d.
	2014			2013			2012
OPERATING ACTIVITIES
Net income	$	1,314			40,466		$	4,188
Adjustments to reconcile net income to net cash used in operating activities:
Cash received and recorded as deferred revenue		—			—			934
Depreciation and amortization		1,317			8			—
Equity in earnings of joint ventures		5,330			(40,228	)		(5,007	)
Changes in accrued interest income on advances to joint ventures and demand note		(4,349	)		(1,381	)		(1,619	)
Amortization and write off of deferred debt issuance cost		4,362			379			379
Changes in accrued interest expense		1,146			352			114
Refundable value added tax liability on import		(26,298	)		—			—
Net currency exchange losses (gains)		(271	)		—			—
Unrealized loss on financial instruments		161			—			—
Other adjustments		35			(38	)		(2,187	)
Changes in working capital:
Restricted cash		(22,180	)		—			—
Trade receivables		(6,115	)		(58	)		—
Unbilled construction contract income		55,174			(51,062	)		(4,111	)
Prepaid expenses and other receivables		26			(530	)		—
Trade payables		864			(212	)		143
Amounts due to owners and affiliates		6,019			—			—
Value added and withholding tax liability		7,660			4,614			—
Accrued liabilities and other payables		3,781			6,473			(469	)
Net cash provided by (used in) operating activities		27,976			(41,217	)		(7,635	)

INVESTING ACTIVITIES
Expenditure for newbuildings and other equipment		(170,906	)		(36,323	)		(57,768	)
Demand note made to Höegh LNG		(140,000	)		—			—
Receipts from repayment of principal on advances to joint ventures		6,666			5,542			6,009
Receipts from repayment of principal on direct financing lease		1,341			—			—
(Increase) decrease in restricted cash		10,700			—			(9,950	)
Net cash provided by (used in) investing activities	$	(292,199	)		(30,781	)	$	(61,709	)

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-8

HÖEGH LNG PARTNERS LP

CONSOLIDATED AND COMBINED CARVE-OUT STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

	Restated - Note 2.d.
	2014			2013			2012
FINANCING ACTIVITIES
Proceeds from long-term debt	$	257,099			—		$	—
Proceeds from amounts due to owners and affiliates		10,193			15,207			—
Proceeds from loans and promissory notes due to owners and affiliates		650			101,493			61,664
Repayment of long-term debt		(44,766	)		—			—
Repayment of amounts due to owners and affiliates		(25,400	)		—			—
Repayment of loans and promissory notes due to owners and affiliates		(49,150	)		—			—
Contributions from (distributions to) owner		(11,198	)		(35,333	)		7,780
Customer loan for funding of value added liability on import		26,297			—			—
Payment of debt issuance cost		(8,023	)		(9,361	)		—
Proceeds from initial public offering, net of underwriters' discounts and expenses of offering (note 3)		203,467			—			—
Cash from proceeds of initial public offering distributed to Höegh LNG		(43,467	)		—			—
Cash distributions to owners		(4,826	)		—			—
Cash settlement of derivative financial instruments		(1,100	)		—			—
(Increase) decrease in restricted cash		(15,184	)		—			—
Net cash provided by financing activities		294,592			72,006			69,444

Increase (decrease) in cash and cash equivalents		30,369			8			100
Effect of exchange rate changes on cash and cash equivalents		—			—			—
Cash and cash equivalents, beginning of period		108			100			—
Cash and cash equivalents, end of period	$	30,477			108		$	100

The accompanying notes are an integral part of the consolidated and combined carve-out financial statements.

F-9

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 and the Tower Yoke Mooring System), SRV Joint Gas Ltd. (the owner of the GDF Suez Neptune ), and SRV Joint Gas Two Ltd. (the owner of the GDF Suez Cape Ann ) in connection with the Partnership’s initial public offering of its common units (the “IPO”).

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 GDF Suez Neptune , the GDF Suez 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, as further described in note 3.

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 and combined carve-out financial statements. The joint ventures and the subsidiaries are, collectively, referred to as the “Combined Entities” in the combined carve-out financial statements. The PGN FSRU Lampung , the GDF Suez Neptune and the GDF Suez Cape Ann are floating storage regasification units (“FSRUs”) and, collectively, referred to in these consolidated and combined carve-out 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 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 GDF Suez Neptune and the GDF Suez 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 to extend for up to 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 and installed for the charterer and was sold to PT PGN LNG, a subsidiary of Perusahaan Gas Negara (Persero) Tbk (“PGN”).

The following table lists the entities included in these consolidated and combined carve-out financial statements and their purpose as of December 31, 2014.

	Jurisdiction of
Name	Incorporation	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 GDF Suez Neptune
SRV Joint Gas Two Ltd. (50% owned) (2)	Cayman Islands	Owns GDF Suez Cape Ann

(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 and combined carve-out 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.

F-10

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

2. Significant accounting policies

Basis of presentation

The consolidated and combined carve-out financial statements are prepared in accordance with United States generally accepted accounting principles (“US GAAP”). All inter-company balances and transactions are eliminated.

As of August 13, 2014, financial statements of the Partnership are consolidated since it was a separate legal entity owning the interests in the subsidiaries and joint ventures. At the closing of the IPO, the transfer of the interests was recorded at Höegh LNG’s consolidated book values. Prior to that date, the income statement, balance sheet and cash flows, as converted to US GAAP, have been carved out of the consolidated financial statements of Höegh LNG and are presented on a combined carve-out basis for the Combined Entities. The combined carve-out financial statements include the related assets, liabilities, revenues, expenses and cash flows directly attributable to Hoegh LNG Lampung Pte. Ltd. and PT Hoegh LNG Lampung. In addition, the investment in 50% of the joint ventures using the equity method of accounting, and the related advances to joint ventures and interest income on the advances, are included in the consolidated and combined carve-out financial statements. The combined carve-out financial statements prior to August 13, 2014, also include allocations of certain administrative expenses.

Included in the combined carve-out equity as of August 12, 2014, were amounts related to promissory notes and related accrued interest due to Höegh LNG. Höegh LNG’s receivables for the promissory notes and related accrued interest of the Partnership’s subsidiaries were contributed to the Partnership as part of the Formation transactions. Refer to note 3 for additional discussion of the contribution. As a result, the liabilities of the Partnership’s subsidiaries are eliminated on consolidation since they were no longer external liabilities to the Partnership. Accordingly, this is equivalent to not transferring the subsidiaries’ liabilities to the Partnership. Therefore, the corresponding amounts have been eliminated for the Partnership’s opening equity position as of August 12, 2014. Details of the liabilities eliminated are as follows:

	As of August 12,
(in thousands of U.S. dollars)	2014
Accrued interest on $48.5 million Promissory note due to Höegh LNG transferred to Partnership	$	(1,684	)
Accrued interest on $101.5 million Promissory note due to Höegh LNG transferred to Partnership		(2,947	)
$40.0 million Promissory note and accrued interest due to Höegh LNG transferred to Partnership		(41,168	)
Elimination to equity as of August 12, 2014	$	45,799

It has been determined that PT Hoegh LNG Lampung, 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 and combined carve-out financial statements. Dividends may only be paid if the retained earnings are positive under Indonesian law and requirements are fulfilled under the Lampung facility. Refer to note 14. As of December 31, 2014, PT Hoegh LNG Lampung has negative retained earnings and therefore cannot make dividend payments under Indonesia law. Under the Lampung facility, there are limitations on cash dividends and loans that can be made to the Partnership. As of December 31, 2014, restricted net assets of the consolidated subsidiaries were $113.4 million.

F-11

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 at the time of its initial investment. The entities have been financed with third party debt and subordinated shareholders 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 losses of joint ventures in the consolidated and combined carve-out balance sheets. For SRV Joint Gas Ltd., the Partnership had a receivable for the advances of $9.8 million and $12.6 million, respectively, and the Partnership’s accumulated losses or its share of net liabilities were $28.4 million and $26.0 million, respectively, as of December 31, 2014 and 2013. The Partnership's carrying value for SRV Joint Gas Two Ltd., consists of a receivable for the advances of $9.1 million and $11.9 million, respectively, and the Partnership’s accumulated losses or its share of net liabilities of $31.2 million and $28.3 million, respectively, as of December 31, 2014 and 2013. The major reason that the Partnership’s accumulated losses in the joint ventures are net liabilities is due to the fair value adjustments for the interest rate swaps recorded as liabilities on the combined balance sheets of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. 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 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. 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.

Carve-out principles

For the period from January 1, 2014 to August 12, 2014 (the date of the IPO) and for the years ended December 31, 2013 and 2012, the combined carve-out financial statements presented herein have been carved out of the consolidated financial statements of Höegh LNG and adjusted to be in accordance with US GAAP.

These combined carve-out financial statements include the assets, liabilities, revenues, expenses and cash flows directly attributable to Hoegh LNG Lampung Pte. Ltd. and PT Hoegh LNG Lampung . In addition, the investment in 50% of the joint ventures, the related advances to joint ventures and interest income on the advances are included in the combined carve-out financial statements.

The combined carve-out financial statements include the financial statements of Hoegh LNG Lampung Pte. Ltd. and PT Hoegh LNG Lampung since the dates of their inception. Hoegh LNG Lampung Pte. Ltd. and PT Hoegh LNG Lampung were incorporated on May 31, 2013 and December 10, 2012, respectively. Prior to October 1, 2013, the investment in the PGN FSRU Lampung and the Mooring were not included in a single purpose entity or accounted for as a discrete unit, but held by a subsidiary of Höegh LNG. From October 1, 2013, the PGN FSRU Lampung , the Mooring and all associated contracts are included in PT Hoegh Lampung Pte. Ltd.

Höegh LNG’s accounting system tracks capital expenditures and expenses by project code, including the capitalized cost of newbuilding and projects under construction, administration costs for those working on such projects through Höegh LNG’s time-write system, commitment fees and deferred debt issuance cost for related financing and certain deferred charges related to contracts. Höegh LNG’s time-write system records project team and administration staff hours worked on specific vessels or by project code for purposes on recording associated staff costs and overhead. Accordingly, for periods prior to October 1, 2013, the capitalized cost of the newbuilding, construction contract revenues related to the Mooring, associated costs and related balances have been specifically identified based on project codes for purpose of preparing the combined carve-out financial statements.

Cash, working capital items, amounts due to owners and affiliates and equity balances are not tracked by project code. Cash and restricted cash were not allocated to the carve-out financial statements unless specific accounts were identified specifically related to the project. Working capital items and accruals were reviewed at the transaction level to identify those specifically related to the newbuilding, the Mooring or the associated contracts. The share of loans due to owners and affiliates related to the financing of the construction in progress and the related interest expense have been allocated to the combined carve-out financial statements.

In addition, there are administrative expenses of Höegh LNG that cannot be attributed to a specific vessel or project directly. The administrative expenses include undistributed corporate and segment management and administrative staffs salary expenses and benefits, and general and administrative expenses. These administrative expenses have been allocated to the combined carve-out financial statements based on the number of vessels, newbuildings and business development projects in Höegh LNG’s fleet, joint ventures and operations.

F-12

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Related parties have provided the commercial and technical services for the FSRUs, including supervision of newbuilding, and employ the crews that work on the FSRUs. Accordingly, neither the Combined Entities nor the Partnership are liable for any pension or post retirement benefits, since they have no direct employees.

Income tax expense has been allocated to the Combined Entities on a separate returns basis.

Management has deemed the allocations reasonable to present the financial position, results of operations, and cash flows of the Partnership on a stand-alone basis. However, the financial position, results of operations and cash flows of the Partnership may differ from those that would have been achieved had the Partnership operated autonomously for all years presented as the Partnership would have had additional administrative expenses, including legal, accounting, treasury and regulatory compliance and other costs normally incurred by a listed public entity. Accordingly, the consolidated and combined carve-out financial statements do not purport to be indicative of the future financial position, results of operations or cash flows of the Partnership.

Significant accounting policies

Certain of the accompanying consolidated and combined carve-out financial statements have been restated. The nature of the restatements and the effect on the restated line items is discussed in note 2d. In addition, certain disclosures in the following notes have been restated to be consistent with the consolidated and combined carve-out financial statements.

Foreign currencies

The reporting currency in the consolidated and combined carve-out financial statements is the U.S. dollar, which is the functional currency of the FSRU-owning entities. 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 and combined carve-out statements of income.

Time charter revenues and related expenses

Time charter revenues:

Revenue arrangements may include the right to use FSRUs for a stated period of time that meet the criteria for lease accounting, in addition to providing a time charter service element. Time charter revenues consist of charter hire payments under time charters, fees for providing time charter services, fees for reimbursement for actual vessel operating expenses, certain tax elements and drydocking costs borne by the charterer on a pass through basis, as well as fees for the reimbursement of certain vessel modifications or other costs (such as reimbursement of certain taxes) borne by the charterer. Time charter revenues are presented net of any value added tax (“VAT”) or other tax.

The lease element of time charters accounted for as operating leases and any upfront payments for amounts reimbursed by the charterer are recognized on a straight line basis over the term of the charter.

The lease element of time charters that are accounted for as direct financing leases is recognized over the lease term using the effective interest rate method and is included in time charter revenues. Direct financing leases are reflected on the balance sheets as net investments in direct financing leases. The time charter for the PGN FSRU Lampung is accounted for as a direct financing lease.

Revenues for the lease element of time charters are not recognized for days that the FSRUs are off hire.

Fees for providing time charter services, reimbursements for actual vessel operating expenses or other costs are recognized as revenues as services are performed or the actual costs are incurred. Revenues for the time charter services element are not recognized for days that the FSRUs are off-hire.

F-13

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Upfront payments of fees for reimbursement of drydocking costs are recognized on a straight line basis over the period to the next drydocking.

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 the responsibility of, and paid directly by the charterers and not included in the income statement. 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 income statement, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, and management fees. When the vessel is on hire, vessel operating expenses are invoiced as fees to the charterer. 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.

Construction revenues and related expenses

For fixed price construction contracts, when the outcome can be estimated reliably, construction contract revenues are recognized based on the percentage of completion method using the ratio of costs incurred to estimated total costs multiplied by the total estimated contract revenue. Revenue from change orders, if any, is not recognized until agreed in writing by the owner. As the percentage of completion method relies on the substantial use of estimates, estimates may be revised throughout the life of a construction contract. The construction cost incurred and estimates to complete on construction contracts are reviewed, at a minimum, on a quarterly basis, as well as when information becomes available that would necessitate a review of the current estimate. Adjustments to estimates for a contract's estimated costs at completion and estimated profit or loss often are required as experience is gained, and as more information is obtained, even though the scope of work required under the contract may not change. The impact of such changes to estimates is made on a cumulative basis in the period when such information has become known. Expected losses on contracts are fully recognized as soon as they are identified.

Construction contract expenses include direct costs on contracts, including project management, labor and materials, amounts payable to subcontractors and capitalized interest.

Insurance and other claims

Insurance claims for property damage are recorded, net of any deductible amounts, for recoveries up to the amount of loss recognized when the claims submitted 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 based on a separate return basis. Income taxes are accounted for using the liability method.

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.

F-14

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 and combined carve-out financial statements. Interest and penalties related to uncertain tax positions is recognized in income tax expense in the consolidated and combined carve-out 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 and other tax liabilities and other current obligations of the entity, principal and interest payments as required by the debt facilities and collateral for a letter of credit related to potential delay liquidated damages to PGN. Restricted cash is classified as long-term when the settlement or collateral period is more than 12 months from the balance sheet date. Classification of restricted cash in the consolidated and combined carve-out statements of cash flows is as an operating, investing or financing activity when the purpose of the restriction is directly related to operations, an investment or as collateral for borrowings, respectively.

Trade receivables and allowance for doubtful accounts

Trade receivables are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable based on historical write-off experience and customer economic data. Account balances are charged off against the allowance when management believes that the receivable will not be recovered. The allowance for doubtful accounts was $0 for the year ended December 31, 2014.

Unbilled construction contract income

Unbilled construction contract income includes accrued revenue on construction contracts.

Deferred debt issuance costs

Debt issuance costs, including arrangement fees and legal expenses, are deferred and presented as deferred debt issuance cost in the consolidated and combined carve-out 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.

Deferred charges

Deferred charges consist primarily of contract origination costs related directly to the negotiation and consummation of the time charter and are amortized over the term of the time charter. For direct financing leases, origination costs related to the time charter are reclassified to net investment in direct financing lease and amortized over the lease term using the effective interest method.

Investments in (accumulated losses) 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, 2014 and 2013, the Partnership had an accumulated share of losses and the balance is classified on the consolidated and combined carve-out balance sheet as a liability on the line item accumulated losses of joint ventures.

