too-20201231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

___________________________________

FORM 20-F

___________________________________

(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, 2020


☐			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

For the transition period from to

Commission file number 1-33198

___________________________________

ALTERA INFRASTRUCTURE L.P.

(Exact name of Registrant as specified in its charter)

___________________________________

Not Applicable

(Translation of Registrant’s Name into English)

Republic of the Marshall Islands

(Jurisdiction of incorporation or organization)

Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, United Kingdom

Telephone: +44 1224 568 200

(Address and telephone number of principal executive offices)

Mark Mitchell

Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, United Kingdom

Telephone: +44 1224 568 200

Email: mark.mitchell@alterainfra.com

(Contact information for company contact person)

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

Title of each class

Trading symbol

Name of each exchange on which registered

Series A Preferred Units

ALIN PR A

New York Stock Exchange

Series B Preferred Units

ALIN PR B

New York Stock Exchange

Series E Preferred Units

ALIN PR E

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.

5,217,093 Class A Common Units

405,931,898 Class B Common Units

5,876,533 Series A Preferred Units

4,910,019 Series B Preferred Units

4,703,023 Series E Preferred Units

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

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

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

Indicate by check mark if the registrant (1) has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

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

Large Accelerated Filer ☐ Accelerated Filer ☐ Non-Accelerated Filer ☒ Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act ¨

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

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

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

U.S. GAAP ¨

International Financial Reporting Standards as issued by the International Accounting Standards Board x

Other ¨

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ¨ No ý

ALTERA INFRASTRUCTURE L.P.

INDEX TO REPORT ON FORM 20-F


		Page
PART I.		1
Item 1.	Identity of Directors, Senior Management and Advisors	2
Item 2.	Offer Statistics and Expected Timetable	2
Item 3.	Key Information	2
	A. Selected Financial Data	2
	B. Capitalization and Indebtedness	4
	C. Reasons for the Offer and Use of Proceeds	4
	D. Risk Factors	4
	Tax Risks	14
Item 4.	Information on the Partnership	15
	A. History and Development of the Partnership	15
	B. Business Overview	15
	FPSO Segment	16
	Shuttle Tanker Segment	17
	FSO Segment	19
	UMS Segment	19
	Towage Segment	20
	Business Strategies	20
	Customers	21
	Safety, Management of Vessel Operations and Administration	21
	Flag, Classification, Audits and Inspections	21
	Regulations	22
	C. Organizational Structure	27
	D. Properties	27
Item 4A.	Unresolved Staff Comments	27
Item 5.	Operating and Financial Review and Prospects	27
	A. Operating Results	28
	Overview of our Business	28
	Operating Segments	28
	Outlook	29
	Significant Developments	29
	Results of Operations	32
	B. Liquidity and Capital Resources	41
	Cash Flows	42
	Critical Accounting Estimates	43
	C. Research and Development, Patents and Licenses, etc.	46
	D. Trend Information	46
	E. Off-Balance Sheet Arrangements	46
	F. Tabular Disclosure of Contractual Obligations	46
	G. Safe Harbor	47
Item 6.	Directors, Senior Management and Employees	47
	A. Directors and Senior Management	47
	Governance	47
	Directors of Altera Infrastructure GP L.L.C.	47
	Our Management	49
	B. Compensation	49
	Executive Compensation	49
	Compensation of Directors	49
	Long-Term Incentive Plan	50


	C. Board Practices	50
	D. Employees	51
	E. Unit Ownership	52
Item 7.	Major Unitholders and Related Party Transactions	52
	A. Major Unitholders	52
	B. Certain Relationships and Related Party Transactions	52
	C. Interests of Experts and Counsel	53
Item 8.	Financial Information	53
	A. Consolidated Financial Statements and Other Financial Informatio n	53
	Legal Proceedings	53
	Cash Distribution Policy	53
	B. Significant Changes	54
Item 9.	The Offer and Listing	54
	A. Offer and Listing Details	54
	B. Plan of Distribution	54
	C. Markets	54
	D. Selling Shareholders	54
	E. Dilution	54
	F. Expense of the Issue	54
Item 10.	Additional Information	54
	A. Share Capital	54
	B. Memorandum and Articles of Association	54
	C. Material Contracts	54
	D. Exchange Controls	54
	E. Taxation	54
	F. Dividends and Paying Agents	58
	G. Statement by Experts	58
	H. Documents on Display	58
	I. Subsidiary Information	59
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 12.	Description of Securities Other than Equity Securities	59

PART II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	59
Item 14.	Material Modifications to the Rights of Unitholders and Use of Proceeds	59
Item 15.	Controls and Procedures	59
	Management’s Report on Internal Control over Financial Reporting	59
Item 16A.	Audit Committee Financial Expert	60
Item 16B.	Code of Ethics	60
Item 16C.	Principal Accountant Fees and Services	60
Item 16D.	Exemptions from the Listing Standards for Audit Committees	61
Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers	61
Item 16F.	Change in Registrant’s Certifying Accountant	61
Item 16G.	Corporate Governance	62
Item 16H.	Mine Safety Disclosure	62

PART III.
Item 17.	Financial Statements	63
Item 18.	Financial Statements	63
Item 19.	Exhibits	63
Signature		66

PART I

This Annual Report should be read in conjunction with the consolidated financial statements and accompanying notes included in this report.

Unless otherwise indicated, references in this Annual Report to “Altera Infrastructure,” “we,” “us” and “our” and similar terms refer to Altera Infrastructure L.P. and/or one or more of its subsidiaries, except that those terms, when used in this Annual Report in connection with the common or preferred units or publicly issued senior notes described herein, shall mean specifically Altera Infrastructure L.P.

In addition to historical information, this Annual Report contains certain forward-looking statements (as such term is defined in Section 21E of the Securities Exchange Act of 1934, as amended) that involve risks and uncertainties. Such forward-looking statements relate to future events and our operations, objectives, expectations, performance, financial condition and intentions. When used in this Annual Report, the words “expect,” “intend,” “plan,” “believe,” “anticipate,” “estimate” and variations of such words and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this Annual Report include, in particular, statements regarding:

•our distribution policy and our ability to make cash distributions on our units;

•our future growth prospects, business strategy, strategic initiatives and other plans and objectives for future operations;

•future capital expenditures and availability of capital resources to fund capital expenditures;

•our liquidity needs and meeting our going concern requirements, including our working capital deficit, anticipated funds and sources of financing for liquidity needs and the sufficiency of cash flows, and our estimation that we will have sufficient liquidity for at least the next one-year period;

•our ability to refinance existing debt obligations, to raise additional debt and capital, to fund capital expenditures, and negotiate extensions or redeployments of existing assets;

•our ability to maintain and expand long-term relationships with major crude oil companies, including our ability to service fields until they no longer produce, and the negative impact of low oil prices on the likelihood of certain contract extensions;

•the derivation of a substantial majority of revenue from a limited number of customers;

•our ability to leverage to our advantage the expertise, relationships and reputation of Brookfield Business Partners L.P. together with its institutional partners (Brookfield Business Partners L.P. and/or any one or more of its affiliates referred to herein as Brookfield) to pursue growth opportunities;

•the outcome and cost of claims and potential claims against us, including, among others, claims and potential claims by COSCO (Nantong) Shipyard (or COSCO) relating to Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd (or Logitel) and related to Brookfield's acquisition by merger of the outstanding publicly held common units;

•the outcome of the investigation by Norwegian authorities of potential violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf and its subsequent recycling;

•our continued ability to enter into fixed-rate time charters and floating production, storage and offloading (or FPSO) contracts with customers, including the effect of a continuation of lower oil prices to motivate charterers to use existing FPSO units on new projects;

•results of operations and revenues and expenses;

•our competitive advantage in the shuttle tanker market;

•the expected lifespan and estimated sales price or recycling value of vessels;

•our expectations as to any impairment of our vessels;

•acquisitions from third parties and obtaining offshore projects that we bid on or may be awarded;

•certainty of completion, estimated delivery and completion dates, commencement of charter, intended financing and estimated costs for newbuildings and acquisitions, including our shuttle tanker newbuildings;

•the expected employment of shuttle tanker newbuildings;

•the expectations as to the chartering of unchartered vessels;

•our expectations regarding competition in the markets we serve;

•our entering into joint ventures or partnerships with companies and any business or asset acquisitions or dispositions;

•our ability to maximize the use of our vessels, including the re-deployment or disposition of vessels no longer under long-term time charter contracts;

•the duration of dry dockings;

•the valuation of goodwill and potential impairment;

•our compliance or ability to comply with covenants under our credit facilities and finance leases;

•the ability of the counterparties for our derivative contracts to fulfill their contractual obligations;

•our hedging activities relating to foreign exchange, interest rate and spot market risks;

•our exposure to foreign currency fluctuations, particularly in Norwegian Krone, Brazilian Real, British Pound and Euro;

•increasing the efficiency of our business and redeploying vessels as charters expire or terminate;

•the adequacy of our insurance coverage;

•the expected impact of heightened environmental and quality concerns of insurance underwriters, regulators and charterers;

•our ability to comply with governmental regulations and maritime self-regulatory organization standards applicable to our business;

•the passage of climate control legislation or other regulatory initiatives that restrict emissions of greenhouse gases;

•anticipated taxation of our partnership and its subsidiaries and taxation of unitholders and the adequacy of our reserves to cover potential liability for additional taxes;

•our intent to take the position that we are not a passive foreign investment company;

•consequences relating to the phasing-out of the London Inter-bank Offered Rate (or LIBOR);

•our general and administrative expenses as a public company and expenses under service agreements with Teekay Corporation and for reimbursements of fees and costs of Altera Infrastructure GP L.L.C., our general partner;

•our ability to avoid labor disruptions and attract and retain highly skilled personnel;

•unexpected changes in business conditions, governmental changes, health epidemics (including the COVID-19 pandemic) and other factors beyond our control that could have a material and adverse effect on our business, financial condition and operating results; and

•the extent of the disruption to and/or adverse impact on our business, operating results and financial condition as a result of the COVID-19 pandemic.

Forward-looking statements are necessary estimates reflecting the judgment of senior management, 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, those factors discussed below in Item 3 – Key Information: Risk Factors and other factors detailed from time to time in other reports we file with the U.S. Securities and Exchange Commission (or the SEC).

We do not intend to revise any forward-looking statements in order to reflect any change in our expectations or events or circumstances that may subsequently arise. You should carefully review and consider the various disclosures included in this Annual Report and in our other filings made with the SEC that attempt to advise interested parties of the risks and factors that may affect our business, prospects and results of operations.

Item 1.Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.Offer Statistics and Expected Timetable

Not applicable.

Item 3.Key Information

A.Selected Financial Data

The following tables present selected consolidated financial data in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (or IFRS) of Altera Infrastructure L.P. and its subsidiaries as at and for the years indicated:


	Year Ended December 31,
(in thousands of U.S. Dollars, except per unit, unit and fleet data)	2020	2019
Statement of Income (Loss) Data:
Revenues	1,182,110	1,252,938
Net income (loss)	(346,163)	(159,067)
Basic and diluted earnings (loss) per limited partner common unit	(0.90)	(0.44)
Cash distributions declared per common unit	—	—
Statement of Financial Position Data:
Cash and cash equivalents	235,734	199,388
Vessels and equipment	3,029,415	3,025,716
Total assets	4,385,631	4,488,238
Total borrowings	3,170,977	3,184,512
Total equity	244,899	597,802
Common units outstanding (1)	411,148,991	411,148,991
Preferred units outstanding (2)	15,489,575	15,800,000
Non-IFRS Financial Data:
EBITDA (3)	165,846	407,790
Adjusted EBITDA (3)	599,323	673,199
Fleet Data (at end of year):
Number of FPSO units	7	8
Number of Shuttle Tankers	29	34
Number of FSO units	4	5
Number of Units for Maintenance and Safety	1	1
Number of Towage vessels	10	10

(1)Common units outstanding includes the common units until January 22, 2020 and the Class A common units and Class B common units from January 22, 2020 until December 31, 2020.

(2)Preferred units outstanding includes the Series A Preferred Units, the Series B Preferred Units and the Series E Preferred Units.

(3)To supplement the consolidated financial statements prepared in accordance with IFRS, we have presented EBITDA and Adjusted EBITDA, which are non-IFRS financial measures. EBITDA and Adjusted EBITDA are intended to provide additional information and should not be considered substitutes for net income (loss) or other measures of performance prepared in accordance with IFRS.

EBITDA represents net income (loss) before interest expense, interest income, income tax expense, and depreciation and amortization. Adjusted EBITDA is EBITDA adjusted to exclude certain items whose timing or amount cannot be reasonably estimated in advance or that are not considered representative of core operating performance. Such adjustments include impairment expenses, gain (loss) on dispositions, net, unrealized gain (loss) on derivative instruments, foreign currency exchange gain (loss) and certain other income or expenses. Adjusted EBITDA also excludes: realized gain or loss on interest rate swaps (as we, in assessing our performance, view these gains or losses as an element of interest expense); realized gain or loss on derivative instruments resulting from amendments or terminations of the underlying instruments; and equity-accounted income (loss). Adjusted EBITDA also includes our proportionate share of Adjusted EBITDA from our equity-accounted investments and excludes the non-controlling interests' proportionate share of Adjusted EBITDA. We do not have control over the operations of, nor do we have any legal claim to the revenues and expenses of our equity-accounted investments. Consequently, the cash flow generated by our equity-accounted investments may not be available for use by us in the period that such cash flows are generated.

EBITDA and Adjusted EBITDA assist our management and security holders by increasing the comparability of our fundamental performance from period to period and against the fundamental performance of other companies in our industry that provide EBITDA or Adjusted EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest expense, interest income, income taxes, depreciation and amortization, and, for Adjusted EBITDA, by excluding certain additional items whose timing or amount cannot be reasonably estimated in advance or that are not considered representative of core operating performance. These items are affected by various and possibly changing financing methods, capital structure and historical cost basis and which items may significantly affect net income (loss) between periods. We believe that including EBITDA and Adjusted EBITDA benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength and health in assessing whether to continue to hold our equity or debt securities as applicable.

EBITDA should not be considered as an alternative to net income (loss) or any other measure of financial performance presented in accordance with IFRS. EBITDA and Adjusted EBITDA exclude certain items that affect net income (loss) and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA as presented in this Annual Report may not be comparable to similarly titled measures of other companies.

Refer to Item 5A. Operating Results - Non-IFRS Financial Measures for reconciliations of EBITDA and Adjusted EBITDA to Net income (loss).

B.Capitalization and Indebtedness

Not applicable.

C.Reasons for the Offer and Use of Proceeds

Not applicable.

D.Risk Factors

The holding of units of our Partnership involves substantial risks. You should carefully consider the following factors in addition to the other information set forth in this Annual Report on Form 20-F. The occurrence of any of the events described in this section could materially and adversely affect our business, financial condition, operating results and ability to pay distributions on, and the trading price of, our preferred units.

Risks Relating to Our Operations

The COVID-19 pandemic is dynamic. The continuation of the pandemic likely will have, and the emergence of other epidemic or pandemic crises could have, material adverse effects on our business, results of operations, or financial condition.

The COVID-19 pandemic is dynamic, including the development of variants of the virus, and its ultimate scope, duration and effects are uncertain. We expect that this pandemic, and any future epidemic or pandemic crises, could result in direct and indirect adverse effects on our industry and customers, which in turn may impact our business, results of operations and financial condition. Effects of the current pandemic include, or may include, among others:

•deterioration of worldwide, regional or national economic conditions and activity, which could adversely affect global demand for crude oil and the price thereof, demand for our services, and charter rates;

•disruptions to our operations as a result of the potential health impact on our employees and crew, and on the workforce of our customers and business partners;

•disruptions to our business from, or additional costs related to, new regulations, directives or practices implemented in response to the pandemic, such as travel restrictions (including for any of our onshore personnel or any of our crew members to timely embark or disembark from our vessels), increased inspection regimes, hygiene measures (such as quarantining and physical distancing) or increased implementation of remote working arrangements;

•potential delays in the loading and discharging of cargo on or from our vessels, and any related off-hire due to quarantine, worker health, or regulations, which in turn could disrupt our operations and result in a reduction of revenue;

•potential newbuilding construction delays, lack of access to required spare parts for our vessels, delays in any repairs to, scheduled or unscheduled maintenance or modifications, or drydocking of, our vessels, as a result of shipyard shutdowns or a lack of berths available by shipyards from a shortage in labor or due to other business disruptions;

•potential delays in vessel inspections and related certifications by class societies, customers or government agencies;

•potential reduced cash flows and financial condition, including potential liquidity constraints;

•reduced access to capital, including the ability to refinance any existing obligations, as a result of any credit tightening generally or due to declines in global financial markets;

•a reduced ability to opportunistically sell any of our vessels on the second-hand market, either as a result of a lack of buyers or a general decline in the value of second-hand vessels;

•a decline in the market value of our vessels, which may cause us to (a) incur impairment charges or (b) breach certain covenants under our financing agreements;

•fewer contract extension opportunities, and in the worst case, contract terminations resulting from relevant early field abandonment programs; and

•potential deterioration in the financial condition and prospects of our customers, joint venture partners or business partners, or attempts by customers or third parties to invoke force majeure contractual clauses as a result of delays or other disruptions.

Although disruption and effects from the COVID-19 pandemic may be temporary or moderated by expanding vaccine accessibility, given the dynamic nature of these circumstances and the worldwide nature of our business and operations, the duration of any business disruption and the related financial impact to us cannot be reasonably estimated at this time. In addition, public health threats and other highly communicable disease outbreaks, such as the COVID-19 pandemic, could adversely affect the business, results of operations or financial condition of us or our customers, suppliers and other business partners and adversely affect the global economy, including worldwide demand for crude oil and the level of demand for the types of services we offer.

The growth of our existing businesses depends on continued growth in global and regional demand for offshore oil transportation and processing and storage services.

Our long-term growth strategy includes a focus on expanding our fleet of shuttle tankers and FPSO units under medium-to-long term charter contracts. Accordingly, our growth depends on continued growth in world and regional demand for these offshore services, which could be negatively affected by a number of factors, such as:

•decreases in the actual or projected price of oil and decreases in the consumption of oil;

•increases in the production of oil 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-oil pipelines to oil pipelines in those markets; and

•availability of new, alternative energy sources.

A significant decline in oil prices may adversely affect our growth prospects and operating results.

Oil prices have significantly declined since mid-2014, and did so further more recently, due to the uncertainty regarding demand created by the COVID-19 pandemic, before recovering. A decline in oil prices may adversely affect our business, financial condition and operating results, as a result of, among other things:

•a reduction in exploration for or development of new offshore oil fields, or the delay or cancellation of existing offshore projects as energy companies lower their capital expenditures budgets, which may reduce our growth opportunities;

•a reduction in, or termination of, production of oil at certain fields we service, which may reduce our revenues under certain contracts;

•lower demand for our vessels, which may reduce charter rates and revenue to us upon redeployment of our vessels, in particular FPSO units, following expiration or termination of existing contracts or upon the initial chartering of vessels, or which may result in extended periods of our vessels being idle between contracts;

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

•the inability or refusal of customers to make charter payments to us due to financial constraints or otherwise; or

•declines in vessel values, which may result in losses to us upon vessel sales or impairment charges against our earnings.

Payments under certain of our shuttle tanker contracts are based on the volume of oil transported and a portion of the payments under certain of our FPSO contracts are based on the volume of oil produced and the price of oil, which depends upon continued production from existing or new oil fields, which generally declines naturally over time. The duration of certain of these contracts is the life of the relevant oil field or is subject to extension or termination by the field operator or vessel charterer, which is beyond our control.

Payments under certain of our shuttle tanker contracts are based on the volume of oil transported and a portion of the payments under certain of our FPSO contracts are based on the volume of oil produced and the price of oil. Oil production levels are affected by several factors, all of which are beyond our control, including: geologic factors, including general declines in production that occur naturally over time; mechanical failure or operator error; the rate of technical developments in extracting oil and related infrastructure and implementation costs; the availability of necessary drilling and other governmental permits; the availability of qualified personnel and equipment; strikes, employee lockouts or other labor unrest; and regulatory changes. In addition, the volume of oil produced may be adversely affected by extended repairs to oil field installations or suspensions of field operations as a result of oil spills or otherwise. Reductions in oil production levels could have a material adverse effect on our business, operating results and financial condition.

Certain of our contracts continue until oil production at the field ceases. If production terminates or the field is abandoned, or if the contract term is not extended, or the applicable contract is not renewed, for any reason, we no longer will generate revenue under the related contract and will need to seek to redeploy the affected vessels. If we are unable to promptly redeploy any affected vessels at rates at least equal to those under the prior contracts or if we are not successful in redeploying any such vessels at all, our operating results could be harmed.

Other contracts under which our vessels operate are subject to extensions beyond their initial term. The likelihood of these contracts being extended may be negatively affected by reductions in oil field reserves, low oil prices generally or other factors.

FPSO units are specialized vessels that have very limited alternative uses and high fixed costs. In addition, FPSO units typically require substantial capital investments prior to being redeployed to a new field and production service contract. These factors increase the redeployment risk of FPSO units. Our clients may also terminate certain of our FPSO production service contracts prior to their expiration under specified circumstances. Any idle time prior to the commencement of a new contract or our inability to redeploy the vessels at acceptable rates may have an adverse effect on our business and operating results.

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

Over the long-term, we intend to continue our practice of primarily acquiring vessels as needed for approved projects only after the medium-to-long-term charters for the projects have been awarded to us. The process of obtaining new medium-to-long-term charters is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. Contracts are awarded based upon a variety of factors, including:

•industry relationships and reputation for customer service and safety;

•experience and quality of ship operations and the quality, experience and technical capability of the crew;

•construction management experience, including the ability to provide on-time delivery of vessels according to customer specifications; and

•competitiveness of the bid in terms of overall price.

Increased competition may cause greater price competition for 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 business, operating results and financial condition.

We derive a substantial majority of our revenues from a limited number of customers, and the loss of any such customers or a contract dispute with any such customer could result in a significant loss of revenues and cash flow.

If we lose a key customer, we may be unable to obtain replacement charters. If a customer exercises its right under some charters to purchase the vessel, or terminate the charter, we may be unable to acquire an adequate replacement vessel or charter. Any replacement newbuilding would not generate revenues during its construction and we may be unable to charter any replacement vessel on terms as favorable to us as those of the terminated charter. The loss of any of our significant customers or a reduction in anticipated revenues from them could have a material adverse effect on our business, operating results and financial condition.

Future adverse economic conditions or other developments may affect our customers’ ability to charter our vessels and pay for our services or outstanding amounts due to us and may adversely affect our business and operating results.

Future adverse economic conditions or other developments relating directly to our customers may lead to a decline in our customers’ operations or ability to pay for our services or willingness to pay outstanding amounts due to us, which could further result in decreased demand for our vessels and services. Our customers’ inability to pay for any reason could also result in their default on our current contracts and charters. The decline in the amount of services requested by our customers or their default on our contracts with them could have a material adverse effect on our business, financial condition and operating results.

Our and many of our customers’ substantial operations outside the United States expose us to political, governmental and economic instability, which could harm our operations.

Because our operations are primarily conducted outside of the United States, they may be affected by economic, political and governmental conditions in the countries where we engage in business or where our vessels are registered. Any disruption caused by these factors could harm our business, including by reducing the levels of oil exploration, development and production activities in these areas. We derive some of our revenues from shipping oil from politically unstable regions, in particular, our operations in Brazil. Hostilities or other political instability in regions where we operate or where we may operate could have a material adverse effect on the growth of our business, operating results and financial condition. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries, companies and/or individuals in Southeast Asia, Russia, the Middle East or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, companies and/or individuals which could also harm our business. Finally, governments could requisition one or more of our vessels, which is most likely during war or national emergency. Any such requisition would cause a loss of the vessel and could harm our cash flow and operating results.

We must make substantial capital expenditures to maintain the operating capacity of our fleet.

We must make substantial capital expenditures to maintain, over the long term, the operating capacity of our fleet. Maintenance capital expenditures include capital expenditures associated with dry docking a vessel, modifying an existing vessel or acquiring a new vessel to the extent these expenditures are incurred to maintain the operating capacity of our fleet. These expenditures could increase as a result of changes in:

•the cost of labor and materials;

•customer requirements;

•increases in fleet size or the cost of replacement vessels;

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

•competitive standards.

Although delivery of the completed vessel will not occur approximately two to three years from the time an order is placed, we typically must pay between 5% to 10% of the purchase price of a shuttle tanker upon signing the purchase contract. During the construction period, we generally are required to make installment payments prior to delivery. Funding of any capital expenditures with debt may significantly increase our interest expense and financial leverage, and funding of capital expenditures through issuing additional equity securities may result in unitholder dilution. Our failure to obtain funding for future capital expenditures could have a material adverse effect on our business, operating results and financial condition.

Delays in the deliveries and commencement of operations of our vessels under their charters could harm our operating results.

Any delay in the operational start-up, or the delivery of any newbuilding vessel we may order, would delay our receipt of revenues under the related charters or contracts. In addition, under some charters we may enter into, if there is a delay, we may be required to pay liquidated damages during the delay in addition to suffering a loss of revenues. For prolonged delays, the customer may terminate the charter. Any such result could adversely affect our operating results and financial condition.

Over time, the value of our vessels may decline, which could adversely affect our operating results.

Values of vessels can fluctuate substantially over time and may decline from existing levels. If the operation of a vessel is not profitable, or if we cannot re-deploy a vessel at attractive rates upon termination of its contract, rather than continue to incur costs to maintain and finance the vessel, we may seek to dispose of it. Our inability to dispose of the vessel at a reasonable value could result in a loss on its sale and adversely affect our operating results and financial condition. Further, if we determine at any time that a vessel’s future estimated useful life and earnings require us to impair its value, we may be required to recognize a significant charge against our earnings.

During the year ended December 31, 2020, we recognized an impairment expense, net of $(269) million. Refer to Item 18 – Financial Statements: Note 11 – Vessels and Equipment." We may also recognize additional vessel or equipment impairments in the future.

Marine transportation and oil production is inherently risky, particularly in the extreme conditions in which many of our vessels operate. An incident involving significant loss of product or environmental contamination by any of our vessels could harm our reputation and business.

Vessels and their cargoes, and oil production facilities we service, are at risk of being damaged or lost because of events such as:

•marine disasters;

•adverse weather, especially relating to our vessels which operate in the North Sea;

•mechanical failures;

•grounding, capsizing, fire, explosions and collisions;

•piracy;

•cyber-attacks;

•human error; and

•war and terrorism.

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

•death or injury to persons, loss of property or damage to the environment and natural resources;

•delays in the delivery of cargo;

•loss of revenues;

•liabilities or costs to recover any spilled oil or other petroleum products and to restore the environment affected by the spill;

•governmental fines, penalties or restrictions on conducting business;

•higher insurance rates;

•acceleration of credit facilities; and

•damage to our reputation and customer relationships generally.

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

War, military tension, revolutions, piracy and terrorist attacks, or increases in such events or activities, could create or increase instability in the world’s financial and commercial markets. This may significantly increase political and economic instability in some of the geographic markets in which we operate or may operate in the future, and may contribute to high levels of volatility in charter rates or oil prices. In addition, oil facilities, shipyards, vessels, pipelines, oil fields or other infrastructure could be targets of future terrorist attacks or warlike operations and our vessels could be targets of pirates, hijackers, terrorists or warlike operations. 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 oil to or from certain locations. If these 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 coverage can increase significantly and such insurance coverage may be more difficult to obtain. In addition, crew costs, including costs which are incurred to the extent we employ on-board armed security guards and escort vessels, 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. Terrorist attacks, war, piracy, hijacking or other events beyond our control that adversely affect the distribution, production or transportation of oil to be shipped by us could entitle customers to terminate the charters and 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 operating results.

A cyber-attack could materially disrupt our business

We rely on information technology systems and networks in our operations and the administration of our business. Cyber-attacks have increased in number and sophistication in recent years. Our operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business or operating results.

The nature of our operations exposes us to substantial environmental and other regulations, which may significantly limit operations or increase expenses and could result in significant environmental liabilities.

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. 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. The costs of compliance associated with environmental regulations and changes thereto could require significant expenditures. We expect to incur substantial expenses in complying with these laws and regulations, including expenses for vessel modifications and changes in operating procedures.

These requirements can affect the values or expected useful lives of our vessels, require 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. Failure to comply with such regulations could result in the imposition of material fines, penalties, criminal sanctions, vessel seizures or temporary or permanent suspension of operations and we could incur material liabilities, including cleanup obligations, in the event that there is a release of petroleum or 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. An incident involving environmental contamination could also harm our reputation and business and in certain instances could lead to termination of our vessel contracts and/or acceleration of our credit facilities.

In January 2020, Økokrim (the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime) and the local Stavanger police raided the premises of our subsidiary Altera Infrastructure Norway AS in Stavanger, Norway, based on a search and seizure warrant issued pursuant to suspected violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018. Although we have not identified any such violations and deny the charges, such violations of Norwegian pollution and export laws, where they do exist, have the potential to trigger financial penalties, with a number of factors taken into consideration when assessing the size of the penalty to be enforced, including the financial capacity of the company, any preventative measures taken, the gravity of the offense and the benefit derived from the violation.

Our insurance and indemnities may not be sufficient to cover risks, losses or expenses that may occur to our property or as a result of our operations.

The operation of vessels carries an inherent risk of catastrophic marine disasters, death or injury of persons and property losses caused by adverse weather conditions, mechanical failures, human error, war, terrorism, piracy and other circumstances or events. We carry hull and machinery (marine and war risks) and protection and indemnity insurance coverage to protect against most of the accident-related risks involved in the conduct of our business. Hull and machinery insurance covers loss of, or damage to, a vessel due to marine perils such as collisions, grounding and weather. Protection and indemnity insurance indemnifies against other liabilities incurred while operating vessels, including injury to the crew, third parties, cargo loss and pollution. However, all risks may not be adequately insured against, and any particular claim may not be paid by insurance. In addition, the majority of our vessels are not insured against loss of revenues resulting from vessel off-hire, based on the cost of this insurance compared to our off-hire experience. We do not insure against all risks and may therefore be exposed under certain circumstances to uninsurable hazards, losses and risks. Any significant off-hire of our vessels could harm our business, operating results and financial condition. Any claims relating to our operations 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 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. In addition, the costs of this protection and indemnity coverage is significantly increasing.

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 catastrophic oil spill or marine disaster or natural disaster could exceed the insurance coverage, which could harm our business, financial condition and operating results. Any uninsured or underinsured loss could harm our business and financial condition. In addition, the insurance may be voidable by the insurers as a result of certain actions, such as vessels failing to maintain certification with applicable maritime regulatory organizations.

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

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 have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency and reporting standards, and incentives or mandates for renewable energy. Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our vessels and require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Revenue generation, access to capital and strategic growth opportunities may also be adversely affected.

Adverse effects upon the oil industry relating to climate change may also adversely affect demand for our services. Although we do not expect that demand for oil will reduce dramatically over the short term, in the long term, climate change may reduce the demand for oil or increased regulation of greenhouse gases may create greater incentives for use of alternative energy sources. Any long-term material adverse effect on the oil industry could have a significant adverse financial and operational impact on our business that we cannot predict with certainty at this time.

Risks Relating to Our Liquidity

We have limited current liquidity.

As at December 31, 2020, we had total liquidity of $235.7 million and a working capital deficit of $230.5 million. Our limited availability under existing credit facilities and our current working capital deficit could limit our ability to meet our financial obligations and growth prospects. We expect to manage our working capital deficit primarily with amounts generated from operations, including extensions and redeployments of existing assets, and additional potential sources of financing, including entering into new debt facilities, borrowing additional amounts under existing facilities, the refinancing or extension of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnerships business interests and/or capital raises. However, there can be no assurance that any such sources of financing will be available to us on acceptable terms, if at all.

Our ability to repay or refinance our debt obligations and to fund our capital expenditures will depend on certain financial, business and other factors, many of which are beyond our control. To the extent we are able to finance these obligations and expenditures with cash

from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage may increase or our unitholders may be diluted. Our business may be adversely affected if we need to access other sources of funding.

Our ability to draw on committed and potential funding sources to help manage our working capital deficit, debt obligations and to fund our capital expenditure, and our future financial and operating performance will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control.

If we are unable to access existing or additional financing sources and generate sufficient cash flow to meet our debt obligations, capital expenditure and other business requirements, we may be forced to take actions such as:

•restructuring our debt;

•seeking additional debt or equity capital;

•selling assets or equity interests in certain assets or joint ventures;

•reducing, delaying or canceling our business activities, acquisitions, investments or capital expenditures; or

•seeking bankruptcy protection.

Such measures may not be successful, and additional debt or equity capital may not be available on acceptable terms or enable us to meet our debt obligations, capital expenditure or other obligations. In addition, our existing financing agreements may restrict our ability to implement some of these measures. The sale of certain assets will reduce cash from operations and the cash available for distributions to unitholders. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis could lead to cross-defaults under other financing agreements and result in obligations becoming due and commitments being terminated under such agreements and would likely result in a reduction of our credit rating, which in turn could harm our ability to incur additional indebtedness.

The use of cash from operations to satisfy debt obligations, capital expenditure or other obligations will reduce cash available for distribution to unitholders. Our ability to obtain bank financing or to access the capital markets for future offerings may be limited by our financial condition at the time of any such financing or offering as well as by adverse market conditions in general. Even if we are successful in obtaining necessary funds, the terms of such financings could limit our ability to pay cash distributions to unitholders or operate our business as currently conducted. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in unitholder dilution.

Our substantial debt levels may limit our flexibility in obtaining additional financing, refinancing credit facilities upon maturity, pursuing other business opportunities and paying distributions.

As at December 31, 2020, our total borrowings were approximately $3.2 billion and our net debt to capitalization ratio was 93%. If we are awarded contracts for additional offshore projects or otherwise acquire additional vessels, our consolidated debt may further increase. We may incur additional debt under existing or future credit facilities. Our level of debt could have important consequences to us, including:

•our ability to obtain additional financing, if necessary, for working capital, capital expenditure or other purposes, and our ability to refinance our credit facilities may be impaired or such financing may not be available on favorable terms;

•limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•we will need a substantial portion of our cash flow from operations 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 levels may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our industry, increases in interest rates or the economy generally;

•if our cash flow and capital resources are insufficient to fund debt service obligations, it may force us to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness; and

•our debt level may limit our flexibility in responding to changing business and economic conditions.

Financing agreements containing operating and financial restrictions may restrict our business and financing activities.

The operating and financial restrictions and covenants in our current financing arrangements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities.

Some of our borrowings contain covenants, debt-service coverage ratio (or DSCR) requirements and other restrictions on us and our subsidiaries typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from, among other things:

•incurring or guaranteeing indebtedness;

•changing ownership or structure, including mergers, consolidations, liquidations and dissolutions;

•paying dividends or distributions if we are in default or do not meet minimum DSCR requirements;

•making capital expenditures in excess of specified levels;

•making certain negative pledges and granting certain liens;

•selling, transferring, assigning or conveying assets;

•making certain loans and investments; or

•entering into a new line of business.

Obligations under our borrowings are secured by several of our vessels, and if we are unable to repay debt under the borrowings, the lenders could seek to foreclose on those assets. Our ability to comply with covenants and restrictions contained in our borrowings may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, compliance with these covenants may be impaired. If restrictions, covenants, ratios or tests in the financing agreements are breached, a significant portion or all of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. This could lead to cross-defaults under other financing agreements and result in obligations becoming due and commitments being terminated under such agreements. We might not have, nor be able to obtain, sufficient funds to make these accelerated payments. Furthermore, the termination of any of our charter contracts by our customers could result in the repayment of the debt facilities to which the chartered vessels relate. As at December 31, 2020, we were in compliance with all covenants relating to our consolidated borrowings.

Restrictions in our financing agreements may prevent us or our subsidiaries from paying distributions.

The payment of principal and interest on our subsidiaries borrowings reduces cash available for distribution to us. In addition, our and our subsidiaries’ financing agreements prohibit the payment of distributions upon the occurrence of the following events, among others:

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

•failure to notify the lenders of any material oil spill or discharge of hazardous material, or of any action or claim related thereto;

•breach or lapse of any 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;

•bankruptcy or insolvency events;

•failure of any representation or warranty to be materially correct;

•a change of control, as defined in the applicable agreement; and

•a material adverse effect, as defined in the applicable agreement.

Our variable-rate indebtedness and finance lease obligations subject us to interest rate risk, which could cause our debt service and finance lease obligations to increase.

We are subject to interest rate risk in connection with borrowings and finance leases which bear interest at variable rates. Interest rates have recently been at relatively low levels and any increase in interest rates could impact the amount of our interest payments, and accordingly, our future earnings and cash flow. In addition, any hedging activities we may enter into may not be effective in fully mitigating our interest rate risk from our variable rate obligations.

There is uncertainty as to the continued use of LIBOR in the future, and the interest rates on our LIBOR-based obligations may increase in the future.

LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform. This guidance indicates that the continuation of LIBOR on the current basis cannot be guaranteed after 2021, and there is substantial risk that LIBOR will be discontinued or modified during 2021. Global regulators are working with the financial sector to transition away from the use of LIBOR and towards the adoption of alternative reference rates. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index calculated by short-term repurchase agreements, backed by Treasury securities (SOFR). SOFR is observed and backward-looking, which stands in contrast with LIBOR under the current methodology, which is an estimated forward-looking rate and relies, to some degree, on the expert judgment of submitting panel members. Whether or not SOFR attains market acceptance as a LIBOR replacement tool remains in question. As such, the future of LIBOR at this time is uncertain.

While the agreements governing our variable-rate borrowings provide for an alternate method of calculating interest rates in the event that a LIBOR rate is unavailable, if LIBOR ceases to exist or if the methods of calculating LIBOR change from their current form, there may be adverse impacts on the financial markets generally and interest rates on our variable-rate borrowings may be materially adversely affected.

Uncertainty as to the nature of potential changes to LIBOR, alternative reference rates or other reforms may adversely affect the trading market for LIBOR-based securities, including certain of our preferred units.

If the calculation agent for our preferred units determines that LIBOR has been discontinued, the calculation agent will determine whether to use a substitute or successor base rate that it has determined in its sole discretion is most comparable to three-month LIBOR, provided that if the calculation agent determines there is an industry accepted successor base rate, the calculation agent shall use such successor base rate. The calculation agent in its sole discretion may also implement changes to the business day convention, the definition of business day, the distribution determination date and any method for obtaining the substitute or successor base rate if such rate is unavailable on the relevant business day, in a manner that is consistent with industry accepted practices for such substitute or successor base rate. Unless the calculation agent determines to use a substitute or successor base rate as so provided, if a published three-month LIBOR rate is unavailable, the distribution rate for our preferred units during the floating rate period will be determined using specified alternative methods. Any such alternative methods may result in distribution

payments that are lower than or that do not otherwise correlate over time with the distribution payments that would have been made on our preferred units during the floating rate period if three-month LIBOR were available in its current form.