Advances to joint ventures represent loan receivables due from the joint ventures and are recorded at cost.

F-15

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 and combined carve-out 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.

Vessels

All costs incurred during the construction of newbuildings, including interest and supervision and technical costs, are capitalized. 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 capitalized. Costs incurred related to routine repairs and maintenance performed during dry docking is 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 are 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.

Derivative instruments

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.

All derivative instruments are initially recorded at fair value as either assets or liabilities in the consolidated and combined carve-out 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 qualifies for hedge accounting.

For derivative financial instruments that are not designated or that do not qualify for hedge accounting, the changes in the fair value of the derivative financial 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.

F-16

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

For derivative financial instruments qualifying as cash flow hedges, changes in the fair value of the effective portion of the derivative financial instruments are initially recorded in other comprehensive income as a component of total equity. Any hedge ineffectiveness is recognized immediately in earnings, as are any gains and losses or amortization on the derivative that are excluded from the assessment of hedge effectiveness. In the periods when the hedged items affect earnings, the associated fair value changes on the hedging derivatives are transferred from accumulated other comprehensive income to the corresponding earnings line item in the consolidated and combined carve-out statement of income. If a cash flow hedge is terminated and the originally hedged item is still considered possible 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 transferred to the corresponding earnings line item (e.g. gain (loss) on derivative financial instruments) in the consolidated and combined carve-out statement of income. If the hedged items are no longer possible of occurring, amounts recognized in total equity are immediately transferred to the earnings line item in the consolidated and combined carve-out statement of income.

Prepaid and deferred revenue

Prepaid revenue includes prepayments of fees for charter hire, vessel operating expenses or other future services. Deferred revenues include payments from charterers for certain vessel modifications which is amortized over the charter or other reimbursements not meeting revenue recognition criteria.

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, the useful lives of vessels, drydocking and the percentage of completion related to the Mooring.

Recent accounting pronouncements

There are no recent accounting pronouncements, whose adoption had a material impact on the consolidated and combined carve-out financial statements in the current year. In May 2014, a new accounting standard, Revenue from Contracts with Customers, was issued by the Financial Accounting Standards Board. Under the new standard, revenue for most contracts with customers will be recognized when promised goods or services are transferred to customers in an amount that reflects consideration that the entity expects to be entitled, subject to certain limitations. The scope of this guidance does not apply to leases, financial instruments, guarantees and certain non-monetary transactions. The standard is effective for annual periods beginning after December 15, 2016 and early adoption is not permitted. The Partnership is currently assessing the impact the adoption this standard will have on the consolidated and combined carve-out financial statements.

Restatement of previously issued financial statements

The consolidated and combined carve-out financial statements for the years ended December 31, 2014 and 2013 have been restated for the following items. There is no effect related to these items impacting the year ended December 31, 2012 or to the total equity at the beginning of the earliest period presented.

Value added taxes (“VAT”), withholding taxes (“WHT”) and other

The Partnership announced in August 2015 that it was reviewing its accounting treatment for certain Indonesian value added tax (“VAT”) and Indonesian withholding tax (“WHT”) transactions for the years ended December 31, 2014 and 2013. All of the VAT and WHT restatement adjustments relate to our subsidiary, PT Hoegh LNG Lampung. In completing the review and reconciliation procedures during 2015, certain VAT balances recorded to the consolidated and combined carve-out balance sheet raised concerns about the appropriateness of the accounting treatment for VAT. The review and reconciliation procedures were subsequently expanded to include WHT balances. In the course of its review, the Partnership also completed a detailed analysis to confirm that all VAT and WHT transactions had been properly reported to Indonesian tax authorities.

F-17

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Errors in accounting treatment of VAT and WHT

In Indonesia, the general rule is that VAT paid on supplier invoices is creditable (“creditable VAT”) against VAT received on customer invoices in determining the net amount of VAT due to the Indonesian tax authorities. The proper accounting treatment for creditable VAT paid on supplier invoices is to record it as a receivable on the balance sheet since it reduces the VAT liability due to the tax authorities on VAT received for customer invoices. However, prior to the start-up of revenue generating activities, VAT on most supplier invoices is non-creditable (“non-creditable VAT”). As a result, non-creditable VAT paid to the tax authorities on supplier invoices cannot subsequently be credited against VAT received on customer invoices. The proper accounting is to record non-creditable VAT as part of the expense of the associated supplier invoices or to capitalize it as a component of the asset to which it relates. Non-creditable VAT was incorrectly recorded as a VAT receivable in the Partnership’s consolidated and combined carve-out balance sheets for the years ended December 31, 2014 and 2013. Non-creditable VAT should have been recorded as components of vessel operating expenses, construction contract expenses, administrative expenses, newbuilding (net investment in direct financing lease) or deferred debt issuance cost.

In addition, due to the understanding reached with the charterer releasing it from the obligation to pay the charter invoices for September and October 2014 (refer to note 20), a correction to expense the VAT associated with the invoices that were not payable from the charterer was required. Following PT Hoegh LNG Lampung’s inquiry process with the Indonesian tax authorities on the proper basis for applying VAT to the construction contract invoices related to the Mooring, an adjustment of approximately $6.2 million was recorded to increase the trade receivables from the charterer and VAT liabilities due to the Indonesian tax authorities on the consolidated and combined carve-out balance sheet.

In Indonesia, WHT is due to be paid on supplier invoices from foreign vendors providing services, goods and financing depending upon applicable tax treaties. The proper accounting treatment is to record WHT as an expense of the period, as other items, net, or a component of the capitalized asset (newbuilding (net investment in direct financing lease) or deferred debt issuance cost). Certain tax amounts are also required to be withheld by the charterer on payments of the time charter /customer invoices. The Partnership’s accounting policy is to record its revenues net of taxes. WHT paid on supplier invoices and withheld on time charter invoices was incorrectly recorded to a liability account in the consolidated and combined carve-out balance sheet.

PT Hoegh LNG Lampung uses an external service provider to complete filings for VAT and WHT to the Indonesian tax authorities as a basis for settlement of its VAT and WHT liabilities. The accuracy of the filings submitted to the tax authorities is dependent on PT Hoegh LNG Lampung providing the external service provider with transaction information for the VAT and WHT computation. In the course of its review, the Partnership identified certain VAT and WHT amounts that had not been previously reported. Amendments to the previous VAT and WHT filings have been made to the Indonesian tax authorities and the impact, including penalties imposed by the Indonesian tax authorities, recorded as part of the restatement adjustments.

Pursuant to the omnibus agreement with Höegh LNG, the Partnership is indemnified by Höegh LNG for non-budgeted, non-creditable Indonesian VAT and non-budgeted Indonesian WHT, and any related impact on cash flow for the periods as further described in note 17.

Related adjustments

As a consequence of the reimbursable nature of certain VAT and WHT under PT Hoegh LNG Lampung’s time charter, related adjustments are required for revenue recognition as follows:

Related adjustments to revenues: Under terms of its time charter, PT Hoegh LNG Lampung is reimbursed by the charterer for Indonesian corporate income taxes, WHT on certain interest expenses, certain services and dividends and all Indonesian taxes, including VAT, related to the Mooring. During 2014, the charterer was invoiced for an estimate of the reimbursement of applicable taxes (the “Tax element”) which is subject to a final settlement pending an audit process to compare the invoiced Tax element to actual applicable taxes incurred. The revenue on the Tax element was recognized in the consolidated and combined carve-out income statements only to the extent that applicable taxes were identified as incurred during the applicable period. The remaining invoiced Tax element was deferred pending the completion of the audit process. As of November 30, 2015, the date of the filing of these restated financial statements, the final settlement of the Tax element has not been completed. As a result of identifying additional VAT related to the Mooring and WHT expenses recorded as part of the restatement adjustments, previously deferred revenues for the Tax element have been recognized as revenue in the restatement adjustments for the additional actual taxes incurred to the extent that such revenues are deemed fixed and determinable.

As discussed in note 20, the Partnership was indemnified by Höegh LNG for hire rate, taxes and VAT payments not received under PT Hoegh LNG Lampung’s time charter for September and October 2014. The Partnership received indemnification payments from Höegh LNG in September and October 2014, respectively, for the September and October 2014 invoices not paid by the charterer of $6.5 million and $6.7 million, respectively. The Partnership originally recognized part of the payments from Höegh LNG for September and October 2014 as revenue, net of certain deferrals related to part of the tax element and VAT. As a result of identifying additional VAT and WHT expenses recorded as part of the restatement, restatement adjustments include recognition of previously deferred indemnification revenues of approximately $4.9 million. After the restatement adjustments, all of the indemnification payments for the September and October 2014 invoices have been recognized as revenue and there is no remaining deferred indemnification on the consolidated and combined carve-out balance sheet. For additional information on the accounting for the indemnification of the loss of hire, refer to note 2 c. significant accounting policies on insurance and other claims.

F-18

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Reclassification and tax adjustments: As the Partnership completed its review of the financial reporting for PT Hoegh LNG Lampung, it identified certain other corrections related to PT Hoegh LNG Lampung for 2014. The main correction was related to a reclassification between vessel operating expenses and administrative expenses. The correction recorded resulted in a decrease in vessel operating expenses and an offsetting increase in administrative expenses for the year ended December 31, 2014. In addition, when the Indonesian tax advisors completed the computation of the tax loss carryforward based upon the restated results for PT Hoegh LNG Lampung the for the year ended December 31, 2014, they altered the tax treatment of a component of the losses on derivative instruments compared with the original tax computation for the year ended December 31, 2014. The tax advisors had subsequently identified a private Indonesian tax ruling indicating that all of the gains and losses on derivative instruments were not tax deductible. As a result, the Partnership has re-evaluated the recognition of the deferred tax asset and associated valuation allowance recorded as a component of other comprehensive income in equity related to the derivative instrument. The net impact of the restatement adjustment increased the deferred tax asset and the income tax benefit recorded to other comprehensive income by $0.1 million. The deferred tax asset on the temporary difference was reduced by approximately $0.2 million which was more than offset by the reduction in the valuation allowance of $0.3 million.

Indirect adjustments related to VAT and WHT

In addition to the related adjustments described below, the restatement adjustments related to VAT and WHT, impacted the capitalized cost of PT Hoegh LNG Lampung’s newbuilding (net investment in direct financing lease) (refer to note 12) and deferred debt issuance cost related to the Lampung facility (refer to notes 10 and 14) and the basis for computing the revenue for the direct financing lease and amortization of debt issuance cost. The lease element of PT Hoegh LNG Lampung’s time charter is accounted for as a direct financing lease (refer to note 2 c. significant accounting policies on time charter revenues). As a result of the restatement adjustments described above, the effective interest rate method was recalculated for the revenue for the direct financing lease and for the amortization of the deferred debt issuance cost. The changes in accounting for the resulting amortization of the direct financing lease and the deferred debt issuance cost do not affect or the Partnership’s cash flows or liquidity.

Impact on earnings per unit

The earnings per unit for the period ended December 31, 2014 is based on Post-IPO net income for the period from August 12, 2014 (the date of the Partnership’s IPO) to December 31, 2014. The net income attributable to the unitholders of the Partnership was originally reported as $13,195. The restated net income attributable to the unitholders of the Partnership was $13,255 reflecting net restatement adjustments of $60. As a result of the small net adjustments for this period of 2014, the earnings per unit, as rounded, did not change from the as reported figure to the as restated figure.

For a summary of the impact of the adjustments to Pre-IPO and Post-IPO net income for the years ended December 31, 2014 and 2013 refer to page F-27. This page also provides the summary impact of the adjustments to total equity and comprehensive income for the years ended December 31, 2014 and 2013.

F-19

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statement of income:

	Year ended December 31, 2014
				Adjustments
(in thousands of U.S. dollars, except per unit amounts)	As reported			VAT, WHT and other			Indirect adjustments			As restated
REVENUES
Time charter revenues	$	20,918			1,339			(30	)	$	22,227
Construction contract revenues		49,277			2,591			—			51,868
Other Revenue		—			474			—			474
Total revenues		70,195			4,404			(30	)		74,569
OPERATING EXPENSES
Voyage expenses		(1,139	)		—			—			(1,139	)
Vessel operating expenses		(5,297	)		(900	)		—			(6,197	)
Construction contract expenses		(35,384	)		(3,186	)		—			(38,570	)
Administrative expenses		(11,656	)		(910	)		—			(12,566	)
Depreciation and amortization		(1,317	)		—			—			(1,317	)
Total operating expenses		(54,793	)		(4,996	)		—			(59,789	)
Equity in earnings (losses) of joint ventures		(5,330	)		—			—			(5,330	)
Operating income		10,072			(592	)		(30	)		9,450
FINANCIAL INCOME (EXPENSES), NET
Interest income		4,959			—			—			4,959
Interest expense		(9,590	)		—			(75	)		(9,665	)
Gain (loss) on derivative financial instruments		(161	)		—			—			(161	)
Other items, net		(2,366	)		(422	)		—			(2,788	)
Total financial income (expense), net		(7,158	)		(422	)		(75	)		(7,655	)
Income (loss) before tax		2,914			(1,014	)		(105	)		1,795
Income tax expense		(505	)		24			—			(481	)
Net income (loss)	$	2,409			(990	)		(105	)	$	1,314

Earnings per unit
Common unit public (basic and diluted)	$	0.50								$	0.50
Common unit Höegh LNG (Basic and diluted)	$	0.50								$	0.50
Subordinated unit (basic and diluted)	$	0.50								$	0.50

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statement of comprehensive income:

	Year ended December 31, 2014
				Adjustments
(in thousands of U.S. dollars, except per unit amounts)	As reported			VAT, WHT and other			Indirect adjustments			As restated
Net income	$	2,409			(990	)		(105	)	$	1,314
Unrealized losses on cash flow hedge		(10,159	)		—			—			(10,159	)
Income tax benefit		1,890			94			—			1,984
Other comprehensive income		(8,269	)		94			—			(8,175	)
Comprehensive income (loss)	$	(5,860	)		(896	)		(105	)	$	(6,861	)

F-20

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out balance sheet:

	As at December 31, 2014
			Adjustments
	As reported		VAT, WHT and other			Indirect adjustments			As restated
ASSETS
Current assets
Cash and cash equivalents	$	30,477		—			—		$	30,477
Restricted cash		21,935		—			—			21,935
Trade receivables		—		6,189			—			6,189
Deferred debt issuance cost		2,603		(29	)		—			2,574
Current portion of net investment in direct financing lease		2,809		85			—			2,894
Current deferred tax asset		318		25			—			343
Prepaid expenses and other receivables		5,091		(4,527	)		—			564
Other current assets		149,906		—			—			149,906
Total current assets		213,139		1,743			—			214,882
Long-term assets
Restricted cash		15,184		—			—			15,184
Deferred debt issuance cost		11,974		(343	)		(75	)		11,556
Net investment in direct financing lease		292,379		120			(30	)		292,469
Long-term deferred tax asset		1,572		95			—			1,667
Other long-term assets		21,626		(6,177	)		—			15,449
Other equipment and advances to joint ventures		12,341		—			—			12,341
Total long-term assets		355,076		(6,305	)		(105	)		348,666
Total assets	$	568,215		(4,562	)		(105	)	$	563,548
LIABILITIES AND EQUITY
Current liabilities
Value added and withholding tax liability		835		2,231			—			3,066
Accrued liabilities and other payables		19,201		(5,836	)		—			13,365
Other current liabilities		31,088		—			—			31,088
Total current liabilities		51,124		(3,605	)		—			47,519
Total long-term liabilities		279,651		—			—			279,651
Total liabilities		330,775		(3,605	)		—			327,170
Total equity		237,440		(957	)		(105	)		236,378
Total liabilities and equity	$	568,215		(4,562	)		(105	)	$	563,548

F-21

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statements of cash flows:

	For the year ended December 31, 2014
				Adjustments
	As reported			VAT, WHT and other			Indirect adjustments			As restated
OPERATING ACTIVITIES
Net income	$	2,409			(990	)		(105	)	$	1,314
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		1,317			—			—			1,317
Equity in earnings of joint ventures		5,330			—			—			5,330
Changes in accrued interest income on advances to joint ventures and demand note		(4,349	)		—			—			(4,349	)
Amortization and write off of deferred debt issuance cost		4,287			—			75			4,362
Changes in accrued interest expense		1,146						—			1,146
Refundable value added tax liability on import		(23,401	)		(2,897	)		—			(26,298	)
Net currency exchange losses (gains)		—			(271	)		—			(271	)
Unrealized loss on financial instruments		161			—			—			161
Other adjustments		59			(24	)		—			35
Changes in working capital:
Restricted cash		(21,935	)		(245	)		—			(22,180	)
Trade receivables		—			(6,115	)		—			(6,115	)
Unbilled construction contract income		54,473			701			—			55,174
Prepaid expenses and other receivables		(4,503	)		4,529			—			26
Trade payables		864			—			—			864
Amounts due to owners and affiliates		6,019			—			—			6,019
Value added and withholding tax liability		(2,459	)		10,119			—			7,660
Accrued liabilities and other payables		9,622			(5,841	)		—			3,781
Net cash provided by (used in) operating activities		29,040			(1,034	)		(30	)		27,976