Further, the same costs and risks that may lead to the discontinuation or unavailability of three-month LIBOR may make one or more of the alternative methods impossible or impracticable to determine. If a published three-month LIBOR rate is unavailable during the floating rate period and banks are unwilling to provide quotations for the calculation of LIBOR, the alternative method sets the distribution rate for a distribution period as the same rate as the immediately preceding distribution period, which could remain in effect in perpetuity unless we redeem our preferred units, and the value of our preferred units may be adversely affected.

We may elect to distribute our available cash to our limited partners, which may adversely affect our ability to grow, meet our financial needs and make distributions on our preferred units.

We have not made quarterly distributions on our common units since 2018. Subject to the limitations in our partnership agreement, our general partner may elect, however, at any time, to distribute our available cash each quarter to our limited partners. “Available cash” is defined in our partnership agreement, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own), less the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own) established by our general partner to:

•provide for the proper conduct of our business;

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

•provide funds for payments to holders of preferred units; or

•provide funds for distributions to our limited partners (including on preferred units) and to our general partner for any one or more of the next four quarters;

•plus all cash on hand (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own) on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit agreements and in all cases are used solely for working capital purposes or to pay distributions to partners.

We may resume paying quarterly cash distributions on our common units in the future and any such distributions under our cash distribution policy, and the timing and amount thereof, could significantly reduce the amount of cash we otherwise would have available in subsequent periods to grow our business, meet our financial needs and make payments on our preferred units.

Risks Relating to Our Relationship with Brookfield

We depend on Brookfield and certain joint venture partners to assist us in operating our businesses and competing in our markets.

We have entered into, and may enter into additional, joint venture arrangements with third parties to expand our fleet and access growth opportunities.

Our ability to compete for offshore oil transportation and processing and storage services, to enter into new charters and expand our customer relationships depends on our ability to maintain our status as a reputable service provider in the industry in addition to our ability to leverage our relationship with Brookfield or our current or future joint venture partners and their reputation and relationships in the offshore industry. If Brookfield or our joint venture partners suffer material damage to their reputation or relationships, it may harm the ability of us to:

•renew existing and obtain new charters;

•successfully interact with shipyards during periods of shipyard construction constraints;

•obtain financing on commercially acceptable terms; or

•maintain satisfactory relationships with suppliers and other third parties.

Our general partner, which is owned by Brookfield, makes all decisions on our behalf, subject to the limited voting rights of our unitholders.

Brookfield owns our general partner. As a result, Brookfield is able to control the appointment and removal of the general partner’s directors and, accordingly, exercises substantial influence over us.

Unlike the holders of common stock in a corporation, our preferred unitholders generally have no voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business; holders of our Class A common unitholders have no voting rights except to the extent required by law. If the unitholders are dissatisfied with the performance of our general partner, they have little or no ability to remove our general partner.

Our partnership agreement restricts our general partner’s obligations to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner.

Our partnership agreement contains provisions that restrict the standards to which our general partner would otherwise be held by Marshall Islands law. For example, 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. Where our partnership agreement permits, our general partner may consider only the interests and factors that it desires, and in such cases, it

has no duty or obligation to give any consideration to any interest of, or factors affecting us, our subsidiaries or our unitholders. Decisions made by our general partner in its individual capacity are made by Brookfield, and not by the board of directors of our general partner. Examples include the exercise of call rights, voting rights with respect to the common units they own, registration rights and their determination whether to consent to any merger or consolidation of the partnership;

•provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes 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 the board of directors of our general partner and not involving a vote of common 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 general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and

•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

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

Our general partner may transfer its 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. In the event of any such transfer, the new members of our general partner would be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers. In the absence of any pre-agreed amendments, waivers or refinancing, any such change of control would likely trigger defaults across a number of our financing agreements, which could result in obligations becoming due and commitments being terminated under such agreements.

Our general partner and its other affiliates own a controlling interest in us and have conflicts of interest and limited or no fiduciary duties, which may permit them to favor their own interests to those of unitholders.

As at the date of this Annual Report, affiliates of Brookfield held 98.7% of our outstanding common units and a 100% interest in our general partner. Neither we nor our general partner or its officers and directors owe any fiduciary duties to holders of our preferred units of Class A common units, other than an implied contractual duty of good faith and fair dealing pursuant to our partnership agreement. Four directors of our general partner also serve as officers, management or non-independent directors (as well as two other directors who serve as independents) of Brookfield or other affiliates of Brookfield. Consequently, these directors may encounter situations in which their fiduciary obligations to Brookfield, or its other affiliates, on one hand, and any obligation to us or our unitholders, on the other hand, are in conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

•neither our partnership agreement nor any other agreement requires Brookfield or affiliates (other than our general partner) to pursue a business strategy that favors us or utilizes our assets, and Brookfield’s directors and officers have fiduciary duties to make decisions in the best interests of the owners of Brookfield, which may be contrary to our interests;

•our general partner is allowed to take into account the interests of parties other than us, such as Brookfield, in resolving conflicts of interest, which has the effect of limiting any obligation to our unitholders;

•our general partner has restricted its liability and reduced its fiduciary duties or obligations under the laws of the Republic of the Marshall Islands, while also restricting the remedies available to our unitholders and unitholders are treated as having agreed to such modified standards and to certain actions that may be taken by our general partner, all as set forth in our partnership agreement;

•our general partner approves our annual budget and the amount and timing of our asset purchases and sales, capital expenditures, borrowings, reserves and issuances of additional partnership securities, each of which can affect the amount of cash that is available for distribution to our unitholders;

•our general partner can determine when certain costs incurred by it and its affiliates are reimbursable by us;

•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;

•our general partner intends to limit its liability regarding our contractual and other obligations;

•our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Risks Relating to Our Structure

Our cash flow and our ability to pay distributions on our units, depends substantially on the ability of our subsidiaries to make distributions to us.

We depend on distributions and other payments from our subsidiaries to provide us with the funds necessary to meet our financial obligations. Our subsidiaries are legally distinct from us and some of them are or may become restricted in their ability to pay dividends and distributions or otherwise make funds available to us pursuant to local law, regulatory requirements and their contractual agreements, including agreements governing their financing arrangements. Any other entities through which we may conduct operations in the future will also be legally distinct from us and may be similarly restricted in their ability to pay dividends and distributions or otherwise make funds available to us under certain conditions.

Certain of our subsidiaries will generally be required to service their debt obligations and committed capital expenditure before making distributions to us, thereby reducing the amount of our cash flow available to us. The amount of cash our subsidiaries can distribute to us principally depends upon the amount of cash they generate from their operations which can be impacted by:

•contract rates and utilization of our vessels, including the rates at which our subsidiaries may be able to redeploy our vessels and the operating performance of our FPSO units, whereby receipt of incentive-based revenue from our FPSO units is dependent upon the fulfillment of applicable performance criteria;

•the price and level of production of, and demand for, crude oil particularly the level of production at the offshore oil fields our subsidiaries service under contracts of affreightment;

•the level of direct operating costs; and

•macroeconomic factors such as global and regional economic and political conditions, the status and effect of any health epidemics, currency exchange rate fluctuations and the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of our business.

We are a “foreign private issuer” under U.S. securities law and therefore, we are exempt from certain requirements applicable to U.S. domestic registrants listed on the NYSE.

Although we are subject to the periodic reporting requirement of the U.S. Securities Exchange Act of 1934, as amended (the Exchange Act), the periodic disclosure required of foreign private issuers under the Exchange Act is significantly different from periodic disclosure required of U.S. domestic registrants. Therefore, there may be less publicly available information about us than is regularly published by or about other public limited partnerships in the United States. We are exempt from certain other sections of the Exchange Act to which U.S. domestic issuers are subject. In addition, our insiders and large unitholders are not obligated to file reports under Section 16 of the Exchange Act related to changes in their holdings of securities, and we generally will be permitted to follow certain home country corporate governance practices instead of those otherwise required under NYSE rules for domestic issuers. We currently intend to follow the same corporate practices as would be applicable to U.S. domestic limited partnerships. However, we may in the future elect to follow our home country law for additional corporate governance practices, as permitted by the rules of the NYSE, in which case our unitholders may be provided less protection than is accorded to investors of NYSE-listed U.S. domestic issuers.

The international nature of our operations may make the outcome of any bankruptcy proceedings difficult to predict.

We were formed under the laws of the Republic of the Marshall Islands and our subsidiaries were formed or incorporated under the laws of the Republic of the Marshall Islands, Norway, Singapore, the United Kingdom and certain other countries besides the United States, and we conduct our business and operations in countries around the world. Consequently, in the event of any bankruptcy, insolvency, liquidation, dissolution, reorganization or similar proceeding involving us or any of our subsidiaries, bankruptcy laws other than those of the United States could apply. We have limited operations in the United States. 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 that it had jurisdiction.

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.

Our partnership affairs are governed by our partnership agreement and by the Marshall Islands Limited Partnership Act (the Marshall Island 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, for nonresident limited partnerships such as us, it is to be applied and construed to make the laws of the Republic of the Marshall Islands, with respect to the subject matter of the Marshall Islands Act, uniform with the laws of the State of Delaware and, so long as it does not conflict with the Marshall Islands Act or decisions of certain Republic of the Marshall Islands courts, the non-statutory law (or case law) of the courts of the State of Delaware is adopted as the law of the Republic of the Marshall Islands. There have been, however, few, if any, Marshall Islands court cases 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 Delaware courts. For example, the rights of our unitholders and any responsibilities of our general partner under Republic of the 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 limited partnership formed in the United States.

Because we are organized under the laws of the Republic 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 Republic of the Marshall Islands, and all of our assets are registered and located outside of the United States. Our business is operated primarily from our offices in the United Kingdom, Norway, Brazil, Singapore and the Netherlands. In addition, our general partner is a Marshall Islands limited liability company and a majority of its directors and officers are 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 to bring an action against us or against these individuals in the United States. Even if successful in bringing an action of this kind, the laws of the Marshall Islands and of other jurisdictions may prevent or restrict the enforcement of a judgment against our assets or the assets of our general partner or its directors and officers.

Our failure to maintain effective internal controls could have a material adverse effect on our business in the future and the price of our units.

We are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act, and stock exchange rules promulgated in response to the Sarbanes-Oxley Act. Any failure to maintain adequate internal controls over financial reporting or to implement required, new or improved controls, or difficulties encountered in their implementation, could cause material weaknesses or significant deficiencies in our internal controls over financial reporting and could result in errors or misstatements in our consolidated financial statements that could be material. Our failure to achieve and maintain effective internal controls could have a material adverse effect on our business, our ability to access capital markets and investors’ perception of us. In addition, material weaknesses in our internal controls could require significant expense and management time to remediate.

The vote by the United Kingdom to leave the European Union could adversely affect us.

The United Kingdom referendum held in 2016 on its membership in the EU resulted in a majority of United Kingdom voters voting to exit the EU (or Brexit). We have operations in the United Kingdom and the EU, and our registered head office is in the United Kingdom, and as a result, we face risks associated with the potential uncertainty and disruptions that may follow Brexit (which occurred on January 31, 2020), including with respect to volatility in exchange rates and interest rates, and potential material changes to the regulatory regime applicable to its business or global trading parties. Brexit could adversely affect European or worldwide political, regulatory, economic or market conditions and could contribute to instability in global political institutions, regulatory agencies and financial markets. Whilst we do not expect any material impact to our business, financial condition, operating results or cash flows as a result of Brexit, any of the aforementioned effects of Brexit, and others we cannot anticipate or that may evolve over time, could have an unexpected material adverse effect on our business, financial condition, operating results or cash flows.

Ineffective internal control over financial reporting could result in errors in our financial statements

As discussed in this Annual Report under Item 15 “Controls and Procedures”, during 2020 we identified a material weakness over information technology (or IT) user access control management; specifically, controls were not operating effectively related to user access controls management to appropriately segregate duties and to adequately restrict user and privileged access to financial applications, data and programs to appropriate personnel. There were no adjustments required in the 2020 interim or annual consolidated financial statements due to this material weaknesses. Management is actively undertaking remediation efforts to address the material weakness identified above through providing additional training to relevant personnel to strengthen competence at the relevant levels across the organization regarding risks and internal controls; improving the operation of controls over IT user access and the level of privileges assigned to IT users; and increasing coordination and monitoring activities related to the execution of the IT user access management controls. Such remediation efforts are intended to address the identified material weakness and enhance our overall financial control environment. Failure to remediate these control deficiencies could adversely affect our business and the price of our units. Although we are taking steps to remediate the deficiency, there is no assurance that other deficiencies or material weaknesses may not exist or arise in the future.

Risks Related to Taxation

In addition to the following risk factors, refer to Item 10E. – Taxation – Material United States Federal Income Tax Considerations and Item 10E. – Taxation – Non-United States Tax Considerations for further discussion of our expected material U.S. federal and non-U.S. income tax considerations and relating to the ownership and disposition of our units.

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

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” (or PFIC), for such purposes in any taxable year for which either (i) at least 75% of its gross income consists of “passive income,” or (ii) at least 50% of the average value of the entity’s assets is attributable to assets that 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). By contrast, income derived from the performance of services does not constitute “passive income.”

There are legal uncertainties involved in determining whether the income derived from our time-chartering activities constitutes rental income or income derived from the performance of services, including the decision in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. 2009), which held that income derived from certain time-chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the Internal Revenue Code of 1986, as amended (or the Code). However, the Internal Revenue Service (or IRS) stated in an Action on Decision (AOD 2010-01) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the Tidewater decision, and in its discussion stated that the time charters at issue in Tidewater would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to Tidewater cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the Tidewater decision in interpreting the PFIC provisions of the Code. Nevertheless, based on our and our subsidiaries current assets and operations, we intend to take the position that we are not now and have never been a PFIC. No assurance can be given, however, that this position would be sustained by a court if contested by the IRS, or that we would not constitute a PFIC for any future taxable year if there were to be changes in our assets, income or operations.

If the IRS were to determine that we are or have been a PFIC for any taxable year during which a U.S. Holder (as defined below under "Item 10 – Additional Information – Material United States Federal Income Tax Considerations") held units, such U.S. Holder would face adverse tax consequences. For a more comprehensive discussion regarding the tax consequences to U.S. Holders if we are treated as a PFIC, please read Item "10 – Additional Information: Material United States Federal Income Tax Considerations –- United States Federal Income Taxation of U.S. Holders – Consequences of Possible PFIC Classification."

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

We or our subsidiaries are subject to tax in certain jurisdictions in which we or our subsidiaries are organized, own assets or have operations, which reduces the amount of our cash available for distribution. In computing our tax obligations 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 us or our subsidiaries. We have established reserves in our financial statements that we believe are adequate to cover our liability for any such additional taxes. We cannot assure you, however, that such reserves will be sufficient to cover any additional tax liability that may be imposed on our subsidiaries. In addition, changes in our operations or ownership could result in additional tax being imposed on us or on our subsidiaries in jurisdictions in which operations are conducted.

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

Unitholders may be subject to tax in one or more countries as a result of owning our units if, under the laws of any such country, we are considered to be carrying on business there. If unitholders are subject to tax in any such country, unitholders may be required to file a tax return with, and pay taxes to, that country based on their allocable share of our income. We may be required to reduce distributions to unitholders on account of any withholding obligations imposed upon us by that country in respect of such allocation to unitholders. The United States may not allow a tax credit for any foreign income taxes that unitholders directly or indirectly incur.

Item 4.Information on the Partnership

A.History and Development of the Partnership

Altera Infrastructure Partners L.P. is an international infrastructure services provider to the offshore oil and gas industry, focused on the ownership and operation of critical infrastructure assets in offshore oil regions of the North Sea, Brazil and the East Coast of Canada. We were formed as a limited partnership established under the laws of the Republic of the Marshall Islands in August 2006 and our affairs are governed by the Marshall Islands Limited Partnership Act and our limited partnership agreement as amended on October 27, 2020. We are a subsidiary of Brookfield Business Partners L.P (NYSE: BBU) (TSX: BBU.UN). Our preferred equity units are listed on the New York Stock Exchange under the ticker symbols “ALIN PR A”, “ALIN PR B” and “ALIN PR E”, respectively. Our registered head office is Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, United Kingdom. Our telephone number at such address is +44 1224 568 200.

In September 2017, affiliates of Brookfield purchased from an affiliate of Teekay Corporation (NYSE: TK) a 49% interest in our general partner and purchased common units, then representing an approximately 60% interest in our total outstanding common units, and certain warrants to purchase additional common units from us. In July 2018, Brookfield, through an affiliate, exercised its option to acquire an additional 2% interest in our general partner from an affiliate of Teekay Corporation. In May 2019, Brookfield purchased Teekay Corporation's remaining interest in us, which increased Brookfield's ownership to a 100% interest in our general partner and approximately 73% of our outstanding common units. On January 22, 2020, Brookfield completed its acquisition by merger (the Merger) of all of the outstanding publicly held and listed common units representing our limited partner interests held by parties other than Brookfield (or unaffiliated unitholders) pursuant to a merger agreement (the Merger Agreement) among us, our general partner and certain members of Brookfield. Under the terms of the Merger Agreement, (a) a newly formed subsidiary of Brookfield merged with and into us and we survived as a wholly owned subsidiary of Brookfield and our general partner, and (b) common units held by unaffiliated unitholders were converted into the right to receive $1.55 in cash per common unit, other than common units held by unaffiliated unitholders who elected to receive the equity consideration. As an alternative to receiving the cash consideration in the merger, each unaffiliated unitholder had the option to elect to forego the cash consideration and instead receive one of our newly designated unlisted Class A common unit per common unit. The Class A common units are economically equivalent to the Class B common units held by Brookfield following the Merger, but have limited voting rights and limited transferability. Refer to Item 18 - Financial Statements: Note 23 - Equity.

As of December 31, 2020, Brookfield owns all of the Class B common units, representing approximately 98.7% of our outstanding common units. All of the Class A common units, representing approximately 1.3% of our outstanding common units, are held by the unaffiliated unitholders.

Refer to Item 18 – Financial Statements: Note 11 – Vessels and Equipment and Note 12 - Advances on Newbuilding Contracts for a description of our capital expenditures during 2020 and 2019 and capital expenditures currently in progress as at December 31, 2020.

The SEC maintains an Internet site at www.sec.gov, that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our website is www.alterainfra.com. The information contained on our website is not part of this annual report.

B.Business Overview

Overview

We are an international infrastructure services provider to the offshore oil and gas industry, focused on the ownership and operation of critical infrastructure assets in offshore oil regions of the North Sea, Brazil and the East Coast of Canada. We have the following five operating segments which are organized based on how management views business activities within particular sectors: FPSO, Shuttle Tanker, floating storage and off-take (or FSO), Units for Maintenance and Safety (or UMS) and Towage. As at December 31, 2020, our fleet was as follows:


	Number of Vessels
	Owned Vessels		Chartered-in Vessels	Committed Newbuildings		Total
FPSO Segment	7	(i)	—	—		7
Shuttle Tanker Segment	25	(ii)	1	3	(iii)	29
FSO Segment	4		—	—		4
UMS Segment	1		—	—		1
Towage Segment	10		—	—		10
Total	47		1	3		51

(i)Includes two FPSO units, the Cidade de Itajai and Pioneiro de Libra, in which our ownership interest is 50 percent.

(ii)Includes three shuttle tankers in which our ownership interest is 50 percent.

(iii)Includes three DP2 shuttle tanker newbuildings scheduled for delivery through early-2022, two of which will join our contract of affreightment (CoA) portfolio in the North Sea and one which will operate under an existing contract off the East Coast of Canada. One of these vessels was delivered to us in January 2021.

The tables below provide a breakdown of total assets by operating segment and non-current assets by region as at December 31, 2020, and revenues for the year ended December 31, 2020 by operating segment and region.

Operating Segments


	Assets	Revenues
(in thousands of U.S Dollars)	As at December 31, 2020	Year Ended December 31, 2020
FPSO Segment	1,220,084	482,802
Shuttle Tanker Segment	2,134,382	543,186
FSO Segment	242,312	113,867
UMS Segment	100,467	1,828
Towage Segment	301,270	45,991
Eliminations	—	(5,564)
Corporate/Other
Cash and cash equivalents and restricted cash	369,123	—
Other assets	17,993	—

Total	4,385,631	1,182,110

Region


	Non-Current Assets	Revenues
(in thousands of U.S Dollars)	As at December 31, 2020	Year Ended December 31, 2020
Norway	2,017,897	638,803
Brazil	829,206	189,928
Netherlands	288,823	40,427
Canada	355,497	110,366
United Kingdom	172,374	137,953
Australia	—	5,640
Other	88,843	58,993

Total	3,752,640	1,182,110

FPSO Segment

FPSO units are offshore production facilities that are ship-shaped or cylindrical-shaped and store processed crude oil in tanks located in the hull of the vessel. FPSO units are production facilities employed to develop oil fields that typically are marginal or located in deepwater areas remote from existing pipeline infrastructure. Of four major types of floating production systems, FPSO units are the most common type. Typically, the other types of floating production systems do not have significant storage and need to be connected into a pipeline system or use an FSO unit for storage. FPSO units are less weight-sensitive than other types of floating production systems and their extensive deck area provides flexibility in process plant layouts. In addition, the ability to utilize surplus or aging tanker hulls for conversion to an FPSO unit provides a relatively inexpensive solution compared to the new construction of other floating production systems. A majority of the cost of an FPSO unit comes from its top-side production

equipment and thus, FPSO units are expensive relative to conventional tankers. An FPSO unit carries on board all the necessary production and processing facilities normally associated with a fixed production platform. As the name suggests, FPSO units are not fixed permanently to the seabed but are designed to be moored at one location for long periods of time. In a typical FPSO unit installation, the untreated well-stream is brought to the surface via sub-sea equipment on the sea floor that is connected to the FPSO unit by flexible flow lines called risers. The risers carry the mix of oil, gas and water from the ocean floor to the vessel, which processes it on board. The resulting crude oil is stored in the hull of the vessel and subsequently transferred to tankers either via a buoy or tandem loading system for transport to shore.

Traditionally for large field developments, the major oil companies have owned and operated new, custom-built FPSO units. FPSO units for smaller fields have generally been provided by independent FPSO contractors under life-of-field production contracts, where the contract’s duration is for the useful life of the oil field. FPSO units have been used to develop offshore fields around the world since the late 1970s.

At December 31, 2020, we owned five FPSO units, in which we have 100% ownership interests, two of which are in lay-up, and two FPSO units in which we have 50% ownership interests. Most independent FPSO contractors have backgrounds in marine energy transportation, oil field services or oil field engineering and construction. Other major independent FPSO contractors are SBM Offshore N.V., BW Offshore, MODEC, Bumi Armada, Yinson Holdings, Bluewater and MISC.

The following table provides additional information about our FPSO units as of December 31, 2020:


Unit	Production Capacity (bbl/day)	Built	Ownership	Field Name and Location	Charterer	Contract End Date
Pioneiro de Libra	50,000	2017	50%	Mero/Libra, Brazil	Petrobras	November 2029
Petrojarl Knarr	63,000	2014	100%	Knarr, Norway	Shell	March 2022 (1)
Cidade de Itajai	80,000	2012	50%	Bauna and Piracaba, Brazil	Karoon	February 2026 (2)
Piranema Spirit	30,000	2007	100%	Piranema, Brazil	Petrobras	April 2021 (3)
Petrojarl I	46,000	1986	100%	Atlanta, Brazil	Enauta	May 2023 (4)
Petrojarl Varg	57,000	1998	100%		Lay-up
Voyageur Spirit	30,000	2008	100%		Lay-up
Total capacity	326,000

(1)The contract has a firm period expiring in March 2022. From March 2022 the charter may be terminated by either party, without penalty, by providing six-months' notice.

(2)The charterer has options to extend the contract to February 2028.

(3)In June 2020, the charterer exercised its termination right with ten months' notice.

(4)Until May 2023, the charter has termination rights with four months' notice subject to the payment of certain termination fees.

The table below provides a breakdown of revenues for our FPSO segment by region:


	Year Ended
	December 31, 2020	December 31, 2019
(in thousands of U.S Dollars)	$	$
Norway	266,475	289,669
Brazil	88,234	121,124


United Kingdom	128,093	66,803



Total	482,802	477,596

Shuttle Tanker Segment

A shuttle tanker is a specialized ship designed to transport crude oil and condensates from offshore oil field installations to onshore terminals and refineries. Shuttle tankers are equipped with sophisticated loading systems and dynamic positioning systems that allow the vessels to load cargo safely and reliably even in harsh weather conditions. Shuttle tankers were developed in the North Sea as an alternative to pipelines. The first cargo from an offshore field in the North Sea was shipped in 1977, and the first dynamically-positioned shuttle tankers were introduced in the early 1980s. Shuttle tankers are often described as “floating pipelines” because these vessels typically shuttle oil from offshore installations to onshore facilities in much the same way a pipeline would transport oil along the ocean floor.

Our shuttle tankers are primarily subject to long-term, fixed-rate time-charter or bareboat charter contracts or under contracts of affreightment for various fields. The number of voyages performed under the contracts of affreightment depends upon the oil production of each field. Competition for charters is based primarily upon price, availability, the size, technical sophistication, age and condition of the vessel and the reputation of the vessel’s manager. Shuttle tanker demand may be affected by the possible substitution of sub-sea pipelines to transport oil from offshore production platforms. The shuttle tankers in our contract of affreightment fleet may operate in the conventional spot market during downtime or maintenance periods for oil field installations or otherwise, which provides greater capacity utilization for the fleet.

Shuttle tankers primarily operate in Brazil, the North Sea and off the East Coast of Canada. As of December 31, 2020, we owned 25 shuttle tankers, in which our ownership interests ranged from 50% to 100%, had three shuttles tankers under construction and chartered-in an additional shuttle tanker. Other shuttle tanker owners include Knutsen, MOL and AET Tankers. We believe that we have competitive advantages in the shuttle tanker market as a result of the quality, type and dimensions of our vessels combined with our market share in the North Sea, Brazil and the East Coast of Canada.

The following tables provide additional information about our shuttle tankers, including our shuttle tanker newbuildings, as of December 31, 2020:

Vessel

Capacity (dwt)

Built

Ownership

Positioning System

Operating Region

Contract Type(1)

Charterer

Contract End Date

Tide Spirit

129,830

2020

100%

DP2

North Sea

CoA

Aker BP, BP, Britoil, ConocoPhillips, Dana, DNO, Eni, Enquest, Equinor, Idemitsu,Ithaca, Lundin, Molgrowest, Nautical, Neptuen, OKEA, OMV, ONE-Dyas, PGNiG, Premier Oil, Repsol Sinopec, Shell, Taqa Bratani, Verus, Vår Energi, Wintershall Dea (2)

Scott Spirit

109,300

2011

100%

DP2

North Sea

CoA

Peary Spirit

109,300

2011

100%

DP2

North Sea

CoA

Nansen Spirit

109,300

2010

100%

DP2

North Sea

CoA

Amundsen Spirit

109,300

2010

100%

DP2

North Sea

CoA

Petroatlantic

93,000

2003

100%

DP2

North Sea

CoA

Petronordic

93,000

2002

100%

DP2

North Sea

CoA

Stena Natalita

108,100

2001

50%(3)

DP2

North Sea

CoA

Navion Oslo

100,300

2001

100%

DP2

North Sea

CoA

Navion Oceania

126,400

1999

100%

DP2

North Sea

CoA

Ingrid Knutsen

111,600

2013

In-chartered (until December 2022)

DP2

North Sea

CoA

Samba Spirit

154,100

2013

100%

DP2

Brazil

Shell

June 2023

Lambada Spirit

154,000

2013

100%

DP2

Brazil

Shell

August 2023

Bossa Nova Spirit

155,000

2013

100%

DP2

Brazil

Shell

November 2023

Sertanejo Spirit

155,000

2013

100%

DP2

Brazil

Shell

January 2024

Beothuk Spirit

148,200

2017

100%

DP2

Canada

ExxonMobil, Canada Hibernia, Chevron, Husky, Mosbacher, Murphy, Nalcor, Equinor, Suncor(2)

May 2030(5)

Norse Spirit

148,200

2017

100%

DP2

Canada

May 2030(5)

Dorset Spirit

148,200

2018

100%

DP2

Canada

May 2030(5)

Altera Thule(8)

148,200

2022

100%

DP2

Canada

May 2030(5)

Navion Gothenburg

152,200

2006

50%(3)

DP2

Brazil

Petrobras

February 2021

Navion Stavanger

148,700

2003

100%

DP2

Brazil

Petrobras

October 2021

Nordic Brasilia

151,300

2004

100%

Far-East

Spot

Nordic Rio

151,300

2004

50%(3)

Far-East

Spot

Aurora Spirit

129,830

2020

100%

DP2

North Sea

Equinor(4)

March 2033

Rainbow Spirit

129,830

2020

100%

DP2

North Sea

Equinor(4)

March 2030

Current Spirit

129,830

2020

100%

DP2

North Sea

Equinor(4)

March 2025

Altera Wind(6)

103,500

2021

100%

DP2

North Sea

Altera Wave(6)(7)

103,500

2021

100%

DP2

North Sea

Navion Anglia

126,400

1999

100%

DP2

Lay-up

Total capacity

3,736,720

(1)“CoA” refers to contracts of affreightment, "TC" refers to time charters, "BB" refers to bareboat charters, "NB" refers to newbuilding vessel.

(2)The charter agreements specify which shuttle tankers may be employed under the contract and the actual usage depends on the transport demand

(3)Owned through a partnership in which we have a 50% ownership interest. The parties share in the profits and losses of the subsidiary partnership in proportion to each party’s relative ownership.

(4)Under the terms of a master agreement with Equinor, the vessels are chartered under individual fixed-rate annually renewable time-charter contracts. The number of vessels Equinor is committed to in-charter may be adjusted annually based on the requirements of the fields serviced and the charter end date is based on the latest production forecast.

(5)The charterer may adjust the number of vessels servicing the East Coast of Canada contract by providing at least 24 months' notice.

(6)The newbuildings will operate in the North Sea CoA fleet.

(7)The newbuilding was delivered to us in January 2021.

(8)The newbuilding will operate in the East Coast of Canada.

Historically, the utilization of shuttle tankers in the North Sea is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our vessels and to the offshore oil platforms. Downtime for repairs and maintenance generally reduces oil production and, thus, transportation requirements.

The table below provides a breakdown of revenues for our shuttle tanker segment by region:


	Year Ended
	December 31, 2020	December 31, 2019
(in thousands of U.S Dollars)	$	$
Norway	288,774	280,577
Brazil	101,694	117,127

Canada	110,366	97,176
United Kingdom	4,507	35,934

Other	37,845	18,773

Total	543,186	549,587

FSO Segment

FSO units provide on-site storage for oil field installations that have no storage facilities or that require supplemental storage. An FSO unit is generally used in combination with fixed or floating production systems that do not have sufficient storage facilities. FSO units are moored to the seabed at a safe distance from a field installation and receive cargo from the production facility via a dedicated loading system. An FSO unit is also equipped with an export system that transfers cargo to shuttle or conventional tankers. Depending on the selected mooring arrangement and where they are located, FSO units may or may not have any propulsion systems. FSO units are often conversions of older shuttle tankers or conventional oil tankers. These conversions, which include installation of a loading and off-take system and hull refurbishment, can generally extend the lifespan of a vessel as an FSO unit by up to 20 years over the normal shuttle tanker lifespan of 20 years.

Our FSO units are generally placed on long-term, fixed-rate time charter or bareboat charter contracts as an integrated part of the field development plan, which provides stable cash flows to us.

As of December 31, 2020, we owned four FSO units. The major markets for FSO units are Asia, West Africa, Northern Europe, the Mediterranean and the Middle East. Our primary competitors in the FSO market are conventional tanker owners who have access to tankers available for conversion, and oil field services companies and oil field engineering and construction companies who compete in the floating production system market. Competition in the FSO market is primarily based on price, expertise in FSO operations, management of FSO conversions and relationships with shipyards, as well as the ability to access vessels for conversion that meet customer specifications.

The following table provides additional information about our FSO units as of December 31, 2020:

Vessel

Capacity (dwt)

Built

Ownership

Field name and location

Contract Type

Charterer

Contract End Date

Randgrid (1)

124,500

1995

100%

Gina Krog, Norway

Time charter

Equinor

October 2021

Suksan Salamander (1)

78,200

1993

100%

Bualuang, Thailand

Bareboat

Teekay Corporation

August 2024

Falcon Spirit

124,500

1986

100%

Al Rayyan, Qatar

Time charter

Qatar Petroleum

May 2022

Dampier Spirit

106,700

1987

100%

Lay-up

Total capacity

433,900

(1)Charterer has option to extend the time charter.

The table below provides a breakdown of revenues for our FSO segment by region:


	Year Ended
	December 31, 2020	December 31, 2019
(in thousands of U.S Dollars)	$	$
Norway	81,726	95,664
United Kingdom	5,353	5,681
Australia	5,640	17,413
Other	21,148	21,359

Total	113,867	140,117

UMS Segment

UMS are used primarily for offshore accommodation, storage and support for maintenance and modification projects on existing offshore installations, or during the installation and decommissioning of large floating production and storage units, floating liquefied natural gas (or FLNG) units and floating drill rigs. The UMS is available for world-wide operations, excluding operations on the Norwegian Continental Shelf, and includes a DP3 positioning system that is capable of operating in deep water and harsh weather. The Arendal Spirit is currently in lay-up.

The following table provides additional information about our UMS as of December 31, 2020:

Vessel

Berths

Built

Ownership

Location

Contract type

Arendal Spirit

500

2015

100%

Norway

Lay-up

The table below provides a breakdown of revenues for our UMS segment by region:


	Year Ended
	December 31, 2020	December 31, 2019
(in thousands of U.S Dollars)	$	$
Norway	1,828	2,940







Total	1,828	2,940

Towage Segment

Long-distance towage and offshore installation vessels are used for the towage, station-keeping, installation and decommissioning of large floating objects such as production and storage units, including FPSO units, FLNG units and floating drill rigs. We operate with long-distance towage and offshore installation vessels with a bollard pull of generally greater than 200 tonnes and a fuel capacity of at least 35-40 days of operation. Our focus is on intercontinental towage requiring trans-ocean movements.

Our vessels operate on voyage-charter and spot contracts. Voyage-charter revenue is less volatile than revenue from spot market rates, as project budgets are prepared and maintained well in advance of the contract commencement.

At December 31, 2020, we owned ten towage vessels.

The following table provides additional information about our towage vessels as of December 31, 2020:


Vessel	Bollard Pull (tonnes)	Built	Ownership	Contract Type
ALP Keeper	302	2018	100%	Voyage-charter
ALP Defender	305	2017	100%	Voyage-charter
ALP Sweeper	303	2017	100%	Voyage-charter
ALP Striker	309	2016	100%	Voyage-charter
ALP Centre	298	2010	100%	Voyage-charter
ALP Guard	285	2009	100%	Voyage-charter
ALP Winger	208	2007	100%	Voyage-charter
ALP Forward	219	2007	100%	Voyage-charter
ALP Ippon	198	2006	100%	Voyage-charter
ALP Ace	192	2006	100%	Voyage-charter

The table below provides a breakdown of revenues for our towage segment by region:


	Year Ended
	December 31, 2020	December 31, 2019
(in thousands of U.S Dollars)	$	$


Netherlands	45,991	74,726





Total	45,991	74,726

Business Strategies

Through teamwork and innovation we are shaping the infrastructure of offshore energy, leading the industry to a sustainable future. Our primary business strategies include the following:

•Providing Superior, Cost-Effective Customer Service by Maintaining High Reliability, Safety, Environmental and Quality Standards. Energy companies demand partners that have a reputation for high reliability, sustainability, safety, environmental and quality standards. We intend to continue to leverage our operational expertise and customer relationships, as well as our uncompromised commitment to safety, to further expand a sustainable competitive advantage with consistent delivery of superior customer service, including working together with customers in seeking to reduce their production costs and find efficiencies.

•Focusing on Enhancing Overall Liquidity and Generating Stable and Recurring Cash Flows from Long-Term Contracts with Creditworthy Customers. We intend to maintain and grow our cash flows by focusing on strong customer relationships and actively seeking

the extension and renewal of existing charter contracts, entering into new medium- to long-term fixed-rate charter contracts with current customers, and identifying new business opportunities with other creditworthy customers for our current fleet. By focusing primarily on maximizing returns from our existing asset base, we believe we can generate stable and reliable cash flows while providing customers with quick-to-market and lower cost solutions. We believe we are well-positioned to extend contracts and redeploy existing assets by leveraging our engineering and operational expertise with our global marketing organization and extensive customer relationships.

•Acquiring Vessels with Existing Contracts or Constructing Additional Assets to Serve Under Medium- to Long-Term, Fixed-Rate Contracts. We intend to seek further sustainable long-term growth by bidding selectively on new revenue-generating projects and acquiring or constructing assets as needed to fulfill such contracts once awarded. We believe this approach facilitates the financing of new vessels based on their anticipated future revenues and ensures that new assets will be employed upon acquisition or completion, which should increase the stability and reliability of cash flows.

•Enhancing our position as a Global Energy Infrastructure Services Business that will Create Long-Term Value for Our Stakeholders. We seek to maximize value for our unitholders, through our commitment to operational excellence and our pursuit of opportunities, including in relation to the wider global energy transition and that lead to strong financial results, in a prudent manner.

•Project Management and Execution of Growth Projects. We continue to focus on executing on our existing shuttle tanker growth projects delivering between now and 2022, while simultaneously seeking new opportunities for growth in our existing businesses and adjacent markets to provide stable and reliable cash flows. In pursuing future growth projects, we may enter into joint ventures and partnerships with other reputable companies in the offshore space.

Customers

Our customers are predominately global energy producers with whom we primarialy have long-term, fixed-rate contracts. Refer to Item 18 – Financial Statements: Note 27 - Segment Reporting - Revenues from Contracts with Customers for a listing of our customers that account for more than 10% of our consolidated revenues.

Safety, Management of Vessel Operations and Administration

Safety and environmental compliance are our top operational priorities. We operate our vessels and equipment in a manner intended to protect the health and safety of our employees, the general public and the environment. We seek to manage the risks inherent in our business and are committed to eliminating incidents that threaten the safety and integrity of our vessels and equipment. We conduct rigorous internal audits of our processes and provide our seafarers with training to improve the safety culture in our fleet.

All vessels in our fleet are operated under our comprehensive and integrated safety management system that complies with the International Management Code for the Safe Operation of Ships and for Pollution Prevention (or ISM Code), the International Standards Organization’s (or ISO) 9001 for Quality Assurance, ISO 14001 for Environment Management Systems, ISO 45001 for Occupational Health and Safety and the Maritime Labor Convention 2006 (or MLC 2006) and is certified by DNV-GL. Compliance with these standards is confirmed on a yearly basis by auditing procedures that includes both internal audits as well as external verification audits by DNV-GL and applicable flag states.

Certain of our subsidiaries provide vessel and equipment management services to other subsidiaries. These include:

•vessel maintenance (including repairs and dry docking) and certification;

•crewing by competent seafarers;

•procurement of stores, bunkers and spare parts;

•management of emergencies and incidents;

•supervision of shipyards and projects during newbuilding and conversions;

•insurance; and

•financial management, human resource and other administrative services.

Flag, Classification, Audits and Inspections

Our vessels are registered with reputable flag states, and the hull and machinery of all of our vessels have been “classed” by one of the major classification societies and members of IACS (International Association of Classification Societies Ltd): DNV-GL, Lloyd’s Register of Shipping or American Bureau of Shipping.

The classification society certifies that the vessel’s design and build conforms to the class rules and meets the requirements of the country for which the vessel is registered and the international conventions to which that country is a signatory. The classification society also verifies that the vessel continues to be maintained in accordance with those requirements. During each five-year period the vessel undergoes annual and intermediate surveys. The vessel's underwater areas are inspected as part of a dry dock at five year intervals. We have enhanced the resiliency of the underwater coatings and marked each vessel hull to facilitate underwater inspections by divers. Underwater inspections are carried out during the second or third annual inspection.

The vessel's flag state also verifies the vessel condition during annual inspections. Also, authorities of a port of call are authorized to undertake regular and spot checks of vessels visiting their jurisdiction.

Processes followed on board are audited by either the flag state or the classification society acting on behalf of a flag state to ensure that they meet the requirements of the ISM Code. Additionally, we have annual internal audits on each vessel.

We follow a comprehensive inspections scheme and carry out two internal inspections and one internal audit annually, which helps monitor that:

•our vessels and operations adhere to our operating standards;

•the structural integrity of the vessel is being maintained;

•machinery and equipment is being maintained to give reliable service;

•we are optimizing performance in terms of speed and fuel consumption; and

•the vessel’s appearance will support our brand and meet customer expectations.

Overall we believe that our vessels are well-maintained and of high quality and provide us with a competitive advantage in the current environment of increasing regulation and customer emphasis on quality of service.

Regulations

General

Our business and the operation of our vessels are significantly affected by international conventions and national, state and local laws and regulations in the jurisdictions in which our vessels operate, as well as in the country or countries of their registration. Because these conventions, laws and regulations change frequently, we cannot predict the ultimate cost of compliance. We are required by various governmental and quasi-governmental agencies to obtain permits, licenses and certificates with respect to our operations. These requirements include but are not limited to the following.

International Maritime Organization (or IMO)

The IMO is the United Nations’ agency for maritime safety and prevention of pollution. IMO regulations relating to pollution prevention for tankers have been adopted by many of the jurisdictions in which our fleet operates. Under IMO regulations and subject to limited exceptions, a tanker must be of double-hull construction in accordance with the requirements set out in these regulations, or be of another approved design ensuring the same level of protection against oil pollution. All of our tankers are double-hulled.

Many countries have ratified and follow the liability regime adopted by the IMO and set out in the International Convention on Civil Liability for Oil Pollution Damage, 1969, as amended (or CLC). Under this convention, a vessel’s registered owner is strictly liable for pollution damage caused in the territorial waters of a contracting state (or under the 1992 protocol to the CLC, the exclusive economic zone or equivalent area) by discharge of persistent oil, subject to certain defenses. The right to limit liability to specified amounts is forfeited under the CLC when the spill is caused by the owner’s actual fault or when the spill is caused by the owner’s intentional or reckless conduct. Vessels trading to contracting states must provide evidence of insurance covering the limited liability of the owner. In jurisdictions where the CLC has not been adopted, various legislative regimes or common law governs, and liability is imposed either on the basis of fault or in a manner similar to the CLC.

IMO regulations also include the International Convention for Safety of Life at Sea (or SOLAS), including amendments to SOLAS implementing the International Ship and Port Facility Security Code (or ISPS), the ISM Code, and the International Convention on Load Lines of 1966. The IMO Marine Safety Committee has also published guidelines for vessels with DP systems, which applies to certain of our shuttle tankers and FSO and FPSO units. SOLAS provides rules for the construction of and the equipment required for commercial vessels and includes regulations for their safe operation. Flag states which have ratified the convention and the treaty generally employ the classification societies, which have incorporated SOLAS 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. Non-compliance with IMO regulations, including SOLAS, the ISM Code, ISPS and the specific requirements for shuttle tankers, FSO units and FPSO units under the NPD (Norway) and HSE (United Kingdom) 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. The United States Coast Guard (or Coast Guard) and European Union authorities have indicated that vessels not in compliance with the ISM Code will be prohibited from trading in U.S. and European Union ports.

The ISM Code requires vessel operators to obtain a safety management certification for each vessel they manage, evidencing the shipowner’s development and maintenance of an extensive safety management system. Each of the existing vessels in our fleet is currently ISM Code-certified, and we expect to obtain safety management certificates for each newbuilding vessel upon delivery.

For offshore support vessels, such as the Arendal Spirit UMS, SOLAS permits certain exemptions and equivalents to be allowed by the relevant vessel’s flag state. The International Code on Intact Stability, 2008 also generally applies to offshore support vessels. The IMO’s Maritime Safety Committee (or MSC) has also adopted amendments to the Intact Stability Code relating to vessels engaged in anchor handling operations and engaged in lifting and towing operations, including escort towing. These amendments became effective January 1, 2020. The IMO has also developed non-mandatory codes and guidelines which apply to various types or aspects of offshore support vessels.

In addition, the International Code of Safety for Ships using Gases or other Low-flashpoint Fuels (the IGF Code), which entered into force on January 1, 2017, applies to ships fueled by gases or other low-flashpoint fuels and sets out mandatory provisions for the arrangement, installation, control and monitoring of machinery, equipment and systems using low-flashpoint fuel. Additional amendments regarding the loading limit for liquefied gas fuel tanks, the protection of the fuel supply for liquefied gas fuel tanks aimed at preventing explosions and fuel containment systems, among other items, will go into effect in 2024.

Annex VI to the IMO’s International Convention for the Prevention of Pollution from Ships (MARPOL) (or Annex VI) sets limits on sulphur oxide and nitrogen oxide emissions (or NOx) from ship exhausts and prohibits emissions of ozone depleting substances, emissions of volatile compounds

from cargo tanks and the incineration of specific substances. Annex VI also includes a world-wide cap on the sulphur content of fuel oil and allows for special "emission control areas" (or ECAs) to be established with more stringent controls on sulphur emissions.

Annex VI also provides for a three-tier reduction in NOx emissions from marine diesel engines, with the final tier (or Tier III) applying to engines installed on vessels constructed on or after January 1, 2016 and which operate in the North American ECA or the U.S. Caribbean Sea ECA as well as ECAs designated in the future by the IMO. In October 2016, IMO’s Marine Environment Protection Committee (or MEPC) approved the designation of the North Sea and the Baltic Sea as ECAs for NOx emissions; these ECAs and the related amendments to Annex VI of MARPOL (with some exceptions) entered into force on January 1, 2019. Ships constructed on or after January 1, 2021 operating in the North Sea or Baltic Sea must comply with NOx Tier III standards.

Effective January 1, 2020, Annex VI imposes a global limit for sulphur in fuel oil used on board ships of 0.50% m/m (mass by mass), regardless of whether a ship is operating outside a designated ECA. To comply with this new standard, ships may utilize different fuels containing low or zero sulphur (e.g., LNG or biofuels), or utilize exhaust gas cleaning systems, known as “scrubbers” which are an accepted equivalent measure for complying with the global limit for sulphur in fuel oil used on board ships. Amendments to the information to be included in bunker delivery notes relating to the supply of marine fuel oil to ships fitted with scrubbers or other accepted equivalent measures became effective January 1, 2019. We have taken and continue to take steps to comply with the sulphur limit and intend to utilize low or zero sulphur fuel where possible.

As of March 1, 2018, amendments to Annex VI imposed new requirements for ships of 5,000 gross tonnage and to collect consumption data for each type of fuel oil they use, as well as certain other data including proxies for transport work. Additional amendments revising, among other terms, the definition of "sulphur content of fuel oil" and "low-flashpoint fuel", and pertaining to the sampling and testing of onboard fuel oil, will become effective in 2022.

The IMO's Ballast Water Management Convention (BWM Convention) entered into force on September 8, 2017 and stipulates two standards for discharged ballast water and requires the implementation of either standard. Vessels will be required to meet one standard by installing an approved Ballast Water Management System (or BWMS). Ships sailing in U.S. waters are required to employ a type-approved BWMS which is compliant with USCG regulations. The USCG has approved a number of BWMS. Amendments to the BWM Convention concerning commissioning testing of BWMS will become effective in 2022.

MARPOL Annex I also states that oil residue may be discharged directly from the sludge tank to the shore reception facility through standard discharge connections. They may also be discharged to the incinerator or to an auxiliary boiler suitable for burning the oil by means of a dedicated discharge pump. Amendments to Annex I expand on the requirements for discharge connections and piping to ensure residues are properly disposed of. Annex I is applicable for existing vessels with a first renewal survey beginning on or after January 1, 2017.

MSC 91 adopted amendments to SOLAS Regulation II-2/10 to clarify that a minimum of two-way portable radiotelephone apparatus for each fire party for fire-fighter's communication shall be carried on board. These radio devices shall be of explosion proof type or intrinsically safe type. All existing ships (built before July 1, 2014) should comply with this requirement not later than the first safety Equipment survey after July 1, 2018. All new vessels constructed (keel laid) on or after July 1, 2014 must comply with this requirement at the time of delivery. Amendments to SOLAS Regulation II-1/2/-12 on protection against noise, Regulation II-2/1 and II 2/10 on firefighting and new Regulation XI-12-1 on harmonization of survey periods of cargo ships not subject to the ESP code became effective January 1, 2020. Additional SOLAS regulation amendments became effective on January 1, 2020 and pertain to the maintenance of life-saving equipment and appliances.

The IMO continues to review and introduce new regulations; as such, it is impossible to predict what additional regulations, if any, may be adopted by the IMO and what effect, if any, such regulations might have on our operations.

European Union (or EU)

The EU has adopted legislation that: bans from European waters manifestly sub-standard vessels (defined as vessels that have been detained twice by EU port authorities, in the preceding two years); creates obligations on the part of EU member port states to inspect minimum percentages of vessels using these ports annually; provides for increased surveillance of vessels posing a high risk to maritime safety or the marine environment; and provides the EU with greater authority and control over classification societies, including the ability to seek to suspend or revoke the authority of negligent societies.

The EU has adopted a Directive requiring the use of low sulphur fuel. Since January 1, 2015, vessels have been required to burn fuel with sulphur content not exceeding 0.1% while within EU member states’ territorial seas, exclusive economic zones and pollution control zones that are included in “SOx Emission Control Areas.” Other jurisdictions have also adopted similar regulations.

IMO regulations required that as of January 1, 2015, all vessels operating within ECAs worldwide recognized under MARPOL Annex VI must comply with 0.1% sulphur requirements. Certain modifications were necessary in order to optimize operation on low sulphur marine gas oil (or LSMGO) of equipment originally designed to operate on Heavy Fuel Oil (or HFO). In addition, LSMGO is more expensive than HFO and this could impact the costs of operations. Our exposure to increased cost is in our spot trading vessels, although our competitors bear a similar cost increase as this is a regulatory item applicable to all vessels. All required vessels in our fleet trading to and within regulated low sulphur areas are able to comply with fuel requirements. The global cap on the sulphur content of fuel oil was reduced from 3.5% to 0.5% effective January 1, 2020.

The EU Ship Recycling Regulation aims to prevent, reduce and minimize accidents, injuries and other negative effects on human health and the environment when ships are recycled and the hazardous waste they contain is removed. The legislation applies to all ships flying the flag of an EU country and to vessels with non-EU flags that call at an EU port or anchorage. It sets out responsibilities for ship owners and for recycling facilities both in the EU and in other countries. Each new ship has to have on board an inventory of the hazardous materials (such as asbestos, lead or mercury) it contains in either its structure or equipment. The use of certain hazardous materials is forbidden. Before a ship is recycled, its owner must provide the company carrying out the work with specific information about the vessel and prepare a ship recycling plan. Recycling may only take place at facilities listed on the EU ‘List of facilities’. In 2014, the Council Decision 2014/241/EU authorized EU countries having ships flying their flag or registered under their flag to ratify or to accede to the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships. The Regulation generally entered into force on December 31, 2018, with certain provisions applicable from December 31, 2020.

We have developed and adopted a stringent process for ship recycling, including direct involvement with the recycling facilities, that ensures this regulation is met when recycling our vessels. The EU Commission also adopted a European List of approved ship recycling facilities, as well as four further implementing decisions dealing with certification and other administrative requirements set out in the Regulation.

North Sea, Canada and Brazil

Our shuttle tankers and FPSO units primarily operate in the North Sea, Brazil and Canada.

There is no international regime in force which deals with compensation for oil pollution from offshore craft, such as FPSO units. Whether the CLC and the International Convention on the Establishment of an International Fund for Compensation for Oil Pollution Damage 1971, as amended by the 1992 Protocol (or the Fund Convention), which deal with liability and compensation for oil pollution, and the Convention on Limitation of Liability for Maritime Claims 1976, as amended by the 1996 Protocol (or the 1976 Limitation of Liability Convention), which deals with limitation of liability for maritime claims, apply to FPSO units is neither straightforward nor certain. This is due to the definition of “ship” under these conventions and the requirement that oil is “carried” on board the relevant vessel. Nevertheless, the wording of the 1992 Protocol to the CLC leaves room for arguing that FPSO units and oil pollution caused by them can come under the ambit of these conventions for the purposes of liability and compensation. However, the application of these conventions also depends on their implementation by the relevant domestic laws of the countries which are parties to them.

UK’s Merchant Shipping Act 1995, as amended (or the MSA), implements the CLC but uses a wider definition of a “ship” than the one used in the CLC and in its 1992 Protocol but still refers to the criteria used by the CLC. It is therefore doubtful that FPSO units fall within its wording. However, the MSA also includes separate provisions for liability for oil pollution. These apply to vessels which fall within a much wider definition and include non-seagoing vessels. It is arguable that the wording of these MSA provisions is wide enough to cover oil pollution caused by offshore crafts such as FPSO units. The liability regime under these MSA provisions is similar to that imposed under the CLC but limitation of liability is subject to the 1976 Limitation of Liability Convention regime (as implemented in the MSA),

With regard to the 1976 Limitation of Liability Convention, it is, again, doubtful whether it applies to FPSO units, as it contains certain exceptions in relation to vessels constructed for or adapted to and engaged in drilling and in relation to floating platforms constructed for the purpose of exploring or exploiting natural resources of the seabed or its subsoil. However, these exceptions are not included in the legislation implementing the 1976 Limitation of Liability Convention in the UK, which is also to be found in the MSA. In addition, the MSA sets out a very wide definition of “ship” in relation to which the 1976 Limitation of Liability Convention is to apply and there is room for argument that if FPSO units fall within that definition of “ship”, they are subject in the UK to the limitation provisions of the 1976 Limitation of Liability Convention.

In the absence of an international regime regulating liability and compensation for oil pollution caused by offshore oil and gas facilities, the Offshore Pollution Liability Agreement 1974 was entered into by a number of oil companies and became effective in 1975. This is a voluntary industry oil pollution compensation scheme which is funded by the parties to it. These are operators or intending operators of offshore facilities used in the exploration for and production of oil and gas located within the jurisdictions of a number of “Designated States” which include the UK, Denmark, Norway, Germany, France, Greenland, Ireland, the Netherlands, the Isle of Man and the Faroe Islands. The scheme provides for strict liability of the relevant operator for pollution damage and remedial costs, subject to a limit, and the operators must provide evidence of financial responsibility in the form of insurance or other security to meet the liability under the scheme.

With regard to FPSO units, Chapter 7 of Annex I of MARPOL (which contains regulations for the prevention of oil pollution) sets out special requirements for fixed and floating platforms, including, amongst others, FPSO units and FSUs. The IMO’s Marine Environment Protection Committee has issued guidelines for the application of MARPOL Annex I requirements to FPSO units and FSUs.

The EU’s Directive 2004/35/CE on environmental liability with regard to the prevention and remedying of environmental damage (or the Environmental Liability Directive) deals with liability for environmental damage on the basis of the “polluter pays” principle. Environmental damage includes damage to protected species and natural habitats and damage to water and land. Under this Directive, operators whose activities caused the environmental damage or the imminent threat of such damage are to be held liable for the damage (subject to certain exceptions). With regard to environmental damage caused by specific activities listed in the Directive, operators are strictly liable. This is without prejudice to their right to limit their liability in accordance with national legislation implementing the 1976 Limitation of Liability Convention. The Directive applies both to damage which has already occurred and where there is an imminent threat of damage. It also requires the relevant operator to take preventive action, to report an imminent threat and any environmental damage to the regulators and to perform remedial measures, such as clean-up. The Environmental Liability Directive is implemented in the UK by the Environmental Damage (Prevention and Remediation) Regulations 2015, as amended and supplemented from time to time.

In June 2013 the EU adopted Directive 2013/30/EU on safety of offshore oil and gas operations and amending Directive 2004/35/EC (or the Offshore Safety Directive). This Directive lays down minimum requirements for member states and the European Maritime Safety Agency for the purposes of reducing the occurrence of major accidents related to offshore oil and gas operations, thus increasing protection of the marine environment and coastal economies against pollution, establishing minimum conditions for safe offshore exploration and exploitation of oil and gas, and limiting disruptions to the EU’s energy production and improving responses to accidents. The Offshore Safety Directive sets out extensive requirements, such as preparation of a major hazard report with risk assessment, emergency response plan and safety and environmental management system applicable to the relevant oil and gas installation before the planned commencement of the operations, independent verification of safety and environmental critical elements identified in the risk assessment for the relevant oil and gas installation, and ensuring that factors such as the applicant’s safety and environmental performance and its financial capabilities or security to meet potential liabilities arising from the oil and gas operations are taken into account when considering granting a license. Under the Offshore Safety Directive, Member States are to ensure that the relevant licensee is financially liable for the prevention and remediation of environmental damage (as defined in the Environmental Liability Directive) caused by offshore oil and gas operations carried out by or on behalf of the licensee or the operator. Member States must lay down rules on penalties applicable to infringements of the legislation adopted pursuant to this Directive. Member States were required to bring into force laws, regulations and administrative provisions necessary to comply with this Directive by 19 July 2015. The Offshore Safety Directive has been implemented in the UK by a number of different UK Regulations, including the Environmental Damage (Prevention and Remediation) (England) Regulations 2015, as amended, (which revoked and replaced the Environmental Damage (Prevention and Remediation) Regulations

2015)) and the Offshore Installations (Offshore Safety Directive)(Safety Case etc.) Regulations 2015, as amended, both of which were effective from July 19, 2015.

In addition to the regulations imposed by the IMO and EU, countries having jurisdiction over North Sea areas impose regulatory requirements in connection with operations in those areas, including the United Kingdom (or UK) and Norway. In the UK, the exploration for and production of oil and gas in the UK, including the UK sector of the North Sea is undertaken pursuant to the Petroleum Act 1998 in accordance with the conditions of a license issued by the UK government. Model clauses included in such licenses require licensees amongst other things to operate in accordance with methods customarily used in good oilfield practice and to take all steps practicable to prevent the escape of oil. Various UK regulations dealing with environmental and other aspects of offshore oil and gas activities are also in place. These regulatory requirements, together with additional requirements imposed by operators in North Sea oil fields, require that we make further expenditures for sophisticated equipment, reporting and redundancy systems on the shuttle tankers and for the training of seagoing staff. Additional regulations and requirements may be adopted or imposed that could limit our ability to do business or further increase the cost of doing business in the North Sea.

In Norway, the Norwegian Pollution Control Authority requires the installation of Volatile Organic Compound (or VOC) emissions reduction units on most shuttle tankers serving the Norwegian continental shelf.

In addition to the requirements of major IMO shipping conventions, the exploration for and production of oil and gas within the Newfoundland & Labrador (or NL) offshore area is conducted pursuant to the Canada Newfoundland and Labrador Atlantic Accord Implementation Act (or the Accord Act) in accordance with the conditions of a license and authorization issued by the Canada-Newfoundland and Labrador Offshore Petroleum Board (or CNLOPB). Various regulations dealing with environmental, occupational health and safety, and other aspects of offshore oil and gas activities have been enacted under the Accord Act. The CNLOPB has also issued interpretive guidelines concerning compliance with the regulations, and compliance with CNLOPB guidelines may be a condition of the issuance or renewal of the license and authorizations. These regulations and guidelines require that the shuttle tankers in the NL offshore area meet stringent standards for equipment, reporting and redundancy systems, and for the training and equipping of seagoing staff. Further, licensees are required by the Accord Act to provide a benefits plan satisfactory to CNLOPB. Such plans generally require the licensee to: establish an office in NL; give NL residents first consideration for training and employment; make expenditures for research and development and education and training to be carried out in NL; and give first consideration to services provided from within NL and to goods manufactured in NL. These regulatory requirements may change as regulations and CNLOPB guidelines are amended or replaced from time to time.

In addition to the regulations imposed by the IMO, Brazil imposes regulatory requirements in connection with operations in its territory, including specific requirements for the operations of vessels flagged in countries other than Brazil. Brazil has several maritime regulations and frequent amendments and updates. Firstly, with respect to environmental protection while operating under Brazilian waters, the Federal Constitution establishes that the State shall regulate and impose protections to the environment, establishing liability in the civil, administrative and criminal spheres. Law no. 6938/1981 sets the National Environmental Policy and Law no. 9966/2000, known as “The Oil Law”, institutes several rules, liabilities and penalties regarding the handling of oil or other dangerous substances, being applicable to foreign vessels and platforms operating in Brazilian waters. Regulating the exploitation and production of oil and natural gas, Law no. 9.478/1997, known as “The Petroleum Law”, created the National Petroleum Agency (or ANP), responsible for regulating and supervising the industry through directives and resolutions. After the discovery of the pre-salt, the mentioned law was altered in some points by Law no. 12.351/2010 and Laws 13.303/2016 and 13.609/2018, being the industry also regulated by several administrative Regulations issued by the ANP. ANP is currently reviewing an amendment to its Ordinance 170/02, with aims to specifically regulate ship-to-ship operations in addition to the transportation of hydrocarbons and byproducts.

Additional requirements and restrictions for the operation of offshore vessels and shuttle tankers are imposed by Law 9.432/97 and by the National Waterway Transport Agency (“ANTAQ”), instituted by Law 10.233/2001, by way of frequently updated administrative resolutions. The transit of vessels and permanence and operation of offshore units in Brazil are further regulated by the Maritime Authorities, through law and administrative Ordinances known as “NORMAM”. Brazil also is a signatory of several IMO/MARPOL conventions, including the deliberation to reduce Sulphur emissions as of January 1st, 2020, agreed during the 70º session of the Marine Environment Protection Committee, held at IMO’s headquarters on June 2016. Under Brazil’s environmental laws, owners and operators of vessels are strictly liable for damages to the environment. Other penalties for non-compliance with environmental laws include fines, loss of tax incentives and suspension of activities. Operators such as Petrobras may impose additional requirements, such as compliance with specific health, safety and environmental standards or the use of local labor. Additional regulations and requirements may be adopted or imposed that could limit our ability to do business or further increase the cost of doing business in Brazil.

United States

The United States has enacted an extensive regulatory and liability regime for the protection and cleanup of the environment from oil spills, including discharges of oil cargoes, bunker fuels or lubricants, primarily through the Oil Pollution Act of 1990 (or OPA 90) and the Comprehensive Environmental Response, Compensation and Liability Act (or CERCLA). OPA 90 affects all owners, bareboat charterers, and operators whose vessels trade to the United States or its territories or possessions or whose vessels operate in United States waters, which include the U.S. territorial sea and 200-mile exclusive economic zone around the United States. CERCLA applies to the discharge of “hazardous substances” rather than “oil” and imposes strict joint and several liabilities upon the owners, operators or bareboat charterers of vessels for cleanup costs and damages arising from discharges of hazardous substances. We believe that petroleum products should not be considered hazardous substances under CERCLA, but additives to oil or lubricants used on vessels might fall within its scope.

Under OPA 90, vessel owners, operators and bareboat charterers are “responsible parties” and are jointly, severally and strictly liable (unless the oil spill results solely from the act or omission of a third party, an act of God or an act of war and the responsible party reports the incident and reasonably cooperates with the appropriate authorities) for all containment and cleanup costs and other damages arising from discharges or threatened discharges of oil from their vessels. These other damages are defined broadly to include:

•natural resources damages and the related assessment costs;

•real and personal property damages;

•net loss of taxes, royalties, rents, fees and other lost revenues;

•lost profits or impairment of earning capacity due to property or natural resources damage;

•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.

OPA 90 limits the liability of responsible parties in an amount it periodically updates. The liability limits do not apply if the incident was caused by violation of applicable U.S. federal safety, construction or operating regulations, including IMO conventions to which the United States is a signatory, or 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 oil removal activities. Liability under CERCLA is also subject to limits unless the incident is caused by gross negligence, willful misconduct or a violation of certain regulations. We currently maintain for each of our vessels pollution liability coverage in the maximum coverage amount of $1 billion per incident. A catastrophic spill could exceed the coverage available, which could harm our business, financial condition and results of operations.

Under OPA 90, with limited exceptions, all newly built or converted tankers delivered after January 1, 1994 and operating in U.S. waters must be double-hulled. All of our tankers are double-hulled.

OPA 90 also requires owners and operators of vessels to establish and maintain with the Coast Guard evidence of financial responsibility in an amount at least equal to the relevant limitation amount for such vessels under the statute. The Coast Guard has implemented regulations requiring that an owner or operator of a fleet of vessels must demonstrate evidence of financial responsibility in an amount sufficient to cover the vessel in the fleet having the greatest maximum limited liability under OPA 90 and CERCLA. Evidence of financial responsibility may be demonstrated by insurance, surety bond, self-insurance, guaranty or an alternate method subject to approval by the Coast Guard. Under the self-insurance provisions, the ship owners or operators must have a net worth and working capital, measured in assets located in the United States against liabilities located anywhere in the world, that exceeds the applicable amount of financial responsibility. We have complied with the Coast Guard regulations by using self-insurance for certain vessels and obtaining financial guarantees from a third party for the remaining vessels. If other vessels in our fleet trade into the United States in the future, we expect to obtain guarantees from third-party insurers.

OPA 90 and CERCLA permit individual U.S. states to impose their own liability regimes with regard to oil or hazardous substance pollution incidents occurring within their boundaries, and some states have enacted legislation providing for unlimited strict liability for spills. Several coastal states, such as California, Washington and Alaska require state-specific evidence of financial responsibility and vessel response plans. We intend to comply with all applicable state regulations in the ports where our vessels call.

Owners or operators of vessels, including tankers operating in U.S. waters are required to file vessel response plans with the Coast Guard, and their tankers are required to operate in compliance with their Coast Guard approved plans. Such response plans must, among other things:

•address a “worst case” scenario and identify and ensure, through contract or other approved means, the availability of necessary private response resources to respond to a “worst case discharge”;

•describe crew training and drills; and

•identify a qualified individual with full authority to implement removal actions.

We have filed vessel response plans with the Coast Guard and have received its approval of such plans. In addition, we conduct regular oil spill response drills in accordance with the guidelines set out in OPA 90.

OPA 90 and CERCLA do not preclude claimants from seeking damages resulting from the discharge of oil and hazardous substances under other applicable law, including maritime tort law. The application of this doctrine varies by jurisdiction.

The United States Clean Water Act also prohibits the discharge of oil or hazardous substances in U.S. navigable waters and imposes strict liability in the form of penalties for unauthorized discharges. The Clean Water Act imposes substantial liability for the costs of removal, remediation and damages and complements the remedies available under OPA 90 and CERCLA discussed above.

Our vessels that discharge certain effluents, including ballast water, in U.S. waters must obtain a Clean Water Act (or CWA) permit from the Environmental Protection Agency (or EPA) titled the “Vessel General Permit” and comply with a range of effluent limitations, best management practices, reporting, inspections and other requirements. The Vessel General Permit incorporates Coast Guard requirements for ballast water exchange and including specific technology-based requirements for vessels, and an implementation schedule to require vessels to meet the ballast water effluent limitations by the first dry docking after January 1, 2016. This permit was set to be effective to December 18, 2018. The Vessel Incidental Discharge Act (or VIDA) was signed into law on December 4, 2018, and established a new framework for the regulation of vessel incidental discharges under the CWA. VIDA requires the EPA to develop performance standards for incidental discharges, and requires the Coast Guard to develop regulations within two years of the EPA’s promulgation of standards. Under VIDA, all provisions of the Vessel General Permit remain in force and effect as currently written until the EPA publishes future standards and the Coast Guard publishes corresponding implementing regulations (anticipated in 2022).

Vessels that are constructed after December 1, 2013 are subject to the ballast water numeric effluent limitations. Several U.S. states have added specific requirements to the Vessel General Permit and, in some cases, may require vessels to install ballast water treatment technology to meet biological performance standards.

The California Biofouling Management Plan requires, inter alia: developing and maintaining a Biofouling Management Plan, developing and maintaining a Biofouling Record Book, mandatory biofouling management of the vessel’s wetted surfaces, mandatory biofouling management for vessels that undergo an extended residency period (i.e. remain in the same location for 45 or more days). All vessel calling at California water were

required to submit the "Annual Marine Invasive Reporting Form" by October 1, 2017 and should have CA-Biofouling management plan after a vessel’s first regularly scheduled out-of-water maintenance (i.e. dry dock) after January 1, 2018, or upon delivery on or after January 1, 2018.

Emissions and Climate Regulation

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change (or 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, entered into the Copenhagen Accord. The Copenhagen Accord is non-binding, but is intended to pave the way for a comprehensive, international treaty on climate change. In December 2015, the Paris Agreement (or the Paris Agreement) was adopted by a large number of countries at the 21st Session of the Conference of Parties (commonly known as COP 21, a conference of the countries which are parties to the United Nations Framework Convention on Climate Change; the COP is the highest decision-making authority of this organization). The Paris Agreement, which entered into force on November 4, 2016, deals with greenhouse gas emission reduction measures and targets from 2020 in order to limit the global temperature increases to well below 2° Celsius above pre-industrial levels. The United States rejoined the Paris agreement in February 2021. Although shipping was ultimately not included in the Paris Agreement, it is expected that the adoption of the Paris Agreement may lead to regulatory changes in relation to curbing greenhouse gas emissions from shipping.

IMO regulations imposing technical and operational measures for the reduction of greenhouse gas emissions became effective in January 2013. In October 2016, the IMO adopted a mandatory data collection system under which vessels of 5,000 gross tonnages and above are to collect fuel consumption and other data and to report the aggregated data so collected to their flag state at the end of each calendar year. The new requirements entered into force on March 1, 2018. The IMO also approved a roadmap for the development of a comprehensive IMO strategy on reduction of greenhouse gas emissions from ships with an initial strategy adopted on April 13, 2018 and a revised strategy to be adopted in 2023.

The EU also has indicated that it intends to propose an expansion of an existing EU emissions trading regime to include emissions of greenhouse gases from vessels, and individual countries in the EU may impose additional requirements. The EU has adopted regulations on the monitoring, reporting and verification (or MRV) of carbon dioxide emissions from vessels (or the MRV Regulation), which entered into force on July 1, 2015. The MRV Regulation aims to quantify and reduce carbon dioxide emissions from shipping and generally requires ship owners and operators to annually monitor, report and verify carbon dioxide emissions for vessels larger than 5,000 gross tonnage calling at any EU and EFTA (Norway and Iceland) port. Data collection takes place on a per voyage basis and started January 1, 2018. The reported carbon dioxide emissions, together with additional data, such as cargo and energy efficiency parameters, are to be verified by independent verifiers and sent to a central database, managed by the European Maritime Safety Agency. To comply with the MRV Regulation, we have prepared an EU MRV monitoring plan and EU MRV monitoring template in line with legislative requirement. During September 2020, the European Parliament adopted its position on a proposal to revise the EU system for monitoring, reporting and verifying carbon dioxide emissions from maritime transportation. Parliament largely agreed that reporting obligations by the EU and the IMO should be aligned and believes that ships of 5,000 gross tonnage and above should be included in the EU Emissions Trading System. The European Parliament has also requested that shipping companies reduce their annual average carbon dioxide emissions per transport unit for all vessels by at least 40% by 2030.

In parallel to the EU MRV Regulation, the IMO has introduced a three-step approach, based on collecting and analyzing fuel consumption data, before agreeing what further actions may be required to reduce greenhouse gas emissions from ships. The IMO data collection system came into effect in March 2018.

The Sustainable Finance Taxonomy Regulation came into force in the EU on July 12, 2020. This Taxonomy Regulation sets out an EU-wide framework (a classification system known as a “taxonomy”) according to which investors and businesses can assess whether certain economic activities are “sustainable” and introduces a requirement, intended to apply from 2022, on financial market participants and large public interest entities to disclose information on how, and to what extent, their products and businesses are aligned with the taxonomy. As such, going forward, we may need to comply with additional disclosure obligations arising from this new EU-wide framework, including as this relates to accessing financial products and corporate bonds that are to be made available as environmentally sustainable.

In the United States, the EPA issued an “endangerment finding” regarding greenhouse gases under the Clean Air Act. While this finding in itself does not impose any requirements on our industry, it authorizes the EPA to regulate directly greenhouse gas emissions through a rule-making process. In addition, climate change initiatives are being considered in the United States Congress and by individual states. Any passage of new climate control legislation or other regulatory initiatives by the IMO, the EU, the United States or other countries or states where we operate that restrict emissions of greenhouse gases could have a significant financial and operational impact on our business that we cannot predict with certainty at this time.

C.Organizational Structure

Our sole general partner is Altera Infrastructure GP L.L.C., which is owned 100% by Brookfield.

Refer to Item 18 – Financial Statements: Note 2d - Interests in other entities for a list of our subsidiaries as of December 31, 2020.

D.Properties

See Item 4.B. - Business Overview.

Item 4A. Unresolved Staff Comments

Not applicable.

Item 5.Operating and Financial Review and Prospects

A.Operating Results

This management’s discussion and analysis of our operating results and financial condition included in Item 5.A of this Annual Report, covers the financial position of our Partnership as at December 31, 2020 and December 31, 2019, and results of operations for the years ended December 31, 2020 and 2019. This information should be read in conjunction with the audited consolidated financial statements as at December 31, 2020 and December 31, 2019, and each of the years in the two years ended December 31, 2020, which are prepared in accordance with IFRS as issued by the IASB. Please refer to Item 18 - Financial Statements.

During 2020, we adopted IFRS as the body of accounting principles used in preparing our consolidated financial statements. Prior to the adoption of IFRS, we prepared our financial statements in accordance with United States generally accepted accounting principles (or US GAAP). The effective transition date of this adoption, for the purposes of the preparation of our consolidated financial statements, is January 1, 2019. As a result, the comparative information included in this Annual Report as at December 31, 2019 and for the year ended December 31, 2019 has been adjusted from amounts previously reported by us in accordance with US GAAP.

IFRS 1 – First-time Adoption of International Financial Reporting Standards (or IFRS 1) provides entities preparing their first consolidated financial statements in accordance with IFRS with optional exemptions from full retrospective application of IFRS. We have applied certain of these optional exemptions as described in Item 18 - Financial Statements Note 3 - Transition to IFRS.

The application of the fair value as deemed cost exemption to our vessels and equipment and advances on newbuilding contracts had a significant impact on the valuation of these assets as at January 1, 2019, and for all periods presented subsequent to the transition to IFRS. Under US GAAP, vessels and equipment were tested for impairment by first comparing the undiscounted cash flows generated by the asset or cash generating unit to the carrying amount. If this test indicated an impairment, the impairment expense was then calculated by comparing the discounted cash flows or appraised values to the carrying amount of the asset or cash generating unit. Under IFRS, an impairment is recognized if the recoverable amount, determined as the higher of the estimated fair value less costs of disposal or the value in use, is less than the carrying value of the asset or cash generating unit, whereby the estimated fair value is either the discounted cash flows generated or an appraised value. As a result, had we not elected to use this optional exemption when transitioning to IFRS, vessels and equipment which had a material decrease in valuation upon transition would have been subjected to historical impairments under IFRS and therefore, for these vessels and equipment, we do not believe that a material difference in valuation would have occurred under a full retrospective application of IFRS. The valuation of certain vessels and equipment and advances on newbuilding contracts, mainly in our shuttle tanker fleet, increased as a result of the application of the fair value as deemed cost exemption. This increase in valuation would likely not have occurred had we not elected to use this optional exemption when transitioning to IFRS. All other optional exemptions that we elected to adopt did not have a material impact on our financial condition or results of operations.

We have applied the mandatory exceptions to retrospective application of IFRS, as applicable to us, described in Item 18 - Financial Statements Note 3 - Transition to IFRS.

Management’s Discussion and Analysis of Financial Conditions and Results of Operations

Overview of our Business

We are a leading global energy infrastructure services provider primarily focused on the ownership and operation of critical infrastructure assets in the offshore oil regions of the North Sea, Brazil and the East Coast of Canada. We were formed as a limited partnership established under the laws of the Republic of the Marshall Islands in August 2006. In January 2020, Brookfield completed the acquisition by merger of all of the outstanding publicly held and listed common units representing our limited partner interests held by parties other than Brookfield. At December 31, 2020, Brookfield held 98.7% of our outstanding common units and a 100% interest in our general partner. The remaining 1.3% of our outstanding common units are held by entities other than Brookfield and its affiliates.

Operating Segments

We currently operate FPSO units, shuttle tankers, FSO units, a UMS and towage vessels and our operations are organized into these five corresponding business segments. As at December 31, 2020, our fleet was as follows:


	Number of Vessels
	Owned Vessels		Chartered-in Vessels	Committed Newbuildings		Total
FPSO Segment	7	(i)	—	—		7
Shuttle Tanker Segment	25	(ii)	1	3	(iii)	29
FSO Segment	4		—	—		4
UMS Segment	1		—	—		1
Towage Segment	10		—	—		10
Total	47		1	3		51

(i)Includes two FPSO units, the Cidade de Itajai and Pioneiro de Libra, in which our ownership interest is 50 percent.

(ii)Includes three shuttle tankers in which our ownership interest is 50 percent.