INVESTING ACTIVITIES
Expenditure for newbuildings and other equipment		(170,755	)		(151	)		—			(170,906	)
Demand note made to Höegh LNG		(140,000	)		—			—			(140,000	)
Receipts from repayment of principal on advances to joint ventures		6,666			—			—			6,666
Receipts from repayment of principal on direct financing lease		1,311			—			30			1,341
(Increase) decrease in restricted cash		10,700			—			—			10,700
Net cash provided by (used in) investing activities	$	(292,078	)		(151	)		30		$	(292,199	)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statements of cash flows:

F-22

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

	For the year ended December 31, 2014
				Adjustments
	As reported			VAT, WHT and other		Indirect adjustments		As restated
FINANCING ACTIVITIES
Proceeds from long-term debt	$	257,099			—		—	$	257,099
Proceeds from amounts due to owners and affiliates		10,193			—		—		10,193
Proceeds from loans and promissory notes due to owners and affiliates		650			—		—		650
Repayment of long-term debt		(44,766	)		—		—		(44,766	)
Repayment of amounts due to owners and affiliates		(25,400	)		—		—		(25,400	)
Repayment of loans and promissory notes due to owners and affiliates		(49,150	)		—		—		(49,150	)
Contributions from (distributions to) owner		(11,198	)		—		—		(11,198	)
Customer loan for funding of value added liability on import		26,297			—		—		26,297
Payment of debt issuance cost		(9,208	)		1,185		—		(8,023	)
Proceeds from initial public offering, net of underwriters' discounts and expenses of offering		203,467			—		—		203,467
Cash from proceeds of initial public offering distributed to Höegh LNG		(43,467	)		—		—		(43,467	)
Cash distributions to owners		(4,826	)		—		—		(4,826	)
Cash settlement of derivative financial instruments		(1,100	)		—		—		(1,100	)
(Increase) decrease in restricted cash		(15,184	)		—		—		(15,184	)
Net cash provided by (used in) financing activities		293,407			1,185		—		294,592

Increase (decrease) in cash and cash equivalents		30,369			—		—		30,369
Effect of exchange rate changes on cash and cash equivalents		—			—		—		—
Cash and cash equivalents, beginning of period		108			—		—		108
Cash and cash equivalents, end of period	$	30,477			—		—	$	30,477

F-23

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statement of income:

	Year ended December 31, 2013

				Adjustments
(in thousands of U.S. dollars)	As reported			VAT, WHT and other			Indirect adjustments		As restated
REVENUES
Time charter revenues	$	—			—			—	$	—
Construction contract revenues		50,362			700			—		51,062
Other revenue		511			—			—		511
Total revenues		50,873			700			—		51,573
OPERATING EXPENSES
Construction contract expenses		(43,272	)		(686	)		—		(43,958	)
Administrative expenses		(8,043	)		—			—		(8,043	)
Depreciation and amortization		(8	)		—			—		(8	)
Total operating expenses		(51,323	)		(686	)		—		(52,009	)
Equity in earnings (losses) of joint ventures		40,228			—			—		40,228
Operating income		39,778			14			—		39,792
FINANCIAL INCOME (EXPENSES), NET
Interest income		2,122			—			—		2,122
Interest expense		(352	)		—			—		(352	)
Other items, net		(1,021	)		(75	)		—		(1,096	)
Total financial income (expense), net		749			(75	)		—		674
Income (loss) before tax		40,527			(61	)		—		40,466
Income tax expense		—			—			—		—
Net income (loss)	$	40,527			(61	)		—	$	40,466

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statement of comprehensive income:

	Year ended December 31, 2013
			Adjustments
(in thousands of U.S. dollars, except per unit amounts)	As reported		VAT, WHT and other			Indirect adjustments		As restated
Net income	$	40,527		(61	)		—	$	40,466
Unrealized losses on cash flow hedge		—		—			—		—
Income tax benefit		—		—			—		—
Other comprehensive income		—		—			—		—
Comprehensive income (loss)	$	40,527		(61	)		—	$	40,466

F-24

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out balance sheet:

	As at December 31, 2013
				Adjustments
	As reported			VAT, WHT and other			Indirect adjustments		As restated
ASSETS
Current assets
Cash and cash equivalents	$	108			—			—	$	108
Unbilled construction contract income		54,473			701			—		55,174
Other current assets		10,542			—			—		10,542
Total current assets		65,123			701			—		65,824
Long-term assets
Restricted cash		10,700			—			—		10,700
Newbuilding / Vessels, net of accumulated depreciation		122,517			55			—		122,572
Deferred debt issuance cost		6,931			811			—		7,742
Long-term deferred tax asset		64			327			—		391
Other long-term assets		21,395			—					21,395
Total long-term assets		161,607			1,193			—		162,800
Total assets	$	226,730			1,894			—	$	228,624
LIABILITIES AND EQUITY
Current liabilities
Value added and withholding tax liability		2,987			1,628			—		4,615
Current deferred tax liability		64			327					391
Other current liabilities		216,480			—			—		216,480
Total current liabilities		219,531			1,955			—		221,486
Total long-term liabilities		55,234			—			—		55,234
Total liabilities		274,765			1,955			—		276,720
Total equity		(48,035	)		(61	)				(48,096	)
Total liabilities and equity	$	226,730			1,894			—	$	228,624

F-25

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s consolidated and combined carve-out statements of cash flows:

	For the year ended December 31, 2013
	As reported			VAT, WHT and other			As restated
OPERATING ACTIVITIES
Net income (loss)	$	40,527		$	(61	)	$	40,466
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		8			—			8
Equity in losses (earnings) of joint ventures		(40,228	)		—			(40,228	)
Changes in accrued interest income on advances to joint ventures and demand note		(1,381	)		—			(1,381	)
Amortization and write off of deferred debt issuance cost		379			—			379
Changes in accrued interest expense		352			—			352
Other adjustments		(38	)		—			(38	)
Changes in working capital:
Trade receivables		(58	)		—			(58	)
Unbilled construction contract income		(50,362	)		(700	)		(51,062	)
Prepaid expenses and other receivables		(530	)		—			(530	)
Trade payables		(212	)		—			(212	)
Value added and withholding tax liability		2,987			1,627			4,614
Accrued liabilities and other payables		6,473			—			6,473
Net cash provided by (used in) operating activities		(42,083	)		866			(41,217	)

INVESTING ACTIVITIES
Expenditure for newbuildings and other equipment		(36,268	)		(55	)		(36,323	)
Receipts from repayment of principal on advances to joint ventures		5,542			—			5,542
Net cash provided by investing activities	$	(30,726	)	$	(55	)	$	(30,781	)

FINANCING ACTIVITIES
Proceeds from amounts due to owners and affiliates		15,207			—			15,207
Proceeds from loans and promissory notes due to owners and affiliates		101,493			—			101,493
Contributions from (distributions to) owner		(35,333	)		—			(35,333	)
Payment of debt issuance cost		(8,550	)		(811	)		(9,361	)
Net cash provided by (used in) financing activities		72,817			(811	)		72,006

Increase (decrease) in cash and cash equivalents		8			—			8
Cash and cash equivalents, beginning of period		100			—			100
Cash and cash equivalents, end of period	$	108		$	—		$	108

F-26

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the effect of the restatement on the Partnership’s previously reported net income (loss) and total equity as of the date and for the periods shown:

	Net Income (loss)									Total Equity
(in thousands of U.S. dollars)	August 12 to December 31, 2014			January 1 to August 12, 2014			Year ended December 31, 2013			As of December 31, 2014			As of December 31, 2013
	(Post-IPO)			(Pre-IPO)			(Pre-IPO)
As previously reported	$	13,195			(10,786	)		40,527			237,440		$	(48,035	)
Adjustments:
VAT, WHT and other		75			(1,065	)		(61	)		(957	)		(61	)
Indirect adjustments		(15	)		(90	)		—			(105	)		—
As restated	$	13,255			(11,941	)		40,466			236,378		$	(48,096	)

3. Formation transactions and Initial Public Offering

During August 2014, the following transactions in connection with the transfer of equity interests, shareholder loans and promissory notes and accrued interest to the Partnership and the IPO occurred:

Capital contribution

Höegh LNG contributed the following to the Partnership:

(i)

Its interests in Hoegh LNG Lampung Pte. Ltd., PT Hoegh LNG Lampung, SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd.;

(ii)

Its shareholder loans made by Höegh LNG to each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., in part to finance the operations of such joint ventures;

(iii)

Its receivables for the $40 million promissory note due to Höegh LNG as well as accrued interest on such note and two other promissory notes relating to Hoegh LNG Lampung Pte. Ltd.;

(iv)

These transactions have been accounted for as a capital contribution by Höegh LNG to the Partnership. However, for purposes of the combined carve-out financial statements, the (i) net assets of the entities and the (ii) shareholder loans to the joint ventures are included in the combined carve-out balance sheet as of December 31, 2013 and June 30, 2014;

Recapitalization of the Partnership

(i)

The Partnership issued to Höegh LNG 2,116,060 common units and 13,156,060 subordinated units and 100% of incentive distribution rights (“IDRs”), which will entitle Höegh LNG to increasing percentages of the cash the Partnership distributes in excess of $0.388125 per unit per quarter;

(ii)

The Partnership issued to Höegh LNG GP LLC, a wholly owned subsidiary of Höegh LNG, a non-economic general partner interest in the Partnership;

Initial Public Offering

(i)

The Partnership issued and sold through the underwriters to the public 11,040,000 common units (including 1,440,000 common units exercised pursuant to the underwriters’ option to purchase additional common units), representing approximately 42% limited partnership interest in the Partnership. The common units were sold for $20.00 per unit resulting in gross proceeds of $220.8 million. The net proceeds of the offering were approximately $203.5 million. Net proceeds is after deduction of underwriters’ discounts, structuring fees and reimbursements and the incremental direct costs attributable to the IPO that were deferred and charged against the proceeds of the offering.

F-27

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

(ii)

The Partnership applied the net proceeds of the offering as follows: (i) $140 million to make a loan to Höegh LNG in exchange for a note bearing interest at a rate of 5.88% per annum, which is repayable on demand or which the Partnership can elect to utilize as part of the purchase consideration in the event the Partnership purchases all or a portion of Höegh LNG’s interests in the Independence , (ii) $20 million for general partnership purposes and (iii) the remainder of approximately $43.5 million to make a cash distribution to Höegh LNG.

Proceeds from IPO and application of funds
(in thousands of U.S. dollars)
Gross proceeds from IPO	$	220,800
Underwriters' discounts, structuring fees and incremental direct IPO expenses		(17,333	)
Net proceeds from IPO		203,467
Loan of initial public offering proceeds to Höegh LNG for demand note		(140,000	)
Cash distribution of initial public offering proceeds to Höegh LNG		(43,467	)
Cash retained for general partnership purposes	$	20,000

At the completion of the IPO, Höegh LNG owned 2,116,060 common units and 13,156,060 subordinated units, representing an approximate 58% limited partnership interest in the Partnership.

Agreements

In connection with the IPO the Partnership entered into several agreements including:

(i)

A $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 governing, among other things:

To what extent the Partnership and Höegh LNG may compete with each other;

The Partnership’s option to purchase from Höegh LNG all or a portion of its interests in an additional FSRU, the Independence , within 24 months after acceptance of such vessel by her charterer, subject to reaching an agreement with Höegh LNG regarding the purchase price and other terms in accordance with the provisions of the omnibus agreement and any rights AB Klaipèdos Nafta has under the related time charter, which the Partnership may exercise at one or more times during such 24-month period;

The Partnership’s rights of first offer on certain FSRUs and LNG carriers operating under charters of five or more years; and

Höegh LNG’s provision of certain indemnities to the Partnership.

(iii)

An administrative services agreement with Höegh LNG Services Ltd., UK (“Höegh UK”), pursuant to which Höegh UK provides certain administrative services to the Partnership; and

(iv)

Höegh UK has entered into an administrative services agreement with Höegh LNG AS (“Höegh Norway”) and Leif Höegh (U.K.) Limited, pursuant to which Höegh Norway and Leif Höegh (U.K.) Limited, provides Höegh UK certain administrative services.

Existing agreements remain in place for provision of certain services to the Partnership’s vessel owning joint ventures or entity, of which the material agreements are as follows:

F-28

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

•

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 GDF Suez Neptune and the GDF Suez 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.

4. 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 other financial items (gains and losses 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 that are considered to benefit the entire organization and interest income from advances to joint ventures and the demand note due from Höegh LNG are included in “Other.”

For the year ended December 31, 2014, Majority held FSRUs includes the direct financing lease related to the PGN FSRU Lampung , and construction contract revenues and expenses of the Mooring. The Mooring was constructed on behalf of, and was sold to, PGN using the percentage of completion method of accounting. The Mooring project was completed as of December 31, 2014. For the years ended December 31, 2013 and 2012, Majority held FSRUs includes a newbuilding, the PGN FSRU Lampung , and construction contract revenues and expenses of the Mooring under construction.

As of December 31, 2014 and 2013, Joint venture FSRUs include two 50% owned FSRUs, the GDF Suez Neptune and the GDF Suez Cape Ann , that operate under long term time charters with one charterer, GDF Suez Global LNG Supply SA.

The accounting policies applied to the segments are the same as those applied in the consolidated and combined carve-out financial statements, except that Joint venture FSRUs are presented under the proportional consolidation method for the segment note and under equity accounting for the consolidated and combined carve-out financial statements. 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, 2014, 2013 and 2012.