(iii)Includes three DP2 shuttle tanker newbuildings scheduled for delivery through early-2022, two of which will join our CoA portfolio in the North Sea and one which will operate under an existing contract off the East Coast of Canada. One of these vessels was delivered to us in January 2021.

The tables below provide a breakdown of total assets as at December 31, 2020 and total revenues for the year ended December 31, 2020, by operating segment:


	Assets	Revenues
(in thousands of U.S Dollars)	As at December 31, 2020	Year Ended December 31, 2020
FPSO Segment	1,220,084	482,802
Shuttle Tanker Segment	2,134,382	543,186
FSO Segment	242,312	113,867
UMS Segment	100,467	1,828
Towage Segment	301,270	45,991
Eliminations	—	(5,564)
Corporate/Other
Cash and cash equivalents and restricted cash	369,123	—
Other assets	17,993	—

Total	4,385,631	1,182,110

Outlook

Our near-to-medium term business strategy is primarily to focus on extending contracts and redeploying existing assets on long-term charters, repaying or refinancing scheduled debt obligations and pursuing additional growth projects. Despite the weakness in the global energy and capital markets, our operating cash flows prior to changes in non-cash working capital items relating to operating activities have remained relatively consistent, supported by a large and well-diversified portfolio of fee-based contracts, which primarily consists of medium-to-long-term contracts with high quality counterparties.

Global crude oil and gas prices have decreased significantly since mid-2014, and more recently, during 2020, the uncertainty regarding demand created by the COVID-19 pandemic has produced volatility in the market with prices increasing in early-2021. This has affected the energy and capital markets and may also adversely affect our business, financial condition and operating results. Potential effects of the pandemic include, among others, force majeure claims relating to existing contracts, increased counterparty risk and/or default, fewer contract extension opportunities, and in the worst case, contract terminations resulting from relevant early field abandonment programs. Conversely, irrespective of recent increases in oil prices we expect that a continuation of relatively low oil prices will motivate charterers to use existing FPSO units on new projects, given their lower cost relative to a newbuilding unit. Our operational focus over the short-term is to focus on extending contracts and the redeployment of our assets that are scheduled to come off charter over the next few years.

Our long-term growth strategy focuses on expanding our fleet of shuttle tankers and FPSO units under medium-to-long term charter contracts. Over the long-term, we intend to continue our practice of primarily acquiring vessels as needed for approved projects only after the medium-to-long-term charters for the projects have been awarded to us, rather than ordering vessels on a speculative basis. We have entered and may enter into joint ventures and partnerships with companies that may provide increased access to such charter opportunities or we may engage in vessel or business acquisitions.

Significant Developments

Contracts

Extension of the Cidade de Itajai FPSO contract

In November 2020, Karoon Energy Ltd. (or Karoon) completed the acquisition of a 100% operating interest, from Petróleo Brasileiro S.A. (or Petrobras), in the Santos Basin concession BM-S-40, containing the Baúna oil field, where the Cidade de Itajai FPSO unit operates. Concurrently, the 50/50 joint venture between Ocyan and us, which owns the Cidade de Itajai FPSO unit, agreed, with Karoon, to exercise options to extend the charter contract and operating agreement of Cidade de Itajai FPSO by four years until at least February 2026.

ENI CoA contract

In September 2020, we were awarded a five-year CoA with ENI S.p.A. in the North Sea. The new contract was effective from November 2020 and is equivalent to one vessel being 100% utilized to service the contract throughout the five-year term.

Dampier FSO contract termination

In September 2020, the Dampier Spirit FSO unit completed operations on the Stag field in Australia. The vessel is expected to be recycled under our responsible recycling regime.

Randgrid FSO contract extension

In June 2020, Equinor exercised the first of twelve one-year options to extend the time-charter contract for the Randgrid FSO unit by one-year until at least October 2021.

Voyageur Spirit contract completion

In June 2020, the Voyageur Spirit FPSO unit completed its final commercial offloading at the Huntington oil field in the United Kingdom and is now in lay-up.

Navion Stavanger contract extension

In April 2020, we entered into an amendment with Petrobras to extend the bareboat charter contract for the shuttle tanker Navion Stavanger to October 2021.

Petrojarl Knarr contract extension

In March 2020, we entered into a contract amendment with AS Norske Shell, as operator for and on behalf of the Knarr field license partners (the “Operator”), that extends the contract for the lease and operation of the Petrojarl Knarr FPSO unit until at least March 2022.

The amendment reduces the day rate from March 2021 to March 2022 and eliminated the fee payable by the Operator if the contract was not extended, in return for the inclusion of an additional production volume and oil price related tariff. The amendment also terminated the Operator’s purchase option for the FPSO unit and provides for a mutual right to terminate the contract on six months’ notice without payment of a penalty, with such termination not to be effective before March 2022.

Petrojarl Foinaven operations contract

In March 2020, we entered into a seven-year agreement with Britoil Ltd., a subsidiary of BP p.l.c., to directly provide the operations for the Petrojarl Foinaven FPSO unit, which Britoil Ltd. has leased on a long-term bareboat contract from Teekay Corporation, to whom we previously provided similar services. As part of the arrangement with Britoil Ltd, we also entered into two shuttle tanker CoAs replacing two existing shuttle tanker time-charter contracts.

Delivery of Shuttle Tanker Newbuildings

During 2020, we took delivery of four LNG-fueled Suezmax DP2 shuttle tanker newbuildings, the Aurora Spirit, the Rainbow Spirit, the Tide Spirit and the Current Spirit. The vessels are constructed based on our E-shuttle design, which incorporates technologies intended to increase fuel efficiency and reduce emissions, using LNG fuel and recovered VOC as a secondary fuel, as well as battery packs for flexible power distribution and blackout prevention. The Aurora Spirit, the Rainbow Spirit and the Current Spirit are operating under the terms of a master agreement with Equinor and the Tide Spirit is operating in our CoA fleet. In January 2021, we took delivery of the Altera Wave, which is currently in transit to the North Sea. The sixth newbuilding is expected to be delivered to us in March 2021, while the final vessel, which is expected to operate off the East Coast of Canada, is expected to be delivered early-2022.

Sale of Vessels

During 2020, we sold for recycling three shuttle tankers, the HiLoad DP unit, the Ostras FPSO unit and the Apollo Spirit FSO unit, all under our responsible recycling regime. We received net proceeds of $28 million and recorded a net gain on sale of $3 million for these vessels during the year ended December 31, 2020.

Financings

In February 2021, we terminated two and amended a further two interest rate swaps that contained early termination provisions, which, if exercised, would have terminated these interest rate swaps during 2021.

In February 2021, we refinanced an existing term loan relating to the financing of the Petrojarl I FPSO unit, which provides for borrowings of $75.0 million and matures in February 2024.

In February 2021, we entered into two unsecured revolving credit facilities with Brookfield. The borrowings available under the two unsecured revolving credit facilities are $70.0 million and $30.0 million, respectively, and mature in February 2022.

During 2020, we agreed to amend the existing credit facility with Brookfield, to increase the total borrowings available under the unsecured revolving credit facility from $100 million to $250 million, including accumulated interest, and extend the maturity date to October 31, 2024.

In October 2020, we completed a $106 million upsizing of an existing term loan, relating to the partial financing of a newbuilding shuttle tanker currently under construction for operation off the East Coast of Canada. As a result, a previously secured bridge loan of $100 million, relating to the same newbuilding shuttle tanker, was terminated.

In August 2020, we completed a $75 million tap issue relating to our senior unsecured green bonds due in October 2024, which increased the total outstanding amount to $200 million.

In June 2020, we completed an extension of a $40 million commercial tranche related to the financing of the Petrojarl Knarr FPSO unit until June 2023. This extension was a condition for a related $390 million export credit agency tranche to not mature in June 2020. In addition, the interest rate swap portfolio associated with this borrowing was also extended until June 2022. As a result of these extensions, certain deposit arrangements and reductions in the negative mark-to-market values of the interest rate swaps were agreed with the lenders.

Securities Repurchase Program

In September 2020, we announced that our board of directors had authorized repurchases of our five-year senior unsecured bonds that mature in July 2023 and our Series A, B and E Preferred Units through open market purchases, privately negotiated transactions and/or pursuant to Rule 10b5-1 plans, in compliance with applicable securities laws and other legal requirements. The timing, volume, and nature of any repurchases will be determined by us, in consultation with the board of directors, based on evaluation of the capital needs of the business, trading prices, applicable legal requirements, and other factors.

During October 2020 through January 2021, we repurchased a total of $13 million of the par value our five-year senior unsecured bonds and a total of $6 million of the par value of our preferred units. The repurchase program was completed in January 2021.

Rebranding Initiative

Effective March 24, 2020, we changed our name to Altera Infrastructure L.P. and the group of entities comprising our affiliates and subsidiaries was rebranded as Altera Infrastructure. Our preferred units, which previously traded on the New York Stock Exchange (or NYSE) under the ticker symbols “TOO PR A”, “TOO PR B” and “TOO PR E”, now trade on the NYSE under the new ticker symbols “ALIN PR A”, “ALIN PR B” and “ALIN PR E”, respectively.

Completion of Brookfield Acquisition by Merger

On January 22, 2020, Brookfield completed the Merger, by which it acquired all of the outstanding publicly held and listed common units representing our limited partner interests held by parties other than Brookfield.

Changes to Board of Directors and Committees

During 2020, we announced the following changes to our general partner's board of directors and committees:

•In December 2020, Ingvild Sæther, President and CEO of Altera Infrastructure Group Ltd., joined the board of directors;

•In December 2020, Benedicte Bakke Agerup joined the board of directors and was appointed as a member of the Audit and Conflicts Committees;

•In December 2020, an Executive Oversight Committee was formed;

•In September 2020, Jim Reid retired from his position as a member for the Corporate Governance Committee;

•In June 2020, Kenneth Hvid retired from his position as a director of the board of directors;

•In March 2020, Nelson Silva joined the board of directors and was appointed as a member of the Audit and Conflicts Committees;

•In March 2020, existing directors Jim Reid and Gregory Morrison were appointed as members of the Corporate Governance Committee;

•In March 2020, the board of directors eliminated the Compensation Committee; and

•In January 2020, David L. Lemmon retired from his position as director of the board of directors and member of the Audit, Compensation and Conflicts Committees. Mr. Lemmon was replaced on the Audit Committee by Bill Utt;

Relocation

In September 2020, the board of directors of the general partner, approved a relocation of our principal office and place of business from its current location in Bermuda to the United Kingdom and more specifically to our current office in Aberdeen, at Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, UK. In connection with this we closed our office in Bermuda and also relocated the headquarters of a number of subsidiaries from Bermuda to the United Kingdom and others to Norway and Canada. In so doing we aim to reduce the complexity of our group structure and better allow for future strategic management of us by the general partner from the United Kingdom and the management of certain underlying assets from Norway. We consider both the United Kingdom and Norway as highly suitable jurisdictions given the group’s history of substantial operations in the North Sea, the nexus to European sources of investment and funding and the ease of doing business in well-established corporate and legal environments. The relocation was completed in December 2020 for the general partner and in early 2021 for affected subsidiaries.

On January 31, 2020, the United Kingdom formally left the EU. We do not expect any material impact to our business, financial condition, operating results or cash flows as a result of Brexit.

COVID-19

During 2020 we did not experience any material business interruptions or direct material financial impact as a result of the COVID-19 pandemic. We continue to focus on the safety of our operations and have introduced a number of proactive measures to protect the health and safety of our crews on our vessels as well as at onshore locations. A majority of our revenues are secured under medium-term contracts that should not be materially affected by the short-term volatility in oil prices. We continue to closely monitor counterparty risk associated with our vessels under contract and will work to mitigate any potential impact on the business.

The extent to which COVID-19 may impact the our results of operations and financial condition, including any possible impairments, will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of the virus or its variants, the effectiveness of vaccines and other actions to contain or treat its impact, among others. Accordingly, an estimate of the future impact cannot be made at this time

Strategic Initiatives

We are exploring with the assistance of retained financial advisors, a number of potential strategic initiatives, which may lead to certain asset sales to optimize our portfolio, seeking joint venture partners for our business interests and/or capital raises or other similar transactions to support future growth.

Økokrim Investigation

In January 2020, Økokrim (the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime) and the local Stavanger police raided the premises of our subsidiary Altera Infrastructure Norway AS in Stavanger, Norway, based on a search and seizure warrant issued pursuant to suspected violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018 and the sale of the vessel for recycling in Alang, India in June 2018. Having reviewed relevant materials together with our advisors, we continue to believe we acted in accordance with the relevant rules and regulations and deny the alleged violations. We are continuing to cooperate with authorities in respect of this matter.

Results of Operations

Below we discuss certain of our consolidated results and, subsequently, certain results for our five business segments.

In the following discussion we include the non-IFRS financial measures EBITDA and Adjusted EBITDA. We define these terms and provide reconciliations of these financial measures with the most directly comparable financial measures calculated and presented in accordance with IFRS below in “Non-IFRS Financial Measures.”

Our Contracts and Charters

The table below illustrates the primary distinctions among our types of charters and contracts for operation of our units and vessels:

FPSO Contracts

Contract of Affreightment

Time Charter

Bareboat Charter

Voyage Charter (1)

Typical contract length

Long-term

One year or more

Single voyage

Hire rate basis (2)

Daily

Typically daily

Daily

Varies

Voyage expenses (3)

Not applicable

We pay

Customer pays

We pay

Vessel operating expenses

We pay

Customer pays

We pay

Off hire (4)

Not applicable

Customer typically does not pay

Varies

Customer typically pays

Customer does not pay

Shutdown (5)

Varies

Not applicable

(1)Under a consecutive voyage charter, the customer pays for idle time.

(2)“Hire rate” refers to the basic payment from the charterer for the use of the vessel.

(3)Voyage expenses are all expenses unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions.

(4)“Off hire” refers to the time a vessel is not available for service.

(5)“Shutdown” refers to the time production services are not available.

Consolidated Results of Operations

The following table presents certain of our consolidated operating results for the years ended December 31, 2020 and 2019:


(in thousands of U.S. Dollars, except percentages)	Year Ended December 31,
	2020	2019	% Change
IFRS:
Revenues	1,182,110	1,252,938	(5.7)
Direct operating costs	(627,792)	(606,691)	3.5
General and administrative expenses	(44,360)	(54,927)	(19.2)
Depreciation and amortization	(316,317)	(358,474)	(11.8)
Interest expense	(192,723)	(205,667)	(6.3)
Interest income	2,770	5,111	(45.8)
Equity-accounted income (loss)	35,921	33,768	6.4
Impairment expense, net	(268,612)	(187,680)	43.1
Gain (loss) on dispositions, net	3,411	12,548	(72.8)

Realized and unrealized gain (loss) on derivative instruments	(96,499)	(34,682)	178.2
Foreign currency exchange gain (loss)	(7,861)	2,193	(458.5)
Other income (expenses), net	(10,472)	(9,677)	8.2
Income (loss) before income tax (expense) recovery	(340,424)	(151,240)	125.1
Income tax (expense) recovery
Current	(6,543)	(4,666)	40.2
Deferred	804	(3,161)	(125.4)
Net income (loss)	(346,163)	(159,067)	117.6

Non-IFRS:
EBITDA(1)	165,846	407,790	(59.3)
Adjusted EBITDA(1)	599,323	673,199	(11.0)

(1)EBITDA and Adjusted EBITDA are non-IFRS financial measures. Please refer to "Non-IFRS Financial Measures" below for definitions of these measures and for reconciliations of these measures with the most directly comparable financial measures calculated and presented in accordance with IFRS.

Revenues

Revenues decreased by $71 million, or 5.7%, for the year ended December 31, 2020, compared to 2019, primarily due to lower utilization and charter rates in the towage fleet, a reduction in charter rates under a contract extension for the Randgrid FSO unit, the completion of the Dampier Spirit FSO unit charter contract in 2020, redeliveries and ceased operations in the conventional tanker segment during 2019, redeliveries and sales of certain vessels, in addition to a decrease in the operating days during 2020 under a certain charter contract in the shuttle tanker segment, lower commercial uptime for the Petrojarl I FPSO unit during 2020, front end engineering design (or FEED) studies revenues received during 2019 relating to the Petrojarl Varg FPSO unit and the completion of the Voyageur Spirit FPSO unit charter contract in 2020, partially offset by operational services provided for the Foinaven FPSO unit operating under a new contract in 2020 and increased rates for shuttle tankers trading in the conventional tanker market during 2020.

Direct Operating Costs

Direct operating costs increased by $21 million, or 3.5%, for the year ended December 31, 2020, compared to 2019, primarily due to the costs associated with the Foinaven FPSO unit operating under a new contract from March 2020, the decommissioning of the Dampier Spirit FSO unit and the delivery of four shuttle tanker newbuildings during 2020, partially offset by lower utilization in the towage fleet, redeliveries and ceased operations in the conventional tanker segment during 2019, the sales of certain vessels in our shuttle tanker fleet during 2020 and 2019, costs associated with the Petrojarl Varg FPSO unit FEED studies during 2019 and the sale of the Ostras FPSO in March 2020.

General and Administrative Expenses

General and administrative expenses was $44 million for the year ended December 31, 2020, compared to $55 million for 2019. The decrease in general and administrative expenses was primarily due to the weakening of the NOK during 2020, compared to 2019, a decrease in travel expenses as a result of the COVID-19 pandemic and a decrease in legal fees due to a high number of dispute settlements occurring during 2019 partially offset by an increase in consulting fees during 2020.

Depreciation and Amortization

Depreciation and amortization decreased to $316 million for the year ended December 31, 2020, compared to $358 million for 2019, primarily due to sales and impairments of vessels and equipment partially offset by the deliveries of shuttle tanker newbuildings during 2020.

Interest Expense

Interest expense decreased to $193 million for the year ended December 31, 2020, compared to $206 million for 2019, primarily due to lower interest rates on our outstanding borrowings during 2020.

Equity-Accounted Income (Loss)

Equity-accounted income was $36 million for the year ended December 31, 2020, which was generally consistent with $34 million for 2019.

Impairment Expense, Net

Impairment expense, net was $269 million for the year ended December 31, 2020, compared to $188 million for 2019. During 2020, the impairment expense, net was recorded on 17 vessels, of which ten vessels, with an aggregate impairment expense of $215 million, was due to a change in the expected earnings or the future redeployment assumptions of the vessels and the remaining seven vessels, with an aggregate impairment expense of $54 million, was due to the expected sales of the vessels. During 2019, an impairment expense, net was recorded on nine vessels, of which five vessels, with an aggregate impairment expense of $180 million, was mainly due to a change in the future redeployment assumptions of the vessels and the remaining four vessels, with an aggregate impairment expense of $8 million, was due to the expected sales of the vessels.

Gain (Loss) on Dispositions, Net

Gain (loss) on dispositions, net was $3 million for the year ended December 31, 2020, compared to $13 million for 2019. During 2020, we sold six vessels and recognized a gain on disposition of $5 million relating to the Apollo Spirit FSO unit. The remaining five vessels were sold at their approximate carrying values. During 2019, we sold three vessels and recognized a gain on disposition of $11 million relating to the Pattani Spirit FSO unit. The remaining two vessels were sold at their approximate carrying values.

Realized and Unrealized Gain (Loss) on Derivative Instruments

As at December 31, 2020 and 2019, we had interest rate swap agreements with aggregate outstanding notional amounts of approximately $1.2 billion and $1.3 billion, respectively, with fixed rates of approximately 3.5% and 3.7%, respectively. Short-term variable benchmark interest rates during the years ended December 31, 2020 and 2019 were generally 1.9% or less and 2.8% or less, respectively, and as such, we incurred realized losses of $59 million (which includes a $27 million realized loss relating to the termination and partial settlement of certain interest rate swaps) and $29 million (which includes a $14 million realized loss relating to the partial settlement of certain interest rate swaps) during the years ended December 31, 2020 and 2019, respectively. We also recognized unrealized losses on interest rate swaps of $42 million and $56 million during the years ended December 31, 2020 and 2019, respectively, due to decreases in long-term LIBOR benchmark rates during these periods.

During the year ended December 31, 2019 we had an unrealized gain on warrants of $51 million. On January 22, 2020, as part of the Merger, all of our outstanding warrants were automatically canceled and ceased to exist. Refer to Item 18 - Financial Statements: Note 19 - Other Financial Liabilities and 23 - Equity.

Foreign Currency Exchange Gain (Loss)

Foreign currency exchange gain (loss) was $(8) million for the year ended December 31, 2020, compared to $2 million for 2019. Our foreign currency exchange gain (loss) is due primarily to the relevant period-end revaluation of NOK-denominated monetary assets and liabilities for financial reporting purposes and, for 2019, the net realized and unrealized gains on our cross-currency swaps. Gains on NOK-denominated net monetary liabilities reflect a stronger U.S. Dollar against the NOK on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on NOK-denominated net monetary liabilities reflect a weaker U.S. Dollar against the NOK on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

During the year ended December 31, 2019, we repaid certain NOK-denominated bonds and settled the related cross currency swaps and, as a result, recorded a realized foreign currency exchange gain and an unrealized foreign currency exchange loss of $4 million, in addition to a $4 million realized foreign currency exchange loss and unrealized foreign currency exchange gain on the associated cross currency swaps.

Income Tax (Expense) Recovery

Income tax (expense) recovery was $(6) million for the year ended December 31, 2020, which was generally consistent with $(8) million for 2019.

Adjusted EBITDA

Adjusted EBITDA decreased by $74 million for the year ended December 31, 2020, compared to 2019. Refer to "Results by Segment" below.

Related Party Transactions

Refer to Item 18 – Financial Statements: Note 22 – Related Party Transactions.

Results by Segment

IFRS requires operating segments to be determined based on internal reports that are regularly reviewed by our chief operating decision maker (or CODM) for the purpose of allocating resources to the segment and to assess its performance. The key measure used by the CODM in assessing performance and in making resource allocation decisions is Adjusted EBITDA.

Adjusted EBITDA represents net income (loss) before interest expense, interest income, income tax (expense) recovery, and depreciation and amortization adjusted to exclude certain items whose timing or amount cannot be reasonably estimated in advance or that are not considered representative of core operating performance. Such adjustments include impairment expenses, gain (loss) on dispositions, net, unrealized gain (loss) on derivative instruments, foreign currency exchange gain (loss) and certain other income or expenses. Adjusted EBITDA also excludes: realized gain or loss on interest rate swaps (as management, in assessing our performance, views these gains or losses as an element of interest expense); realized gain or loss on derivative instruments resulting from amendments or terminations of the underlying instruments; and equity-accounted income (loss). Adjusted EBITDA also includes our proportionate share of Adjusted EBITDA from our equity-accounted investments and

excludes the non-controlling interests' proportionate share of Adjusted EBITDA. We do not have control over the operations of, nor have any legal claim to the revenues and expenses of our equity-accounted investments. Consequently, the cash flow generated by our equity-accounted investments may not be available for use by us in the period that such cash flows are generated.

Adjusted EBITDA is also used by external users of our consolidated financial statements, such as investors and our controlling unitholder.

See “Non-IFRS Financial Measures” for a reconciliation of Adjusted EBITDA to the most directly comparable IFRS measure.

FPSO Segment

As at December 31, 2020, our FPSO fleet consisted of seven units, including two units of which we own 50% through our joint ventures with Ocyan S.A. (or Ocyan). The Petrojarl Varg and Voyageur Spirit FPSO units are currently in lay-up. In March 2020, we sold the Ostras FPSO unit under a responsible recycling regime and received net proceeds of $2 million. We also provided management services for three FPSO units on behalf of the disponent owners or charterers of these units during 2020.

FPSO units provide production, processing and storage services to oil companies operating offshore oil field installations. These services are typically provided under long-term, fixed-rate contracts, some of which also include certain incentive compensation or penalties based on the level of oil production, the price of oil and other operational measures. Historically, the utilization of FPSO units and other vessels in the North Sea, where the Petrojarl Knarr FPSO unit operates, is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our units and the offshore oil platforms, which generally reduces oil production. The strengthening or weakening of the U.S. Dollar relative to the NOK, Brazilian Real and British Pound may result in significant decreases or increases, respectively, in our revenues and direct operating costs, as significant components of revenues are earned and direct operating costs are incurred in these currencies for our FPSO units.

The following table presents certain of the FPSO segment’s operating results for 2020 and 2019:


	Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)	2020	2019	% Change
Revenues	482,802	477,596	1.1
Direct operating costs	(270,419)	(235,335)	14.9
General and administrative(1)	(28,590)	(31,773)	(10.0)
Adjusted EBITDA from equity-accounted investments(2)	101,352	98,297	3.1
Adjusted EBITDA	285,145	308,785	(7.7)
Depreciation and amortization	(94,293)	(109,865)	(14.2)
Impairment expense, net	(156,677)	(136,631)	14.7
Gain (loss) on dispositions, net	(92)	—	100.0

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FPSO segment based on estimated use of corporate resources).

(2)Adjusted EBITDA from equity-accounted investments represents our proportionate share of Adjusted EBITDA from equity-accounted vessels.

Revenues. Revenues increased by $5 million for 2020, compared to 2019, primarily due to:

•an increase of $61 million due to providing operational services for the Foinaven FPSO unit, which commenced operations under a new contract in March 2020;

•an increase of $8 million due to the recharge of direct operating costs to our joint ventures (offset by an increase in direct operating costs of $8 million); and

•an increase of $4 million due to revenues related to FEED studies received during 2020;

partially offset by

•a decrease of $27 million due to lower uptime for the Petrojarl I FPSO unit, including the unit being offhire during December 2020, due to operational issues;

•a decrease of $21 million due to the completion of the charter contract for the Voyageur Spirit FPSO unit in June 2020;

•a decrease of $13 million due to revenues related to the Petrojarl Varg FPSO unit FEED studies recognized during 2019; and

•a decrease of $6 million due to the completion of the charter contract for the Ostras FPSO unit in March 2019.

Direct operating costs. Direct operating costs increased by $35 million for 2020, compared to 2019, primarily due to:

•an increase of $47 million due to direct operating costs associated with providing operational services for the Foinaven FPSO unit, which commenced operations under a new contract in March 2020;

•an increase of $8 million due to direct operating costs relating to our joint ventures (offset by an increase in revenues of $8 million);

•an increase of $7 million due to direct operating costs related to FEED studies during 2020; and

•an increase of $4 million due to higher repairs and maintenance expenses on the Petrojarl I FPSO unit, relating to the unit being offhire during December 2020 due to operational issues;

partially offset by

•a decrease of $15 million due to direct operating costs related to the Petrojarl Varg FPSO unit FEED studies during 2019;

•a decrease of $7 million due to the sale of the Ostras FPSO unit in March 2020;

•a decrease of $6 million due to lower repairs and maintenance expenses on the Piranema Spirit FPSO unit as a result of preparation for the decommissioning of the unit; and

•a decrease of $5 million due to the completion of the charter contract for the Voyageur Spirit FPSO unit in June 2020;

Adjusted EBITDA. Adjusted EBITDA (including Adjusted EBITDA from equity-accounted joint ventures) decreased by $24 million for 2020, compared to 2019, primarily due to the increase in direct operating costs of $35 million, as described above, partially offset by the increase in revenues of $5 million, as described above, a $3 million decrease in general and administrative expenses and a $3 million increase in adjusted EBITDA from equity-accounted investments.

Depreciation and amortization. Depreciation and amortization expense decreased by $16 million for 2020, compared to 2019, primarily due to the impairments of our FPSO units during 2020 and 2019, as described below.

Impairment expense, net. Impairment expense, net of $157 million for 2020 was related to a $57 million impairment recorded on the Petrojarl Knarr FPSO unit and a $42 million impairment of the Petrojarl I FPSO unit due to changes in the expected earnings of the units as a result of a decline in crude oil prices during early-2020, a $27 million impairment recorded on the Petrojarl Varg FPSO unit in early-2020 due to a reassessment of the future redeployment opportunities for the unit and an additional impairment on the Petrojarl Varg FPSO unit of $31 million in late-2020 due to the expected sale of the unit.

Impairment expense, net of $136 million for 2019 was related to a $34 million impairment recorded on the Petrojarl Varg FPSO unit and a $98 million impairment recorded on the Voyageur Spirit FPSO unit as a result of reassessments of the future redeployment opportunities for the units, in addition to a $4 million impairment recorded on the Ostras FPSO unit due to the expected sale of the unit.

Shuttle Tanker Segment

As at December 31, 2020, our shuttle tanker fleet consisted of 25 owned vessels that operate under fixed-rate CoAs, time charters and bareboat charters (including three shuttle tankers in which our ownership interest is 50 percent), three shuttle tanker newbuildings which are expected to deliver through early-2022 (one of which was delivered to us in January 2021) and one in-chartered vessel. All of our operating shuttle tankers provide transportation services to energy companies predominately in the North Sea, Brazil and the East Coast of Canada. Our shuttle tankers occasionally service the conventional spot tanker market and we occasionally charter-in shuttle tankers in the spot market. The strengthening or weakening of the U.S. Dollar relative to the NOK, Euro and Brazilian Real may result in significant decreases or increases, respectively, in our direct operating costs, as significant components of direct operating costs are incurred in these currencies for our shuttle tankers.

The following table presents certain of the shuttle tanker segment’s operating results for 2020 and 2019 and also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the shuttle tanker segment:


(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	Year Ended December 31,
	2020	2019	% Change
Revenues	543,186	549,587	(1.2)
Direct operating costs	(251,259)	(245,833)	2.2
General and administrative(1)	(10,891)	(14,986)	(27.3)
Adjusted EBITDA attributable to non-controlling interests(2)	(10,989)	(10,864)	1.2
Adjusted EBITDA	270,047	277,904	(2.8)
Depreciation and amortization	(163,864)	(184,089)	(11.0)
Impairment expense, net	(35,257)	(15,342)	129.8
Gain (loss) on dispositions, net	(1,872)	1,335	(240.2)
Calendar-Ship-Days
Owned vessels	8,988	9,345	(3.8)
Chartered-in vessels	678	787	(13.9)
Total	9,666	10,132	(4.6)

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the shuttle tanker segment based on estimated use of corporate resources).

(2)Adjusted EBITDA attributable to non-controlling interests represents the non-controlling interests' proportionate share of Adjusted EBITDA from our consolidated joint ventures.

Revenues. Revenues decreased by $6 million for 2020, compared to 2019, primarily due to:

•a decrease of $15 million due to the redelivery, to us, of the Stena Sirita during 2019 and Navion Bergen during 2020;

•a decrease of $13 million due to a decrease in operating days under a master agreement with Equinor; and

•a decrease of $7 million due to lower rates on certain bareboat charter contracts;

partially offset by

•an increase of $21 million due to higher rates in the conventional tanker market;

•an increase of $6 million due to an additional vessel operating under the East Coast of Canada charter contract until May 2020; and

•an increase of $3 million due to higher utilization in the CoA fleet.

Direct operating costs. Direct operating costs increased by $5 million for 2020, compared to 2019, primarily due to:

•an increase of $23 million due to the delivery of four of the shuttle tanker newbuildings during 2020;

•an increase of $4 million due to lay-up costs associated with two vessels, one of which was sold during 2020; and

•an increase of $2 million due to higher compensation costs;

partially offset by

•a decrease of $16 million due to the sale of certain vessels during 2020 and 2019; and

•a decrease of $11 million due to lower charter hire expenses due to the redelivery of certain vessels to their owners during 2020 and 2019.

Adjusted EBITDA. Adjusted EBITDA decreased by $8 million for 2020, compared to 2019, primarily due to the decrease in revenues of $6 million, described above.

Depreciation and amortization. Depreciation and amortization expense decreased by $20 million for 2020, compared to 2019, primarily due to:

•a decrease of $35 million due to the sale or classification of vessels as held for sale during 2020 and 2019; and

•a decrease of $3 million due to the completion of depreciation on certain vessels and equipment as they reached the end of their estimated useful lives during 2020 and 2019;

partially offset by

• an increase of $18 million due to the deliveries of four of the shuttle tanker newbuildings during 2020.

Impairment expense, net. Impairment expense, net of $35 million for 2020 was related to a $17 million impairment recorded on the Navion Gothenburg as a result of a change in the expected operating plans of the vessel, an $8 million impairment recorded on the Navion Oslo due to the expected sale of the vessel, a $4 million impairment recorded on the Navion Bergen due to the expected sale of the vessel (which was sold during the third quarter of 2020), a $4 million impairment recorded on the Navion Stavanger as a result of a change in the expected earnings of the vessel, and a $3 million impairment recorded on the Navion Anglia due to the expected sale of the vessel.

Impairment expense, net of $15 million for 2019 was related to a $12 million impairment recorded on the Navion Gothenburg as a result of an assessment of significant repairs required to continue operations under its existing charter contract, a $2 million impairment recorded on the Navion Hispania due to the expected sale of the vessel and a $2 million impairment recorded on the Stena Sirita due to the expected sale of the vessel.

The average size of our owned shuttle tanker fleet decreased for 2020, compared to 2019, primarily due to the sales of the Navion Hispania and Stena Sirita in January 2020, the HiLoad DP unit in May 2020, the Navion Bergen in August 2020 and the Alexita Spirit and Nordic Spirit during 2019, partially offset by the deliveries of the Aurora Spirit, Rainbow Spirit, Tide Spirit and Current Spirit in January 2020, February 2020, July 2020 and August 2020, respectively. Three shuttle tanker newbuildings have been excluded from calendar-ship-days as these vessels were not yet delivered to us as at December 31, 2020.

The average size of our chartered-in fleet decreased for 2020, compared to 2019, primarily due to the redelivery of two vessel in November 2019 and September 2020, respectively.

FSO Segment

As at December 31, 2020, our FSO fleet consisted of four units that operate under fixed-rate time charters or fixed-rate bareboat charters, for which we have 100% ownership interests.

FSO units provide an on-site storage solution to oil field installations that have no oil storage facilities or that require supplemental storage. Our revenues and direct operating costs for the FSO segment are affected by fluctuations in currency exchange rates, as a significant component of revenues are earned and vessel operating expenses are incurred in NOK and Australian Dollars for certain vessels. The strengthening or weakening of the U.S. Dollar relative to the NOK or Australian Dollar may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

The following table presents certain of the FSO segment’s operating results for 2020 and 2019:


	Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)	2020	2019	% Change
Revenues	113,867	140,117	(18.7)
Direct operating costs	(51,018)	(43,234)	18.0
General and administrative(1)	(2,889)	(4,169)	(30.7)
Adjusted EBITDA attributable to non-controlling interests(2)	312	(500)	(162.4)
Adjusted EBITDA	60,272	92,214	(34.6)
Depreciation and amortization	(37,969)	(43,309)	(12.3)
Impairment expense, net	(53,775)	—	100.0
Gain (loss) on dispositions, net	5,380	11,213	(52.0)

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FSO segment based on estimated use of corporate resources).

(2)Adjusted EBITDA attributable to non-controlling interests represents the non-controlling interests' proportionate share of Adjusted EBITDA from our consolidated joint ventures.

Revenues. Revenues decreased by $26 million for 2020, compared to 2019, primarily due to:

•a decrease of $14 million due to lower charter rates under a contract extension for the Randgrid FSO unit during 2020; and

•a decrease of $12 million due to the completion of the Dampier Spirit FSO unit charter contract during 2020.

Direct operating costs. Direct operating costs increased by $8 million for 2020, compared to 2019, primarily due to the decommissioning of the Dampier Spirit FSO unit during 2020.

Adjusted EBITDA. Adjusted EBITDA decreased by $32 million for 2020, compared to 2019, primarily due to the decrease in revenues, as described above, and the increase in direct operating costs, as described above.

Depreciation and amortization. Depreciation and amortization decreased by $5 million for 2020, compared to 2019, primarily due to the Apollo Spirit FSO unit being fully depreciated during 2019 and certain components of the Randgrid FSO unit being fully depreciated during 2020.

Impairment expense, net. Impairment expense, net of $54 million for 2020 was related to impairments recorded on the Randgrid FSO unit, as a result of a change in the expected earnings of the unit, and on the Dampier Spirit FSO unit and Apollo Spirit FSO unit due to the expected sales of the vessels.

Gain (loss) on dispositions, net. Gain (loss) on dispositions, net was $5 million for 2020, due to the sale of the Apollo Spirit FSO unit in late-2020. Gain (loss) on dispositions, net was $11 million for 2019, due to the sale of the Pattani Spirit FSO unit after the completion of its bareboat charter in April 2019.

UMS Segment

As at December 31, 2020, our UMS fleet consisted of one unit, the Arendal Spirit UMS, in which we own a 100% interest.

The UMS is used primarily for offshore accommodation, storage and support for maintenance and modification projects on existing offshore installations, or during the installation and decommissioning of large floating exploration, production and storage units, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs. The UMS is available for world-wide operations, excluding operations within the Norwegian Continental Shelf, and includes a DP3 keeping system that is capable of operating in deep water and harsh weather. The Arendal Spirit is currently in lay-up.

The following table presents certain of the UMS segment’s operating results for 2020 and 2019:


	Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)	2020	2019	% Change
Revenues	1,828	2,940	(37.8)
Direct operating costs	(8,977)	(5,825)	54.1
General and administrative(1)	(397)	(1,567)	(74.7)

Adjusted EBTIDA	(7,546)	(4,452)	69.5
Depreciation and amortization	(2,328)	(3,415)	(31.8)
Impairment expense, net	—	(35,707)	(100.0)

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the UMS segment based on estimated use of corporate resources).

Revenues and Adjusted EBITDA. Revenues and Adjusted EBITDA decreased by $1 million and $3 million, respectively, for 2020, compared to 2019, primarily due to a $3 million insurance settlement received during the first quarter of 2019 relating to the gangway replacement of the Arendal Spirit in 2016.

Impairment expense, net. Impairment expense, net of $36 million for 2019 was related to impairments recorded on the Arendal Spirit UMS as a result of a change in the future redeployment assumptions of the unit.

Towage Segment

As at December 31, 2020, our towage fleet consisted of ten long-distance towage and offshore installation vessels. We own a 100% interest in each of the vessels in our towage fleet.

Long-distance towing and offshore installation vessels are used for the towage, station-keeping, installation and decommissioning of large floating objects, such as exploration, production and storage units, including FPSO units, FLNG units and floating drill rigs.

The following table presents certain of the towage segment’s operating results for 2020 and 2019:


	Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)	2020	2019	% Change
Revenues	45,991	74,726	(38.5)
Direct operating costs	(51,683)	(67,160)	(23.0)
General and administrative(1)	(1,593)	(2,328)	(31.6)
Adjusted EBITDA	(7,285)	5,238	239.1
Depreciation and amortization	(17,863)	(17,796)	0.4
Impairment expense, net	(22,903)	—	100.0

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the towage segment based on estimated use of corporate resources).

Revenues. Revenues decreased by $29 million for 2020, compared to 2019, primarily due to lower utilization and charter rates in the towage fleet as a result of decreased demand in the offshore market.

Direct operating costs and Adjusted EBITDA. Direct operating costs and Adjusted EBITDA decreased by $15 million and $13 million, respectively, for 2020, compared to 2019, primarily due to lower utilization of the towage fleet as described above.

Impairment expense, net. Impairment expense, net of $23 million for 2020 was related to impairments recorded on the ALP Forward, ALP Winger, ALP Ippon and ALP Ace towage vessels as a result of changes in the expected earnings of the vessels.

Conventional Tanker Segment

During March and April 2019, respectively, we redelivered our two in-chartered conventional tankers to their owners and ceased operations in this segment.

The following table presents certain of the conventional tanker segment’s operating results for 2020 and 2019:


	Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)	2020	2019	% Change
Revenues	—	7,972	(100.0)
Direct operating costs	—	(9,304)	(100.0)
General and administrative(1)	—	(104)	(100.0)
Adjusted EBITDA	—	(1,436)	(100.0)

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the conventional tanker segment based on estimated use of corporate resources).

Revenues and Adjusted EBITDA. Revenues decreased and adjusted EBITDA increased for 2020, compared to 2019, as a result of ceasing operations in the conventional segment during 2019.

Non-IFRS Financial Measures

To supplement the consolidated financial statements, we use EBITDA and Adjusted EBITDA, which are non-IFRS financial measures, as measures of our performance EBITDA represents net income (loss) before interest expense, interest income, income tax expense, and depreciation and amortization. Adjusted EBITDA is EBITDA adjusted to exclude certain items whose timing or amount cannot be reasonably estimated in advance or that are not considered representative of core operating performance. Such adjustments include impairment expenses, gain (loss) on dispositions, net, unrealized gain (loss) on derivative instruments, foreign currency exchange gain (loss) and certain other income or expenses. Adjusted EBITDA also excludes: realized gain or loss on interest rate swaps (as we, in assessing our performance, view these gains or losses as an element of interest expense); realized gain or loss on derivative instruments resulting from amendments or terminations of the underlying instruments; and equity-accounted income (loss). Adjusted EBITDA also includes our proportionate share of Adjusted EBITDA from our equity-accounted investments and excludes the non-controlling interests' proportionate share of Adjusted EBITDA. We do not have control over the operations of, nor

do we have any legal claim to the revenues and expenses of our equity-accounted investments. Consequently, the cash flow generated by our equity-accounted investments may not be available for use by us in the period that such cash flows are generated.

EBITDA and Adjusted EBITDA are intended to provide additional information and should not be considered as the sole measures of our performance or as a substitute for net income (loss) or other measures of performance prepared in accordance with IFRS. In addition, these measures do not have a standardized meaning and may not be comparable to similar measures presented by other companies. These non-IFRS measures are used by our management, and we believe that these supplementary metrics assist investors and other users of our financial reports in comparing our financial and operating performance across reporting periods and with other companies.

The following table reconciles EBITDA and Adjusted EBITDA to net loss for the years ended December 31, 2020 and 2019:


(in thousands of U.S. Dollars)	Year Ended December 31,
	2020	2019
Net income (loss)	(346,163)	(159,067)
Less:
Depreciation and amortization	(316,317)	(358,474)
Interest expense	(192,723)	(205,667)
Interest income	2,770	5,111
Income tax (expense) recovery
Current	(6,543)	(4,666)
Deferred	804	(3,161)
EBITDA	165,846	407,790
Less:
Equity-accounted income (loss)	35,921	33,768
Impairment expense, net	(268,612)	(187,680)
Gain (loss) on dispositions, net	3,411	12,548
Realized and unrealized gain (loss) on derivative instruments	(96,499)	(34,682)
Foreign currency exchange gain (loss)	(7,861)	2,193
Other income (expenses), net	(10,472)	(9,677)
Adjusted EBITDA attributable to non-controlling interests(2)	10,677	11,364
Add:
Realized gain (loss) on foreign currency forward contracts	(1,310)	(5,054)
Adjusted EBITDA from equity-accounted investments(1)	101,352	98,297
Adjusted EBITDA	599,323	673,199

(1)Adjusted EBITDA from equity-accounted investments, which is a non-IFRS financial measure and should not be considered as an alternative to equity-accounted income (loss) or any other measure of financial performance presented in accordance with IFRS, represents our proportionate share of Adjusted EBITDA (as defined above) from equity-accounted investments. This measure does not have a standardized meaning, and may not be comparable to similar measures presented by other companies. Adjusted EBITDA from equity-accounted investments is summarized in the table below:


	Year Ended December 31,
(in thousands of U.S. Dollars)	2020	2019
Equity-accounted income (loss)	35,921	33,768
Less:
Depreciation and amortization	(32,414)	(32,288)
Interest expense, net	(14,307)	(19,469)
Income tax (expense) recovery
Current	(317)	(250)

EBITDA	82,959	85,775
Less:
Realized and unrealized gain (loss) on derivative instruments	(15,484)	(12,527)
Foreign currency exchange gain (loss)	(2,909)	5
Adjusted EBITDA from equity-accounted vessels	101,352	98,297

(2)Adjusted EBITDA attributable to non-controlling interests, which is a non-IFRS financial measure and should not be considered as an alternative to net income (loss) attributable to non-controlling interests in subsidiaries or any other measure of financial performance presented in accordance with IFRS, represents the non-controlling interests' proportionate share of Adjusted EBITDA (as defined above) from our consolidated joint ventures. This measure does not have a standardized meaning, and may not be comparable to similar measures presented by other companies. Adjusted EBITDA attributable to non-controlling interests is summarized in the table below:


	Year Ended December 31,
(in thousands of U.S. Dollars)	2020	2019
Net income (loss) attributable to non-controlling interests in subsidiaries	(7,154)	(8,409)
Less:
Depreciation and amortization	(6,087)	(11,394)
Interest expense	(902)	(1,576)
Interest income	16	106
EBITDA	(181)	4,455
Less:
Impairment expense, net	(11,394)	(6,905)
Gain (loss) on dispositions, net	633	—
Foreign currency exchange gain (loss)	(97)	(4)
Adjusted EBITDA attributable to non-controlling interests	10,677	11,364

B. Liquidity and Capital Resources

Liquidity and Cash Needs

Liquidity and capital requirements are managed through cash flows from operations, use of credit facilities and refinancing existing debt. We aim to maintain sufficient financial liquidity to meet our ongoing operating requirements.

Our business model is to employ our vessels on fixed-rate contracts with oil companies, typically with terms between three and ten years. Our near-to-medium term business strategy is primarily to focus on extending contracts and redeploying existing assets on long-term charters, repaying or refinancing scheduled debt obligations and pursuing additional growth projects. Our operating cash flows prior to changes in non-cash working capital items relating to operating activities have remained relatively consistent, supported by a large and well-diversified portfolio of fee-based contracts, which primarily consist of medium-to-long-term contracts with high quality counterparties. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, we believe it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels.

Our primary liquidity needs for the next twelve months are to pay existing committed capital expenditures, to make scheduled repayments of borrowings and related interest rate swaps, to pay debt service costs, to make quarterly distributions on outstanding preferred units, to pay operating expenses and dry-docking expenditures, to fund general working capital requirements, to settle claims and potential claims against us and to manage our working capital deficit. Please refer to the contractual obligations table below for a summary of our contractual obligations as at December 31, 2020.

The following table presents our liquidity as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Cash and cash equivalents	235,734	199,388
Total liquidity(1)	235,734	304,388
Working capital surplus (deficit)	(230,494)	(105,855)

(1)Defined as cash, cash equivalents and undrawn revolving credit facilities

The working capital deficit of $230.5 million as at December 31, 2020, has significantly increased from $105.9 million as at December 31, 2019. The increase in the working capital deficit was primarily due to a $177.3 million increase in other financial liabilities, primarily due to certain interest rate swaps containing early-termination provisions, which, if exercised, would terminate these interest rate swaps during the 12 months ending December 31, 2021; partially offset by a $36.3 million increase in cash and cash equivalents.

Primarily as a result of the working capital deficit and committed capital expenditures, during the one-year period from December 31, 2020, we will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet our obligations and commitments and minimum liquidity requirements under our financial covenants in our credit facilities. Additional potential sources of financing that we are actively pursuing, or expect to pursue, during the one-year period include entering into new debt facilities, borrowing additional amounts under existing facilities, the refinancing or extension of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnerships business interests and/or capital raises. Based on our liquidity at the date of these financial statements, the liquidity we expect to generate from operations over the following year, and by incorporating our plans to raise additional liquidity that we consider probable of completion, we expect that we will have sufficient liquidity to meet our existing liquidity needs for at least the next 12 months. In February 2021, we entered into two unsecured revolving credit facilities with Brookfield, which provide for borrowings of up to $70.0 million and $30.0 million, respectively, and refinanced an existing term loan relating to the financing of the Petrojarl I FPSO unit, which provides for borrowings of $75.0 million. Additionally, in February 2021, we terminated or amended a total of four of our interest rate swaps that contained early-termination provisions, which, if exercised, would have terminated these interest rate swaps during the 12 months ending December 31, 2021. Refer to Item 18 – Financial Statements: Note 2b - Going concern for additional information.

As at December 31, 2020, our total future contractual obligations for three newbuildings under construction were estimated to be $248.5 million. As at December 31, 2020, gross payments made towards our seven newbuilding commitments were $720.7 million. We have secured $733.5 million of borrowings or long-term financing under sale and leaseback transactions relating to our shuttle tanker newbuildings.

As at December 31, 2020, we had total borrowings outstanding of $3,211 million compared to $3,229 million as at December 31, 2019. The borrowings consisted of the following:


	December 31, 2020	December 31, 2019
	$	$
U.S. Dollar Revolving Credit Facilities	439,600	513,200
U.S. Dollar Term Loans	1,426,370	1,399,309
U.S. Dollar Bonds	1,138,086	1,075,000
U.S. Dollar Non-Public Bonds	206,870	241,145
Total principal	3,210,926	3,228,654

The use of the credit facilities, term loans, bonds and finance leases is primarily related to ongoing operations and capital expenditures. Agreement for some of these borrowings and financings contain covenants, DSCR requirements and other restrictions typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from, among other things: incurring or guaranteeing indebtedness; changing ownership or structure, including mergers, consolidations, liquidations and dissolutions; paying dividends or distributions if we are in default or do not meet minimum DSCR requirements; making capital expenditures in excess of specified levels; making certain negative pledges and granting certain liens; selling, transferring, assigning or conveying assets; making certain loans and investments; or entering into a new line of business. Obligations under our credit facilities are secured by certain vessels, and if we are unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. Should we not meet these financial covenants or should we breach other covenants or DSCR requirements and not remedy the breach within an applicable cure period, if any, the lender may accelerate the repayment of the revolving credit facilities and term loans, thus having an impact on our short-term liquidity requirements and which may trigger cross-defaults or accelerations under other credit facilities. DSCR breaches can be remedied with cash cures by placing funds in escrow. As at December 31, 2020, we were in compliance with all covenants relating to our consolidated borrowings.

The table below outlines our consolidated net debt to capitalization as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Borrowings	3,170,977	3,184,512
Obligations relating to finance leases	139,239	21,544
Due to related parties	194,628	21,306
Less:
Cash and cash equivalents	235,734	199,388
Restricted cash	133,389	106,869
Net debt	3,135,721	2,921,105
Total equity	244,899	597,802
Total equity and net debt	3,380,620	3,518,907
Net debt to capitalization ratio	93%	83%

The increase in the net debt to capitalization ratio to 93% as at December 31, 2020 was mainly a result of an increase in related party borrowings under an unsecured revolving credit facility provided by Brookfield and the net loss of $346 million for the year ended December 31, 2020.

The COVID-19 pandemic could adversely impact our operations, our customers and our suppliers and has materially adversely affected the global economy, including the worldwide demand for crude oil and the level of demand for the types of services we offer. The pandemic may result in direct and indirect adverse effects on our industry and on our business, financial condition and operating results. Our business involves the ownership and operation of critical infrastructure assets in offshore oil regions and any significant decrease in demand for crude oil could adversely affect demand for our vessels and the types of services we offer. Our business model is to employ our vessels on fixed-rate contracts with oil companies, typically with terms between three and ten years, and therefore we do not expect any significant near-term impact on our liquidity, except for a decline in activity in the towage market. Additionally, we are actively pursuing additional steps to preserve liquidity and our financial flexibility, which includes the completion of the strategic and financing initiatives described above. However, a continuation of the pandemic may result in reduced cash flow and financial condition, including potential liquidity constraints and potential reduced access to capital as a result of any credit tightening generally or due to continued declines in global financial markets. Although disruption and effects from the COVID-19 pandemic may be temporary, a continued decrease in worldwide demand for crude oil and demand for the types of services we offer may adversely affect our business, financial condition and operating results, particularly in relation to voyage charters priced at spot market rates.

Cash Flows

The following table summarizes our sources and uses of cash for the periods presented:


	Year Ended December 31,
(in thousands of U.S. Dollars)	2020	2019
Net operating cash flow	282,319	350,882
Net financing cash flow	234,364	(71,101)
Net investing cash flow	(476,023)	(304,532)

Operating Cash Flows

Net cash flow from operating activities decreased to $282 million for 2020, compared to $351 million for 2019, primarily due to changes in non-cash working capital items which used $13 million of operating cash flows during 2020 compared to a contribution of $13 million during 2019. The decrease in non-cash working capital items for the year ended December 31, 2020, compared to last year is primarily due to the timing of payments made to vendors and settlements of balances with related parties, partially offset by the timing of payments received from customers.

Net cash flow from operating activities also decreased for 2020 compared to 2019, due to a decrease in revenues, an increase in direct operating costs and an increase in realized losses on interest rate swaps, partially offset by a decrease in general and administrative expenses and a decrease in interest paid. Refer to "Consolidated Results of Operations" above.

For a further discussion of changes in the consolidated statements of income (loss) items described above for our five reportable segments, please read “Results of Operations”.

Financing Cash Flows

We use our revolving credit facilities to finance capital expenditures and for general corporate purposes. Occasionally, we will do this until longer-term financing is obtained, at which time we typically use all or a portion of the proceeds from the longer-term financings to prepay outstanding amounts under the revolving credit facilities. Our proceeds from borrowings, net of financing costs, were $304 million in 2020 and $472 million in 2019.

Net proceeds from borrowings related to the sale and leaseback of vessels were $119 million and $22 million in 2020 and 2019, respectively. These proceeds were used to fund installment payments on the certain of the shuttle tanker newbuildings.

We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments of our borrowings were $329 million in 2020, compared to $410 million in 2019. The decrease in repayments is mainly due to repayments associated with the maturity of our NOK-denominated bonds, certain five-year senior unsecured bonds and one debt facility during 2019, partially offset by an increase in repayments due to $13 million of our $700.0 million five-year senior unsecured bonds repurchased during 2020 and a $12 million prepayment on one debt facility during 2020.

In March 2018, we entered into a credit agreement with Brookfield for an unsecured revolving credit facility, which as at December 31, 2020, provides for borrowings of up to $225 million. During 2020, we drew down $205 million related to this credit facility. During 2019, we prepaid $200 million and drew down $95 million related to this facility.

Lease payments on our vessel in-charter leases and office leases during 2020 and 2019 were $20 million and $15 million, respectively.

Cash distributions paid to our preferred unitholders and totaled $32 million in 2020 and $32 million in 2019. During 2020, we repurchased 311,381 of our outstanding preferred units for a cash payment of $6 million. Subsequent to December 31, 2020, aggregate cash distributions of $8 million for our Series A, Series B and Series E Preferred Units relating to the fourth quarter of 2020 were declared and were paid on February 16, 2021.

Investing Cash Flows

During 2020, net cash flow used for investing activities was $476 million, primarily due to $480 million of vessel and equipment additions, mainly relating to $369 million of installment payments for the shuttle tanker newbuildings, $63 million of additions relating to VOC equipment accounted for as finance leases and $41 million of drydocking expenditure and certain capital modifications, and a $27 million increase in restricted cash mainly relating to cash sweep requirements under an amended loan agreement, partially offset by $28 million from the sales of vessels and equipment and $6 million cash acquired relating the acquisition of one company.

During 2019, net cash flow used for investing activities was $305 million, primarily relating to $232 million of additions to our vessels and equipment, mainly relating to installment payments on our shuttle tanker newbuilding vessels, a $98 million increase in restricted cash mainly due to amounts held in escrow as at December 31, 2019 for a shuttle tanker newbuilding installment payment and an $8 million investment in one of our equity-accounted investments, partially offset by proceeds of $33 million from the sales of vessels and equipment.

Critical Accounting Estimates

The preparation of financial statements requires us to make estimates in the application of our accounting policies based on our best assumptions, judgments and opinions that affect 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 that are not readily apparent from other sources, during the reporting period. These estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with IFRS. However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates and such differences could be material. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

For a further description of our material accounting policies, critical judgements and estimates see Item 18 - Financial Statements: Note 2 - Significant Accounting Policies.

Determination of Control

Description. We consolidate an investee when we control the investee, with control existing if, and only if, we have (a) power over the investee, (b) exposure, or rights, to variable returns from involvement with the investee and (c) the ability to use that power over the investee to affect the amount of our returns.

Judgments and Uncertainties. In determining if we have power over an investee, judgments are made when identifying which activities of the investee are relevant in significantly affecting returns of the investee and the extent of existing rights that give us the current ability to direct the relevant activities of the investee. Judgments are required to assess our control over our non-wholly owned subsidiaries and investments in joint ventures. Judgments are made as to the amount of potential voting rights, the existence of contractual relationships that provide voting power and the ability for us to appoint directors. We enter into voting agreements which provide us the ability to contractually direct the relevant activities of the investee. In assessing if we have exposure, or rights, to variable returns from involvement with the investee, judgments are made concerning whether returns from an investee are variable and how variable those returns are on the basis of the substance of the arrangement, the size of those returns and the size of those returns relative to others, particularly in circumstances where our voting interest differs from the ownership interest in an investee. In determining if we have the ability to use our power over the investee to affect the amount of our returns, judgments are made when we are an investor as to whether we are a principal or agent and whether another entity with decision making rights is acting as our agent. If it is determined that we are acting as an agent, as opposed to a principal, we do not control the investee.

Effect if Actual Results Differ from Assumptions. A different assessment of power over an investee, exposure, or rights to variable returns from involvement with the investee or the ability to use our power over the investee to affect the amount of our returns could result in a determination of control, or not, and the resulting consolidation, or not, of an investee. We have concluded on the assessment of control over our investees based on our interpretation of the underlying agreements. There have been no historical changes in our assessment and we are not aware of any expected future changes, which would likely only result from an amendment of an existing agreement.

Impairment and Vessels and Equipment

Description. The carrying value of each of our vessels and equipment represents cost less accumulated depreciation and impairment losses. We depreciate the cost of our vessels and equipment, less an estimated residual value, on a straight-line basis over its expected useful life. The carrying values of our vessels and equipment may not represent their market value at any point in time because the market prices of second-hand vessels tend to fluctuate with changes in charter rates and the cost of newbuildings. Both charter rates and newbuilding costs tend to be cyclical in nature.

At each reporting date we assess whether there is any indication that assets or cash generating units, relating specifically to our vessels and equipment and right-of use-assets, are impaired. We review vessels and equipment for impairment whenever events or circumstances indicate the carrying value of an asset, including the carrying value of the charter contract, if any, under which the vessel is employed, may not be recoverable. This occurs when the asset’s recoverable amount, determined as the higher of the estimated fair value less costs of disposal or the value in use, is less than the carrying value of the asset or cash generating unit. For vessels and equipment operating under charter contracts, the estimated fair value less costs of disposal, which in cases where an active second-hand sale and purchase market does not exist, is the discounted cash flows from that vessel. In cases where an active second-hand sale and purchase market exists, an appraised value is used to estimate the fair value of the vessel and equipment. An appraised value is generally the amount we would expect to receive if we were to sell the vessel. Such appraisal is normally completed by us. The value in use is the present value of the future cash flows that the Partnership expects to derive from the asset or cash generating unit. If the recoverable amount of an asset exceeds the asset’s carrying value, no impairment is recognized. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail.

The following table presents by segment, certain vessels and equipment which, although their recoverable amount exceeds their carrying value as at December 31, 2020, we consider to be at a higher risk of future impairment.


(in thousands of U.S. Dollars, except number of vessels) Reportable Segment	Number of Vessels	Carrying Values $
FPSO Segment	4	314,330
Shuttle Tanker Segment	4	74,593
UMS Segment	1	59,774
Towage Segment	2	17,678

Judgments and Uncertainties. Depreciation on vessels and equipment is calculated on a straight-line basis so as to write-off the net cost of each asset over its expected useful life to its estimated residual value. Residual value of the vessel hull is estimated as the lightweight tonnage of each vessel multiplied by scrap value per ton. The estimated useful lives, residual values and depreciation methods are reviewed annually, with the effect of any changes recognized on a prospective basis. Certain of the Partnership's FPSO units and FSO units have undergone conversions or capital upgrades prior to commencing operations under their current contracts. The estimated useful lives of such vessels is generally substantially lower than that of a comparable newbuilding vessel. For a newbuilding FPSO unit, we use an estimated useful life of 20 to 25 years commencing the date

the unit arrives at the oil field and is in a condition that is ready to operate. Some of our FPSO units have oil field and contract specific equipment which is depreciated over the expected life of the oil field or contract. Shuttle tankers are depreciated using an estimated useful life of 20 years commencing the date the vessel is delivered from the shipyard. FSO units are depreciated over the estimated term of the contract, inclusive of extension options. UMS are depreciated over an estimated useful life of 35 years commencing the date the unit arrives at the oil field and is in a condition that is ready to operate. Towage vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. Dry docks and overhauls on our vessels are depreciated over an estimated useful life of two and a half to five years.

However, the actual life of a vessel may be different than the estimated useful life, with a shorter actual useful life potentially resulting in an impairment expense. The estimated useful life of our vessels takes into account design life, commercial considerations and regulatory restrictions. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail and include assumptions about future charter rates, vessel utilization, operating expenses, dry-docking expenditures, residual values or estimated sale proceeds and the remaining expected life of our vessels. Our estimated charter rates are based on rates under existing vessel contracts and market rates at which we expect we can re-charter our vessels. Our estimates of vessel utilization, including estimated off-hire time and the estimated amount of time our shuttle tankers may spend operating in the spot tanker market when not being used in their capacity as shuttle tankers, are based on historical experience and our projections of the number of future shuttle tanker voyages. Our estimates of direct operating costs and dry-docking expenditures are based on historical operating and dry-docking costs and our expectations of future inflation and operating requirements. Residual value of the vessel hull is estimated as the lightweight tonnage of each vessel multiplied by scrap value per ton. Estimated sale proceeds are based on second-hand sale and purchase market data, or, where applicable, offers made or received on the vessels. The remaining estimated lives of our vessels and equipment used in our estimates of future cash flows are consistent with those used in the calculation of depreciation.

Certain assumptions relating to our estimates of future cash flows are more predictable by their nature in our experience, including estimated revenue under existing contract terms, ongoing operating costs and remaining vessel life. Certain assumptions relating to our estimates of future cash flows require more discretion and are inherently less predictable, such as future charter rates beyond the firm period of existing contracts and vessel residual values or sale proceeds, due to factors such as the volatility in vessel charter rates and vessel values. We believe that the assumptions used to estimate future cash flows of our vessels are reasonable at the time they are made. We can make no assurances, however, as to whether our estimates of future cash flows, particularly future vessel charter rates or vessel values, will be accurate.

Effect if Actual Results Differ from Assumptions. An impairment is recognized if the recoverable amount, determined as the higher of the estimated fair value less costs of disposal or the value in use, is less than the carrying value of the asset or cash generating unit. The impairment loss recognized is an amount equal to the excess of the carrying value of the asset over its recoverable value at the date of impairment. The recoverable value of the vessel and equipment becomes the new lower cost basis for the asset and will result in a lower annual depreciation expense than for periods before the impairment was recognized. Any changes in the estimates used in determining residual values of vessels and equipment, estimated useful lives or the assumptions used relating to our projections of future cash flows may impact depreciation and amortization and/or impairment expense, net in our consolidated statements of income (loss).

Revenue Recognition

Description. Each charter may, depending on its terms, contain a lease component, a non-lease component or both. For those charters accounted for as an operating lease, revenues that are fixed on or prior to the commencement of the charter are recognized by us on a straight-line basis daily over the term of the charter. For a finance lease, the lease component of charter hire receipts is allocated to the lease receivable and revenues over the term of the lease using the effective interest rate method and the non-lease element is recognized by us on a straight-line basis daily over the term of the charter.

Judgments and Uncertainties. At the inception of the charter, the classification of the lease as an operating lease or a finance lease may involve the use of judgment as to the determination of the lease term. Such judgment is required as the duration of certain of our charters is unknown at commencement of the charter. The charterer may have the option to extend the charter or terminate the charter early. In addition, certain charters impose penalties on the charterer if they terminate the charter early and such penalties can vary in size depending on when, during the term of the charter, the termination right is exercised. Such penalties could impact the determination of the lease term and requires the use of judgment. When judgment is required as to the determination of the lease term, we usually use a weighted average assessment utilizing probabilities assigned to different lease terms based on varying factors such as expected oil field life, preliminary indications from customers and our own estimates. Once an initial assessment is made, the lease term is only adjusted when new information is available, such as a contract modification. Any future contract modifications may impact the lease term and the classification of the lease. We are currently not aware of any future contract modifications, however, such transactions are inherent in our business.

Effect if Actual Results Differ from Assumptions. A different assessment of the lease term could result in an operating lease being classified as a finance lease or a finance lease being classified as an operating lease. A change in the lease classification would result in different method of revenue recognition being applied to the lease component of the charter. In addition, if we conclude that a determination of the lease term results in the inclusion of termination penalties in the minimum lease payments under the charter, this is recognized as revenue over the lease term. Conversely, a different assessment of the lease term may result in termination penalties being excluded from the minimum lease payments and thus not recognized over the lease term.

Decommissioning Liabilities

Description. We have a decommissioning liability related to the requirement to remove the sub-sea mooring and riser system associated with the Randgrid FSO unit and to restore the environment surrounding the facility. The costs associated with this decommissioning liability are to be reimbursed by the charterer, if certain conditions associated with the work are met. The obligation is expected to be settled at the end of the contract under which the FSO unit currently operates.

Judgments and Uncertainties. We recognize a decommissioning liability in the period in which we have a present legal or constructive liability and a reasonable estimate of the amount can be made. Liabilities are measured based on current requirements, technology and price levels and the present value is calculated using amounts discounted over the period for which the cash flows are expected to occur. Amounts are discounted using

a rate that reflects the risks specific to the liability. On a periodic basis, management reviews these estimates and changes, if any, will be applied prospectively. The estimated decommissioning liability is recorded as a non-current liability, with a corresponding increase in the carrying amount of the related asset. As the decommissioning liability will be covered by contractual payments to be received from the charterer, we have recognized a separate receivable. The liability and associated receivable are increased in each reporting period due to the passage of time, and the amount of accretion is charged to Other income (expense), net in the period.

Effect if Actual Results Differ from Assumptions. Periodic revisions to the estimated timing of cash flows, to the original estimated undiscounted cost and to changes in the discount rate can result in an increase or decrease to the decommissioning liability and associated receivable. Actual costs incurred upon settlement of the obligation are recorded against the decommissioning liability to the extent of the liability recorded.

Taxes

Description. Deferred income tax assets are recognized for all deductible temporary differences, carry forward of unused tax credits and unused tax losses, to the extent that it is probable that deductions, tax credits and tax losses can be utilized

Judgments and Uncertainties. The future realization of deferred tax assets depends on the existence of sufficient taxable income to utilize tax losses. This analysis requires, among other things, the use of estimates and projections in determining future reversals of temporary differences, forecasts of future profitability and evaluating potential tax-planning strategies.

Effect if Actual Results Differ from Assumptions. If we determined that it was probable that we were able to realize a deferred tax asset in the future, in excess of the recorded amount, an adjustment to the deferred tax assets would typically increase our net income (or decrease our loss) in the period such determination was made. Likewise, if we determined that it was probable we were not able to realize all or a part of our deferred tax asset in the future, an adjustment to the deferred tax assets would typically decrease our net income (or increase our loss) in the period such determination was made.

C.Research and Development, Patents and Licenses, etc.

Not applicable.

D.Trend Information

Refer to Item 5.A.- Operating Results.

E.Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

F.Tabular Disclosure of Contractual Obligations

In the ordinary course of business, we enter into contractual arrangements that may require future cash payments. The table below outlines our contractual obligations as at December 31, 2020:


	Payments as at December 31, 2020
	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter

	(in millions of U.S. Dollars)

Bond repayments(1)	1,138.1	—	251.1	687.0	200.0	—	—
Secured debt - scheduled repayments(1)	1,279.0	294.2	231.6	207.9	160.1	124.9	260.3
Secured debt - repayments on maturity(1)	793.8	69.0	70.5	274.6	182.0	—	197.7
Unsecured revolving credit facility - due to related parties(1)	229.0	—	—	—	229.0	—	—
Obligations related to finance leases(1)	141.6	7.9	7.5	7.5	7.5	7.5	103.7
Interest rate swaps(2)	203.6	189.6	14.0	—	—	—	—
Foreign currency forward contracts(2)	54.1	54.1	—	—	—	—	—
Lease liabilities(3)	38.9	15.4	14.2	2.7	2.5	2.0	2.1
Newbuilding contracts(4)	248.5	175.5	73.0	—	—	—	—
Total	4,126.6	805.7	661.9	1,179.7	781.1	134.4	563.8

(1)Our interest-bearing obligations include bonds, commercial bank debt, an unsecured revolving credit facility provided by Brookfield and obligations related to finance leases. Refer to Item 18 – Financial Statements: Note 20 – Borrowings, Item 18 – Financial Statements: Note 22 – Related Party Transactions and Item 18 – Financial Statements: Note 12 – Advances on Newbuilding Contracts for terms upon which future interest payments are determined.

(2)Refer to Item 18 – Financial Statements: Note 19 – Other Financial Liabilities for a summary of the terms of our derivative instruments which economically hedge certain of our floating rate interest-bearing obligations.

(3)Consists of the undiscounted contractual maturities of our lease liabilities. Refer to Item 18 – Financial Statements: Note 10 – Right-of-use Assets and Lease Liabilities.

(4)Consists of the estimated remaining payments for the acquisition of three shuttle tanker newbuildings. Refer to Item 18 – Financial Statements: Note 12 – Advances on Newbuilding Contracts.

G.Safe Harbor

See the first section of "Part I" above which contains our forward-looking statements.

Item 6.Directors, Senior Management and Employees

A.Directors and Senior Management

Governance

Our limited partnership agreement provides for the management and control of our Partnership by a general partner. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are expressly non-recourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are non-recourse to it.

The general partner has a board of directors. The general partner has sole responsibility and authority for the central management and control of our Partnership, which is exercised through its board of directors. Accordingly, references herein to “our directors” and “our board” refer to the board of directors of the general partner.

Because certain directors of our general partner are also directors and/or officers of Brookfield or other affiliates thereof, such directors have fiduciary duties to Brookfield or such other affiliates that may cause them to pursue business strategies that disproportionately benefit Brookfield or such other affiliates or which otherwise are not in our best interests.

Directors of Altera Infrastructure GP L.L.C

The following table presents certain information concerning our board of directors. Ages of the directors and officers are as of December 31, 2020.

Name

Age

Position

Benedicte Bakke Agerup

Director (1)

Ian Craig

Director (2)

Craig Laurie

Director (3)

Gregory Morrison

Director (4)

Jim Reid

Director (5)

Nelson Silva

Director (6)

Ingvild Sæther

Director and President & Chief Executive Officer, Altera Infrastructure Group Ltd. (7)

William L. Transier

Director (8)

Denis Turcotte

Director (9)

Bill Utt

Chairman of the board of directors (10)

(1)Member of the Audit Committee and Conflicts Committee.

(2)Member of the Audit Committee, Project & Opportunity Review Committee (Chair) and Conflicts Committee (Chair).

(3)Member of the Corporate Governance Committee.

(4)Member of the Corporate Governance Committee.

(5)Observer to the Audit Committee and member of Project & Opportunity Review Committee.

(6)Member of the Audit Committee and Conflicts Committee.

(7)Member of the Executive Oversight Committee.

(8)Member of the Audit Committee (Chair).

(9)Member of the Corporate Governance Committee and Executive Oversight Committee (Chair).

(10)Chair of the Corporate Governance Committee and member of Project & Opportunity Review Committee, Audit Committee and Executive Oversight Committee.

Certain biographical information about each of these individuals is set forth below.

Benedicte Bakke Agerup was appointed as a director of our general partner in December 2020. Ms. Agerup brings more than 30 years of experience from the finance and maritime industry to the board of directors. From 2010 to 2017 Ms. Agerup served as Chief Financial Officer of Wilhelmsen ASA, a global provider of maritime and logistics services. Ms. Agerup has previously served as deputy chair of the Norwegian Hull Club as well as on the board of a number of other listed and unlisted companies within the finance and maritime sector and has been a member of a

variety of audit and risk committees. Ms. Agerup currently sits on the board of directors of Treasure ASA. Ms. Agerup holds a degree in Economics and Business Administration from the Norwegian School of Economics and studied an advanced management program at Harvard Business School.

Ian Craig was appointed as a director of our general partner in June 2017. Mr. Craig has served in various executive positions in Shell, most recently in Nigeria where he was an Executive Vice President for Sub Saharan Africa and in Russia where he was Chief Executive Officer of Sakhalin Energy, an incorporated joint venture of Gazprom, Shell, Mitsui and Mitsubishi. Prior to that, Mr. Craig was a board member and Technical Director of Enterprise Oil plc until its acquisition by Shell in 2002. Mr. Craig had earlier held executive management positions with other oil exploration and production companies including Sun Oil and BP. Since retiring in 2013, Mr. Craig has also previously served as a non-executive director of Petroceltic plc, as a Special Advisor to OMV’s supervisory board, and he currently serves as an advisor to KAZ Minerals plc.

Craig Laurie was appointed as a director of our general partner in September 2018. Mr. Laurie is a Managing Partner in Brookfield’s Private Equity Group overseeing Capital Markets, Finance and Planning. Mr. Laurie joined Brookfield in 1997 and has held a number of senior finance positions across the organization, including Chief Financial Officer of Brookfield Business Partners. Prior to joining Brookfield, Mr. Laurie worked in restructuring and advisory services at Deloitte. Mr. Laurie is a Chartered Professional Accountant and holds a Bachelor of Commerce from Queen’s University.

Gregory Morrison was appointed as a director of our general partner in July 2019. Mr. Morrison is currently a director of Brookfield Bermuda Limited. Mr. Morrison has more than 35 years of experience in the insurance and reinsurance industries. He served as Chief Executive Officer of Trisura Group Ltd. (TSX:TSU) and Platinum Underwriters Holdings Ltd., previously traded on the NYSE, both multi-line insurance and reinsurance companies. Mr. Morrison also served as Chief Executive Officer of London Reinsurance Group Inc. and Imagine Group Holdings Ltd, reinsurers in the life and property casualty markets. Mr. Morrison currently sits on the board of directors of a number of companies, including Trisura Group Ltd., Aetna Life & Casualty (Bermuda) Limited, Stonybrook Capital LLC, Aspen Bermuda Limited, Multi-Strat Holdings and various international subsidiaries of Brookfield Asset Management. Mr. Morrison is a Fellow of the Society of Actuaries (retired) and is an active member of various audit and risk committees.

Jim Reid was appointed as a director of our general partner in September 2017. Mr. Reid is a Managing Partner and a Chief Investment Officer in Brookfield’s Private Equity Group. Mr. Reid is responsible for originating, evaluating and structuring investments and financings in the energy sector, and for overseeing operations in Brookfield’s energy segment. He established Brookfield’s Calgary office in 2003 after spending several years as a Chief Financial Officer for two oil and gas exploration and production companies in Western Canada. Mr. Reid obtained his Chartered Professional Accountant designation at PricewaterhouseCoopers in Toronto and holds a Bachelor of Arts in Commerce from the University of Toronto.

Nelson Silva was appointed as a director of our general partner in March 2020. Mr Silva has had a 43-year career in leadership roles in energy and natural resources companies, including Petrobras, BG Group, BHP Billiton and Vale. From June 2016 to December 2018, Mr. Silva served as Chief Strategy and Performance Officer and member of the Executive Team of Petrobras. Prior to Petrobras, Mr. Silva served as the Chief Executive Officer of BG Group in South America for seven years. Mr. Silva was also previously President of the Aluminum business unit and Marketing Director of Carbon Steel Materials of BHP Billiton and Marketing Director of Vale.

Ingvild Sæther was appointed as a director of our general partner in December 2020. Ms. Sæther is the President and Chief Executive Officer of Altera Infrastructure Group Ltd. Please refer to the biographical information included in "Our Management" below.

William L. Transier was appointed as a director of our general partner in March 2019. Mr. Transier is the co-founder and Chief Executive Officer of Transier Advisors, LLC, an independent advisory firm. Mr. Transier also serves as the chairman of the board of directors of Helix Energy Solutions Group, Inc since July 2017, and Battalion Oil Corporation since October 2019. In April 2020, Mr. Transier was elected to the board of directors of Exela Technologies, Inc. where he serves as chairman of the audit committee and member of the special transactions committee. Mr. Transier has also served on the boards of directors of Sears Holding Corporation from October 2018 to October 2019, Gastar Exploration Inc. from August 2018 to February 2019, CHC Group Ltd. from 2016 to July 2017, Paragon Offshore Plc. from 2014 to July 2017 and Cal Dive International, Inc. Mr. Transier was the co-founder of Endeavour International Corporation, an international oil and gas exploration and production company. He served as non-executive Chairman of Endeavour’s board of directors from 2014 until 2015, as Chairman, Chief Executive Officer and President of Endeavor from 2006 to 2014 and as co-Chief Executive Officer from formation in 2004 through 2006. Mr. Transier also served as Executive Vice President and Chief Financial Officer of Ocean Energy, Inc. and it’s predecessor company, Seagull Energy Corporation, from 1996 to 2003. Before his tenure with Ocean Energy, Mr. Transier served in various roles, including partner, in the audit department and head of the Global Energy practice of KPMG LLP. Mr. Transier has a BBA degree from the University of Texas, MBA from Regis University, and MA in Theological Studies from Dallas Baptist University and is a Certified Public Accountant.