F-29

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

	Year ended December 31, 2014
																Consolidated
	Majority			Joint venture FSRUs						Total						and Combined
	held			(proportional						Segment						Carve-out
(in thousands of U.S. dollars)	FSRUs			consolidation)			Other			reporting			Eliminations			Reporting
	(Restated)						(Restated)			(Restated)						(Restated)
Time charter revenues	$	22,227			41,319			—			63,546			(41,319	)	$	22,227
Construction contract revenues		51,868			—			—			51,868			—			51,868
Other revenue		474			—			—			474			—			474
Total revenues		74,569			41,319			—			115,888						74,569
Operating expenses		(13,689	)		(8,485	)		(6,213	)		(28,387	)		8,485			(19,902	)
Construction contract expenses		(38,570	)		—			—			(38,570	)		—			(38,570	)
Equity in earnings of joint ventures		—			—			—			—			(5,330	)		(5,330	)
Segment EBITDA		22,310			32,834			(6,213	)		48,931
Depreciation and amortization		(1,317	)		(9,148	)		—			(10,465	)		9,148			(1,317	)
Operating income (loss)		20,993			23,686			(6,213	)		38,466						9,450
Gain (loss) on derivative instruments		(161	)		(11,878	)		—			(12,039	)		11,878			(161	)
Other financial income (expense), net		(11,952	)		(17,138	)		4,458			(24,632	)		17,138			(7,494	)
Income (loss) before tax		8,880			(5,330	)		(1,755	)		1,795			—			1,795
Income tax expense		(505	)		—			24			(481	)		—			(481	)
Net income (loss)	$	8,375			(5,330	)		(1,731	)		1,314			—		$	1,314

	As of December 31, 2014
												Consolidated
	Majority		Joint venture FSRUs				Total					and Combined
	held		(proportional				Segment					Carve-out
(in thousands of U.S. dollars)	FSRUs		consolidation)		Other		reporting		Eliminations			Reporting
	(Restated)				(Restated)		(Restated)					(Restated)
Newbuildings	$	—		—		—		—		—		$	—
Vessels, net of accumulated depreciation		—		279,670		—		279,670		(279,670	)		—
Net investment in direct financing lease		295,363						295,363					295,363
Advances to joint ventures		—		—		18,952		18,952		—			18,952
Total assets		372,930		300,327		190,618		863,875		(300,327	)		563,548
Accumulated losses of joint ventures		—		—		50		50		(59,680	)		(59,630	)
Expenditures for newbuildings, vessels & equipment		172,324		2,358		—		174,682		(2,358	)		172,324
Expenditures for drydocking		—		—		—		—		—			—
Principal repayment direct financing lease	$	1,341		—		—		1,341		—		$	1,341

F-30

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

	Year ended December 31, 2013
																Consolidated
	Majority			Joint venture FSRUs						Total						and Combined
	held			(proportional						Segment						Carve-out
(in thousands of U.S. dollars)	FSRUs			consolidation)			Other			reporting			Eliminations			Reporting
	(Restated)									(Restated)						(Restated)
Time charter revenues	$	—			41,110			—			41,110			(41,110	)	$	—
Construction contract revenues		51,062			—			—			51,062			—			51,062
Other revenues		511			—			—			511			—			511
Total revenues		51,573			41,110			—			92,683						51,573
Operating expenses		(4,490	)		(8,763	)		(3,553	)		(16,806	)		8,763			(8,043	)
Construction contract expenses		(43,958	)		—			—			(43,958	)		—			(43,958	)
Equity in earnings of joint ventures		—			—			—			—			40,228			40,228
Segment EBITDA		3,125			32,347			(3,553	)		31,919
Depreciation and amortization		(8	)		(9,053	)		—			(9,061	)		9,053			(8	)
Operating income (loss)		3,117			23,294			(3,553	)		22,858						39,792
Gain (loss) on derivative instruments		—			35,038			—			35,038			(35,038	)		—
Other financial income (expense), net		(1,448	)		(18,104	)		2,122			(17,430	)		18,104			674
Income (loss) before tax		1,669			40,228			(1,431	)		40,466			—			40,466
Income tax expense		—			—			—			—			—			—
Net income (loss)	$	1,669			40,228			(1,431	)		40,466			—		$	40,466

	As of December 31, 2013
			Joint venture
	Majority		FSRUs				Total					Combined
	held		(proportional				Segment					carve-out
(in thousands of U.S. dollars)	FSRUs		consolidation)		Other		reporting		Eliminations			reporting
	(Restated)						(Restated)					(Restated)
Newbuildings	$	122,572		—		—		122,572		—		$	122,572
Vessels, net of accumulated depreciation		—		286,460		—		286,460		(286,460	)		—
Advances to joint ventures		—		—		24,510		24,510					24,510
Total assets		203,787		307,335		24,510		535,632		(307,335	)		228,297
Accumulated losses of joint ventures		—		—		50		50		(54,350	)		(54,300	)
Expenditures for newbuildings, vessels & equipment		36,590		522		—		37,112		(522	)		36,590
Expenditures for drydocking	$	—		—		—		—		—		$	—

F-31

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

	Year ended December 31, 2012
																Consolidated
	Majority			Joint venture FSRUs						Total						and combined
	held			(proportional						Segment						carve-out
(in thousands of U.S. dollars)	FSRUs			consolidation)			Other			reporting			Eliminations			reporting
Time charter revenues	$	—			41,076			—			41,076			(41,076	)	$	—
Construction contract revenues		5,512			—			—			5,512			—			5,512
Other revenues		—			—			—			—			—			—
Total revenues		5,512			41,076			—			46,588						5,512
Operating expenses		(2,372	)		(8,652	)		(813	)		(11,837	)		8,652			(3,185	)
Construction contract expenses		(5,512	)		—			—			(5,512	)		—			(5,512	)
Equity in earnings of joint ventures		—			—			—			—			5,007			5,007
Segment EBITDA		(2,372	)		32,424			(813	)		29,239
Depreciation and amortization		—			(9,060	)		—			(9,060	)		9,060			—
Operating income (loss)		(2,372	)		23,364			(813	)		20,179						1,822
Gain (loss) on derivative instruments		—			693			—			693			(693	)		—
Other financial income (expense), net		(115	)		(19,050	)		2,481			(16,684	)		19,050			2,366
Income (loss) before tax		(2,487	)		5,007			1,668			4,188			—			4,188
Income tax expense		—			—			—			—			—			—
Net income (loss)	$	(2,487	)		5,007			1,668			4,188			—		$	4,188

For the years ended December 31, 2014, 2013 and 2012, the percentage of consolidated and combined carve-out total revenues from the following customers accounted for over 10% of the consolidated and combined carve-out total revenues:

	Year ended
	December 31,
	2014			2013			2012
PGN		100	%		100	%		100	%

5. Time charter revenues and net investment in direct financing lease

As of December 31, 2014, the minimum contractual future revenues to be received under the time charters during the next five years and thereafter are as follows:

(in thousands of U.S. dollars)	Total
	(Restated)
2015	$	39,131
2016		39,131
2017		39,131
2018		39,131
2019		39,131
Thereafter		580,611
Total	$	776,266

The long-term time charter for the PGN FSRU Lampung with PGN 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 direct 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, taxes and drydocking costs. 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 option price. 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.

F-32

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 direct financing lease is reflected on the balance sheets as net investment in direct financing lease, a receivable, as follows:

	As of December 31,
(in thousands of U.S. dollars)	2014
	(Restated)
Minimum lease payments	$	589,074
Unguaranteed residual value		146,000
Unearned income		(441,465	)
Initial direct cost, net		3,095
Net investment in direct financing lease at inception		296,704
Principal repayment and amortization for July 22 to December 31, 2014		(1,341	)
Net investment in direct financing lease at December 31, 2014		295,363
Less: Current portion		(2,894	)
Long term net investment in direct financing lease	$	292,469

There were no financing leases as of December 31, 2013. There was no allowance for doubtful accounts as of December 31, 2014.

6. Construction contract revenues

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)			(Restated)
Construction contract revenue	$	51,868			51,062		$	5,512
Construction contract expenses		(38,570	)		(43,958	)		(5,512	)
Recognized contract margin (loss)	$	13,298			7,104		$	—

PGN formally accepted the PGN FSRU Lampung and signed the Certificate of Acceptance on October 30, 2014 which was the condition for the final payment related to the Mooring. As such the Mooring project was 100% completed as of December 31, 2014. PGN issued invoices for delay liquidated damages of $7,116 related to claims from PGN on the project for the year end December 31, 2014. Subsequent to the year ended December 31, 2014, an understanding with PGN has been reached under which no delay liquidated damages will be payable. Due to this subsequent event, no delay liquated damages are reflected in the construction contract expenses for the year ended December 31, 2014. Refer to note 20. As of December 31, 2014 the Partnership recorded a warranty allowance of $2,000 for technical issues that requires the replacement of equipment parts for the Mooring. Refer to note 20.

As of December 31, 2013 and 2012, the Mooring project was estimated to be 52% and 6% completed, respectively. In the initial stages of the contract, the Partnership’s policy is to record revenue in an amount equal to the cost incurred until sufficient information is available to estimate profit on the project with a reasonable level of certainty. As a result, no contract margin was recognized for the year ended December 31, 2012. Refer to note 9.

F-33

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

7. Financial income (expenses)

The components of financial income (expenses) are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)			(Restated)
Interest income	$	4,959			2,122		$	2,481
Interest expense:
Interest expense		(9,163	)		(6,110	)		(3,769	)
Commitment fees		(1,587	)		(2,162	)		(1,729	)
Amortization of debt issuance cost		(4,362	)		(379	)		(379	)
Capitalized interest		5,447			8,299			5,763
Total interest expense		(9,665	)		(352	)		(114	)
Loss on derivative instruments		(161	)		—			—
Other items, net:
Foreign exchange gain (loss)		124			9			—
Bank charges and fees and other		(84	)		—			—
Withholding tax on interest expense and other		(2,828	)		(1,105	)		(1	)
Total other items, net		(2,788	)		(1,096	)		(1	)
Total financial income (expense), net	$	(7,655	)		674		$	2,366

Interest income related to the demand note due from Höegh LNG from its inception date of August 12, 2014 and the advances to the joint ventures for each of the years ended December 31, 2014, 2013 and 2012. Interest expense related to the Lampung facility (note 14) from its initial drawdown on March 4, 2014 and loans and promissory notes due to owners and affiliates until the closing date of the IPO on August 12, 2014 and for each the years ended December 31, 2013 and 2012. Refer to note 17.

8. Income tax

The components of income tax expense recognized in the consolidated and combined carve-out statements of income are as follows:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)			(Restated)
Total current tax (benefit) expense	$	505		$	—		$	—
Deferred tax (benefit) expense for
Change in temporary differences		(259	)		(6,788	)		—
Tax loss carry forward		(1,253	)		—			—
Change in valuation allowance		1,488			6,788			—
Total deferred tax (benefit) expense		(24	)		—			—
Total income tax (benefit) expense	$	481		$	—		$	—

F-34

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Deferred tax (benefit) expense recognized in the consolidated combined carve-out 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)	2014			2013		2012
Cash flow hedge derivative financial instruments	$	(2,374	)		—	$	—
Valuation allowance		390			—		—
Deferred tax (benefit) recognized in OCI	$	(1,984	)		—	$	—

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)	2014			2013			2012
	(Restated)			(Restated)
Income (loss) before tax	$	1,795			40,466		$	4,188
At applicable statutory tax rate
Amount computed at corporate tax of 0%		—			—			—
Foreign tax rate differences		(960	)		44			—
Permanent differences:
Tax deduction foreign exchange losses in local currency		—			(2,535	)		—
Non deductible withholding taxes		905			189			—
Tax credits and exemptions		(1,497	)		—			—
Non deductible other financial items		286			—			—
Non deductible foreign exchange loss		61			—			—
Other non deductible costs		198			60			—
Deferred tax asset not probable of realization		—			2,626			—
Adjustment for valuation allowance		1,488			(384	)		—
Tax expense (benefit) for year recognized in net income	$	481			—		$	—

F-35

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Deferred income tax assets (liabilities) are summarized as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2014			2013
	(Restated)			(Restated)
Current deferred tax assets:
Direct financing lease		81			—
Accrued liabilities and other payables		524			11
Derivative financial instruments		1,170			—
Current valuation allowance		(1,399	)		(11	)
Long-term deferred tax assets:
Newbuildings		—			7,359
Direct financing lease		6,596			—
Derivative financial instruments		1,205			—
Other equipment		6			—
Prepaid and deferred revenue		—			233
Tax loss carry forward		1,253			—
Long term valuation allowance		(7,244	)		(6,777	)
Current deferred tax liabilities:
Unbilled construction contract income		—			(327	)
Accrued liabilities and other receivables		(33	)		(64	)
Long term deferred tax liabilities:
Deferred debt issuance cost		(149	)		(276	)
Deferred charges		—			(148	)
Deferred tax assets (liabilities), net	$	2,010		$	—

The Partnership is not subject to Marshall Islands corporate income taxes. The Partnership is subject to tax for earnings of its subsidiary incorporated in Singapore and its FSRU-owing entity incorporated in Indonesia. For the year ended December 31, 2014, the current tax expense relates to the Singapore subsidiary mainly due to internal interest income. For the year ended December 31, 2014, the FSRU-owning entity incorporated in Indonesia incurred a tax loss. The tax loss carryforward of $1,253 expires in 2019.

A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that some or all of the benefit will not be realized. Given the lack of historical operations in Indonesia, management of the Partnership concluded a valuation allowance should be established to reduce the deferred tax assets to the amount deemed more-likely-than-not of realization. A component of the deferred tax asset relates to the cash flow hedge of the interest rate swap with a term of over 11 years. Management concluded that approximately $2,000 of the deferred tax asset was more-likely-than-not of realization over the term of the swap and recognized a deferred tax asset for that amount. Deferred tax expenses for the change in the valuation allowance of $1,488 and $390 were recorded to income tax expense in the consolidated and combined statement of income and consolidated and combined statement of comprehensive income, respectively, for the year ended December 31, 2014.

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. In 2013, a tax loss was incurred in Indonesia principally due to unrealized losses on foreign exchange that does not impact the income statement prepared in the functional currency of U.S. dollars. In 2014, the Indonesia authorities have approved the change of currency for tax reporting to U.S. dollars. Under existing tax law, it is not clear if the prior year tax loss carryforward from foreign exchange losses can be utilized when the tax reporting currency is subsequently changed. Due to the uncertainty of this tax position, a provision was recognized for the year ended December 31, 2013 and the resulting unrecognized tax benefit was $2,626. There was no change in the unrecognized tax benefits as of December 31, 2014.

F-36

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

9. Unbilled construction contract income

The unbilled construction contract income of $0 and $ 55,174 for the years ended December 31, 2014 and 2013 (restated), respectively, relate to the construction and installation of the Mooring for PGN. As of December 31, 2014 the Mooring project was completed and all payments received from PGN. The unbilled construction contract income represented the excess of contract costs and profits recognized to the balance sheet date on the percentage of completion accounting method over the amount of contract billings to the balance sheet date.

10. Deferred debt issuance cost

Debt issuance costs are deferred and amortized to interest expense over the term of the related debt. The deferred debt issuance costs are comprised of the following amounts:

	As of
	December 31,
(in thousands of U.S. dollars)	2014			2013
	(Restated)			(Restated)
Total deferred debt issuance cost	$	19,283		$	11,258
Accumulated amortization		(5,153	)		(791	)
Total deferred debt issuance cost, net		14,130			10,467

Current deferred debt issuance cost		2,574			2,725
Long term deferred debt issuance cost		11,556			7,742
Total deferred debt issuance cost	$	14,130		$	10,467

Amortization of deferred debt issuance cost for the years ended December 31, 2014 (restated), 2013 and 2012 was $4,362, $379 and $379, respectively. The Mooring tranche of the Lampung facility was repaid July 3, 2014 and the deferred debt issuance cost for that tranche of $1,747 was fully amortized for the year ended December 31, 2014. Due to an early repayment of the Lampung facility of $7.9 million for the year ended December 31, 2014, the amortization included a write down of debt issuance cost of $495.

11. Other long-term assets and other long-term liabilities

The components other long-term assets are as follows:

	As of December 31,
(in thousands of U.S. dollars)	2014		2013
	(Restated)
Refundable value added tax on import	$	15,449	$	—
Total other long-term assets		15,449		—

Refundable value added tax was paid in Indonesia in local currency on the import of PGN FSRU Lampung into the country. The original balance was reduced for net value added tax incurred for the year ended December 31, 2014. The receivable can be recovered by requesting a refund from the tax authorities for the net outstanding balance as of a given date or applying future periods next value added tax liabilities against the receivable. The process to obtain a refund takes more than twelve months. The charterer provided an advance for the funding of the refundable value added tax on import.

F-37

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The current portion and long term advance for refundable value added tax, at December 31, 2014 exchange rates, were as follows:

	As of December 31,
	2014			2013
Total advance for refundable value added tax on import		24,524			—
Less: Current portion of advance for refundable value added tax (note 15)		(2,318	)		—
Long term advances for value added tax recorded in Other long-term liabilities	$	22,206		$	—

12. Newbuildings and other equipment

	As of December 31,
(in thousands of U.S. dollars)	2014			2013
		(Restated)			(Restated)
Newbuilding beginning of period	$	122,572		$	86,067
Additions		169,003			29,574
Capitalized interest		3,292			6,931
Transfer to vessel/ net investment in direct financing lease		(294,867	)		—
Newbuilding end of period	$	—		$	122,572

In the middle of May 2014, the PGN FSRU Lampung was deemed substantially complete to begin the commissioning under the time charter contract. The newbuilding was transferred on the balance sheet to vessels until such time as the time charter commenced. The vessel was transferred on the balance sheet to net investment in direct financing lease at the start of the time charter. However, due to delays by the unrelated pipeline contractor completing the pipeline and minor damage to the FSRU by a tugboat during the pipeline installation, the time charter did not commence until July 21, 2014. As a result, the vessel was depreciated until the start of the direct financing lease. The depreciation expense for the PGN FSRU Lampung for the year ended 2014 was $1,286.

As of December 31, 2014 and 2013, other equipment consists principally of office equipment and computers. Other equipment of $93 is recorded net of accumulated depreciation of $39 in the consolidated and combined carve-out balance sheet. Depreciation expense was $31 and $8 for the years ended December 31, 2014 and 2013, respectively. There was no corresponding expense for the year ended December 31, 2012.

13. Advances to joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Current portion of advances to joint ventures	$	6,665	$	7,112
Long-term advances to joint ventures		12,287		17,398
Advances/shareholder loans to joint ventures	$	18,952	$	24,510

The Partnership had advances of $9.8 million and $12.6 million due from SRV Joint Gas Ltd. as of December 31, 2014 and 2013, respectively. The Partnership had advances of $9.1 million and $11.9 million due from SRV Joint Gas Two Ltd. as of December 31, 2014 and 2013,

F-38

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The advances consist of shareholders 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 GDF Suez Neptune and the GDF Suez Cape Ann were delivered on November 30, 2009 and June 1, 2010, respectively. The shareholders loans are subordinated to the joint ventures’ 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 GDF Suez Neptune and the GDF Suez 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 include a payment of interest for the first month of the quarter and a repayment of principal. Interest is accrued for the last two months of the quarter for repayment in the latter years of the loans. Since the shareholder loans are subordinated to long-term bank debt, the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt.

14. Long-term debt

	As of
	December 31,
(in thousands of U.S. dollars)		2014			2013
Lampung facility:
$ 178.6 million Export credit tranche	$	168,640		$	—
$ 58.5 million FSRU tranche		43,693			—
$ 61.9 million Mooring tranche		—			—
Total debt		212,333			—
Less: Current portion of long-term debt		(19,062	)		—
Long-term debt	$	193,271		$	—

Lampung facility

In September 2013, PT Hoegh LNG Lampung (the “Borrower”) entered into a secured $299 million term loan facility and $10.7 million standby letter of credit 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. The $10.7 million standby letter of credit facility supports guarantees to PGN for delivery obligations of the FSRU and Mooring under the lease, operation and maintenance agreement (the “LOM”). Höegh LNG is the guarantor for the facility. The facility was drawn in installments as construction was completed. The term loan facility includes two commercial tranches, or the FSRU tranche and the Mooring tranche, and the export credit tranche. The interest rates vary by tranche. The letter of credit facility was undrawn as of December 31, 2014 and 2013.

On March 4, 2014, the Borrower drew $96 million of the Lampung facility, of which $28.4 million, $32.1 million and $35.5 million were drawn on the FSRU tranche, the Mooring tranche and the export credit tranche, respectively. On April 8, 2014, the Borrower drew $161.1 million of the Lampung facility, of which $18.0 million and $143.1 million were drawn on the FSRU tranche and export credit tranche, respectively. On July 3, 2014, the full principal amount of $32.1 million on the Mooring tranche and accrued interest was repaid. The final available commitment on the FSRU tranche of $12.1 million was never drawn. On December 29, 2014, the Borrower made an early repayment of $7.9 million, of which $1.6 million and $6.3 million was repaid on the FSRU tranche and the Export credit tranche, respectively. Following the acceptance by PGN of the PGN FSRU Lampung , the quarterly repayments also began on December 29, 2014. As of December 31, 2013, the Lampung facility was undrawn.

The FSRU tranche of $58.5 million has an interest rate of LIBOR plus a margin of 3.4%. The interest rate for the export credit tranche of $178.6 million is LIBOR plus a margin of 2.3%. The first repayment of the both tranches occurred on December 29, 2014. The FSRU tranche is repayable quarterly over 7 years with a final balloon payment of $16.5 million. The export credit tranche is repayable in quarterly instalments 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 Mooring tranche of $61.9 million bore interest at a rate equal to LIBOR plus a margin of 2.5%. The tranche was fully repaid on July 3, 2014.

F-39

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Commitment fees were 1.4%, 0.9% and 1.0% of the undrawn portions of the FSRU tranche, the export credit tranche and the Mooring tranche, 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 beginning from the second quarterly repayment date of the export credit tranche;

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.

Höegh LNG, as guarantor, has issued the following guarantees related to the Lampung facility: (a) an unconditional and irrevocable on-demand guarantee for all amounts due under the financing agreements, to be released after the date falling 180 days after acceptance of the FSRU under the LOM subject to the relevant terms and conditions being met; (b) an unconditional and irrevocable on-demand guarantee for the repayment of the balloon repayment instalment of the FSRU tranche callable only at final maturity of FSRU tranche; (c) an unconditional and irrevocable on-demand guarantee for the Borrower's obligation to ensure the required balance is in the debt service reserve account on the 8 ^th repayment date (or such earlier date as is applicable if an event of default occurs); (d) 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 (e) undertaking that, if the LOM 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 project 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 limit, among other things, the ability of the Borrower 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.

$288 million facility

In June 2011, Höegh LNG entered into a $288 million facility for the purpose of providing up to 50% of the financing for two newbuildings, including the PGN FSRU Lampung. Fifty percent of the debt issuance cost on the $288 facility, or $1.9 million, was included in the consolidated and combined carve-out financial statements until September, 2013. In addition, the commitment fees of 1.2% on 50% of the outstanding balance have been included in interest expense until September, 2013. The facility was never drawn for the PGN FSRU Lampung and was replaced by the $299 million Lampung facility, described above, as financing for the PGN FSRU Lampung in September, 2013. The $288 million facility would have required repayment starting three months after delivery of the applicable FSRU and would have been repaid in installments over a three year period.

F-40

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The outstanding long-term debt as of December 31, 2014 is repayable as follows:

(in thousands of U.S. dollars)	Total
2015	$	19,062
2016		19,062
2017		19,062
2018		19,062
2019		19,062
2020 and thereafter		117,023
Total	$	212,333

15. Accrued liabilities and other payables

	As of
	December 31
(in thousands of U.S. dollars)	2014		2013
		(Restated)
Accrued administrative expenses	$	400	$	75
Accrued operating expense		2,247		—
Current tax payable		505		—
Warranty provision (note 20)		2,000		—
Current portion of advance for refundable value added tax (note 11)		2,318		—
Accrued expenditure for newbuilding		—		645
Accrued construction contract expenses		—		6,732
Accrued debt issuance cost		—		391
Other accrued liabilities		339		—
Other payables		5,556		—
Total accrued liabilities and other payables	$	13,365	$	7,843

16. Investments in joint ventures

	As of
	December 31,
(in thousands of U.S. dollars)		2014		2013
Accumulated losses of joint ventures	$	59,630	$	54,300

F-41

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The Partnership has a 50% interest in each of SRV Joint Gas Ltd. (owner of GDF Suez Neptune ) and SRV Joint Gas Two Ltd. (owner of GDF Suez 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)	2014			2013			2012
Time charter revenues	$	82,638			82,220		$	82,151
Other revenues		—			—			—
Total revenues	$	82,638			82,220		$	82,151
Operating expenses		(16,970	)		(17,526	)		(17,303	)
Depreciation and amortization		(18,912	)		(18,722	)		(18,735	)
Operating income		46,756			45,972			46,113
Unrealized gain (loss) on derivative instruments		(23,757	)		70,075			1,386
Other financial expense, net		(34,275	)		(36,207	)		(38,100	)
Net income (loss)	$	(11,276	)		79,840		$	9,399
Share of joint ventures owned		50	%		50	%		50	%
Share of joint ventures net income (loss) before eliminations		(5,638	)		39,920			4,700
Eliminations		308			308			307
Equity in earnings (losses) of joint ventures	$	(5,330	)		40,228		$	5,007

	As of
	December 31,
(in thousands of U.S. dollars)	2014			2013
Cash and cash equivalents	$	10,719		$	11,578
Other current assets		3,317			2,530
Total current assets		14,036			14,108
Restricted cash		25,104			25,104
Vessels, net of accumulated depreciation		577,897			592,092
Other long-term assets		2,174			2,538
Total long-term assets		605,175			619,734
Current portion of long-term debt		20,768			19,522
Amounts and loans due to owners and affiliates		14,516			15,246
Derivative financial instruments		23,887			26,274
Other current liabilities		8,278			8,270
Total current liabilities		67,449			69,312
Long-term debt		501,369			522,136
Loans due to owners and affiliates		24,575			34,795
Derivate financial liabilities		101,910			75,766
Other long-term liabilities		24,612			21,261
Total long-term liabilities		652,466			653,958
Net liabilities	$	(100,704	)	$	(89,428	)
Share of joint ventures owned		50	%		50	%
Share of joint ventures net liabilities before eliminations		(50,352	)		(44,714	)
Eliminations		(9,278	)		(9,586	)
Accumulated losses of joint ventures	$	(59,630	)	$	(54,300	)

F-42

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

17. Related party transactions

Income (expenses) from related parties

The Combined Entities were an integrated part of Höegh LNG until the close of the IPO on August 12, 2014 and for each of the years ended December 31, 2013 and 2012. In connection with the IPO, the Partnership entered into several agreements with Höegh LNG (and certain of its subsidiaries) for the provision of services. Refer to note 3 for additional information. As such, Höegh LNG and its subsidiaries have provided general and corporate management services to the Partnership and the Combined Entities. As described in note 2, certain administrative expenses have been included in the combined carve-out financial statements of the Combined Entities based on actual hours incurred. In addition, management has allocated remaining administrative expenses and Höegh LNG management’s share based payment costs based on the number of vessels, newbuildings and business development projects of Höegh LNG prior to the closing of the IPO. A subsidiary of Höegh LNG has provided the building supervision of the newbuilding and Mooring and ship management for PGN FSRU Lampung.

	Year ended
Statement of income:	December 31,
(in thousands of U.S. dollars)	2014			2013			2012
	(Restated)
Revenues
Time charter and Construction contract revenues indemnified by Höegh LNG (1)	$	13,269			—		$	—
Operating expenses
Vessel operating expenses (2)		(5,297	)		—			—
Hours and overhead (3)		(2,016	)		(2,088	)		(1,025	)
Allocated administration expenses (4)		(4,723	)		(4,260	)		(1,332	)
Construction contract expense: supervision cost (5)		(761	)		(2,559	)		(661	)
Construction contract expense: capitalized interest (6)		(690	)		(1,179	)		(30	)
Financial (income) expense		—
Interest income from joint ventures and demand note (7)		4,959			2,122			2,481
Interest expense and commitment fees from Höegh LNG (8)		(998	)		(352	)		(114	)
Total	$	3,743			(8,316	)	$	(681	)

	As of
Balance sheet	December 31,
(in thousands of U.S. dollars)	2014		2013
Newbuilding
Newbuilding supervision cost (6)	$	1,228	$	4,935
Interest expense capitalized from Höegh LNG (7)		1,464		4,579
Total	$	2,692	$	9,514

Time charter revenues indemnified by Höegh LNG: Höegh LNG has made payments of $6.5 million and $6.7 million for September and October 2014 invoices, respectively, for hire rate payments not received for the PGN FSRU Lampung pursuant to its agreement to indemnify the Partnership under the omnibus agreement. Refer to Indemnifications below and notes 2. d. and 20. Revenue is recognized for the full amount of these payments.

F-43

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Vessel operating expenses: A subsidiary of Höegh LNG provides ship management of vessels, including crews and the provision of all other services and supplies.

Hours, travel expenses and overhead: Subsidiaries of Höegh LNG provide management, accounting, bookkeeping and administrative support. 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. Subsequent to the closing of the IPO, this includes services under administrative service agreements.

Allocated administrative expenses: As described in note 2 until the closing of the IPO on August 12, 2014, administrative expenses of Höegh LNG that could not be attributed to a specific vessel or project based upon the time-write system were allocated to the consolidated and combined carve-out income statement based on the number of vessels, newbuildings and certain business development projects of Höegh LNG. For the period from January 1, 2014 to August 12, 2014 and for the year ended December 31,2013, the allocated expenses also include cost incurred in preparation for the IPO.

Supervision cost: Höegh LNG Fleet Management AS manages the newbuilding process including site supervision including manning for the services and direct accommodation and travel cost. Manning costs are based upon actual hours incurred. Such costs, excluding overhead charges, are capitalized as part of the cost of the newbuilding and included in the construction contract expense for the Mooring.

Interest expense capitalized charged from Höegh LNG and affiliates : As described under 8) below, Höegh LNG and its affiliates have provided funding for the PGN FSRU Lampung and the Mooring (a component of the construction contract expense), which qualify under US GAAP as capitalized interest for the construction in progress.

Interest income from joint ventures and demand note: 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. In the consolidated and combined carve-out statements of cash flows, the interest paid from joint ventures is treated as a return on investment and included in net cash flows from operating activities. Interest income also includes interest on the $140 million demand note due from Höegh LNG. Refer to Demand note due from owner below.

Interest expense charged from Höegh LNG and affiliates: Höegh LNG and its affiliates have provided loans and promissory notes and intercompany funding for the construction of the PGN FSRU Lampung , the construction contract expense of the Mooring. Refer to Amounts, loans and promissory notes due to owners and affiliates below. Prior to transfer of the newbuilding and contracts to PT Hoegh LNG Lampung and the establishment of the promissory notes in October 2013, the carve-out financial statements include an allocation of debt and interest expense from Höegh LNG for the funding of construction of the PGN FSRU Lampung and the construction contract expense of the Mooring. Refer to 6) above which describes the interest expense, which was capitalized.

Receivables and payables from related parties

Demand note due from owner

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Demand note due from owner	$	143,241	$	—

The Partnership lent $140 million to Höegh LNG from the net proceeds of the IPO. The note is repayable on demand or the Partnership can elect to utilize the note as part of the purchase consideration in the event all or a portion of Höegh LNG’s interests in the Independence are purchased by the Partnership. The note bears interest at a rate of 5.88% per annum. The balances in the table above include outstanding principal and accrued interest of $3,241.

Refer to note 13 for advances to joint ventures.

F-44

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Amounts, loans and promissory note due to owners and affiliates

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Amounts due to owners and affiliates	$	6,019	$	15,207

Amounts due to owners and affiliates principally relate to short term funding and trade payables of operating activities as of December 31, 2014 and capital expenditures as of December 31, 2013 by a subsidiary of Höegh LNG. The balance does not bear interest. When the Lampung facility was drawn (note 14), the outstanding amount related to short-term funding of capital expenditures of $25.4 million was repaid on March 5, 2014.

Loans and promissory notes due to owners and affiliates consist of the following:

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
$48.5 million Promissory note due to Höegh LNG	$	—	$	49,507
$101.5 million Promissory note due to Höegh LNG		—		103,606
$40.0 million Promissory note due to Höegh LNG		—		40,317
$85.0 million Revolving credit facility due to Höegh LNG		467		—
Loans and promissory notes due to owners and affiliates	$	467	$	193,430

At the beginning of the fourth quarter of 2013, PT Hoegh LNG Lampung, in Indonesia, became the owner of the construction in progress for the PGN FSRU Lampung and the unbilled construction contract receivable for the Mooring as discussed in note 2. As a result, promissory notes were entered into due to Höegh LNG in the amounts of $48.5 million, $101.5 million and $40.0 million. All of the promissory notes and accrued interest are payable on demand. The $48.5 million and $101.5 million promissory notes bear interest at a fixed rate of 9% per year. The $40.0 million promissory note bears interest at three month LIBOR plus a margin of 3.2%. As of December 31, 2013, the promissory notes had outstanding balances of $49.5 million, $103.6 million and $40.3 million including outstanding interest of $1.0 million, $2.1 million and $0.3 million, respectively. On February 3, 2014, the $101.5 million promissory note, excluding accrued interest, was converted to equity. On March 5, 2014, the principal on the $48.5 million promissory note was repaid, excluding accrued interest.

In August 2014, upon the closing of the IPO, Höegh LNG’s receivables for the $40 million promissory note and related accrued interest and the outstanding accrued interest on the $48.5 million and $101.5 million promissory notes of the Partnership’s subsidiaries were contributed to the Partnership as part of the formation transactions. Refer to notes 2 and 3 for additional discussion of the contribution. As a result, the liabilities of the Partnership’s subsidiaries eliminate in consolidation since there are no longer external liabilities to the Partnership.

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 for a term of three years and is unsecured. Interest on drawn amounts is payable quarterly at LIBOR plus a margin of 4.0%. Additionally, a 1.4% quarterly commitment fee is due to Höegh LNG on undrawn available amounts. The balance as of December 31, 2014, relates to accrued commitment fees. No amount was drawn on the revolving credit facility as of December 31, 2014.

The outstanding loans and promissory notes due to owners and affiliates are denominated in U.S. dollars and had a weighted average interest rate for the years ended December 31, 2014 and 2013 of 4.48% and 4.29%, respectively.

F-45

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Indemnifications

Environmental indemnifications:

Under the omnibus agreement, Höegh LNG will 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. Liabilities resulting from a change in law are excluded from the environmental indemnity. There is an aggregate cap of $5.0 million on the amount of indemnity coverage provided by Höegh LNG for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $500, in which case Höegh LNG is liable for claims only to the extent such aggregate amount exceeds $500.