Denis Turcotte was appointed as a director of our general partner in September 2018. Mr. Turcotte is a Managing Partner in Brookfield’s Private Equity Group, responsible for business operations. Mr. Turcotte joined Brookfield’s Private Equity Group in 2017, prior to which he served as a member of the Brookfield Private Equity Advisory Board for ten years and as a member of the Brookfield Business Partners’ Board of Directors from 2016 until 2017. Prior to joining Brookfield, Mr. Turcotte held several roles, including Principal with North Channel Management and Capital Partners, Chief Executive Officer of Algoma Steel, President of the Paper Group and Executive Vice President Corporate Development and Planning with Tembec. Mr. Turcotte holds a Bachelor of Engineering from Lakehead University and an MBA from the University of Western Ontario.

Bill Utt was appointed as chairman and director of our general partner in June 2017. Mr. Utt brings over 33 years of engineering and energy industry experience to the board of directors. From 2006 until his retirement in 2014, he served as chairman, President and Chief Executive Officer of KBR Inc., a global engineering, construction and services company. From 1995 to 2006, Mr. Utt served as the President and Chief Executive Officer of SUEZ Energy North America and President and Chief Executive Officer of Tractebel’s North American energy businesses. Prior to 1995 he held senior management positions with CRSS, Inc., which was a developer and operator of independent power and industrial energy facilities prior to its merger with Tractebel in 1995. Mr. Utt also currently serves as a member of the board of directors for BrandSafway Industrial Services, a Clayton, Dubilier & Rice, LLC and Brookfield Asset Management portfolio company. Mr. Utt served as a director and chairman of Teekay Corporation (NYSE: TK) from 2015 to 2017 and as director of Teekay GP L.L.C., the general partner of Teekay LNG Partners L.P (NYSE:TGP) from

2017 to 2018. Mr. Utt also served on the board of directors for Cobalt International Energy (NYSE: CIE) from 2012 to 2018 and as the chairman from 2016 to 2018.

Our Management

In February 2017, the Partnership and its wholly-owned subsidiary, Altera Infrastructure Holdings L.L.C. (or Holdco), entered into a services agreement with Altera Infrastructure Group Ltd. (or the Service Provider, formerly known as Teekay Offshore Group Ltd.), a subsidiary of Holdco. Pursuant to the service agreement, the Service Provider provides certain services to us. The following table presents certain information regarding the senior management team that is principally responsible for our operations and their positions with the Service Provider as at December 31, 2020:

Name

Age

Position

Ingvild Sæther

President and Chief Executive Officer, Altera Infrastructure Group Ltd.

Jan Rune Steinsland

Chief Financial Officer, Altera Infrastructure Group Ltd.

Duncan Donaldson

General Counsel, Altera Infrastructure Group Ltd.

Ingvild Sæther was appointed President and Chief Executive Officer of Altera Infrastructure Group Ltd., a company that provides services to us, in February 2017. In December 2020, she joined the board of directors of our general partner. Ms. Sæther joined Teekay Corporation in 2002, as a result of Teekay’s acquisition of Navion AS from Statoil ASA. Ms. Sæther held management positions in Teekay’s conventional tanker business until 2007, when she assumed the commercial responsibility for Teekay’s shuttle tanker activities in the North Sea, and in 2011, Ms. Sæther assumed the position of President, Teekay Offshore Logistics. Ms. Sæther has over 25 years of experience in the shipping and offshore sector and has been engaged in a number of boards and associations related to the industry.

Jan Rune Steinsland was appointed Chief Financial Officer of Altera Infrastructure Group Ltd. in September 2018. Mr. Steinsland joined us from drilling contractor Songa Offshore SE where he served as Chief Financial Officer from 2013 to 2018. Mr. Steinsland brings 30 years of energy and offshore industry experience. Previous assignments of Mr. Steinsland’s include serving as Chief Financial Officer at drilling contractor Ocean Rig and the financial group Acta Holding, as well as serving in several management positions at ExxonMobil. Mr. Steinsland has a Lic. Oec. degree from the University of St. Gallen, Switzerland and is a Certified European Financial Analyst (CEFA).

Duncan Donaldson was appointed General Counsel of Altera Infrastructure Group Ltd. in February 2018. Mr. Donaldson is a United Kingdom national and has been a qualified lawyer in England and Wales since 2005. Throughout his career, Mr. Donaldson has specialized in the Energy, Transportation and Infrastructure sectors, first in private practice with Linklaters LLP in London and subsequently in a variety of legal roles within the offshore business units of the A.P. Moller-Maersk Group. Most recently Mr. Donaldson served for three years as Chief Legal Counsel, North and South America for Maersk Drilling based in Houston, during which time he was also registered as a Foreign Legal Consultant with the State Bar of Texas. Mr. Donaldson has a BA (Hons) degree from Cambridge University and completed his post-graduate legal education at Nottingham Law School.

B.Compensation

Executive Compensation

Refer to Item 18. - Financial Statements: Note 22 - Related Party Transactions.

Compensation of Directors

Each of our independent directors receives compensation for attending meetings of the board of directors, as well as committee meetings. Each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under the law of the Republic of the Marshall Islands. During 2020, the compensation for our directors was as follows:

Board of directors

Each independent director, other than the Chair, received a director fee of $140,000 per annum. The Chair received a director fee of $140,000 per annum and an additional fee of $60,000 per annum.

Audit Committee

Independent members of the Audit Committee each received an additional committee fee of $10,000 per annum and the independent chair of the Audit Committee received an additional fee of $20,000 per annum.

Conflicts Committee

Independent members of the Conflicts Committee each received an additional committee fee of $7,500 per annum and the independent chair of the Conflicts Committee received an additional fee of $12,500 per annum. Additionally, all independent members are paid an additional $1,500 per meeting if the committee is required to meet more than 12 times per annum.

Corporate Governance Committee

Independent members of the Corporate Governance Committee each received an additional committee fee of $7,500 per annum and the independent chair of the Corporate Governance Committee received an additional fee of $12,500 per annum.

Project & Opportunity Review Committee

The independent chair of the Project & Opportunity Review Committee received an additional fee of $5,000 per annum.

Executive Oversight Committee

No compensation was provided to the members of the Executive Oversight Committee.

Long-Term Incentive Plans

2006 Long-Term Incentive Plan

Our general partner adopted the Altera Infrastructure L.P. 2006 Long-Term Incentive Plan for employees and directors of and consultants to our general partner and to its affiliates who perform services for us. The plan provided for the award of restricted units, phantom units, unit options, unit appreciation rights and other unit or cash-based awards. There were no awards made under the 2006 Long-Term Incentive Plan during 2020 and no future awards under the plan are contemplated.

Executive Long-Term Incentive Plan

During May 2020, the general partner adopted an Executive Long-Term Incentive Plan to attract and retain senior management personnel, to incentivize decision-making with a long-term view and to motivate and influence behavior that is consistent with maximizing value for unitholders in a prudent manner. Plan participants may be granted annual awards that generally vest on the first anniversary of the grant date based on continuous service. The awards provide the opportunity to participate in a profit pool determined by the extent, if any, to which liquidity arising from the occurrence of certain change of control events exceeds a specified threshold. Upon adoption of the Executive Long-Term Incentive Plan, outstanding phantom option unit awards granted under the 2006 Long-Term Incentive Plan were cancelled and replaced with awards under the new plan that vest over a five-year period.

C.Board Practices

Board Structure, Practices and Committees

The board of directors oversees the general partner's management and our business. The day-to-day affairs of our business are managed by key employees of our operating subsidiaries.

Size, independence and composition of the board of directors

Pursuant to the general partner’s operating agreement, the board of directors may, from time to time, establish the size of the board of directors, provided the size of the board of directors may not be fewer than five directors or greater than fifteen directors. As at December 31, 2020, the board of directors consisted of ten directors.

Election and removal of directors

The general partner's operating agreement authorizes the general partner’s members to appoint, remove and replace the directors on the board of directors and to fill any vacancies arising, subject to the terms and conditions of the operating agreement. Common units do not entitle the holders thereof to vote to elect the directors of the general partner. Directors are appointed to serve until their successors are appointed or until they resign or are removed.

Service contracts

There are no service contracts between us and any of our directors providing for benefits upon termination of their employment or service.

Audit Committee

The Audit Committee of our general partner is composed of three or more directors, each of whom must meet the independence standards of the NYSE, the SEC and any other applicable laws and regulations governing independence from time to time. This committee is currently comprised of directors William L. Transier (Chair), Bill Utt, Nelson Silva, Ian Craig and Benedicte Bakke Agerup, all independent directors. Jim Reid is an observer to the committee. All members of the committee are financially literate and the board of directors has determined that Mr. Transier qualifies as an audit committee financial expert.

The Audit Committee assists the board of directors in fulfilling its responsibilities for general oversight of:

•the integrity of our financial statements;

•our compliance with legal and regulatory requirements;

•the qualifications and independence of our independent auditor; and

•the performance of our internal audit function and our independent auditor.

Conflicts Committee

The Conflicts Committee of our general partner is to be composed of at least two directors and is currently comprised of Ian Craig (Chair), Benedicte Bakke Agerup and Nelson Silva. The members of the Conflicts Committee must not be officers or employees of our general partner or directors, officers or employees of the general partner's affiliates, and must meet the director independence standards of the NYSE and SEC applicable to audit committee membership and certain other requirements.

The Conflicts Committee:

•reviews specific matters that the board of directors believes may involve conflicts of interest; and

•determines if the resolution of the conflict of interest is fair and reasonable to us.

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 general partner of any duties it may owe us or our unitholders. The board of directors is not obligated to seek approval of the Conflicts Committee on any matter, and may determine the resolution of any conflict of interest itself.

Corporate Governance Committee

The Corporate Governance Committee of our general partner is composed of at least two directors. This committee is currently comprised of directors Bill Utt (Chair), Denis Turcotte, Gregory Morrison and Craig Laurie.

The Corporate Governance Committee:

•oversees the operation and effectiveness of the board of directors and its corporate governance; and

•develops, updates and recommends to the board of directors, corporate governance principles and policies applicable to us and our general partner and monitors compliance with these principles and policies.

Project & Opportunity Review Committee

The Project & Opportunity Review Committee of our general partner is composed of at least two directors. This committee is currently comprised of directors Ian G. Craig (Chair), Jim Reid and Bill Utt.

The Project & Opportunity Review Committee:

•reviews capital projects and other commercial opportunities proposed by management that require the board of director's approval; and

•makes recommendations to assist management in ensuring that all fundamental technical, cost, performance, operations, financial and risk aspects of the proposal have been sufficiently addressed prior to presentation to the board of directors for approval and the appropriate trade-offs and balance of costs, risks, and returns have been achieved.

Executive Oversight Committee

The Executive Oversight Committee of our general partner is composed of three directors. This committee is currently comprised of directors Denis Turcotte (Chair), Bill Utt and Ingvild Sæther.

The Executive Oversight Committee may exercise all the powers of the board of directors in the management of our business and affairs, for us and as our general partner, between quarterly, scheduled meetings of the board of directors, except with respect to matters specifically reserved for another committee of the board of directors or matters which have been determined to be non-routine.

The committee charters are available under “Investors – Governance” from the home page of our web site at www.alterainfra.com.

D.Employees

Crewing and Staff

As at December 31, 2020, approximately 1,700 seagoing employees served on our vessels, compared to approximately 1,900 as of December 31, 2019 and approximately 2,000 as of December 31, 2018. As at December 31, 2020, our subsidiaries employed approximately 550 staff who served on shore in technical, commercial and administrative roles in various countries compared to approximately 450 staff as at December 31, 2019 and approximately 400 staff as at December 31, 2018. The increase in onshore employees is a result of in sourcing corporate support services previously provided by Teekay Corporation. We also have an insignificant number of temporary employees serving on our vessels.

Collective Bargaining Agreements

Substantially all officers and seamen for the Norway-flagged vessels are covered by a collective bargaining agreement with Norwegian unions (Norwegian Maritime Officers’ Association, Norwegian Union of Marine Engineers and the Norwegian Seafarers’ Union). We have entered into a Collective Bargaining Agreement with Norwegian offshore unions (SAFE, Industry Energi and DSO), through its membership in Norwegian Shipowners Association (or NSA), and NSA (NOR agreement) which covers substantially all of the offshore employees on board our vessels on the Norwegian Continental Shelf.

We have entered into a Collective Bargaining Agreement with Sindicato dos Trabalhadores Offshore do Brasil (or SINDITOB) and Unified Trade Union of Oil, Petrochemical and Plastic Workers of the States of Alagoas and Sergipel (or Sindipetro-AI), which collectively covers substantially all Brazilian resident offshore employees on board our FPSO units operating in Brazil.

We have entered into a Collective Bargaining Agreement with the Fish, Food and Allied Workers Union of Newfoundland and Labrador and the Canadian Merchant Service Guild in Canada. The agreement covers substantially all of the offshore employees on board our shuttle tankers operating in the East Coast of Canada.

We have entered into a Collective Bargaining Agreement with Unite the Union, which covers substantially all of the offshore employees on board our FPSO units operating in the United Kingdom.

We believe our relationships with these local labor unions are good, with long-term collective bargaining agreements which demonstrate commitment from both parties.

Human Capital Measures

We have certain programs and initiatives aimed at developing and retaining our employees. All of our employees are required to participate in annual accountability plans and performance reviews. The accountability plan involves establishing annual goals and priorities, mainly intended to focus on the development and training of employee's, and is assessed as part of the employees annual performance review. Additionally, we have implemented a talent review program to ensure that, annually, talent is identified and appropriate resources are allocated to assist in the development and retention of the identified employees.

To supplement the programs and initiatives described above, we have developed, or are in the process of developing, organizational-wide policies as described below:

•A compensation and benefits policy, which includes processes to benchmark our employees' compensation and benefits against relevant markets and industries, to ensure our employees are compensated competitively and fairly;

•A recruitment policy which establishes the requirements for recruiting for open positions and ensures that we are equitably selecting candidates; and

•A training and development policy is currently being developed and aims at offering both internal and external training, as well as focusing on personal development.

We are also developing an Accountability Leadership framework which aims at creating clear roles and accountabilities, clarity on decision making and defining an optimal organizational structure.

Our commitment to training is fundamental to the development of our seafarers for marine operations. Our cadet training is designed to balance academic learning with hands-on training at sea. We have relationships with training institutions in Canada, Norway, Brazil and the United Kingdom. After receiving formal training at one of these institutions, cadet training continues on-board vessels and through our Quality Assurance and Training Officers program. All certifications and trainings completed by our seafarers are stored centrally. We also have a career development plan that was implemented to ensure a continuous flow of qualified officers are trained on our vessels and familiarized with our operational standards, systems and policies, which also forms the basis for promotion. We aim to promote internally where possible.

E.Unit Ownership

As at December 31, 2020, the current directors of our board of directors, as a group, beneficially own, directly or indirectly, or exercise control and direction over, our units representing in the aggregate less than 1% of our issued and outstanding units on a fully exchanged basis. As at December 31, 2020, senior management of the Service Provider, as a group, beneficially own, directly or indirectly, or exercise control and direction over, none of our issued and outstanding units on a fully exchanged basis.

Item 7.Major Unitholders and Related Party Transactions

A.Major Unitholders

The following table sets forth the beneficial ownership, as at the date of this Annual Report, of our common units by each person that beneficially owns more than 5% of the outstanding common units. Unless otherwise indicated, each unitholder listed below has sole voting and investment power with respect to the common units set forth in the following table. Our Class A common units are economically equivalent to the Class B common units held by Brookfield following the Merger, but have limited voting rights and limited transferability.


Identity of Person or Group	Class B Common Units	Percent of Class B Common Units Owned	Class A Common Units	Percent of Class A Common Units Owned	Percent of Total Class A and Class B Common Units Owned
Brookfield (1)	405,931,898	100%	—	—%	98.7%

____________________________

(1)Excludes the general partner interest held by our general partner, a 100%-owned subsidiary of Brookfield.

As at the date of this Annual Report, affiliates of Brookfield directly control the Partnership through its 100% interest in our general partner.

B.Certain Relationships and Related Party Transactions

Certain Relationships

As of the date of this Annual Report, Brookfield holds a 100% ownership interest in our general partner and 100% of our outstanding Class B common units, which represent 98.7% of our combined outstanding Class A and Class B common units.

Craig Laurie, Gregory Morrison, Jim Reid and Denis Turcotte are directors of our general partner. Messrs. Laurie and Turcotte are Managing Partners in Brookfield's Private Equity Group, Mr. Reid is a Managing Partner and Chief Investment Officer in Brookfield's Private Equity Group. Mr. Morrison is a director of Brookfield Bermuda Limited and various international subsidiaries of Brookfield Asset Management.

William L. Transier is a director of our general partner and has served as a director of Westinghouse Electric Company, a wholly-owned subsidiary of Brookfield, since 2017.

Bill Utt is a director and chairman of our general partner and a director of BrandSafway, part of the Clayton, Dubilier & Rice, LLC and Brookfield Asset Management portfolio. Brookfield Asset Management owns a 48% interest in BrandSafway.

Transactions with Brookfield

a.2020 Merger with Brookfield

On January 22, 2020, Brookfield completed its acquisition by merger of all of the outstanding publicly held and listed common units representing our limited partner interests held by unaffiliated unitholders pursuant to the Merger Agreement among us, our general partner and certain members of Brookfield. As a result of the Merger, Brookfield owns 100% of our Class B common units, representing approximately 98.7% of our outstanding common units. All of the Class A common units, representing approximately 1.3% of our outstanding common units as of the closing of the Merger, are held by the unaffiliated unitholders who elected to receive the equity consideration rather than cash in respect of their common units in the Merger.

In connection with the Merger, the incentive distribution rights held by our general partner and all of our outstanding warrants to purchase common units were canceled and ceased to exist, with no consideration being delivered to the holders thereof.

b.Loan from Brookfield

Refer to Item 18. - Financial Statements: Note 22(a) - Related Party Transactions for a description of a $225 million revolving credit agreement we entered into with Brookfield.

c.2018 Purchase of Senior Unsecured Bonds by Brookfield

Refer to Item 18. - Financial Statements: Note 22(b) - Related Party Transactions for a description of Brookfield’s purchase from us in July 2018 of $500 million principal amount of our 8.50% senior unsecured bonds due 2023, and related transactions.

Other

Refer to Item 18. - Financial Statements: Note 22 - Related Party Transactions for additional information about these and other related-party transactions.

C.Interests of Experts and Counsel

Not applicable.

Item 8.Financial Information

A.Consolidated Financial Statements and Other Financial Information

Refer to Item 18. - Financial Statements.

Legal Proceedings

Occasionally we have been, and expect to continue to be, subject to legal proceedings and claims in the ordinary course of our business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources.

Refer to Item 18. – Financial Statements: Note 17 – Provisions and Contingencies for a description of certain claims made against us.

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

We currently do not make quarterly distributions on our common units. Subject to the limitations in our partnership agreement, our general partner may elect to distribute our available cash (as defined in our partnership agreement and after deducting expenses, including estimated future capital expenditures and reserves) rather than retaining it each quarter. Available cash is determined after payment of distributions on our preferred units. In determining the amount of cash available for distribution, the board of directors of our general partner, in making the determination on our behalf, approves the amount of cash reserves to set aside, including reserves for future capital expenditures, anticipated future credit needs, working

capital and other matters. We also rely upon external financing sources, including commercial borrowings and proceeds from debt and equity offerings, to fund our capital expenditures.

We believe it is in the best interests of our common unitholders to conserve more of our internally-generated cash flows to fund these projects and to reduce debt levels. As a result, in January 2019, we reduced our quarterly distributions on our common units to $nil.

B.Significant Changes

Not applicable.

Item 9.The Offer and Listing

A.Offer and Listing Details

Neither of our Class A common units or our Class B common units are listed on a national securities exchange. Our Series A, B and E Preferred Units are listed on the NYSE under the symbols “ALIN PR A”, “ALIN PR B” and “ALIN PR E”, respectively.

B.Plan of Distribution

Not applicable.

C.Markets

Refer to Item 9.A - Offer and Listing Details.

D.Selling Shareholders

Not applicable.

E.Dilution

Not applicable.

F.Expenses of the Issue

Not applicable.

Item 10.Additional Information

A.Share Capital

Not applicable.

B.Memorandum and Articles of Association

The information required to be disclosed under Item 10B is set forth in Exhibit 2.7 (Description of Securities Registered Under Section 12 of the Exchange Act) and incorporated herein by reference.

C.Material Contracts

The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which we are 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:

a.Agreement and Plan of Merger, dated September 30, 2019, by and among Teekay Offshore Partners L.P., Brookfield TK Acquisition Holdings LP, Brookfield TK Merger Sub LLC, Teekay Offshore GP L.L.C. and the other parties thereto.

D.Exchange Controls

We are not aware of any governmental laws, decrees or regulations, including foreign exchange controls, or other legislation in the Republic of the Marshall Islands that restrict the export or import of capital, or that affect the remittance of distributions, interest or other payments to holders of our securities that are non-resident and not citizens and otherwise not conducting business or transactions in the Republic of the Marshall Islands.

We are not aware of any limitations on the right of non-resident or foreign owners to hold or vote our securities imposed by the laws of the Republic of the Marshall Islands or our partnership agreement.

E.Taxation

Material United States Federal Income Tax Considerations

The following is a discussion of certain material U.S. federal income tax considerations that may be relevant to unitholders. This discussion is based upon provisions of the Internal Revenue Code of 1986, as amended (or the Code), legislative history, applicable U.S. Treasury Regulations (or Treasury Regulations), judicial authority and administrative interpretations, all as in effect on the date of this Annual Report, and which are subject to change, possibly with retroactive effect, or are subject to different interpretations. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Altera Infrastructure L.P.

This discussion is limited to unitholders who hold their units as capital assets for tax purposes. This discussion does not address all tax considerations that may be important to a particular unitholder in light of the unitholder’s circumstances, or to certain categories of unitholders that may be subject to special tax rules, such as:

•dealers in securities or currencies,

•traders in securities that have elected the mark-to-market method of accounting for their securities,

•persons whose functional currency is not the U.S. dollar,

•persons holding our units as part of a hedge, straddle, conversion or other “synthetic security” or integrated transaction,

•certain U.S. expatriates,

•financial institutions,

•insurance companies,

•persons subject to the alternative minimum tax,

•persons that actually or under applicable constructive ownership rules own 10% or more of our units (by vote or value), and

•entities that are tax-exempt for U.S. federal income tax purposes.

If a partnership (including any entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our units, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. Partners in partnerships holding our units should consult their tax advisors to determine the appropriate tax treatment of the partnership’s ownership of our units.

This discussion does not address any U.S. estate tax considerations or tax considerations arising under the laws of any state, local or non-U.S. jurisdiction. Each unitholder is urged to consult its tax advisor regarding the U.S. federal, state, local, non-U.S. and other tax consequences of the ownership or disposition of our units.

United States Federal Income Taxation of U.S. Holders

As used herein, the term U.S. Holder means a beneficial owner of our units that is for U.S. federal income tax purposes: (i) a U.S. citizen or U.S. resident alien (or a U.S. Individual Holder), (ii) a corporation or other entity taxable as a corporation, that was created or organized under the laws of the United States, any state thereof or the District of Columbia, (iii) an estate whose income is subject to U.S. federal income taxation regardless of its source, or (iv) a trust that either is subject to the supervision of a court within the United States and has one or more U.S. persons with authority to control all of its substantial decisions or has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

Distributions

We have elected to be taxed as a corporation for U.S. federal income tax purposes. Subject to the discussion of passive foreign investment companies (or PFICs) below, any distributions made by us to a U.S. Holder with respect to our units generally will constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current and accumulated earnings and profits allocated to the U.S. Holder’s units, as determined under U.S. federal income tax principles. Distributions in excess of our current and accumulated earnings and profits allocated to the U.S. Holder’s units will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in our units and thereafter as capital gain, which will be either long term or short term capital gain depending upon whether the U.S. Holder has held the units for more than one year. U.S. Holders that are corporations for U.S. federal income tax purposes generally will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. For purposes of computing allowable foreign tax credits for U.S. federal income tax purposes, dividends received with respect to our units will be treated as foreign source income and generally will be treated as “passive category income.”

Subject to holding period requirements and certain other limitations, dividends received with respect to our publicly traded preferred units by a U.S. Holder who is an individual, trust or estate (or a Non-Corporate U.S. Holder) will be treated as “qualified dividend income” that is taxable to such Non-Corporate U.S. Holder at preferential capital gain tax rates provided that we are not classified as a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (we intend to take the position that we are not now and have never been classified as a PFIC, as discussed below). Any dividends received with respect to our units not eligible for these preferential rates, including our common units, will be taxed as ordinary income to a Non-Corporate U.S. Holder.

Special rules may apply to any “extraordinary dividend” paid by us. Generally, an extraordinary dividend is a dividend with respect to a share of stock if the amount of the dividend is equal to or in excess of 10% of a common stockholder’s, or 5% of a preferred stockholder’s adjusted tax basis (or fair market value in certain circumstances) in such stock. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a stockholder’s adjusted tax basis (or fair market value in certain circumstances). If we pay an

“extraordinary dividend” on our publicly traded preferred units that is treated as “qualified dividend income,” then any loss recognized by a Non-Corporate U.S. Holder from the sale or exchange of such units will be treated as long-term capital loss to the extent of the amount of such dividend.

Certain Non-Corporate U.S. Holders are subject to a 3.8% tax on certain investment income, including dividends. Non-Corporate U.S. Holders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our units.

Sale, Exchange or Other Disposition of Units

Subject to the discussion of PFICs 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 tax basis in such units. Subject to the discussion of extraordinary dividends above, such gain or loss generally will be treated as (i) 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, or short-term capital gain or loss otherwise and (ii) U.S.-source gain or loss, as applicable, for foreign tax credit purposes. Non-Corporate U.S. Holders 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 certain limitations.

Certain Non-Corporate U.S. Holders are subject to a 3.8% tax on certain investment income, including capital gains from the sale or other disposition of units. Non-Corporate U.S. Holders should consult their tax advisors regarding the effect, if any, of this tax on their disposition of our units.

Consequences of Possible PFIC Classification

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either: (i) at least 75% of its gross income is “passive” income, or (ii) at least 50% of the average value of its assets is attributable to assets that 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. By contrast, income derived from the performance of services does not constitute “passive income.”

There are legal uncertainties involved in determining whether the income derived from our time-chartering activities constitutes rental income or income derived from the performance of services, including legal uncertainties arising from the decision in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. 2009), which held that income derived from certain time-chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the Code. However, the Internal Revenue Service (or IRS) stated in an Action on Decision (AOD 2010-01) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the Tidewater decision, and in its discussion stated that the time charters at issue in Tidewater would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to Tidewater cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the Tidewater decision in interpreting the PFIC provisions of the Code. Moreover, the market value of our units may be treated as reflecting the value of our assets at any given time. Therefore, a decline in the market value of our units, which is not within our control, may impact the determination of whether we are a PFIC. Nevertheless, based on our and our subsidiaries’ current assets and operations, we intend to take the position that we are not now and have never been a PFIC. No assurance can be given, however, that the IRS, or a court of law, will accept our position or that we would not constitute a PFIC for any future taxable year if there were to be changes in our or our subsidiaries’ assets, income or operations.

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder generally would be subject to different taxation rules depending on whether the U.S. Holder makes a timely and effective election to treat us as a “qualified electing fund” (or 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 units, as discussed below.

Taxation of U.S. Holders Making a Timely QEF Election. A U.S. Holder who makes a timely QEF election (or an Electing Holder), must report the Electing Holder’s pro rata share of our ordinary earnings and net capital gain, if any, for each taxable year for which we are a PFIC that ends with or within the Electing Holder’s taxable year, regardless of whether or not the Electing Holder received distributions from us in that year. Such income inclusions would not be eligible for the preferential tax rates applicable to qualified dividend income. The Electing Holder’s adjusted tax basis in our 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 our 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 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 the U.S. Holder’s timely filed U.S. federal income tax return (including extensions).

If a U.S. Holder has not made a timely QEF election with respect to the first year in the U.S. Holder’s holding period of our units during which we qualified as a PFIC, the U.S. Holder may be treated as having made a timely QEF election by filing a QEF election with the U.S. Holder’s timely filed U.S. federal income tax return (including extensions) and, under the rules of Section 1291 of the Code, a “deemed sale election” to include in income as an “excess distribution” (described below) the amount of any gain that the U.S. Holder would otherwise recognize if the U.S. Holder sold the U.S. Holder’s units on the “qualification date”. The qualification date is the first day of our taxable year in which we qualified as a “qualified electing fund” with respect to such U.S. Holder. In addition to the above rules, under very limited circumstances, a U.S. Holder may make a retroactive QEF election if the U.S. Holder failed to file the QEF election documents in a timely manner. If a U.S. Holder makes a timely QEF election for one of our taxable years, but did not make such election with respect to the first year in the U.S. Holder’s holding period of our units during which we qualified as a PFIC and the U.S. Holder did not make the deemed sale election described above, the U.S. Holder also will be subject to the more adverse rules described below.

A U.S. Holder’s QEF election will not be effective unless we annually provide the U.S. Holder with certain information concerning our income and gain, calculated in accordance with the Code, to be included with the U.S. Holder’s U.S. federal income tax return. We have not provided our U.S. Holders with such information in prior taxable years and do not intend to provide such information in the current taxable year. Accordingly, U.S. Holders will not be able to make an effective QEF election at this time. If, contrary to our expectations, we determine that we are or will be a PFIC for any taxable year, we will provide U.S. Holders with the information necessary to make an effective QEF election with respect to our units.

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 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 for the first year a U.S. Holder holds or is deemed to hold our units and for which we are a PFIC, the U.S. Holder generally would include as ordinary income in each taxable year that we are a PFIC the excess, if any, of the fair market value of the U.S. Holder’s units at the end of the taxable year over the U.S. Holder’s adjusted tax basis in the 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 units over the fair market value thereof at the end of the taxable year that we are a PFIC, 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 our units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our units in taxable years that we are a PFIC would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of our units in taxable years that we are a PFIC 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 also determined to be PFICs.

If a U.S. Holder makes a mark-to-market election for one of our taxable years and we were a PFIC for a prior taxable year during which such U.S. Holder held our units and for which (i) we were not a QEF with respect to such U.S. Holder and (ii) such U.S. Holder did not make a timely mark-to-market election, such U.S. Holder would also be subject to the more adverse rules described below in the first taxable year for which the mark-to-market election is in effect and also to the extent the fair market value of the U.S. Holder’s units exceeds the U.S. Holder’s adjusted tax basis in the units at the end of the first taxable year for which the mark-to-market election is in effect.

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 who does not make either a QEF election or a “mark-to-market” election for that year (or 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 distribution received by the Non-Electing Holder on our units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years or, if shorter, the Non-Electing Holder’s holding period for our units), and (ii) any gain realized on the sale, exchange or other disposition of our units. Under these special rules:

•the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for our 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 taxable year;

•the amount allocated to each of the other taxable years would be subject to U.S. federal income tax at the highest rate of tax in effect for the applicable class of taxpayer for that year; and

•an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

Additionally, for each year during which a U.S. Holder holds our units, we are a PFIC, and the total value of all PFIC units that such U.S. Holder directly or indirectly holds exceeds certain thresholds, such U.S. Holder will be required to file IRS Form 8621 with its annual U.S. federal income tax return to report its ownership of our units. In addition, if a Non-Electing Holder who is an individual dies while owning our units, such Non-Electing Holder’s successor generally would not receive a step-up in tax basis with respect to such units.

U.S. Holders are urged to consult their tax advisors regarding the PFIC rules, including the PFIC annual reporting requirements as well as the applicability, availability and advisability of, and procedure for, making QEF, Mark-to-Market and other available elections with respect to us, and the U.S. federal income tax consequences of making such elections.

U.S. Return Disclosure Requirements for U.S. Individual Holders

U.S. Individual Holders who hold certain specified foreign financial assets, including stock in a foreign corporation that is not held in an account maintained by a financial institution, with an aggregate value in excess of $50,000 on the last day of a taxable year, or $75,000 at any time during that taxable year, may be required to report such assets on IRS Form 8938 with their U.S. federal income tax return for that taxable year. This reporting requirement does not apply to U.S. Individual Holders who report their ownership of our units under the PFIC annual reporting rules described above. Penalties apply for failure to properly complete and file IRS Form 8938. U.S. Individual Holders are encouraged to consult with their tax advisors regarding the possible application of this disclosure requirement to their investment in our units.

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

A beneficial owner of our units (other than a partnership, including any entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is a Non-U.S. Holder.

Distributions

In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on distributions received from us with respect to our units unless the distributions are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an

applicable income tax treaty, are attributable to a permanent establishment that the Non-U.S. Holder maintains in the United States). If a Non-U.S. Holder is engaged in a trade or business within the United States and the distributions are deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on those distributions in the same manner as if it were a U.S. Holder.

Sale, Exchange or Other Disposition of Units

In general, a non-U.S. Holder is not subject to U.S. federal income tax on any gain resulting from the disposition of our units unless (i) such gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment that the Non-U.S. Holder maintains in the United States) or (ii) the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year in which such disposition occurs and meets certain other requirements. If a Non-U.S. Holder is engaged in a trade or business within the United States and the disposition of our units is deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on the resulting gain in the same manner as if it were a U.S. Holder.

Information Reporting and Backup Withholding

In general, distributions taxable as dividends with respect to, or the proceeds from a sale, redemption or other taxable of a disposition of, our units held by a Non-Corporate U.S. Holder will be subject to information reporting requirements, unless such distribution taxable as a dividend is paid and received outside the United States by a non-U.S. payor or non-U.S. middleman (within the meaning of U.S. Treasury Regulations), or such proceeds are effected through an office outside the U.S. of a broker that is considered a non-U.S. payor or non-U.S. middleman (within the meaning of U.S. Treasury Regulations). These amounts also generally will be subject to backup withholding if the Non-Corporate U.S. Holder:

•fails to timely provide an accurate taxpayer identification number;

•is notified by the IRS that it has failed to report all interest or distributions required to be shown on its U.S. federal income tax returns; or

•in certain circumstances, fails to comply with applicable certification requirements.

Information reporting and backup withholding generally will not apply to distributions taxable as dividends on our units to a Non-U.S. Holder if such dividend is paid and received outside the United States by a non-U.S. payor or non-U.S. middleman (within the meaning of U.S. Treasury Regulations) or the Non-U.S. Holder properly certifies under penalties of perjury as to its non-U.S. status (generally on IRS Form W-8BEN, W-8BEN-E, W-8ECI or W-8EXP, as applicable) and certain other conditions are met or the Non-U.S. Holder otherwise establishes an exemption.

Payment of proceeds to a Non-U.S. Holder from a sale, redemption or other taxable disposition of our units to or through the U.S. office of a broker, or through a broker that is considered a U.S. payor or U.S. middleman (within the meaning of U.S. Treasury Regulations), generally will be subject to information reporting and backup withholding, unless the Non-U.S. Holder properly certifies under penalties of perjury as to its non-U.S. status (generally on IRS Form W-8BEN, W-8BEN-E, W-8ECI or W-8EXP, as applicable) and certain other conditions are met or the Non-U.S. Holder otherwise establishes an exemption.

Backup withholding is not an additional tax. Rather, a Non-Corporate U.S. Holder or Non-U.S. Holder 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 accurately completing and timely filing a U.S. federal income tax return with the IRS.

Non-United States Tax Considerations

Republic of the Marshall Islands Tax Considerations. Because we and our subsidiaries do not, and we do not expect that we or they will, conduct business, transactions or operations in the Republic of the Marshall Islands, and because all documentation related to our securities issuances was executed outside of the Republic of the Marshall Islands, under current Republic of the Marshall Islands law, holders of our units will not be subject to Republic of the Marshall Islands taxation or withholding on distributions, including upon a return of capital, we make to our unitholders, so long as such persons are not citizens of and do not reside in, maintain offices in, nor engage in business, operations, or transactions in the Republic of the Marshall Islands. In addition, such unitholders will not be subject to Republic of the Marshall Islands stamp, capital gains or other taxes on the purchase, ownership or disposition of units, and they will not be required by the Republic of the Marshall Islands to file a tax return relating to the units. It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, including the Republic of the Marshall Islands, of such unitholder's investment in us. Accordingly, each unitholder is urged to consult its tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of such unitholder.

F.Dividends and Paying Agents

Not applicable.

G.Statement by Experts

Not applicable.

H.Documents on Display

Our Partnership is subject to the information filing requirements of the Exchange Act, and accordingly we are required to file periodic reports and other information with the SEC. As a foreign private issuer under the SEC’s regulations, we file annual reports on Form 20-F and furnish other

reports on Form 6-K. The information disclosed in our reports may be less extensive than that required to be disclosed in annual and quarterly reports on Forms 10-K and 10-Q required to be filed with the SEC by U.S. issuers.

Documents concerning us that are referred to herein may be accessed on our website under “Investors - Reports and Presentations” from the home page of our web site at www.alterainfra.com, or may be inspected at our principal executive offices at Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, United Kingdom. Those documents electronically filed via the SEC’s Electronic Data Gathering, Analysis, and Retrieval (or EDGAR) system may also be obtained from the SEC’s website at www.sec.gov, free of charge.

I.Subsidiary Information

Not applicable.

Item 11.Quantitative and Qualitative Disclosures About Market Risk

Refer to the information contained in this Annual Report under Item 18 – Financial Statements: Note 29c. - Market Risk.

Item 12.Description of Securities Other than Equity Securities

Not applicable.

PART II

Item 13.Defaults, Dividend Arrearages and Delinquencies

Not Applicable.

Item 14.Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The management of Altera, with the participation of our Chief Executive Officer and Chief Financial Officer of the Service Provider, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the U.S. Securities and Exchange Act of 1934, as amended (or the Exchange Act)) as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of the Service Provider have concluded that, as a result of a material weakness in internal control over financial reporting, as described below, as of December 31, 2020, our disclosure controls and procedures were not effective.

In designing and evaluating our disclosure controls and procedures, our management, with the participation of the Chief Executive Officer and Chief Financial Officer of the Service Provider, recognize that any controls and procedures, no matter how well designed and operated, can only provide reasonable assurance that the desired control objectives will be achieved, and that the management must necessarily exercise judgment when evaluating possible controls and procedures. Because of the limitations inherent in all controls systems, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud in the company have been detected.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed, under the supervision of the Chief Executive Officer and Chief Financial Officer of the Service Provider, and implemented by our management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with IFRS and the requirements of the SEC.

Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets, provide reasonable assurance that transactions are recorded in the manner necessary to permit the preparation of financial statements in accordance with IFRS, and that receipts and expenditures are only carried out in accordance with the authorization of our management and directors; and provide reasonable assurance regarding the prevention or timely detection of any unauthorized acquisition, use or disposition of our assets, that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements.

Material weakness

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

We have assessed the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, we have concluded that our internal control over financial reporting, as of December 31, 2020, was not effective due to the existence of control deficiencies related to user access management within the IT environment and which was deemed to represent a material weakness in our internal control over financial reporting.