Other indemnifications :

Under the omnibus agreement Höegh LNG will also indemnify the Partnership for losses:

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 and October 2014 invoices not paid by PGN (refer to notes 2.d. and 20);

with respect to any obligation to pay liquidated damages to PGN 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. The Partnership filed a claim for indemnification for PGN’s claims for delay liquidated damages in the total amount of $7.1 million (refer to note 20);

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. The Partnership indemnified for recovery of the $6.2 million VAT liability related to a Mooring invoice. The Partnership filed a claim for indemnification with respect to non-budgeted value added tax and withholding tax related to the restatement periods up to and including December 31, 2014 of approximately $1.2 million in the fourth quarter of 2015. The indemnification payment was received from Höegh LNG in the fourth quarter of 2015 and recorded as a contribution to equity. Refer to note 2.d. for additional information on the restatement adjustments related to value added tax and withholding tax.

18. Financial Instruments

Fair value measurements

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

F-46

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Cash and cash equivalents and restricted cash – The fair value of the cash and cash equivalents and restricted cash approximates its carrying amounts reported in the consolidated and combined carve-out balance sheets.

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.

Demand note due from owner affiliates – The fair value of the fixed rate demand note approximates the carrying amount of the receivable and accrued interest reported in the consolidated and combined carve-out balance sheets since the amount is payable on demand. Refer to note 17.

Amounts due to owners and affiliates – The fair value of the non-interest bearing payable approximates its carrying amounts reported in the consolidated and combined carve-out balance sheets since it is to be settled consistent with trade payables.

Loans and promissory notes due to owners and affiliates – The fair values of the variable-rate and the fixed rate loans and promissory notes approximates their carrying amounts of the liabilities and accrued interest reported in the consolidated and combined carve-out balance sheets since the amounts are payable on demand. Refer to note 17.

Derivative financial instruments – 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 the subsidiary’s credit worthiness given the level of collateral provided and the credit worthiness of the counterparty to the derivative.

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.

			As of						As of
			December 31, 2014						December 31, 2013
			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	$	30,477			30,477			108			108
Restricted cash		1		37,119			37,119			10,700			10,700
Derivative financial instruments		2		(9,220	)		(9,220	)		—			—
Other:
Advances (shareholder loans) to joint ventures		2		18,952			19,629			24,510			25,242
Demand note due from owner		2		143,241			143,241			—			—
Current amounts due to owners and affiliates		2		(6,019	)		(6,019	)		(15,207	)		(15,207	)
Loans and promissory notes due to owners and affiliates		2		(467	)		(467	)		(193,430	)		(193,430	)
Lampung facility		2	$	(212,333	)		(214,636	)		—			—

F-47

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Financing Receivables

The following table contains a summary of the loan receivables by type of borrower and the method by which the credit quality is monitored on a quarterly basis:

			As of
			December 31,
Class of Financing Receivables (in thousands of U.S. dollars)	Credit Quality Indicator	Grade	2014		2013
Advances/ loans to joint ventures	Payment activity	Performing	$	18,952	$	24,510
Demand note due from owner	Payment activity	Performing	$	143,241	$	—

The shareholder loans to joint ventures are classified as advances to joint ventures in the consolidated and combined carve-out balance sheet. Refer to note 13.

19.

Risk management and concentrations of risk

Derivative instruments can be used in accordance with the overall risk management policy.

Foreign exchange risk

All revenues, financing, interest expenses from financing and most expenditures for newbuildings 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, 2014, 2013 and 2012, no derivative financial instruments have been used to manage foreign exchange risk.

Interest rate risk

Interest rate swaps are utilized to exchange a receipt of floating interest for a payment of fixed interest to reduce the exposure to interest rate variability on its outstanding floating-rate debt. As of December 31, 2014, there are interest rate swap agreements on the Lampung facility floating rate debt that are designated as cash flow hedges for accounting purposes. No derivative instruments were outstanding as of December 31, 2013. As of December 31, 2014, the following interest rate swap agreements were outstanding:

(in thousands of U.S. dollars)

Interest
rate
index

Notional
amount

Fair
value
carrying
amount
liability

Term

Fixed
interest
rate (1)

LIBOR-based debt

Interest rate swaps (2)

LIBOR

212,333

(9,220

)

Sept 2026

2.8

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 Borrower of 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 amortized over 12 years to match the outstanding balance 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 for $237.1 million of the Lampung facility. As of December 29, 2014, a prepayment of $7.9 million on the Lampung facility occurred. The notional amount of the interest rate swaps was higher than the outstanding balance on the Lampung facility. Therefore, it was decided that the amount of the over hedge of the interest rate swaps would be settled with a cash payment of $1.1 million. This resulted in the amendment of the original interest rate swaps and the hedge was de-designated for accounting purposes. The effective date of the settlement was December 29, 2014. The other terms of the interest rate swaps did not change but the nominal amount of the interest rate swap were reduced to match the outstanding debt. The amended interest rate swaps were re-designated as a cash flow hedge for accounting purposes.

F-48

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the consolidated and combined carve-out balance sheets.

	Current			Long-term
	liabilities:			liabilities:
	derivative			derivative
	financial			financial
(in thousands of U.S. dollars)	instruments			instruments
As of December 31, 2014
Interest rate swaps	$	(4,676	)	$	(4,544	)
As of December 31, 2013
Interest rate swaps	$	—		$	—

The following effects of cash flow hedges relating to interest rate swaps are included in losses on derivative financial instruments in the consolidated and combined carve-out statements of income for the year ended December 31, 2014. There were no realized or unrealized gains or losses on derivative financial instruments for the years ended December 31, 2013 and 2012.

	Year ended
	December 31, 2014
	Realized		Unrealized
	gains		gains
(in thousands of U.S. dollars)	(losses)		(losses)			Total
Interest rate swaps:
Ineffective portion of cash flow hedge	$	—		(145	)	$	(145	)
Amortization of amount excluded from hedge effectiveness		—		(11	)		(11	)
Reclassification from accumulated other comprehensive income		—		(5	)		(5	)
Loss on derivative financial instruments	$	—		(161	)	$	(161	)

The effect of cash flow hedges relating to interest rate swaps and the related tax effects on other comprehensive income included in the consolidated and combined carve-out statements of other comprehensive income and changes in accumulated other comprehensive income (“OCI”) in the consolidated and combined carve-out statements of changes in partner’s capital/ owner’s equity is as follows for the year ended and as of December 31, 2014.

	Cash Flow Hedge
(in thousands of U.S. dollars)	Before tax gains (losses)			Tax benefit (expense)		Net of tax			Accumulated OCI
Balance as of December 31, 2013									$	—
Effective portion of unrealized loss on cash flow hedge $		(10,164	)		1,984		(8,180	)		(8,180	)
Reclassification of amortization of cash flow hedge to earnings		5			—		5			5
Other comprehensive income (loss) for period $		(10,159	)		1,984		(8,175	)
Balance as of December 31, 2014									$	(8,175	)

There were no cash flow hedges for the years ended December 31, 2013 and 2012.

F-49

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Refer to note 8 for additional information on the tax effects included in other comprehensive income.

As of December 31, 2014, the estimated amounts to be reclassified from accumulated other comprehensive income to earnings during the next twelve months is $855 for amortization of accumulated other comprehensive income for losses on the de-designated interest rate swap and reversal of the related deferred tax benefit.

Credit risk

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 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 is a single charterer 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. No allowance for doubtful accounts was recorded for the year ended December 31, 2014. 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 charter terminate prematurely, there could be delays in obtaining a new time charter and the rates could be lower depending upon the prevailing market conditions.

20. Commitments and contingencies

Contractual commitments

As of December 31, 2014, there were no material contractual commitments required to be made in 2015.

Claims and Contingencies

PGN claims including delay liquidated damages

Following certain delays by the unrelated pipeline contractor completing the pipeline and minor damage to the FSRU by a tugboat during the pipeline installation, the time charter hire on the PGN FSRU Lampung commenced July 21, 2014 for the start of commissioning. During the commissioning to test the PGN FSRU Lampung project (including the Mooring) and the pipeline functionality, problems were identified on August 29, 2014 with the regasification system for the FSRU. This required that the parts of the regasification system were disassembled and transferred to shore for repair under provision of the warranties for the vessel. The equipment was reinstalled and all commissioning completed to allow the Partnership to deliver the Certificate of Acceptance to PGN. PGN formally accepted and signed the Certificate of Acceptance dated October 30, 2014.

The Partnership’s subsidiary had commitments to pay a day rate for delay liquidated damages to PGN up to a maximum amount of $10.7 million if the PGN FSRU Lampung was not connected to the Mooring and ready to deliver LNG by the scheduled arrival date or acceptance was not achieved by the scheduled delivery date.

PGN had concerns about requirements under the time charter contract to pay hire rates for periods the regasification system was not functioning and issued invoices for $7.1 million for delay liquidated damages for amounts PGN believed it had claims for delays in the scheduled arrival date and the acceptance date. PGN did not pay its time charter hire for September or October 2014. Delay liquidated damages cease on the date of the Certificate of Acceptance of October 30, 2014.The Partnership had included potential delay liquidated damages due to PGN in its project contingency as part of estimated total construction contract costs for the Mooring (as the first deliverable under the contract) as the basis for computing the percentage of completion.

F-50

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

The Partnership is indemnified under the omnibus agreement by Höegh LNG for delay liquidated damages. The Partnership filed indemnification claims for the delay liquidated damages invoiced from PGN for the total of $7.1 million and recorded to this amount to construction contract expenses for claims for the months of September and October 2014. The amounts were to be paid to the Partnership by Höegh LNG prior to any delay liquidated damages being paid to PGN.

The Partnership is also indemnified by Höegh LNG for any hire rate payments not received 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 filed indemnification claims for the September and October 2014 invoices not paid by PGN of $6.5 million and $6.7 million, respectively, for hire rate payments including the Tax element and VAT and received payments from Höegh LNG in September and October 2014, respectively. Indemnification for hire rate payments is accounted for consistent with the accounting policies for loss of hire insurance, and is recognized when the proceeds are received. Therefore, the Partnership has recognized the payments from Höegh LNG for September and October 2014 as revenue, including additional revenues recognized of $4.9 million due to the restatement adjustments. For additional information, refer to note 2 significant accounting policies on insurance and other claims and note 2 d. restatement of previously issued financial statements.

The Partnership’s subsidiary is jointly and severally liable for the delay liquidated damages of the pipeline contractor to the extent the pipeline contractor fails to perform. Similarly, the pipeline contractor is jointly and severally liable for the Partnership’s delay liquidated damages. The Partnership’s maximum exposure for the pipeline contractor’s delay liquidated damages is approximately $11.5 million. Further, the Partnership’s subsidiary and the pipeline contractor have an agreement to cover the other party’s delay liquidated damages to the extent caused by the other party’s scope of work. As of December 31, 2014, the Partnership had not received any claims from PGN or the pipeline contractor related to the contractor’s delay liquidated damages. The Partnership is indemnified by Höegh LNG for any potential delay liquidated damages, net of any recoveries, arising for or from claims of the pipeline contractor.

Subsequent to December 31, 2014, an understanding with PGN, the pipeline contractor and the Partnership’s subsidiary has been reached. As a result, PGN will not pay the time charter hire for September or October 2014, the Partnership’s subsidiary will not pay the delay liquidated damages, the Partnership’s subsidiary is released from joint and several liability for the pipeline contractor’s delay liquidated damages, the pipeline contractor is released from joint and several liability for the Partnership’s subsidiary’s delay liquidated damages and neither the Partnership’s subsidiary nor the pipeline contractor cover the other party’s delay liquidated damages to the extent caused by the other party’s scope of work. Due to this subsequent event, no delay liquidated damages are reflected in the construction contract expenses for the year ended December 31, 2014. Refer to note 6. Since the Partnership’s subsidiary will not pay any delay liquidated damages to PGN, the Partnership will not receive any indemnification from Höegh LNG for this item.

As of December 31, 2013, cash collateral of $10.7 million, classified as restricted cash in the consolidated and combined carve-out balance sheet, was provided for in a letter of credit arrangement for the delay liquidated damages. As part of the Lampung facility, a $10.7 million letter of credit facility replaced the original letter of credit arrangement and the restricted cash was released in the first quarter of 2014. No amounts were drawn on the letter of credit facility as of December 31, 2014. On February 16, 2015, the letter of credit expired. Refer to note 23.

Additionally, a warranty allowance of $2.0 million was recorded to construction contract expenses for replacement of equipment parts on the Mooring for the year ended December 31, 2014. The repairs are expected to take place in 2015 and 2016. The Partnership filed indemnification claims for the warranty allowance of $2.0 million related to the Mooring. The amount will be paid to the Partnership by Höegh LNG when costs are incurred for the warranty. When the funding for the indemnification is received from Höegh LNG, the amount will be recorded as a contribution to equity. For additional information, refer to note 2 significant accounting policies on insurance and other claims.

The Partnership is indemnified by Höegh LNG for non-budgeted expenses (including repair costs) incurred in connection with the PGN FSRU Lampung project prior to the date of acceptance. In the first quarter of 2015, the Partnership filed indemnification claims for non-budgeted expenses and costs of $3.1 million related to the year ended December 31, 2014. Höegh LNG paid us for this amount by March 31, 2015. The amount is recorded as a contribution to equity in the first quarter of 2015. Refer to note 2 significant accounting policies on insurance and other claims.

F-51

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

During January 2015, certain regasification equipment on the PGN FSRU Lampung was upgraded. There was no off-hire as a result. It is expected that warranties will cover the upgrades but, if not, the cost of the upgrade would be indemnified by Höegh LNG.

21. Supplemental cash flow information

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014		2013		2012
Supplemental disclosure of non-cash financing activities
Non-cash capital contribution from conversion of debt	$	101,500		—	$	—
Non-cash elimination to equity at IPO (note 2)		45,799		—		—
Supplemental disclosure of non-cash investing activities
Non-cash capitalized interest for newbuilding	$	1,418		—	$	—

22. Earning per unit and cash distributions

The calculation of basic and diluted earnings per unit are presented below

	August 12 to December 31,
(in thousands of U.S. dollars, except unit and per unit numbers)	2014
	(Restated)
Post IPO net income attributable to the unitholders of Höegh LNG Partners LP	$	13,255
Less: Dividends paid or to be paid (1)		(13,707	)
Under (over) distributed earnings		(452	)
Under (over) distributed earnings attributable to:
Common units public		(190	)
Common units Höegh LNG		(36	)
Subordinated units Höegh LNG		(226	)
		(452	)
Basic and diluted weighted average units outstanding (in thousands)
Common units public		11,040
Common units Höegh LNG		2,116
Subordinated units Höegh LNG		13,156
Basic and diluted earnings per unit:
Common units public	$	0.50
Common units Höegh LNG	$	0.50
Subordinated units Höegh LNG	$	0.50

(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.

Earnings per unit information for the period ended December 31, 2014 is for the period from August 12, 2014 (the date of the Partnership’s IPO) to December 31, 2014. Earnings per unit information has not been presented for any period prior to the Partnership’s IPO as the information is not comparable due to changes in the basis of preparation of the financial statements (refer to note 2) and the Partnership’s structure (refer to note 3).

As of December 31, 2014, the total number of units outstanding was 26,312,120. Common units outstanding were 13,156,060 of which 11,040,000 common units were held by the public and 2,116,060 common units were held by Höegh LNG. Höegh LNG owned 13,156,060 subordinated units. The General Partner has a non-economic interest and has no units.

F-52

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Earnings per unit is calculated by dividing net income by the weighted average number of units outstanding during the applicable period.

The common unitholders’ and subordinated unitholders’ interest in net income are calculated as if all net income were distributed according to terms of the Partnerships’ First 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; and iii) provide funds for distributions to the unitholders for any one or more of the next four quarters. Therefore, the earnings per unit is 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 financial instruments and unrealized gains or losses on foreign exchange transactions.

During the subordination period, the common units will have the right under the Partnership Agreement to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3375 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units.

The amount of minimum distributions is $0.3375 per unit per quarter, or $1.35 per unit on an annual basis, and is made during the subordination period in the following manner:

•

first , 100.0% to the common unitholders, pro rata, until the Partnership distributes for each outstanding common unit an amount equal to the minimum quarterly distribution of $0.3375 for that quarter;

•

second , 100.0% to the common unitholders, pro rata, until the Partnership distributes for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; and

•

third , 100.0% to the subordinated unitholders, pro rata, until the Partnership distributes for each subordinated unit an amount equal to the minimum quarterly distribution of $0.3375 for that quarter.

In addition, Höegh LNG currently holds all of 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.