IT user access controls management

IT user access controls are intended to ensure that access to financial applications and data is adequately restricted to appropriate personnel. Our management has identified control deficiencies related to information technology general controls over information technology systems that support our financial reporting process. Specifically, control deficiencies were identified in the operation of controls related to user access controls management to appropriately segregate duties and to adequately restrict user and privileged access to financial applications, data and programs to appropriate personnel. The deficiencies are primarily related to insufficient controls with respect to granting access, and lack of performance of review controls covering segregation of duties, and sensitive and critical access.

These deficiencies, when aggregated, impacted the effectiveness of IT applications and IT dependent controls and created a reasonable possibility that a material misstatement to the 2020 interim or annual financial statements would not be prevented or detected on a timely basis.

Our management has analyzed the material weakness relating to IT user assess control management and has performed additional analysis and mitigation controls and procedures in preparing our financial statements. Management notes the implementation of a new IT system and the relocation of various IT activities contributed to the material weakness. The implementation and relocation of activities is expected to be nonrecurring. We have concluded that our financial statements present, in all material respects, our financial condition, results of operations and cash flow as at and for the periods presented, and there were no adjustments required to the 2020 interim or annual consolidated financial statements due to this material weakness. Apart from the material weakness described above, our management has not identified any other deficiencies that have led management to conclude that our internal control over financial reporting was not effective.

Remediation plan

Our management is actively undertaking remediation efforts to address the material weakness identified above through the following actions:

•providing additional training to relevant personnel to strengthen competence at the relevant levels across the organization regarding risks and internal controls.

•improving the operation of controls over IT user access and the level of privileges assigned to IT users; and

•increasing coordination and monitoring activities related to the execution of the IT user access management controls.

We believe that the above actions, together with any modifications thereto, which we may determine to be appropriate, will be effective in remediating the material weakness related to access management described above. However, the material weakness cannot be considered remediated until the controls operate for a sufficient period of time and management has concluded, through testing, that our internal controls are operating effectively.

Changes in Internal Control

Other than the material weakness described above, there were no changes in our internal control over financial reporting during the year ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16A. Audit Committee Financial Expert

The board of directors of our general partner has determined that director William L. Transier qualifies as an audit committee financial expert in accordance with the SEC and is independent under applicable NYSE and SEC standards.

Item 16B. Code of Ethics

In March 2020, as a result of us no longer being affiliated with Teekay Corporation, we amended our previously adopted Standards of Business Conduct Policy by adopting our own Code of Conduct that applies to all our employees and the directors of our general partner. This document is available under “Investors – Governance” from the home page of our web site (www.alterainfra.com).

Item 16C. Principal Accountant Fees and Services

Our principal accountants for 2020 and 2019 were Ernst & Young AS and Ernst & Young LLP (Canada), respectively. The following table shows the fees we incurred for services provided by our principal accountants for 2020 and 2019.


	2020		2019
	(in thousands of U.S. Dollars)
Audit Fees (1)	$	2,159	$	1,364
Audit-Related Fees (2)	36		3
Tax Fees (3)	329		510
Total	$	2,524	$	1,877

(1)Audit fees represent fees for professional services provided in connection with the audits of our consolidated financial statements and effectiveness of internal control over financial reporting, review of our quarterly consolidated financial statements and audit services provided in connection with other statutory or regulatory filings.

(2)Audit-related fees relate to other accounting consultations.

(3)Tax fees relate primarily to transfer pricing advisory and corporate tax compliance fees.

The Audit Committee of our general partner’s board of directors has the authority to pre-approve permissible audit-related and non-audit services not prohibited by law to be performed by our independent auditors and associated fees. Engagements for proposed services either may be separately pre-approved by the Audit Committee or entered into pursuant to detailed pre-approval policies and procedures established by the Audit Committee, as long as the Audit Committee is informed on a timely basis of any engagement entered into on that basis. The Audit Committee separately pre-approved all engagements and fees paid to our principal accountant in 2020.

Item 16D. Exemptions from the Listing Standards for Audit Committees

Mr. Jim Reid, who serves on the Audit Committee of our board of directors as an observer, is a Managing Partner and the Chief Investment Officer in Brookfield’s Private Equity Group. Affiliates of Brookfield are the largest common unitholder of us and the owner of a 100% interest in our general partner. As an observer, Mr. Reid does not have voting rights on the Audit Committee. He is neither the chair of the Audit Committee nor an executive officer of us. Accordingly, we rely on the exemption provided in Rule 10A-3(b)(1)(iv)(D) of the U.S. Securities Exchange Act for Mr. Reid’s service on the Audit Committee. We do not believe that Mr. Reid’s affiliation with Brookfield materially adversely affects the ability of the Audit Committee to act independently or to satisfy the other requirements relating to audit committees contained in Rule 10A-3 under the Exchange Act.

Item 16E. Purchases of Units by the Issuer and Affiliated Purchasers

The following table summarizes the Preferred units repurchased under our repurchase plan(1):


(in thousands of U.S. Dollars, except unit and per unit data)	Total number of Preferred units purchased #	Average price paid per Preferred unit $		Total number of class of Preferred units purchased #
Series A Preferred units
October 1, 2020 - October 31, 2020	30,055	$	17.75	30,055
November 1, 2020 - November 30, 2020	57,454	19.60		87,509
December 1, 2020 - December 31, 2020	35,958	21.46		123,467

Series B Preferred units
October 1, 2020 - October 31, 2020	8,298	$	19.07	8,298
November 1, 2020 - November 30, 2020	55,584	20.13		63,882
December 1, 2020 - December 31, 2020	26,099	21.75		89,981
January 1, 2021 - January 31, 2021	956	21.98		90,937

Series C Preferred units
October 1, 2020 - October 31, 2020	9,334	$	19.04	9,334
November 1, 2020 - November 30, 2020	55,856	20.04		65,190
December 1, 2020 - December 31, 2020	31,787	21.68		96,977

(1)In September 2020, we announced that our board of directors had authorized repurchases of our five-year senior unsecured bonds that mature in July 2023 and our Series A, B and E Preferred Units through open market purchases, privately negotiated transactions and/or pursuant to Rule 10b5-1 plans, in compliance with applicable securities laws and other legal requirements. The timing, volume, and nature of any repurchases will be determined by us, in consultation with the board of directors, based on evaluation of the capital needs of the business, trading prices, applicable legal requirements, and other factors. The repurchase program was completed in January 2021.

Item 16F. Change in Registrant’s Certifying Accountant

Ernst & Young LLP (Canada) was previously the principal accountants for Altera Infrastructure L.P. In 2020, in order to align the geographical location of our key corporate and accounting functions with our principal accountants the decision was made to transition from Ernst & Young LLP (Canada) to Ernst & Young AS. Ernst & Young LLP (Canada) resigned as our independent registered public accounting firm for the audit of our

financial statements for the year ending December 31, 2020. On October 22, 2020, we engaged Ernst & Young AS as our principal accountants. The decision to change accountants was approved by the audit committee of the board of directors of our general partner. The report of Ernst & Young LLP (Canada) on our consolidated financial statements as of and for the fiscal year ended December 31, 2019 did not contain an adverse opinion or a disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principles, except as follows:

Ernst & Young LLP (Canada)’s report on our consolidated financial statements as of and for the year ended December 31, 2019 contained a separate paragraph stating “As discussed in Note 2 to the consolidated financial statements, the Partnership changed its method for accounting for leases in 2019."

During the fiscal year ended December 31, 2019 and the subsequent interim periods through October 22, 2020, there were no: (1) disagreements with Ernst & Young LLP (Canada) on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of Ernst & Young LLP (Canada) would have caused Ernst & Young LLP (Canada) to make reference thereto in their report on our financial statements for such fiscal period, and (2) no “reportable events” (as defined in SEC Regulation S-K Item 304(a)(1)(v)).

Item 16G. Corporate Governance

Our corporate practices are not materially different from those required of U.S. domestic limited partnerships under the NYSE Listing Standards.

Item 16H. Mine Safety Disclosure

Not applicable.

PART III

Item 17.Financial Statements

Not applicable.

Item 18.Financial Statements

The following financial statements, together with the related reports of Ernst & Young AS and Ernst & Young LLP (Canada), Independent Registered Public Accounting Firms thereon, are filed as part of this Annual Report:


			Page
Report of Independent Registered Public Accounting Firm			F-1
Consolidated Financial Statements
Consolidated Statements of Financial Position			F-4
Consolidated Statements of Income (Loss)			F-5
Consolidated Statements of Comprehensive Income (Loss)			F-6
Consolidated Statements of Changes in Equity			F-7
Consolidated Statements of Cash Flows			F-9
Notes to the Consolidated Financial Statements			F-10

All 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 Consolidated Financial Statements and therefore have been omitted.

Item 19.Exhibits

The following exhibits are filed as part of this Annual Report:


1.1			Certificate of Limited Partnership of Teekay Offshore Partners L.P., dated August 30, 2016. (1)
1.2			Seventh Amended and Restated Agreement of Limited Partnership of Teekay Offshore Partners L.P. dated January 22, 2020. (2)
1.3			Certificate of Formation of Teekay Offshore GP L.L.C., dated August 25, 2006. (1)
1.4			Second Amended and Restated Limited Liability Company Agreement of Teekay Offshore GP L.L.C., as amended. (2)
1.5			Certificate of Limited Partnership of Teekay Offshore Operating L.P., dated September 22, 2006. (1)
1.6			Amended and Restated Agreement of Limited Partnership of Teekay Offshore Operating L.P. (1)
1.7			Certificate of Formation of Teekay Offshore Operating GP L.L.C., dated September 22, 2006. (1)
1.8			Second Amendment to Seventh Amended and Restated Agreement of Limited Partnership of Altera Infrastructure L.P. (3)
2.1			Agreement, dated September 8, 2017, for U.S. $600,000,000 Secured Revolving Credit Facility, between Teekay Shuttle Tankers L.L.C. and Den Norske Bank Capital L.L.C. and various other banks. (4)
2.2			Credit Agreement, dated July 31, 2015, among OOGTK Libra GmbH & Co KG, ABN AMRO Bank N.V. and various other banks for a U.S. $803,711,786.92 term loan due 2027. (5)
2.3			Agreement, dated February 24, 2014 among Knarr L.L.C., Citibank, N.A. and others, for a U.S. $815,000,000 Secured Term Loan Facility. (6)
2.4			Indenture, dated as of July 2, 2018, among Teekay Offshore Partners L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (7)
2.5			Second Supplemental Indenture, dated as of July 3, 2018, among Teekay Offshore Partners, L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (7)
2.6			Description of Securities Registered Under Section 12 of the Exchange Act.
4.1			Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. (1)
4.2			Form of Amended and Restated Omnibus Agreement. (1)
4.3			Amended and Restated Subordinate Promissory Note, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P. (8)
4.4			Registration Rights Agreement, dated September 25, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P. (4)
4.5			Master Services Agreement, dated September 25, 2017, by and between Teekay Corporation, Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P. (4)
4.6			Trademark License Agreement, dated September 25, 2017, by and between Teekay Corporation and Teekay Offshore Partners L.P. (4)
4.7			Agreement and Plan of Merger, dated as of September 30, 2019, by and among Teekay Offshore Partners L.P., Brookfield TK Acquisition Holdings LP, Brookfield TK Merger Sub LLC, Teekay Offshore GP L.L.C. and the other parties thereto. (9)
4.8			Amendment and Restated Credit Agreement, dated as of August 7, 2020, between Altera Infrastructure L.P. and Brookfield TK Loan LP and various other affiliated lenders.
4.9			Second Amended and Restated Credit Agreement, dated as of November 25, 2020, between Altera Infrastructure L.P. and Brookfield TK Loan LP and various other affiliated lenders.
8.1			List of subsidiaries of Altera Infrastructure L.P. (incorporated by reference - Refer to Item 18 – Financial Statements: Note 2d - Interests in other entities)
12.1			Rule 13a-14(a)/15d-14(a) Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd.
12.2			Rule 13a-14(a)/15d-14(a) Certification of Jan Rune Steinsland, Chief Financial Officer of Teekay Offshore Group Ltd.
13.1			Teekay Offshore Partners L.P. Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2			Teekay Offshore Partners L.P. Certification of Jan Rune Steinsland, Chief Financial Officer of Teekay Offshore Group Ltd. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1			Letter of Ernst & Young LLP (Canada), dated March 4, 2021, regarding change in independent registered public accounting firm.
101.INS			Inline XBRL Instance Document
101.SCH			Inline XBRL Taxonomy Extension Schema
101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB			Inline XBRL Taxonomy Extension Label Linkbase
101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)

(1)Previously filed as exhibits 3.1, 3.3, 3.5, 3.6, 3.7, 10.2 and 10.3 to our Registration Statement on Form F-1 (File No. 333-139116), filed with the SEC on December 4, 2006, and hereby incorporated by reference to such Registration Statement.

(2)Previously filed as exhibits 1.2 and 1.4 to our Report on Form 20-F (File No. 1-33198), Filed with the SEC on February 28, 2020, and hereby incorporated by reference to such Report.

(3)Previously filed as exhibit 1.1 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 3, 2020, and hereby incorporated by reference to such Report.

(4)Previously filed as exhibits 4.4, 10.5, 10.6 and 10.7 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 24, 2017, and hereby incorporated by reference to such Report.

(5)Previously filed as exhibit 2.4 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 17, 2015, and hereby incorporated by reference to such Report.

(6)Previously filed as exhibit 2.1 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 19, 2015, and hereby incorporated by reference to such Report.

(7)Previously filed as exhibits 4.1 and 4.2 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on July 5, 2018, and hereby incorporated by reference to such Report.

(8)Previously filed as exhibit 10.4 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 1, 2017, and hereby incorporated by reference to such Report.

(9)Previously filed as Annex A to Exhibit (a)(1) to Schedule 13e-3 (File No. 5-82284), filed with the SEC on December 12, 2019, and hereby incorporated by reference to such Schedule.

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.

ALTERA INFRASTRUCTURE L.P.

By: Altera Infrastructure GP L.L.C., its General Partner

Date: March 4, 2021

By:

/s/ Mark Mitchell

Mark Mitchell
Secretary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the Board of Directors of Altera Infrastructure L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Altera Infrastructure L.P. and subsidiaries (the “Partnership”) as of December 31, 2020, the related consolidated statements of loss, comprehensive loss, changes in equity and cash flows for the year ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2020, and the results of its operations and its cash flows for the year then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Going concern assessment

Description of the Matter

The consolidated financial statements of the Partnership are prepared on the going concern basis of accounting. As described in Note 2b to the consolidated financial statements, the Partnership has a significant working capital deficit as of December 31, 2020 and will need to obtain additional sources of financing to meet its obligations and commitments, and minimum liquidity requirements under its financial covenants, during the twelve-month period from the end of the reporting period. Management is engaged in discussions with various financial institutions and its significant shareholders in order to obtain the additional sources of financing needed, some of which were secured after balance sheet date as described in Note 31 to the consolidated financial statements.

Management’s cash flow forecasts include assumptions related to financing plans, which management believes provide sufficient liquidity to allow the Partnership to meet its obligations and commitments, and minimum liquidity requirements under its financial covenants. Management’s cash flow forecasts assume refinancing existing loans and interest swaps, additional drawing on existing loan facilities, and liquidity support from its owners. Additionally, the cash flow forecasts include assumptions related to estimated charter rates, vessel utilization percentages and cash inflow from sale of certain vessels, to which the overall going concern assessment is sensitive, and which are judgmental because they are forward-looking in nature.

Auditing the Partnership’s going concern assessment described above is complex because it involves a high degree of auditor judgment to assess the reasonableness of the cash flow forecasts, planned refinancing actions and other assumptions used in the Partnership’s going concern assessment. The Partnership’s ability to execute the planned refinancing actions are especially judgmental given the uncertainty in and volatility of the economic environment and global financial markets.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design, and tested controls over the Partnership’s going concern assessment process. We tested controls over management’s review of significant assumptions in relation to financing options used in the assessment and the sensitivity analyses over the key inputs to the cash flow forecasts described above.

Further, we evaluated the key estimates that impact the cash flows in management’s going concern assessment, which include estimated charter rates, vessel utilization percentages and the expected cash inflow from sale of vessels. We compared the charter rates to both historical rates and current information from contract negotiations with potential customers and evaluated whether increases or decreases of future charter rates in the forecasts compared to prior forecasts estimated by management were consistent with external industry outlook reports. We independently assessed the sensitivity and impact of reasonably possible changes in key assumptions and estimates included in management’s cash flow forecasts and liquidity position and compared those results to the sensitivity analyses performed by management.

F-1

In relation to management’s plans for loan and interest swap refinancing, and the liquidity support from its shareholders, we inspected that signed agreements after balance sheet date were consistent with management’s forecasts. Furthermore, we tested management’s assertion that it is probable that their additional plans will be effectively implemented within one year after the end of the reporting period. These procedures included, among others, understanding the nature and extent of past financing transactions concluded with the counterparties, assessing relevant data and metrics (such as contracted cash flows and existing leverage / gearing ratios, where applicable) and inspection of the terms and conditions proposed by banks. We compared the proposed terms and conditions of the financing arrangements with those of the Partnership’s existing loan facilities and evaluated management’s analysis of their impact on the forecasted cash flows. We discussed the status of the refinancing efforts and their viability with management and assessed the probability of the Partnership executing the plans effectively. For the sale of vessels included in the cash flow forecast, for a sample of the vessels we recalculated expected proceeds based on the planned recycling destination and current recycling prices based on external market reports. Our procedures also included comparing the expected proceeds against the Partnership’s historically achieved proceeds from recycling of similar vessels. We assessed the adequacy of the Partnership’s going concern disclosures included in Note 2b in the consolidated financial statements.

Impairment of vessels

Description of the Matter

At December 31, 2020, the carrying value of vessels, floating production, storage and off-loading (FPSO) units, floating storage and off-loading (FSO) units and units for maintenance and safety (UMS) (hereafter named “vessels”) was $3,029 m, net of impairment losses of $269 m recognized in the consolidated statement of loss during the period.

As explained in Note 2l to the consolidated financial statements, management assesses, at each reporting date, whether there are any indications that assets or cash-generating units are impaired. Management has determined that, for impairment purposes, each individual vessel, except for the Partnership’s contract of affreightment (COA) vessels, is a cash-generating unit. Management has determined that all COA vessels are a single cash generating unit. Impairment is recognized if the recoverable amount, determined as the higher of value-in-use and fair value less cost to dispose, is less than the carrying value of the asset or cash generating unit. Management uses a discounted cash flow approach to estimate the fair value of its vessels and equipment that are not classified as held for sale. The assessment requires management to make estimates and assumptions, the most significant of which are charter rates and redeployment possibilities post-contract expiry and discount rates.

Auditing management’s impairment of vessels analysis was complex and highly judgmental due to the significant judgments made by management to estimate the charter rates for non-contracted revenue days, the redeployment possibilities and the discount rate which are particularly subjective. These judgments involve assumptions about the markets in which the Partnership operates through the end of the useful lives of the vessels and due to the sensitivity of the value-in-use calculations to management's assumptions.

How We Addressed the Matter in Our Audit

We obtained an understanding of the Partnership’s impairment process and evaluated the design and tested the operating effectiveness of the controls over the Partnership’s determination of key inputs to the impairment assessment, including determination of charter rates post-contract expiry, the possibilities for redeployment, and the discount rate.

We analyzed management’s impairment assessment by comparing the methodology used to assess impairment of each vessel against the accounting guidance in IAS 36 Impairment of Assets. These procedures included, among others, to involve our specialists to assist in the testing of the Partnership’s model, method, and the discount rate.

We tested the reasonableness of the charter rates for non-contracted revenue days and redeployment assumptions by comparing them to both historical rates and current information from contract negotiations with potential customers. We evaluated whether increases or decreases of future charter rates in the forecasts compared to prior forecasts estimated by management were consistent with external industry outlook reports. We also analyzed how the economic factors such as future supply and demand for the Partnership’s vessels have been incorporated in management’s assumptions for redeployment of both idle vessels and vessels with contracts expiring before the end of useful life.

To test the discount rate our procedures included evaluating the method and model used against practices common in the industry. We tested the source information underlying the calculation as well as the mathematical accuracy of the model. With the assistance of our specialists, we also developed a range of independent estimates comparing those to the discount rate selected by management.

Further, we evaluated management's ability to accurately forecast by comparing actual results to management's historical forecasts. We tested the mathematical accuracy of management's calculation of the recoverable amount and agreed, on a sample basis, the inputs to the source information and underlying assumptions used by management. We assessed the adequacy of the Partnership’s impairment disclosures in Note 2l, 2v and 11 in the consolidated financial statements.

/s/ Ernst & Young AS

We have served as the Partnership’s auditor since 2020.

Stavanger, Norway

March 4, 2021

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and the Board of Directors of Altera Infrastructure L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of Altera Infrastructure L.P. and subsidiaries (the “Partnership”) as of December 31, 2019 and January 1, 2019, the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and changes in equity for the year ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and January 1, 2019, and the results of its operations and its cash flows for the year ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ Ernst & Young LLP

Chartered Professional Accountants

We served as the Partnership’s auditor from 2019 to 2020.

Vancouver, Canada

March 4, 2021

F-3

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands of U.S. Dollars)


		As at	As at	As at
		December 31,	December 31,	January 1,
		2020	2019	2019
	Notes	$	$	$
ASSETS
Current assets
Cash and cash equivalents		235,734	199,388	225,040
Financial assets	5	103,514	107,992	9,568
Accounts and other receivable, net	6	222,629	204,825	143,710
Vessels and equipment classified as held for sale	7	7,500	15,374	12,528
Inventory		16,308	18,581	20,254
Due from related parties	22	9,980	—	58,885
Other assets	9	37,326	16,844	20,989
Total current assets		632,991	563,004	490,974
Non-current assets
Financial assets	5	36,372	—	2,075
Accounts and other receivable, net	6	—	17,276	36,536
Vessels and equipment	11	3,029,415	3,025,716	3,548,501
Advances on newbuilding contracts	12	127,335	297,100	113,796
Equity-accounted investments	13	241,731	232,216	208,819
Deferred tax assets	21	5,153	7,000	9,168
Due from related parties	22	—	—	949
Other assets	9	185,521	218,813	185,191
Goodwill	14	127,113	127,113	127,113
Total non-current assets		3,752,640	3,925,234	4,232,148
Total assets		4,385,631	4,488,238	4,723,122
LIABILITIES
Current liabilities
Accounts payable and other	15	302,414	272,618	213,480
Other financial liabilities	19	198,985	21,697	23,290
Borrowings	20,22	362,079	353,238	554,336
Due to related parties	22	7	21,306	183,795
Total current liabilities		863,485	668,859	974,901
Non-current liabilities
Accounts payable and other	15	128,671	222,659	264,732
Other financial liabilities	19	144,350	164,511	144,867
Borrowings	20,22	2,808,898	2,831,274	2,543,406
Due to related parties	22	194,628	—	—
Deferred tax liabilities	21	700	3,133	2,183
Total non-current liabilities		3,277,247	3,221,577	2,955,188
Total liabilities		4,140,732	3,890,436	3,930,089
EQUITY
Limited partners - common units	23	—	169,737	350,088
Limited partners - Class A common units	23	(2,505)	—	—
Limited partners - Class B common units	23	(157,897)	—	—
Limited partners - preferred units	23	376,512	384,274	384,274
General partner	23	6,828	9,587	10,971
Accumulated other comprehensive income		4,071	4,410	7,361
Non-controlling interests in subsidiaries	24	17,890	29,794	40,339
Total equity		244,899	597,802	793,033
Total liabilities and equity		4,385,631	4,488,238	4,723,122

The accompanying notes are an integral part of the consolidated financial statements.

F-4

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(in thousands of U.S. Dollars, except per unit data)


		Year Ended	Year Ended
		December 31,	December 31,
		2020	2019
	Notes	$	$
Revenues	25	1,182,110	1,252,938
Direct operating costs	26	(627,792)	(606,691)
General and administrative expenses	27	(44,360)	(54,927)
Depreciation and amortization	27	(316,317)	(358,474)
Interest expense	20,22	(192,723)	(205,667)
Interest income		2,770	5,111
Equity-accounted income (loss)	13	35,921	33,768
Impairment expense, net	11	(268,612)	(187,680)
Gain (loss) on dispositions, net	8	3,411	12,548

Realized and unrealized gain (loss) on derivative instruments	19,22	(96,499)	(34,682)
Foreign currency exchange gain (loss)		(7,861)	2,193
Other income (expenses), net	22,30	(10,472)	(9,677)
Income (loss) before income tax (expense) recovery		(340,424)	(151,240)
Income tax (expense) recovery
Current	21	(6,543)	(4,666)
Deferred	21	804	(3,161)
Net income (loss)		(346,163)	(159,067)
Attributable to:
Limited partners - common units		(368,341)	(181,424)
General partner		(2,771)	(1,384)
Limited partners - preferred units		32,103	32,150
Non-controlling interests in subsidiaries	24	(7,154)	(8,409)
		(346,163)	(159,067)
Basic and diluted earnings (loss) per limited partner common unit	23	(0.90)	(0.44)

The accompanying notes are an integral part of the consolidated financial statements.

F-5

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands of U.S. Dollars)


		Year Ended	Year Ended
		December 31,	December 31,
		2020	2019
	Notes	$	$
Net income (loss)		(346,163)	(159,067)
Other comprehensive income (loss)
Items that will not be reclassified subsequently to net income (loss):
Pension adjustments, net of taxes		1,438	(1,662)
Items that may be reclassified subsequently to net income (loss):
To interest expense:
Realized gain on qualifying cash flow hedging instruments	19	(811)	(689)
To equity income:
Realized gain on qualifying cash flow hedging instruments		(966)	(600)
Total other comprehensive income (loss)		(339)	(2,951)
Comprehensive income (loss)		(346,502)	(162,018)
Attributable to:
Limited partners - common units		(368,677)	(184,353)
General partner		(2,774)	(1,406)
Limited partners - preferred units		32,103	32,150
Non-controlling interests in subsidiaries	24	(7,154)	(8,409)
		(346,502)	(162,018)

The accompanying notes are an integral part of the consolidated financial statements.

F-6

ALTERA INFRASTRUCTURE L.P AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands of U.S. Dollars and units)


		PARTNERS’ EQUITY
		Limited Partners
	Notes	Class A Common Units #	Class A Common Units and Additional Paid-in Capital $	Class B Common Units #	Class B Common Units and Additional Paid-in Capital $	Common Units #	Common Units and Additional Paid-in Capital $	Preferred Units #	Preferred Units $	General Partner $	Accumulated Other Comprehensive Income $	Non- controlling Interests $	Total Equity $
Balance as at January 1, 2020		—	—	—	—	411,149	169,737	15,800	384,274	9,587	4,410	29,794	597,802
Exchange of equity instruments	20	5,217	2,154	405,932	167,583	(411,149)	(169,737)	—	—	—	—	—	—
Net income (loss)		—	(4,674)	—	(363,667)	—	—	—	32,103	(2,771)	—	(7,154)	(346,163)
Other comprehensive income (loss)		—	—	—	—	—	—	—	—	—	(339)	—	(339)
Distributions declared:

Preferred Units - Series A ($1.8124 per unit)		—	—	—	—	—	—	—	(10,855)	—	—	—	(10,855)
Preferred Units - Series B ($2.1252 per unit)		—	—	—	—	—	—	—	(10,613)	—	—	—	(10,613)
Preferred Units - Series E ($2.2188 per unit)		—	—	—	—	—	—	—	(10,636)	—	—	—	(10,636)
Other distributions		—	—	—	—	—	—	—	—	—	—	(4,750)	(4,750)



Contribution of Capital from Brookfield		—	—	—	37,060	—	—	—	—	—	—	—	37,060






Repurchase of Preferred Units		—	20	—	1,529	—	—	(311)	(7,761)	12	—	—	(6,200)
Equity based compensation and other		—	(5)	—	(402)	—	—	—	—	—	—	—	(407)
Balance as at December 31, 2020		5,217	(2,505)	405,932	(157,897)	—	—	15,489	376,512	6,828	4,071	17,890	244,899

The accompanying notes are an integral part of the consolidated financial statements.

F-7


		PARTNERS’ EQUITY
		Limited Partners
	Notes	Class A Common Units #	Class A Common Units and Additional Paid-in Capital $	Class B Common Units #	Class B Common Units and Additional Paid-in Capital $	Common Units #	Common Units and Additional Paid-in Capital $	Preferred Units #	Preferred Units $	General Partner $	Accumulated Other Comprehensive Income $	Non- controlling Interests $	Total Equity $
Balance as at January 1, 2019		—	—	—	—	410,315	350,088	15,800	384,274	10,971	7,361	40,339	793,033
Net income (loss)		—	—	—	—	—	(181,424)	—	32,150	(1,384)	—	(8,409)	(159,067)
Other comprehensive income (loss)		—	—	—	—	—	—	—	—	—	(2,951)	—	(2,951)
Distributions declared:

Preferred Units - Series A ($1.8124 per unit)		—	—	—	—	—	—	—	(10,874)	—	—	—	(10,874)
Preferred Units - Series B ($2.1252 per unit)		—	—	—	—	—	—	—	(10,626)	—	—	—	(10,626)
Preferred Units - Series E ($2.2188 per unit)		—	—	—	—	—	—	—	(10,650)	—	—	—	(10,650)
Other distributions		—	—	—	—	—	—	—	—	—	—	(3,636)	(3,636)



Contribution from non-controlling interests in subsidiaries		—	—	—	—	—	—	—	—	—	—	1,500	1,500





Equity based compensation and other		—	—	—	—	834	1,073	—	—	—	—	—	1,073
Balance as at December 31, 2019		—	—	—	—	411,149	169,737	15,800	384,274	9,587	4,410	29,794	597,802

The accompanying notes are an integral part of the consolidated financial statements.

F-8

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of U.S. Dollars)


		Year Ended December 31,
		2020	2019
	Notes	$	$
Operating Activities
Net income (loss)		(346,163)	(159,067)
Adjusted for the following items:
Depreciation and amortization	11	316,317	358,474
Equity-accounted (income) loss, net of distributions received	13	(6,532)	(16,113)
Impairment expense, net	11	268,612	187,680
(Gain) loss on dispositions, net	8	(3,411)	(12,548)
Unrealized (gain) loss on derivative instruments	19	36,045	443
Deferred income tax expense (recovery)	21	(804)	3,161
Provisions and other items	17	(3,503)	(1,547)
Other non-cash items		34,629	(22,942)
Changes in non-cash working capital, net	28	(12,871)	13,341
Net operating cash flow		282,319	350,882
Financing Activities
Proceeds from borrowings	20	312,149	492,517
Repayments of borrowings and settlement of related derivative instruments	19,20	(329,073)	(410,429)
Financing costs related to borrowings	20	(8,023)	(20,752)
Proceeds from borrowings related to sale and leaseback of vessels	12	119,073	23,800
Repayments of borrowings related to sale and leaseback of vessels	12	(1,190)	—
Financing costs related to borrowings from sale and leaseback of vessels	12	(187)	(2,256)
Proceeds from borrowings from related parties	22	205,000	95,000
Prepayment of borrowings from related parties	22	—	(200,000)
Lease liability repayments	10	(20,332)	(14,695)
Capital provided by others who have interests in subsidiaries		—	1,500

Distributions to limited partners and preferred unitholders	23	(32,103)	(32,150)
Distributions to others who have interests in subsidiaries	24	(4,750)	(3,636)
Repurchase of preferred units	23	(6,200)	—
Net financing cash flow		234,364	(71,101)
Investing Activities
Additions
Vessels and equipment	11,12	(479,981)	(231,658)
Equity-accounted investments	13	(3,948)	(7,886)
Dispositions
Vessels and equipment	8	27,996	33,341
Changes in restricted cash	5	(26,520)	(98,329)
Acquisition of company (net of cash acquired of $6.4 million)		6,430	—
Net investing cash flow		(476,023)	(304,532)
Cash and cash equivalents
Change during the year		40,660	(24,751)
Impact of foreign exchange on cash		(4,314)	(901)
Balance, beginning of the year		199,388	225,040
Balance, end of the year		235,734	199,388

Supplemental cash flow information (note 28)
The accompanying notes are an integral part of the consolidated financial statements.

F-9

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

1.Nature and Description of the Partnership

Altera Infrastructure L.P. and its wholly-owned or controlled subsidiaries (collectively, the Partnership and formerly Teekay Offshore Partners L.P.) is an international infrastructure services provider to the offshore oil and gas industry, focused on the ownership and operation of critical infrastructure assets in offshore oil regions of the North Sea, Brazil and the East Coast of Canada. The Partnership was formed as a limited partnership established under the laws of the Republic of the Marshall Islands in August 2006 and the Partnership's affairs are governed by the Marshall Islands Limited Partnership Act and its limited partnership agreement as amended on October 27, 2020. The Partnership is a subsidiary of Brookfield Business Partners L.P. (NYSE: BBU) (TSX: BBU.UN) (or with its affiliates, Brookfield). The Partnership’s preferred equity units are listed on the New York Stock Exchange under the ticker symbols “ALIN PR A”, “ALIN PR B” and “ALIN PR E” respectively. The registered head office of the Partnership is Altera House, Unit 3, Prospect Park, Arnhall Business Park, Westhill, Aberdeenshire, AB32 6FJ, United Kingdom.

Unless the context otherwise requires, the terms "we," "us," or "our," as used herein, refer to the Partnership.

2.Significant Accounting Policies

a.Basis of presentation

These consolidated financial statements of the Partnership have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (or IFRS) and using the accounting policies described below. The consolidated financial statements have been prepared under the assumption that the Partnership operates on a going concern basis and have been presented in U.S. dollars rounded to the nearest thousand unless otherwise indicated.

For all periods up to and including the year ended December 31, 2019, the Partnership prepared its financial statements in accordance with accordance with United States Generally Accepted Accounting Principles (or previous GAAP). These financial statements for the year ended December 31, 2020, are the first the Partnership has prepared in accordance with IFRS. Refer to Note 3 for information on how the Partnership adopted IFRS.

In the opinion of management of the Partnership’s general partner, Altera Infrastructure GP L.L.C. (or the general partner), these consolidated financial statements reflect all adjustments, which are of a normal recurring nature, necessary to present fairly, in all material respects, the Partnership’s consolidated financial position, results of operations, changes in total equity and cash flows as at dates and for the periods presented. These consolidated financial statements were approved by management and authorized for issue on March 4, 2020.

b.Going concern

As at December 31, 2020, the Partnership had a working capital deficit of $230.5 million primarily relating to the scheduled maturities and repayments of $362.1 million of outstanding borrowings and the settlement of $199.0 million of other financial liabilities, primarily interest rate swaps, during the 12 months ending December 31, 2021, which amounts were classified as current liabilities as at December 31, 2020. The Partnership also anticipates making payments related to commitments to fund certain vessels under construction through 2022 of $248.5 million; however, the Partnership has secured long-term financing related to these vessels.

The working capital deficit of $230.5 million as at December 31, 2020, has significantly increased from $105.9 million as at December 31, 2019. The increase in the working capital deficit was primarily due to: a $177.3 million increase in other financial liabilities, primarily due to certain interest rate swaps containing early-termination provisions, which, if exercised, would terminate these interest rate swaps during the 12 months ending December 31, 2021 (see note 19); partially offset by a $36.3 million increase in cash and cash equivalents.

Based on these factors, the Partnership will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet its obligations and commitments and minimum liquidity requirements under its financial covenants. Additional potential sources of financing that the Partnership is actively pursuing or may consider pursuing, during the one-year period to December 31, 2021, include entering into new debt facilities, borrowing additional amounts under existing facilities, the refinancing or extension of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnerships business interests and/or capital raises. Additional potential sources of amounts generated from operations include the extensions and redeployments of existing assets.

The Partnership is actively pursuing or may pursue the financing initiatives described above, which it considers probable of completion based on the Partnership’s history of being able to raise and refinance borrowings for similar types of vessels and based on the Partnership's assessment of current conditions and estimated future conditions. The Partnership is in various stages of progression on these matters. In February 2021, the Partnership entered into two unsecured revolving credit facilities with Brookfield, which provide for borrowings of up to $70.0 million and $30.0 million, respectively, and refinanced an existing term loan relating to the financing of the Petrojarl I FPSO unit, which provides for borrowings of $75.0 million. Additionally, in February 2021, the Partnership terminated or amended a total of four of its interest rate swaps that contained early-termination provisions, which, if exercised, would have terminated these interest rate swaps during the 12 months ending December 31, 2021. See Note 31 for additional information.

Based on the Partnership’s liquidity at the date of these consolidated financial statements, the liquidity it expects to generate from operations over the following year, and by incorporating the Partnership’s plans to raise additional liquidity that it considers probable of completion, the Partnership expects that it will have sufficient liquidity to enable the Partnership to continue as a going concern for at least the one-year period to December 31, 2021.

c.Basis of consolidation

The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, which are the entities over which the Partnership has control. An investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Non-controlling interests in the equity of the Partnership’s

F-10

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

subsidiaries held by others are shown separately in equity in the consolidated statements of financial position. All intercompany balances, transactions, revenues and expenses are eliminated in full in these consolidated financial statements.

d.Interests in other entities

(i) Subsidiaries

Subsidiaries are consolidated from the date of acquisition, being the date on which the Partnership obtained control, and continue to be consolidated until the date when control is lost.

Non-controlling interests may be initially measured either at fair value or at the non-controlling interests’ proportionate share of the fair value of the acquiree’s identifiable net assets. The choice of measurement basis is made on an acquisition by acquisition basis. Subsequent to acquisition, the carrying amount of non-controlling interests is the amount of those interests at initial recognition plus the non-controlling interests’ share of subsequent changes in the Partnership's capital in addition to changes in ownership interests. Total comprehensive income (loss) is attributed to non-controlling interests, even if this results in the non-controlling interests having a deficit balance.

The following provides information about the Partnership's wholly-owned subsidiaries as at December 31, 2020:

Name of Subsidiary

State or Jurisdiction of Incorporation

Proportion of Ownership Interest

ALP Ace BV

Netherlands

100%

ALP Centre BV

Netherlands

100%

ALP Defender BV

Netherlands

100%

ALP Forward BV

Netherlands

100%

ALP Guard BV

Netherlands

100%

ALP Ippon BV

Netherlands

100%

ALP Keeper BV

Netherlands

100%

ALP Maritime Contractors BV

Netherlands

100%

ALP Maritime Group BV

Netherlands

100%

ALP Maritime Holding BV

Netherlands

100%

ALP Maritime Services BV

Netherlands

100%

ALP Ocean Towage Holding BV

Netherlands

100%

ALP Striker BV

Netherlands

100%

ALP Sweeper BV

Netherlands

100%

ALP Winger BV

Netherlands

100%

Altera (Atlantic) Chartering ULC

Canada

100%

Altera (Atlantic) Management ULC

Canada

100%

Altera Al Rayyan LLC

Marshall Islands

100%

Altera do Brasil Servicos Maritimos Ltda.