If for any quarter:

•

the Partnership has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•

the Partnership has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders in the following manner:

•

first , 100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.388125 per unit for that quarter (the “first target distribution”);

•

second , 85.0% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.421875 per unit for that quarter (the “second target distribution”);

•

third , 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.50625 per unit for that quarter (the “third target distribution”); and

F-53

HÖEGH LNG PARTNERS LP

NOTES TO THE CONSOLIDATED AND COMBINED CARVE-OUT FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

•

thereafter , 50.0% to all unitholders, pro rata, and 50.0% to the holders of the incentive distribution rights, pro rata.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above assume that the Partnership does not issue additional classes of equity securities.

23. Subsequent events

On February 16, 2015, the $10.7 million standby letter of credit under the Lampung facility that supported guarantees to PGN for delivery obligations of the FSRU and Mooring under the LOM expired.

Subsequent to December 31, 2014, an understanding with PGN, the pipeline contractor and the Partnership’s subsidiary has been reached. As a result, PGN will not pay the time charter hire for September or October 2014, the Partnership’s subsidiary will not pay the delay liquidated damages, the Partnership’s subsidiary is released from joint and several liability for the pipeline contractor’s delay liquidated damages, the pipeline contractor is released from joint and several liability for the Partnership’s subsidiary’s delay liquidated damages and neither the Partnership’s subsidiary nor the pipeline contractor cover the other party’s delay liquidated damages to the extent caused by the other party’s scope of work. Due to this subsequent event, the previously recorded delay liquidated damages were reversed from construction contract expenses for the year ended December 31, 2014. Refer to notes 6 and 20. Since the Partnership’s subsidiary will not pay any delay liquidated damages to PGN, the Partnership will not receive any indemnification from Höegh LNG for this item.

On April 23, 2015, the Partnership declared a quarterly cash distribution with respect to the quarter ended March 31, 2015 of $0.3375 per unit. The distribution corresponds to an annualized distribution of $1.35 per unit.

Except for the restated and updated information referred to in note 2.d, the consolidated and combined carve-out financial statements continue to present information as of the date of the original filing of the Form 20-F for the year ended December 31, 2014. Other events occurring after the date of the original filing or other disclosures necessary to reflect subsequent events have been or will be addressed in other reports filed with or furnished to the Securities and Exchange Commission subsequent to the date of the original filing of the Form 20-F.

F-54

Report of Independent Auditors

The Board of Directors of Höegh LNG Partners LP

We have audited the accompanying combined financial statements of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., which comprise the combined balance sheets as of December 31, 2014 and 2013, and the related combined statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2014, and the related notes to the combined financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these combined financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. at December 31, 2014 and 2013, and the combined results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young AS

Oslo, Norway

April 24, 2015

F-55

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

COMBINED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

	Notes		2014			2013			2012
REVENUES
Time charter revenues		3	$	82,638		$	82,220		$	82,151
Total revenues				82,638			82,220			82,151
OPERATING EXPENSES
Vessel operating expenses		11		(15,026	)		(15,404	)		(15,049	)
Administrative expenses		11		(1,944	)		(2,122	)		(2,254	)
Depreciation and amortization		6		(18,912	)		(18,722	)		(18,735	)
Total operating expenses				(35,882	)		(36,248	)		(36,038	)
Operating income				46,756			45,972			46,113
FINANCIAL INCOME (EXPENSES), NET
Interest income		4		—			—			1
Interest expense		4, 5, 11		(34,241	)		(36,169	)		(38,065	)
Gain (loss) on derivative financial instruments		4, 13		(23,757	)		70,075			1,386
Other financial items, net		4		(34	)		(38	)		(36	)
Total financial income (expense), net				(58,032	)		33,868			(36,714	)
Income before tax				(11,276	)		79,840			9,399
Income tax expense				—			—			—
Net income (loss)			$	(11,276	)	$	79,840		$	9,399

The accompanying notes are an integral part of the combined financial statements.

F-56

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

	2014			2013		2012
Net income	$	(11,276	)	$	79,840	$	9,399
Other comprehensive income		—			—		—
Comprehensive income (loss)	$	(11,276	)	$	79,840	$	9,399

The accompanying notes are an integral part of the combined financial statements.

F-57

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

COMBINED BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(in thousands of U.S. dollars)

	Notes		2014			2013
ASSETS
Current assets
Cash and cash equivalents		12	$	10,719		$	11,578
Trade receivables				154			31
Deferred debt issuance cost		5		364			368
Prepaid expenses				2,799			2,131
Total current assets				14,036			14,108
Long-term assets
Restricted cash		10,12		25,104			25,104
Vessels, net of accumulated depreciation		6,11,14		577,897			592,092
Deferred debt issuance cost		5		2,174			2,538
Total long-term assets				605,175			619,734
Total assets			$	619,211		$	633,842
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt		10,12	$	20,768		$	19,522
Trade payables				40			—
Amounts due to owners and affiliates		7		14,516			15,246
Derivative financial instruments		13		23,887			26,274
Prepaid and deferred revenue		8		1,652			1,730
Accrued liabilities		9		6,586			6,540
Total current liabilities				67,449			69,312
Long-term liabilities
Long-term debt		10,12		501,369			522,136
Loans due to owners		7,12		24,575			34,795
Derivative financial instruments		13		101,910			75,766
Prepaid and deferred revenue		8		24,612			21,261
Total long-term liabilities				652,466			653,958
Total liabilities				719,915			723,270
EQUITY
Paid in capital				100			100
Retained deficit				(100,804	)		(89,528	)
Total equity				(100,704	)		(89,428	)
Total liabilities and equity			$	619,211		$	633,842

The accompanying notes are an integral part of the combined financial statements.

F-58

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

COMBINED STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(in thousands of U.S. dollars)

						Accumulated
						Other
	Paid in		Retained			Comprehensive		Total
	Capital		Deficit			Income		Equity
Balance as of December 31, 2011	$	100		(178,767	)		—	$	(178,667	)
Net income		—		9,399			—		9,399
Other comprehensive income		—		—			—		—
Balance as of December 31, 2012	$	100		(169,368	)		—	$	(169,268	)
Net income		—		79,840			—		79,840
Other comprehensive income		—		—			—		—
Balance as of December 31, 2013		100		(89,528	)		—		(89,428	)
Net income		—		(11,276	)		—		(11,276	)
Other comprehensive income		—		—			—		—
Balance as of December 31, 2014	$	100		(100,804	)		—	$	(100,704	)

The accompanying notes are an integral part of the combined financial statements.

F-59

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

COMBINED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 2012

(in thousands of U.S. dollars)

	2014			2013			2012
OPERATING ACTIVITIES
Net income	$	(11,276	)	$	79,840		$	9,399
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		18,912			18,722			18,735
Unrealized gain on derivative financial instrument		23,757			(70,075	)		(1,386	)
Accrued interest expense on loans to owners		2,217			2,763			3,239
Amortization of deferred revenue		(1,718	)		(942	)		(1,353	)
Amortization of deferred debt issuance cost		368			371			372
Expenditure for drydocking		—			—			(1,443	)
Cash received and recorded as deferred revenue		4,992			722			4,314
Other adjustments		—			(86	)		77
Changes in working capital:
Trade receivables		(123	)		154			(185	)
Prepaid expenses		(668	)		(842	)		(624	)
Amounts due to owners and affiliates		165			(177	)		730
Trade payables		40			—			—
Accrued liabilities		45			312			66
Net cash provided by operating activities		36,711			30,762			31,941

INVESTING ACTIVITIES
Expenditure for vessel modification and equipment		(4,717	)		(1,043	)		(2,870	)
Net cash used in investing activities		(4,717	)		(1,043	)		(2,870	)

FINANCING ACTIVITIES
Repayment of long-term debt		(19,521	)		(18,350	)		(17,249	)
Repayment of principal of loans due to owners		(13,332	)		(11,084	)		(12,018	)
Net cash provided by financing activities		(32,853	)		(29,434	)		(29,267	)

Increase (decrease) in cash and cash equivalents		(859	)		285			(196	)
Cash and cash equivalents, beginning of year		11,578			11,293			11,489
Cash and cash equivalents, end of year	$	10,719		$	11,578		$	11,293

The accompanying notes are an integral part of the combined financial statements.

F-60

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 certain of Höegh LNG’s interests in entities including SRV Joint Gas Ltd. (the owner of the GDF Suez Neptune), and SRV Joint Gas Two Ltd. (the owner of the GDF Suez Cape Ann) in connection with the Partnership’s initial public offering of its common units (the “IPO”). On August 12, 2014, the Partnership completed its IPO. Prior to the closing of the IPO, Höegh LNG contributed to the Partnership its 50% equity in each of the entities owning the GDF Suez Neptune, the GDF Suez Cape Ann and the shareholder loans due to it from those entities.

These combined financial statements which include the individual financial statements of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”) for the purpose of meeting the requirements of Securities and Exchange Commission Rule 3-09 of Regulation S-X. The Partnership owns 50% in each of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., and the remaining 50% ownership interests are held by joint venture partners, Mitsui O.S.K.Lines, Ltd. and Tokyo LNG Tanker Co. The GDF Suez Neptune and the GDF Suez Cape Anne are floating storage regasification units (“FSRUs”) and are collectively referred to in these combined financial statements as the vessels or the “FSRUs.” SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd. are referred to in these combined financial statements individually as the “joint venture” and together as the “joint ventures.”

The GDF Suez Neptune and the GDF Suez Cape Ann operate under long-term time charters with GDF Suez Global LNG Supply S.A., a subsidiary of GDF Suez S.A. (“GDF Suez”), with expiration dates in 2029 and 2030, respectively, and, in each case, with an option to extend for up to two additional periods of five years each. In the years ended December 31, 2014, 2013 and 2012, 100% of the joint ventures’ total revenues were derived from GDF Suez.

Höegh LNG Fleet Management AS, a subsidiary of Höegh LNG, provided commercial and technical operations of the FSRUs for the years ended December 31, 2014, 2013 and 2012.

The following table lists the entities combined in these combined financial statements and their purpose as of December 31, 2014.

Name	Jurisdiction of Incorporation	Purpose
SRV Joint Gas Ltd. (50% ownership)	Cayman Islands	Owns GDF Suez Neptune
SRV Joint Gas Two Ltd. (50% ownership)	Cayman Islands	Owns GDF Suez Cape Ann

2. Significant accounting policies

a. Basis of presentation

The combined financial statements include the financial statements of SRV Joint Gas Ltd. and SRV Joint Gas Two Ltd., which are under common management. The combined financial statements are prepared in accordance with the US GAAP policies of the Partnership. All inter-company balances and transactions are eliminated.

b. Accounting policies

Foreign currencies

The reporting currency in the combined financial statements is the U.S. dollar, which is the functional currency of each of the joint ventures. All revenues are received in U.S. dollars and a majority of the expenditures for investments and all of the long-term debt and shareholder loans 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 combined statements of income.

F-61

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Time charter revenues and related expenses

Time charter revenues:

Revenue arrangements may include the right to use FSRUs for a stated period of time that meet the criteria for operating lease accounting, in addition to providing a time charter service element. Time charter revenues consist of charter hire payments under time charters, fees for providing time charter services, fees for reimbursement for actual vessel operating expenses and drydocking costs borne by the charterer on a pass through basis; as well as fees for the reimbursement of certain vessel modifications or other costs borne by the charterer.

Revenues for the lease element of time charters are not recognized for days that the FSRUs are off-hire.

Fees for providing time charter services and reimbursements for actual vessel operating expenses are recognized as revenues as services are performed. Revenues for the time charter services element are not recognized for days that the FSRUs are off-hire.

Upfront payments of fees for reimbursement of drydocking costs are recognized on a straight line basis over the period to the next drydocking, which is generally between five and seven years.

Related expenses:

Vessel operating expenses, reflected in expenses in the income statement, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and technical management fees. Höegh LNG Fleet Management AS provides the technical operation services of the FSRUs. Therefore, the joint ventures have no employees. When the vessel is on hire, vessel operating expenses are invoiced as fees to the charterer. 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.

Insurance claims

Insurance claims for property damage are recorded, net of any deductible amounts, for recoveries up to the amount of loss recognized when the claims submitted to insurance carriers are probable of recovery. Claims for property damage in excess of the loss recognized and for loss off hire are considered gain contingencies, which are recognized when the proceeds are received.

Income taxes

The joint ventures are not liable for income taxes to the Cayman Islands and therefore would only incur income tax liabilities to the extent assessed by countries in which they operate. As of December 31, 2014, 2013 and 2012, the joint ventures believe that they incurred no income tax expenses or liabilities.

Pursuant to Section 883 of the Internal Revenue Code of the United States (the "Code"), U.S. source income earned by a non-U.S. company from the operation of ships in international transportation is generally exempt from U.S. tax if the company operating the ships meets, among other things, the following three requirements: (1) the company is organized in a country which grants an equivalent exemption from income taxes to U.S. corporations with respect to that type of international transportation income; (2) the company is more than 50% owned, or is treated as owned after applying certain attribution rules, by individuals who are residents, as defined, in such country or another foreign country that grants an equivalent exemption to U.S. corporations; and (3) the company meets certain substantiation, reporting and other requirements. The joint ventures believe that they qualified for the exemption for 2014, 2013 and 2012 and, therefore, they were not subject to tax on their U.S. source income.

F-62

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

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 consist of bank deposits, which may only be used to settle payments as required by loan agreements. Restricted cash is classified as long-term when the settlement or required loan agreement period is more than 12 months from the balance sheet date.

Trade receivables and allowance for doubtful accounts

Deferred debt issuance costs

Debt issuance costs, including arrangement fees and legal expenses, are deferred and presented as deferred debt issuance cost in the combined 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 is repaid early, any unamortized portion of the deferred debt issuance costs is recognized as interest expense in the period in which the loan is repaid.

Vessels

Expenditures covering recurring routine repairs and maintenance are expensed as incurred.

F-63

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Impairment of long-lived assets

Derivative instruments

Derivatives are entered into to reduce market risks associated with its operations. The joint ventures have interest rate swaps 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 December 31, 2014 and 2013, the interest rate swaps were not designated as hedges for accounting purposes.

All derivative instruments are initially recorded at fair value as either current or long-term assets or liabilities as derivative financial instruments in the combined balance sheet and are subsequently remeasured to fair value. The changes in the fair value of the derivative financial instruments are recognized in earnings under financial income (expenses), net as gain (loss) on derivative instruments.

Prepaid and deferred revenue

Prepaid revenue includes prepayments of fees for charter hire, vessel operating expenses or other future services. Deferred revenues include payments from charterers for certain vessel modifications and upfront payments for drydocking costs which is amortized over the charter term or until the next planned drydocking, respectively.

Use of estimates

The preparation of financial statements in accordance with U.S. GAAP requires that management make estimates and assumptions affecting the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates subject to such estimates and assumptions include the useful lives of vessels, drydocking and the valuation of derivatives.

Recent accounting pronouncements

There are no recent accounting pronouncements, whose adoption would have a material impact on the combined financial statements in the current year. In May 2014, a new accounting standard, Revenue from Contracts with Customers, was issued by the Financial Accounting Standards Board. Under the new standard, revenue for most contracts with customers will be recognized when promised goods or services are transferred to customers in an amount that reflects consideration that the entity expects to be entitled, subject to certain limitations. The scope of this guidance does not apply to leases, financial instruments, guarantees and certain non-monetary transactions. The standard is effective for annual periods beginning after December 15, 2016 and early adoption is not permitted. The joint ventures are currently assessing the impact the adoption this standard will have on the combined financial statements.

F-64

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

3. Time charter revenues

As at December 31, 2014, the minimum contractual future revenues to be received under the time charters as of December 31, 2014, during the next five years and thereafter are as follows:

(in thousands of U.S. dollars)	Total
2015	$	65,375
2016		65,375
2017		65,375
2018		65,375
2019		65,375
Thereafter		664,464
Total	$	991,338

The long-term time charters for the GDF Suez Neptune and the GDF Suez Cape Ann with GDF Suez have initial terms of 20 years expiring in 2029 and 2030, respectively. The time charters are accounted for as operating leases. The minimum contractual future revenues include the fixed payments for the lease and services elements for the 20 year period but exclude the variable fees from the charterer for vessel operating, subsequent modification and drydocking costs. Additionally, each time charter has options to extend the contract term for two five-year periods. Payments for option periods are not included in minimum contractual future revenues until such time as the options are exercised.

4. Financial income (expenses)

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014			2013			2012
Interest income	$	—			—		$	1
Interest expense:
Interest expense		(33,873	)		(35,798	)		(37,693	)
Amortization of deferred debt issuance cost		(368	)		(371	)		(372	)
Total interest expense		(34,241	)		(36,169	)		(38,065	)
Unrealized gain (loss) on derivative instruments		(23,757	)		70,075			1,386
Other financial items, net		(34	)		(38	)		(35	)
Total financial income (expense), net	$	(58,032	)		33,868		$	(36,714	)

Interest expense for the years ended December 31, 2014, 2013 and 2012 included interest expense of $3,439, $4,243 and $4,961, respectively, on the subordinated shareholders loans from the Partnership and other joint venture owners (note 11). The unrealized gain (loss) on derivative instruments related to the mark to market adjustment on the interest rate swaps (note 13).

F-65

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

5. Deferred debt issuance cost

Deferred debt issuance costs are deferred and amortized to interest expense over the term of the related debt. The deferred debt issuance costs are comprised of the following amounts:

	As of
	December 31,
(in thousands of U.S. dollars)	2014			2013
Deferred debt issuance cost	$	4,607		$	4,607
Accumulated amortization		(2,069	)		(1,701	)
Total deferred debt issuance cost		2,538			2,906

Current deferred debt issuance cost		364			368
Long-term deferred debt issuance cost		2,174			2,538
Total deferred debt issuance cost	$	2,538		$	2,906

Amortization expense of deferred debt issuance cost, a component of interest expense, was $368, $371 and $372 for the years ended December 31, 2014, 2013 and 2012, respectively.

6. Vessels, net of accumulated depreciation

				Dry-
(in thousands of U.S. dollars)	Vessel			docking			Total
Historical cost December 31, 2012	$	654,413			8,443		$	662,856
Additions		1,043			—			1,043
Disposals		—			—			—
Historical cost December 31, 2013		655,456			8,443			663,899
Accumulated depreciation December 31, 2012		(49,128	)		(3,957	)		(53,085	)
Depreciation for the year		(17,371	)		(1,351	)		(18,722	)
Accumulated depreciation December 31, 2013		(66,499	)		(5,308	)		(71,807	)
Vessel, net December 31, 2013	$	588,957			3,135		$	592,092

				Dry-
(in thousands of U.S. dollars)	Vessel			docking			Total
Historical cost December 31, 2013	$	655,456			8,443		$	663,899
Additions		4,717			—			4,717
Disposals		—			—			—
Historical cost December 31, 2014		660,173			8,443			668,616
Accumulated depreciation December 31, 2013		(66,499	)		(5,308	)		(71,807	)
Depreciation for the year		(17,561	)		(1,351	)		(18,912	)
Accumulated depreciation December 31, 2014		(84,060	)		(6,659	)		(90,719	)
Vessel, net December 31, 2014	$	576,113			1,784		$	577,897

F-66

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

7. Amounts and loans due to owners and affiliates

Amounts due to owners and affiliates include trade liabilities and the current portion of the long-term loans due to owners. Trade liabilities due to owners and affiliates principally relate to short term funding of operations by affiliates and do not bear interest.

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Trade liabilities due to owners and affiliates	$	1,186	$	1,021
Current portion of long-term loans due to owners		13,330		14,225
Amounts due to owners and affiliates	$	14,516	$	15,246

The current portion of long-term loans, included in the table above, and long-term loans due to owners and affiliates are as follows:

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Current portion of long-term loans due to owners	$	13,330	$	14,225
Long-term loans due to owners		24,575		34,795
Total loans due to owners	$	37,905	$	49,020

The loans due to owners consist of shareholders 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 GDF Suez Neptune and the GDF Suez Cape Ann were delivered November 30, 2009 and June 1, 2010, respectively. The shareholders loans are subordinated to the long-term bank debt, consisting of the Neptune facility and the Cape Ann facility described in note 10. 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 Partnership is due 50% 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 the joint ventures.

The shareholder loans have financed part of the construction of the vessels and operating expenses until the delivery and commencement of operations of the GDF Suez Neptune and the GDF Suez 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 include a payment of interest for the first month of the quarter and a repayment of principal. Interest is accrued for the last two months of the quarter for repayment in the latter years of the loans. However, there is no fixed repayment schedule. Since the shareholder loans are subordinated to long-term bank debt, the repayment plan is subject to quarterly discretionary revisions based on available cash after servicing of the long-term bank debt.

8. Prepaid and deferred revenue

	As of
(in thousands of U.S. dollars)	December 31,
	2014		2013
Current deferred revenue	$	1,652	$	1,730
Long-term deferred revenue		24,612		21,261
Total prepaid and deferred revenue	$	26,264	$	22,991

F-67

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

9. Accrued liabilities

	As of
	December 31,
(in thousands of U.S. dollars)	2014		2013
Accrued external interest expense	$	4,998	$	5,189
Other accruals		1,588		1,351
Accrued liabilities	$	6,586	$	6,540

10. Debt

	As of
	December 31,
(in thousands of U.S. dollars)	2014			2013
$300 million Neptune facility	$	257,604		$	267,420
$300 million Cape Ann facility		264,533			274,238
Total debt		522,137			541,658
Less: Current portion of long-term debt		(20,768	)		(19,522	)
Long-term debt	$	501,369		$	522,136

Neptune facility

In December 2007, the joint venture owning GDF Suez Neptune, as the borrower, entered into a $300 million secured facility with a syndicate of banks as long term financing of the construction the GDF Suez Neptune (the “Neptune facility”). The facility is secured with a first priority mortgage of the GDF Suez Neptune, an assignment of its rights under the time charter and a pledge of the borrower’s cash accounts. The Partnership 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 Holdings Ltd. 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 twelve years with a final balloon payment of $165 million due in April 2022. The Neptune facility bears interest at a rate equal to three month LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swaps to the borrower (see note 13), which are not reflected in the LIBOR rate for the facility.

There were no financial covenants in the Neptune facility as of December 31, 2014 and 2013, but certain other covenants and restrictions apply. The borrower is required to maintain insurance coverage for damage to the FSRU equivalent to 120% 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, restricted cash for debt service for the next six months including interest payment on the facility and associated interest rate swap agreements and certain distribution accounts. Cash in the operating account from charter hire 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 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 disbursements or paying dividends 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, retention accounts are fully funded, or the written consent of the lenders. The facility agreement limits the borrower’s ability to raise additional debt, enter into certain material transactions and make guarantees.

F-68

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Cape Ann facility

In December 2007, the joint venture owning GDF Suez Cape Ann, as the borrower, entered into a $300 million secured facility with a syndicate of banks as long term financing of the construction the GDF Suez Cape Ann (the “Cape Ann facility”). The facility is secured with a first priority mortgage of the GDF Suez Cape Ann, an assignment of its rights under the time charter and a pledge of the borrower’s cash accounts. The Partnership 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 Holdings Ltd. 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 twelve years with a final balloon payment of $165 million due in October 2022. The Cape Ann facility bears interest at a rate equal to three month LIBOR plus a margin of 0.5%. The syndicate of banks also provides interest rate swaps to the borrower (see note 13), which are not reflected in the LIBOR rate for the facility.

There are no financial covenants in the Cape Ann facility as of December 31, 2014 and 2013, but certain other covenants and restrictions apply. The borrower is required to maintain insurance coverage for damage to the FSRU equivalent to 120% 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, restricted cash for debt service for the next six months including interest payment on the facility and associated interest rate swap agreements and certain distribution accounts. Cash in the operating account from charter hire 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 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 disbursements or paying dividends 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, retention accounts are fully funded, or the written consent of the lenders. The facility agreement limits the borrower’s ability to raise additional debt, enter into certain material transactions and make guarantees.

The debt is denominated in U.S. dollars and bears interest at floating rates at a weighted average interest rate for the years ended December 31, 2014, 2013 and 2012 of 0.80%, 0.90% and 1.09 % respectively.

The outstanding debt as of December 31, 2014 is repayable as follows:

Year Ending December 31,
(in thousands of U.S. dollars)
2015	$	20,768
2016		22,093
2017		23,503
2018		25,003
2019		26,599
2020 and thereafter		404,171
Total	$	522,137

11. Related party transactions

The joint ventures are single purpose joint ventures owning and operating the FSRUs. See note 7 for amounts and loans due to owners and affiliates. The joint ventures do not have any employees. As described in note 1, a subsidiary of Höegh LNG, has charged the joint ventures for the years ended December 31, 2014, 2013 and 2012 for the provision of technical and commercial management of the FSRUs. Amounts included in the combined statements of income for the years ended December 31, 2014, 2013 and 2012 or capitalized in the combined balance sheets as of December 31, 2014 and 2013 are as follows:

F-69

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

	Year ended
Statement of income:	December 31,
(in thousands of U.S. dollars)	2014		2013		2012
Vessel operating expenses:
Technical management fees for FSRUs (1)	$	1,344		1,300	$	1,300
Other vessel operating expenses (2)		13,682		14,104		13,749
Administrative expenses:
Commercial management fees for FRSUs (1)		570		750		780
Other fees (3)		755		749		760
Financial income (expense):
Interest expense from shareholder loans (4)		3,439		4,243		4,961
Total	$	19,790		21,146	$	21,550

	As of
Balance sheet	December 31,
(in thousands of U.S. dollars)	2014		2013
Vessels
Supervision cost for modifications (5)	$	203	$	22
Total long-term assets	$	203	$	22

Technical and commercial management fees for FSRUs: Höegh LNG Fleet Management AS, a subsidiary of Höegh LNG, provided commercial and technical operations of the FSRUs as well as bookkeeping and administrative support for which it was paid a fixed annual fee as agreed with the charterer and other owners, respectively.

Other vessel operating expenses: In addition to the technical management fees, Höegh LNG Fleet Management AS, invoices the joint ventures for the actual costs incurred for vessel operating expenses such as crewing, repairs and maintenance, insurance, stores, lube oils and communication expenses.

Other fees: In addition to the commercial management fees, Höegh LNG charges an annual fee to the joint ventures in accordance with agreements with the joint venture owners.

Interest expense from shareholder loans: The Partnership and the other owners have provided subordinated financing to the joint ventures as shareholder loans. Interest expense is accrued monthly for the shareholder loans and recorded to interest expense. Under terms of the shareholders’ loan agreement, the principal and interest is repaid based upon available cash after servicing other debt (note 7) and, accordingly, only a portion of the accrued interest expense has been paid for the years ended December 31, 2014, 2013 and 2012. In the combined statements of cash flows, the interest expense paid for the period is included in net cash flows provided from operating activities.

Supervision cost for modifications: Höegh LNG Fleet Management AS manages the process for major modifications to vessels including site supervision at the shipyard. Costs include manning for the services and direct accommodation and travel cost. Manning costs are based upon actual hours incurred. Such costs, excluding overhead charges, are capitalized as part of the cost of the modification of the vessel.

12.

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 and cash equivalents and restricted cash approximates its carrying amounts reported in the combined carve-out balance sheets.

Loan due to owners – 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.

F-70

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Total debt– The fair values of the variable-rate debt 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.

Derivative financial instruments– The fair values of the interest rates swaps are estimated based on the present value of cash flows over the term of the instrument based on the relevant LIBOR interest rate curves, adjusted for the joint ventures’ credit worthiness given the level of collateral provided and the credit worthiness of the counterparty to the derivative, as appropriate.

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.

			As of						As of
			December 31, 2014						December 31, 2013
			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	$	10,719			10,719			11,578		$	11,578
Restricted cash		1		25,104			25,104			25,104			25,104
Interest rate swaps		2		(125,797	)		(125,797	)		(102,040	)		(102,040	)
Other:
Loans due to owners		2		(37,905	)		(39,258	)		(49,020	)		(50,485	)
Total debt		2	$	(522,137	)		(468,916	)		(541,658	)	$	(427,669	)

13.

Risk management and concentrations of risk

Derivative instruments can be used in accordance with the overall risk management policy. As of December 31, 2014 and 2013, there are no derivative instruments designated as hedges for accounting purposes.

Foreign Exchange Risk

All revenues, financing, interest expenses from financing and most expenditures for newbuildings and vessel modifications are denominated in U.S. dollars. Certain operating expenses can be denominated in currencies other than U.S. dollars. As of December 31, 2014 and 2013, no derivative financial instruments have been used to manage foreign exchange risk.

Interest Rate Risk

Interest rate swaps 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 its outstanding floating-rate debt. As at December 31, 2014 and 2013, there were interest rate swap agreements on the floating rate debt that are not designated as hedges for accounting purposes.

F-71

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

As of December 31, 2014, 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
Interest rate swaps (2)	LIBOR	$	25,555	$	6,400	Oct 2029		5.345	%
Interest rate swaps (2)	LIBOR		36,927		9,086	July 2029		5.353	%
Interest rate swaps (2)	LIBOR		184,548		45,663	Oct 2029		5.363	%
Interest rate swaps (2)	LIBOR		26,064		6,686	Jan 2030		5.385	%
Interest rate swaps (2)	LIBOR		37,662		9,667	Apr 2030		5.389	%
Interest rate swaps (2)	LIBOR	$	188,223		48,295	Jan 2030		5.399	%
				$	125,797

1) Excludes the margins paid on the floating-rate loans of 0.5%.

2) All interest rate swaps are U.S. dollar denominated and principal amount reduces quarterly.

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the combined balance sheets.

	Current		Long-term
	liabilities:		liabilities:
	derivative		derivative
	financial		financial
(in thousands of U.S. dollars)	instruments		instruments
As of December 31, 2014
Interest rate swaps	$	23,887	$	101,910
As of December 31, 2013
Interest rate swaps	$	26,274	$	75,766

Unrealized and realized gains (losses) of the interest rate swap are recognized in earnings and reported in gain (loss) on derivative instruments in the combined statements of income.

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014			2013		2012
Realized gains (losses)	$	—			—	$	—
Unrealized gains (losses)		(23,757	)		70,075		1,386
Total	$	(23,757	)		70,075	$	1,386

F-72

SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

Credit risk and concentrations of 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 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. Periodic evaluations are performed of the relative credit standing of those financial institutions. In addition, exposure is limited by diversifying among counter parties. There is a single charterer for both vessels 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 charterer's financial condition. In addition, time charters generally require the payment of the time charter rates on the first banking day of the month of hire which limits the risk of non-performance. Accordingly, no collateral or other security is required. No losses were incurred relating to the charterer for the years ended December 31, 2014, 2013 and 2012. While the maximum exposure to loss due to credit risk is the book value at the balance sheet date, should the time charter terminate prematurely, there could be delays in obtaining a new time charter and the rates could be lower depending upon the prevailing market conditions.

14. Commitments and contingencies

Assets Pledged

The following table summarizes the assets pledged for debt facilities as of December 31, 2014 and 2013:

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014		2013
Book value of vessel secured against long-term loans	$	577,897	$	592,092

Commitments:

The GDF Suez Neptune was subject to regular drydocking and modification work in March and April 2015. Committed orders for parts were $1.1 million as of December 31, 2014. Refer to note 16 for additional information.

Contingencies:

The GDF Suez Cape Ann is operating in China on a sub-charter entered into by GDF Suez. GDF Suez has informed SRV Joint Gas Two Ltd. that the sub-charterer is covering any potential corporate income taxes directly with the authorities on the joint venture’s behalf. To the extent that income tax liabilities would arise, the joint venture would be compensated by GDF Suez under terms of the time charter.

15. Supplemental cash flow information

	Year ended
	December 31,
(in thousands of U.S. dollars)	2014		2013
Supplemental cash flow information:
Interest paid	$	35,980	$	35,980

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SRV JOINT GAS LTD. AND SRV JOINT GAS TWO LTD.

NOTES TO THE COMBINED FINANCIAL STATEMENTS

(in thousands of U.S. dollars, unless otherwise indicated)

16. Subsequent events

On February 20, 2015 a contract with a shipyard was entered for regular drydocking and modification work for GDF Suez Neptune. The contractual commitment under the shipyard contract is EUR 7.3 million.

GDF Suez entered into a subcharter in Uruguay, pursuant to which GDF Suez and SRV Joint Gas Ltd. amended the GDF Suez Neptune time charter in February 2015. Such amendments apply only during the term of the subcharter. In connection with the subcharter, the charterer has agreed to reimburse the joint venture owner for the costs of modifying the GDF Suez Neptune for the subcharter and, the charterer will after the expiration of the subcharter, reimburse the costs of reinstating the vessel in order for her to be in every way fitted for service under the charter, during which times the vessel will be on-hire (so long as the time for the modification does not exceed an agreed-upon drydocking allowance). The charterer is also required to compensate the vessel owner for time spent and costs and expenses incurred in connection with the subcharter and arrange for the importation, stay and exportation into and from Uruguay of the GDF Suez Neptune and any materials or equipment needed for the vessel owner’s performance of the subcharter.

Management evaluated subsequent events through April 24, 2015.

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