Brazil

100%

Altera Grand Banks AS

Norway

100%

Altera Grand Banks Shipping AS

Norway

100%

Altera Infrastructure Crewing AS

Norway

100%

Altera Infrastructure Coöperatief U.A.

Netherlands

100%

Altera Infrastructure Finance Corp.

Marshall Islands

100%

Altera Infrastructure Group Ltd.

Marshall Islands

100%

Altera Infrastructure FSO Holdings Limited

United Kingdom

100%

Altera Infrastructure Holdings LLC

Marshall Islands

100%

Altera Infrastructure Holdings Pte. Ltd.

Singapore

100%

Altera Infrastructure Norway AS

Norway

100%

Altera Infrastructure Production (Singapore) Pte. Ltd.

Singapore

100%

Altera Infrastructure Production AS

Norway

100%

Altera Infrastructure Production Crew AS

Norway

100%

Altera Infrastructure Production Holdings AS

Norway

100%

Altera Infrastructure Production Holdings Limited

United Kingdom

100%

Altera Infrastructure Services Pte. Ltd

Singapore

100%

Altera Knarr AS

Norway

100%

Altera Libra Netherlands BV

Netherlands

100%

Altera Luxembourg S.a.r.l.

Luxembourg

100%

Altera Netherlands BV

Netherlands

100%

F-11

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Altera Norway Hiload AS

Norway

100%

Altera Norway Holdings AS

Norway

100%

Altera Norway Marine AS

Norway

100%

Altera Operations Australia Pty Ltd.

Australia

100%

Altera Partners Holding AS

Norway

100%

Altera Petrojarl FPSO Petrolífera do Brasil Ltda.

Brazil

100%

Altera Petrojarl I Servicos de Petroleo Ltda.

Brazil

100%

Altera Piranema Servicos de Petroleo Ltda.

Brazil

100%

Altera Production UK Limited

United Kingdom

100%

Altera Shuttle Loading Pte. Ltd.

Singapore

100%

Altera Shuttle Tanker Finance LLC

Marshall Islands

100%

Altera Shuttle Tankers LLC

Marshall Islands

100%

Altera Varg Production Limited.

United Kingdom

100%

Altera Voyageur Production Limited.

United Kingdom

100%

Altera Wave AS

Norway

100%

Altera Wind AS

Norway

100%

Amundsen Spirit LLC

Marshall Islands

100%

Apollo Spirit LLC

Marshall Islands

100%

Arendal Spirit AS

Norway

100%

Arendal Spirit LLC

Marshall Islands

100%

Aurora Spirit AS

Norway

100%

Bossa Nova Spirit LLC

Marshall Islands

100%

Clipper LLC

Marshall Islands

100%

Current Spirit AS

Norway

100%

Dampier Spirit LLC

Marshall Islands

100%

Gina Krog AS

Norway

100%

Gina Krog Offshore Pte. Ltd.

Singapore

100%

Golar Nor (UK) Limited

United Kingdom

100%

Knarr LLC

Marshall Islands

100%

Lambada Spirit LLC

Marshall Islands

100%

Logitel Offshore Holding AS

Norway

100%

Logitel Offshore Norway AS

Norway

100%

Logitel Offshore Pte. Ltd.

Singapore

100%

Logitel Offshore Rig I Pte. Ltd.

Singapore

100%

Logitel Offshore Rig II Pte. Ltd.

Singapore

100%

Logitel Offshore Rig III LLC

Marshall Islands

100%

Nansen Spirit LLC

Marshall Islands

100%

Navion Bergen AS

Norway

100%

Navion Bergen LLC

Marshall Islands

100%

Navion Gothenburg AS

Norway

100%

Navion Offshore Loading AS

Norway

100%

Peary Spirit LLC

Marshall Islands

100%

Petrojarl I LLC

Marshall Islands

100%

Petrojarl I Production AS

Norway

100%

Piranema LLC

Marshall Islands

100%

Piranema Production AS

Norway

100%

Rainbow Spirit AS

Norway

100%

Salamander Production (UK) Limited

United Kingdom

100%

Samba Spirit LLC

Marshall Islands

100%

Scott Spirit LLC

Marshall Islands

100%

Sertanejo Spirit LLC

Marshall Islands

100%

Siri Holdings LLC

Marshall Islands

100%

Teekay Australia Offshore Holdings Pty Ltd.

Australia

100%

Teekay FSO Finance Pty Ltd.

Australia

100%

F-12

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Teekay Hiload LLC

Marshall Islands

100%

Teekay Offshore Business Process Services (Philippines) Inc.

Philippines

100%

Tide Spirit AS

Norway

100%

Tiro Sidon UK L.L.P.

United Kingdom

100%

Teekay Petrojarl Offshore Siri AS

Norway

100%

TPO Siri LLC

Marshall Islands

100%

Varg LLC

Marshall Islands

100%

Varg Production AS

Norway

100%

Voyageur LLC

Marshall Islands

100%

The following table presents details of non-wholly owned subsidiaries of the Partnership:

Name of Subsidiary

State or Jurisdiction of Incorporation

Proportion of Ownership Interest

KS Apollo Spirit

Norway

89%

Navion Gothenburg LLC

Marshall Islands

50%

Nordic Rio LLC

Marshall Islands

50%

Partrederiet Stena Ugland Shuttle Tankers I DA

Norway

50%

Partrederiet Stena Ugland Shuttle Tankers II DA

Norway

50%

Partrederiet Stena Ugland Shuttle Tankers III DA

Norway

50%

The Partnership has determined that the above entities are non-wholly owned subsidiaries of the Partnership based on its assessment of control. For non-wholly owned subsidiaries, the Partnership is exposed to variable returns from its involvement with the investee and has substantive decision making authority to affect the returns of its investment, as well as the power to direct the activities of the entities that can significantly impact the economic performance of the entity.

(ii) Joint ventures

Joint ventures are joint arrangements whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. Joint control is the contractually agreed sharing of control over an arrangement, which exists when decisions about the relevant activities require unanimous consent of the parties sharing control. The Partnership accounts for joint ventures using the equity method of accounting within equity-accounted investments in the consolidated statements of financial position.

Interests in joint ventures accounted for using the equity method are initially recognized at cost. Subsequent to initial recognition, the carrying value of the Partnership’s interest in a joint venture is adjusted for the Partnership’s share of comprehensive income and distributions of the investee. Profit and losses resulting from transactions with a joint venture are recognized in the consolidated financial statements based on the interests of unrelated investors in the investee. The carrying value of joint ventures is assessed for impairment at each reporting date. Impairment losses on equity-accounted investments may be subsequently reversed in net income. Further information on the impairment of long-lived assets is available in Note 2(l).

The following table presents details of the Partnership's joint ventures:

Name of Joint Venture

State or Jurisdiction of Incorporation

Proportion of Ownership Interest

OOG-TKP FPSO GmbH

Austria

50%

OOG-TKP FPSO GmbH & Co KG

Austria

50%

OOG-TKP Oil Services Ltd.

Cayman Islands

50%

OOG-TK Libra GmbH

Austria

50%

OOG-TK Libra GmbH & Co KG

Austria

50%

OOGTK Libra Operator Holdings Limited

Cayman Islands

50%

OOGTK Libra Producao de Petroleo Ltda

Brazil

50%

OOG-TKP Operator Holdings Limited

Cayman Islands

50%

OOG-TKP Producao de Petroleo Ltda

Brazil

50%

TK-Ocyan Libra Oil Services Ltd.

Cayman Islands

50%

e.Foreign currency translation

The U.S. dollar is the functional and presentation currency of the Partnership. The Partnership’s vessels operate in international shipping markets in which substantially all income and expenses are settled in U.S. dollars. In addition, the Partnership's most significant assets, its vessels and

F-13

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

equipment, are bought and sold in U.S. dollars and the Partnership's most significant liabilities, its commercial bank borrowings, are denominated in U.S. dollars. Foreign currency denominated monetary assets and liabilities are translated using the rate of exchange prevailing at the reporting date and non-monetary assets and liabilities are measured at historic cost and are translated at the rate of exchange at the transaction date. Foreign currency denominated revenues and expenses are measured at average rates during the period. Gains or losses on translation of these items are included in foreign currency exchange gain (loss) in the consolidated statements of income (loss).

f.Cash and cash equivalents

Cash and cash equivalents include cash on hand, non-restricted deposits and short-term investments with original maturities of three months or less.

g.Accounts and other receivable, net

Accounts and other receivable, net includes trade receivables and other unbilled receivables. Accounts and other receivable, net, except for trade receivables, are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, less any allowance for expected credit losses. Trade receivables are recognized initially at their transaction price.

h.Inventory

Inventories are the materials or supplies consumed in the rendering of services. Inventory is valued at the lower of cost and net realizable value. Cost is determined using specific identification where possible and practicable or using the first-in, first-out method. Costs include direct and indirect expenditures incurred in bringing the inventory to its existing condition and location. Net realizable value represents the estimated selling price in the ordinary course of business, less the estimated costs of completion and the estimated costs necessary to make the sale.

i.Related party transactions

In the normal course of operations, the Partnership enters into various transactions with related parties, which have been measured at their exchange value and are recognized in the consolidated financial statements. Related party transactions are further described in Note 22.

j.Vessels and equipment

Vessels and equipment are measured at cost less accumulated depreciation and accumulated impairment losses, if any. Cost includes expenditures that are directly attributable to the acquisition of the asset including the cost of materials and direct labor, any other costs directly attributable to bringing the assets to a working condition for their intended use, and the cost of dismantling and removing the items and restoring the site on which they are located. All pre-delivery costs incurred during the construction of vessels and equipment, including interest, supervision and technical costs, are capitalized. The acquisition cost and all costs incurred to restore used vessels and equipment purchased by the Partnership to the standard required to service the Partnership’s customers are capitalized.

Depreciation of an asset commences when it is available for use. Vessels and equipment are depreciated for each component of the asset classes as follows:


Component						Estimated Useful Life
Dry docks and Overhauls						2.5 - 5 years
Capital Modifications (1)						3 - 20 years
Vessels and Equipment (2)						9 - 35 years

(1)Includes field and contract specific equipment for the Partnership's FPSO units and FSO units, capital upgrades for the Partnership's shuttle tankers and mid-life refurbishments for the Partnership's UMS.

(2)Certain of the Partnership's FPSO units and FSO units have undergone conversions or capital upgrades prior to commencing operations under their current contracts. The estimated useful lives of such vessels is generally substantially lower than that of a comparable newbuilding vessel. For a newbuilding vessel, the Partnership uses an estimated useful life of 20 to 25 years for its FPSO units, 20 years for its shuttle tankers, 35 years for its UMS and 25 years for its towage and offshore installation (or Towage) vessels. The estimated useful life of the Partnership's FSO units are generally the contract term for the unit, inclusive of extension options.

Depreciation on vessels and equipment is calculated on a straight-line basis so as to write-off the net cost of each asset over its expected useful life to its estimated residual value. Residual value of the vessel hull is estimated as the lightweight tonnage of each vessel multiplied by scrap value per ton. The estimated useful lives, residual values and depreciation methods are reviewed annually, with the effect of any changes recognized on a prospective basis.

Vessel capital modifications include the addition of new equipment or can encompass various modifications to the vessel which are aimed at improving or increasing the operational efficiency and functionality of the asset. This type of expenditure is amortized over the estimated useful life of the modification. Expenditures covering recurring routine repairs or maintenance are expensed as incurred.

Generally, the Partnership dry docks each shuttle tanker or towage vessel every two and a half to five years, depending on the nature of work and external requirements. The vessels are required to undergo planned dry docking for replacement of certain components, major repairs and major maintenance of other components, which cannot be carried out while the vessels are operating. The Partnership capitalizes a portion of the costs incurred during dry docking and amortizes those costs on a straight-line basis from the completion of a dry docking over the estimated useful life of the dry dock, which is generally until the commencement of the subsequent dry dock. Included in capitalized dry docking are costs incurred as part of the dry docking to meet regulatory requirements, or expenditures that either add economic life to the vessel, increase the vessel’s earning capacity or improve the vessel’s operating efficiency. A portion of the cost of acquiring a new vessel is allocated to the components expected to be

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ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

replaced or refurbished at the next dry-docking. The Partnership expenses costs related to routine repairs and maintenance performed during dry docking that do not improve operating efficiency or extend the useful lives of the assets.

Advances on newbuilding contracts consists of prepayments related to newbuilding contracts for vessels and equipment not yet delivered to the Partnership and include the share of borrowing costs that are directly attributable to the acquisition of the underlying vessel. When a vessel is delivered, the prepaid amount is reallocated to Vessels and equipment.

k.Right-of-use assets and lease obligations

The Partnership assesses whether a contract is, or contains, a lease at inception of the contract. A right-of-use asset and corresponding lease liability is recognized at the lease commencement date for contracts that are, or contain, a lease component, except for short-term leases and leases of low value.

Agreements to charter in vessels and to lease land and buildings for which the Partnership substantially has the right to control the asset for a period of time in exchange for consideration are recognized in the consolidated statements of financial position as right-of-use assets within Other assets and are initially measured at cost, which comprises the initial amount of the lease liabilities adjusted for any lease payments made at or before the commencement date. Subsequently, the right-of-use assets are measured at cost less accumulated depreciation and impairment losses, if any. The right-of-use assets are depreciated on a straight-line basis over the lesser of the lease term or remaining life of the underlying asset, depending on the lease terms.

The Partnership charters in vessels from other vessel owners on time-charter contracts, whereby the vessel owner provides use of the vessel to the Partnership, as well as operates the vessel for the Partnership. A time-charter contract is typically for a fixed period of time, although in certain cases the Partnership may have the option to extend the charter. The Partnership will typically pay the owner a daily hire rate that is fixed over the duration of the charter. The Partnership is generally not required to pay the daily hire rate during periods the vessel is not able to operate.

The Partnership has determined that all of its time-charter-in contracts contain both a lease component (lease of the vessel) and a non-lease component (operation of the vessel). The Partnership has allocated the contract consideration between the lease component and non-lease component on a relative standalone selling price basis. Given that there are no observable standalone selling prices for either of these two components, judgment is required in determining the standalone selling price of each component. The standalone selling price of the non-lease component has been determined using a cost-plus approach, whereby the Partnership estimates the cost to operate the vessel using cost benchmarking studies prepared by a third party, when available, or internal estimates when not available, plus a profit margin. The standalone selling price of the lease component has been determined using an adjusted market approach, whereby the Partnership calculates a rate excluding the operating component based on a market time-charter rate from published broker estimates, when available, or internal estimates when not available. The discount rate of the lease is determined using the Partnership’s incremental borrowing rate, which is based on the fixed interest rate the Partnership could obtain when entering into a secured loan facility of similar term.

The Partnership has elected to recognize the lease payments of short-term leases in profit or loss on a straight-line basis over the lease term and variable lease payments not dependent on a rate or index in the period in which the obligation for those payments is incurred, which is consistent with the recognition of payment for the non-lease component. Short-term leases are leases with an original term of one year or less, excluding those leases with an option to extend the lease for greater than one year or an option to purchase the underlying asset, that the lessee is reasonably certain to exercise.

The corresponding lease obligation is recognized as a liability in the consolidated statements of financial position under Accounts payable and other and initially measured at the present value of the outstanding lease payments at the commencement date.

The Partnership recognizes the lease payments for short-term leases and leases of low value as an operating expense on a straight-line basis over the term of the lease.

l.Asset impairment

At each reporting date the Partnership assesses whether there is any indication that assets or cash generating units, relating specifically to its vessels and equipment and right-of use-assets, are impaired. This assessment includes a review of internal and external factors which includes, but is not limited to, changes in the technological, political, economic or legal environments in which the Partnership operates, structural changes in the industry, changes in the level of demand, physical damage and obsolescence due to technological changes. The Partnership has determined that, for impairment purposes, each individual vessel, except for the Partnership's contract of affreightment (or CoA) vessels, is a cash generating unit. The Partnership has determined that all CoA vessels are a single cash generating unit.

An impairment is recognized if the recoverable amount, determined as the higher of the estimated fair value less costs of disposal or the value in use, is less than the carrying value of the asset or cash generating unit. In cases where an active second-hand sale and purchase market does not exist, the Partnership uses a discounted cash flow approach to estimate the fair value of its vessel and equipment. In cases where an active second-hand sale and purchase market exists, an appraised value is used to estimate the fair value of the vessel and equipment. An appraised value is generally the amount the Partnership would expect to receive if it were to sell the vessel. Such appraisal is normally completed by the Partnership. The value in use is the present value of the future cash flows that the Partnership expects to derive from the asset or cash generating unit. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail.

At each reporting date the Partnership assesses whether there is any indication that an impairment loss may have decreased. Where an impairment loss subsequently reverses, the carrying amount of the asset or cash generating unit is increased to the revised estimate.

m.Goodwill

Goodwill represents the excess of the price paid for the acquisition of a business over the fair value of the net tangible and intangible assets and liabilities acquired. Goodwill is allocated to the cash generating unit or units to which it relates. The Partnership identifies cash generating units as

F-15

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

identifiable groups of assets whose cash inflows largely independent of the cash inflows from other assets or groups of assets. The Partnership has identified the shuttle tanker segment as the group of cash generating units to which the Partnership's goodwill relates.

Goodwill is evaluated for impairment on an annual basis or more frequently if an event occurs or circumstances change that would indicate that the recoverable amount of a reporting unit was below its carrying value. Impairment is determined for goodwill by assessing if the carrying value of a cash generating unit, including the allocated goodwill, exceeds its recoverable amount determined as the greater of the estimated fair value less costs of disposal or the value in use. Impairment losses recognized in respect of a cash generating unit are first allocated to the carrying value of goodwill and any excess is allocated to the carrying amount of assets in the cash generating unit. Any goodwill impairment is charged to Impairment expense, net on the consolidated statements of income (loss) in the period in which the impairment is identified. Impairment losses on goodwill are not subsequently reversed.

n.Revenues

Each vessel charter may, depending on its terms, contain a lease component, a non-lease component or both. Revenues that are fixed on or prior to the commencement of the contract are recognized by the Partnership on a straight-line basis daily over the term of the contract.

A highly probable criterion is required to be met with regards to recognizing revenue arising from variable consideration resulting from contract modifications and claims. For variable consideration, revenue is only recognized to the extent that it is highly probable that a significant reversal in the amount of revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved.

(i) FPSO Contracts

Pursuant to an FPSO contract, the Partnership charters an FPSO unit to a customer for a fixed period of time, generally more than one year. The obligations within an FPSO contract, which include the lease of the FPSO unit to the charterer as well as the operation of the FPSO unit, are satisfied as services are rendered over the duration of such contract, as measured using the time that has elapsed from commencement of performance. Fees relating to the lease and operation of the FPSO (or hire) are typically invoiced monthly in arrears, based on a fixed daily hire amount. In certain FPSO contracts, the Partnership is entitled to a lump sum amount due upon commencement of the contract and may also be entitled to termination fees if the contract is canceled early. While the fixed daily hire amount may be the same over the term of the FPSO contract, in certain cases, the daily hire amount declines over the duration of the FPSO contract. As a result of the Partnership accounting for compensation from such charters on a straight-line basis over the duration of the charter, FPSO contracts where revenues are recognized before the Partnership is entitled to such amounts under the FPSO contracts will result in the Partnership recognizing a contract asset and FPSO contracts where revenues are recognized after the Partnership is entitled to such amounts under the FPSO contracts will result in the Partnership recognizing a contract liability.

Some FPSO contracts include variable consideration components in the form of expense adjustments or reimbursements, incentive compensation and penalties. For example, some FPSO contracts contain provisions that allow the Partnership to be compensated for increases in the Partnership's costs to operate the unit during the term of the contract. Such provisions may be in the form of annual hire rate adjustments for changes in inflation indices or foreign currency rates, or in the form of cost reimbursements for vessel operating expenditures incurred. The Partnership may also earn additional compensation from periodic production tariffs, which are based on the volume of oil produced, the price of oil, as well as other monthly or annual operational performance measures. During periods in which production on the FPSO unit is interrupted, penalties may be imposed. Variable consideration under the Partnership’s contracts is typically recognized as incurred as either such revenues are allocated and accounted for under lease accounting requirements or, alternatively, when such consideration is allocated to the distinct period in which such variable consideration was earned. The Partnership does not engage in any specific activities to minimize residual value risk. Given the uncertainty involved in oil field production estimates and the resulting impact on oil field life, FPSO contracts typically will include extension options or options to terminate early.

The Partnership has allocated the contract consideration between the lease component and non-lease component on a relative standalone selling price basis. Given that there are no observable standalone selling prices for either of these two components, judgment is required in determining the standalone selling price of each component. The standalone selling price of the non-lease component has been determined using a cost-plus approach, whereby the Partnership estimates the cost to operate the unit using internal estimates, plus a profit margin. The standalone selling price of the lease component has been determined using an adjusted market approach, whereby the Partnership calculates a rate excluding the operating component based on a market rate from published broker estimates, when available, or internal estimates when not available.

(ii) CoAs

Voyages performed pursuant to a CoA for the Partnership’s shuttle tankers are priced based on the pre-agreed terms in the CoA. The obligations within a voyage performed pursuant to a CoA, which the Partnership believes will typically include the lease of the vessel to the charterer as well as the operation of the vessel, are satisfied as services are rendered over the duration of the voyage, as measured using the time that has elapsed from commencement of performance. In addition, any expenses that are unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions, are the responsibility of the vessel owner. Consideration for such voyages consists of a fixed daily hire rate for the duration of the voyage, the reimbursement of costs incurred from fuel consumed during the voyage, as well as a fixed lump sum intended to compensate for time necessary for the vessel to return to the field following completion of the voyage. While such consideration is generally fixed, certain sources of variability exist, including variability in the duration of the voyage and the actual quantity of fuel consumed during the voyage. Payment for the voyage is not due until the voyage is completed. The duration of a single voyage will typically be less than two weeks and, as a result, the Partnership has applied the practical expedient in IFRS 15.121(a). The Partnership does not engage in any specific activities to minimize residual value risk due to the short-term nature of the contracts.

F-16

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

approach, whereby the Partnership estimates the cost to operate the vessel using internal estimates, plus a profit margin. The standalone selling price of the lease component has been determined using an adjusted market approach, whereby the Partnership calculates a rate excluding the operating component based on a market rate from published broker estimates, when available, or internal estimates when not available.

(iii) Time Charter Contracts

Pursuant to a time charter contract, the Partnership charters a vessel or FSO unit to a customer for a fixed period of time, generally one year or more. The obligations under a time-charter contract, which includes the lease of the vessel to the charterer as well as the operation of the vessel, are satisfied as services are rendered over the duration of such contract, as measured using the time that has elapsed from commencement. In addition, any expenses that are unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions, are the responsibility of the customer, as long as the vessel is not off-hire. Hire is typically invoiced monthly in advance for time-charter contracts, based on a fixed daily hire amount. In certain long-term time-charters, the fixed daily hire amount will increase on an annual basis by a fixed amount to offset expected increases in operating costs. Therefore, the Partnership has applied the practical expedient in IFRS 15.B16.

As a result of the Partnership accounting for compensation from such charters on a straight-line basis over the duration of the charter, such fixed increases in rate will result in revenues being accrued in the first portion of the charter and such amount drawn down in the last portion of the charter. Some times charters include variable consideration components in the form of expense adjustments or reimbursements, incentive compensation and penalties. For example, certain time charters contain provisions that allow the Partnership to be compensated for increases in the Partnership's costs during the term of the charter. Such provisions may be in the form of annual hire rate adjustments for changes in inflation indices or in the form of cost reimbursements for vessel operating expenditures or dry-docking expenditures. During periods in which the vessels are off-hire or minimum speed and performance metrics are not met, penalties may be imposed. Variable consideration under the Partnership’s contracts is typically recognized as incurred as either such revenues are allocated and accounted for under lease accounting requirements or, alternatively, as such consideration is allocated to the distinct period in which such variable consideration was earned. The Partnership does not engage in any specific activities to minimize residual value risk.

The Partnership has allocated the contract consideration between the lease component and non-lease component on a relative standalone selling price basis. Given that there are no observable standalone selling prices for either of these two components, judgment is required in determining the standalone selling price of each component. The standalone selling price of the non-lease component has been determined using a cost-plus approach, whereby the Partnership estimates the cost to operate the vessel using internal estimates, plus a profit margin. The standalone selling price of the lease component has been determined using an adjusted market approach, whereby the Partnership calculates a rate excluding the operating component based on a market rate from published broker estimates, when available, or internal estimates when not available.

(iv) Bareboat Charter Contracts

Pursuant to a bareboat charter contract, the Partnership charters a vessel or FSO unit to a customer for a fixed period of time, generally one year or more, at rates that are generally fixed. The customer is responsible for operation and maintenance of the vessel with their own crew as well as any expenses that are unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions. If the vessel goes off-hire due to a mechanical issue or any other reason, the monthly hire received by the vessel owner is normally not impacted by such events. A bareboat charter contract contains only a lease component and revenue is recognized over the duration of such contract, as measured using the time that has elapsed from commencement of the lease. Hire is typically invoiced monthly in advance for bareboat charters, based on a fixed daily hire amount. Revenue is recognized in line with invoicing using the practical expedient in IFRS 15.B16.

(v) Voyage Charters

Voyage charters are charters for a specific voyage. Voyage charters for the Partnership’s shuttle tankers and towage vessels are priced on a current or “spot” market rate. The obligations within a voyage charter contract are satisfied as services are rendered over the duration of the voyage, as measured using the time that has elapsed from commencement of performance. In addition, expenses that are unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions, are the responsibility of the vessel owner. The Partnership’s voyage charters for shuttle tankers normally contain a lease, whereas for towage vessels such contracts do not normally contain a lease. Such determination involves judgment about the decision-making rights the charterer has under the contract. Consideration for such contracts is generally fixed; however, certain sources of variability exist. Delays caused by the charterer result in additional consideration. Payment for the voyage is not due until the voyage is completed. The duration of a single voyage will typically be less than three months and, as a result, the Partnership has applied the practical expedient in IFRS 15.121(a). The Partnership does not engage in any specific activities to minimize residual value risk due to the short-term nature of the contracts.

Where the term of the contract is based on the duration of a single voyage, the Partnership uses a load-to-discharge basis in determining proportionate performance. Consequently, the Partnership does not begin recognizing revenue until a voyage charter has been agreed to by the customer and the Partnership, even if the vessel has discharged its prior cargo and is sailing to the anticipated load location for its next voyage. For towage voyages, proportionate performance is determined based on commencement of the tow to completion of the tow.

The consolidated statements of financial position reflect, in Other assets, the accrued portion of revenues for those voyages that commence prior to the consolidated statement of financial position date and complete after the date of the consolidated statement of financial position and reflect, in Accounts payable and other, the deferred portion of revenues which will be earned in subsequent periods.

(vi) Management Fees and Other

The Partnership also generates revenues from the operation of volatile organic compounds (or VOC) systems on certain of the Partnership’s shuttle tankers, and from the management of certain vessels on behalf of the disponent owners or charterers of these assets. Such services include the arrangement of third-party goods and services for the asset’s disponent owner or charterer. The obligations within these contracts typically consists of crewing, technical management, insurance and, potentially, commercial management. The obligations are satisfied concurrently and rendered over the duration of the management contract, as measured using the time that has elapsed from commencement of the contract. Consideration for

F-17

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

such contracts generally consists of a fixed monthly management fee, plus the reimbursement of crewing costs for vessels being managed and all operational costs for the VOC systems. Management fees are typically invoiced monthly. Revenue is recognized in line with invoicing using the practical expedient in IFRS 15.B16.

o.Direct operating costs

Direct operating cost include the following expenses: voyage expenses; operating expenses; charter hire and compensation. Voyage expenses are all expenses unique to a particular voyage, including bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions. Operating expenses include ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses. Charter hire expenses represent the cost to charter-in a vessel for a fixed period of time. Compensation includes the compensation costs for crewing and shore-based employees.

Voyage expenses and operating expenses are recognized when incurred except when the Partnership incurs pre-operational costs related to the repositioning of a vessel that relates directly to a specific customer contract, that generates or enhances resources of the Partnership that will be used in satisfying performance obligations in the future, and where such costs are expected to be recovered via the customer contract. In this case, such costs are capitalized as contract costs and amortized over the duration of the customer contract.

The Partnership recognizes operating leases from vessels chartered from other owners in charter hire expenses.

p.Financial instruments

Classification and measurement

The table below summarizes the Partnership’s classification and measurement of financial assets and liabilities:

Measurement Category

Consolidated Statement of Financial Position Account

Financial assets

Cash and cash equivalents

Amortized cost

Cash and cash equivalents

Restricted cash

Amortized cost

Financial assets

Derivative instruments

FVTPL

Financial assets

Other financial assets

Amortized cost

Financial assets

Accounts receivable

Amortized cost

Accounts and other receivable, net

Due from related parties

Amortized cost

Due from related parties

Investment in finance leases

Amortized cost

Other assets

Financial liabilities

Accounts payable and other

Amortized cost

Accounts payable and other

Derivative instruments

FVTPL

Other financial liabilities

Obligations relating to finance leases

Amortized cost

Other financial liabilities

Due to related parties

Amortized cost

Due to related parties

Borrowings

Amortized cost

Borrowings

The classification of financial assets depends on the specific business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.

At initial recognition, the Partnership measures a financial asset or liability at its fair value plus, in the case of a financial asset not at fair value through profit or loss (or FVTPL), transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets and liabilities carried at FVTPL are expensed in Other income (expenses), net in the consolidated statements of income (loss).

Financial assets are measured at amortized cost dependent on their contractual cash flow characteristics and the business model for which they are held. Financial assets classified as amortized cost are recorded initially at fair value, then subsequently measured at amortized cost using the effective interest rate method, less any impairment.

Financial liabilities measured at amortized cost are initially recorded at fair value and, in the case of borrowings, net of directly attributable transaction costs. Financial liabilities are then subsequently measured at amortized cost using the effective interest rate method with gains or losses recognized in the consolidated statements of income (loss).

Impairment

The Partnership recognizes a loss allowance for expected credit losses (or ECL) on financial assets measured subsequently at amortized cost, including trade receivables, amounts due from related parties, investments in finance leases and contract assets. The ECL is recognized upon inception of the financial asset and revised at each reporting date thereafter until maturity or disposal of the financial asset. The Partnership measures the loss allowance for a financial asset at an amount equal to the lifetime ECL if the credit risk on a financial asset has increased significantly since initial recognition. If the credit risk on a financial asset has not increased significantly, the Partnership measures the loss allowance for that financial instrument at an amount equal to the 12-months ECL. In making this assessment, the Partnership considers information that is reasonable and supportable, including historical experience and forward looking information that is available without undue cost or effort.

F-18

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The Partnership utilizes a simplified approach for measuring the loss allowance at an amount equal to the lifetime ECL for trade receivables, contract assets and investments in finance leases. The ECL on trade receivables are estimated by using reference to past default experience of the debtor and an analysis of the debtor’s current financial position, which also forms a basis for the Partnership's future expectations for potential defaults of the debtor.

The ECL is presented as a direct reduction to the carrying value of the financial asset it relates to. The initial recognition of an ECL and all changes to an ECL at each reporting date thereafter are reflected in Other income (expenses), net in the consolidated statements of income (loss). As at December 31, 2020, the Partnership recorded an ECL of $1.4 million (December 31, 2019 - $nil. January 1, 2019 - $nil).

Derivative instruments

The Partnership selectively utilizes derivative financial instruments primarily to manage financial risks, including foreign exchange risks and interest rate risks. All derivative instruments are initially recorded at fair value as either assets or liabilities in the accompanying consolidated statements of financial position and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative instrument.

Hedge accounting is applied when the derivative is designated as a hedge of a specific exposure and there is assurance that it will continue to be highly effective as a hedge based on an expectation of offsetting cash flows or fair value. Hedge accounting is not applied if the hedge is not effective or will no longer be effective, the derivative was sold or exercised, or the hedged item was sold, repaid or is no longer probable of occurring. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as a hedge or the hedging relationship is terminated. Once discontinued, the cumulative change in fair value of a derivative that was previously recorded in Other comprehensive income by the application of hedge accounting will be recognized in the Partnership's profit or loss over the remaining term of the original hedging relationship as amounts related to the hedged item are recognized in profit or loss. The Partnership has not designated, for accounting purposes, any derivatives as hedges of a specific exposure for all periods presented in these consolidated financial statements.

For derivative financial instruments that are not designated as accounting hedges, the changes in the fair value of the derivative financial instruments are recognized in earnings. Gains and losses from the Partnership’s non-designated foreign currency forward contracts and interest rate swaps are recorded in realized and unrealized gain (loss) on derivative instruments in the consolidated statements of income (loss). The assets or liabilities relating to unrealized mark-to-market gains and losses on derivative financial instruments are recorded in financial assets and other financial liabilities, respectively.

q.Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, regardless of whether that price is directly observable or estimated using another valuation technique. In estimating the fair value of an asset or a liability, the Partnership takes into account the characteristics of the asset or liability if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.

Fair value measurement is disaggregated into three hierarchical levels: Level 1, 2 or 3. Fair value hierarchical levels are based on the degree to which the inputs to the fair value measurement are observable. The levels are as follows:


Level 1 -			Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 -			Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the asset’s or liability’s anticipated life.
Level 3 -			Inputs are unobservable and reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs in determining the estimate.

Further information on fair value measurements is described in Note 4.

r.Income taxes

The Partnership is subject to income taxes relating to its subsidiaries in Norway, Australia, Brazil, the United Kingdom, Singapore, Qatar, Canada, Luxembourg and the Netherlands.

(i) Current income tax

Current income tax assets and liabilities are measured at the amount expected to be paid to tax authorities, net of recoveries based on the tax rates and laws enacted or substantively enacted at the reporting date.

(ii) Deferred income tax

Deferred income tax liabilities are provided for using the liability method on temporary differences between the tax bases used in the computation of taxable income and carrying amounts of assets and liabilities in the consolidated financial statements.

Deferred income tax assets are recognized for all deductible temporary differences, carry forward of unused tax credits and unused tax losses, to the extent that it is probable that deductions, tax credits and tax losses can be utilized. Such deferred income tax assets and liabilities are not recognized if the temporary difference arises from goodwill or from the initial recognition of other assets and liabilities in a transaction that affects neither the taxable income nor the accounting income, other than in a business combination. The carrying amount of deferred income tax assets are reviewed at each reporting date and reduced to the extent it is no longer probable that the income tax asset will be recovered.

Deferred income tax liabilities are recognized for taxable temporary differences associated with equity-accounted investments, except where the Partnership is able to control the reversal of the temporary difference and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred income tax assets arising from deductible temporary differences associated with such investments are only recognized

F-19

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

to the extent that it is probable that there will be sufficient taxable income against which to utilize the benefits of the temporary differences and they are expected to reverse in the foreseeable future.

Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset realized, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred income tax liabilities and assets reflects the tax consequences that would follow from the manner in which the Partnership expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities.

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority within a single taxable entity or the Partnership intends to settle its current tax assets and liabilities on a net basis in the case where there exist different taxable entities in the same taxation authority and when there is a legally enforceable right to set off current tax assets against current tax liabilities.

s.Provisions

Provisions are recognized when the Partnership has a present obligation, either legal or constructive, as a result of a past event, it is probable that the Partnership will be required to settle the obligation and a reliable estimate of the amount of the obligation can be made. Provisions are recorded within Accounts payable and other in the consolidated statements of financial position.

The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the obligation, its carrying amount is the present value of those cash flows.

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the receivable is recognized as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

(i) Decommissioning liability

The Partnership has a decommissioning liability related to the requirement to remove the sub-sea mooring and riser system associated with the Randgrid FSO unit and to restore the environment surrounding the facility. The costs associated with this decommissioning liability are to be reimbursed by the charterer, if certain conditions associated with the work are met. The obligation is expected to be settled at the end of the contract under which the FSO unit currently operates.

The Partnership recognizes a decommissioning liability in the period in which it has a present legal or constructive liability and a reasonable estimate of the amount can be made. Liabilities are measured based on current requirements, technology and price levels and the present value is calculated using amounts discounted over the period for which the cash flows are expected to occur. Amounts are discounted using a rate that reflects the risks specific to the liability. On a periodic basis, management reviews these estimates and changes, if any, will be applied prospectively. The estimated decommissioning liability is recorded as a non-current liability, with a corresponding increase in the carrying amount of the related asset. As the decommissioning liability will be covered by contractual payments to be received from the charterer, the Partnership has recorded a separate receivable. The liability and associated receivable are increased in each reporting period due to the passage of time, and the amount of accretion is charged to Other income (expense), net in the period. Periodic revisions to the estimated timing of cash flows, to the original estimated undiscounted cost and to changes in the discount rate can also result in an increase or decrease to the decommissioning liability and associated receivable. Actual costs incurred upon settlement of the obligation are recorded against the decommissioning liability to the extent of the liability recorded.

t.Assets held for sale

Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the non-current asset or disposal group is available for immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification subject to limited exceptions.

Non-current assets and disposal groups classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell and are classified as current. Once classified as held for sale, vessels and equipment are no longer depreciated.

u.Deferred financing costs

Deferred financing costs related to a borrowing, including bank fees, commissions and legal expenses, are capitalized and amortized, over the term of the relevant loan facility, to interest expense using an effective interest rate method. Deferred financing costs are presented as a reduction from the carrying amount of the related financial liability, unless no amounts have been drawn under the debt liability or the debt issuance costs exceed the carrying value of the related debt liability, in which case the debt issuance costs are presented as Other non-current assets.

If a debt modification is considered substantial, fees paid to amend an arrangement pursuant to which a credit facility is extinguished are associated with the extinguishment of the old debt instrument and included in determining the debt extinguishment gain or loss to be recognized. Any unamortized deferred financing costs are written off. If a debt modification is not considered substantial, then the fees are associated with the modification, along with any existing unamortized deferred financing costs and premium or discount, are amortized as an adjustment of interest expense over the remaining term of the modified debt instrument using the effective interest method.

v.Critical accounting judgments and key sources of estimation uncertainty

The preparation of financial statements requires management to make critical judgments, estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses that are not readily apparent from other sources, during the reporting period. These estimates and

F-20

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

Critical judgments and estimates made by management and utilized in the normal course of preparing the Partnership’s consolidated financial statements are outlined below.

Critical accounting judgments

(i) Determination of control

The Partnership consolidates an investee when it controls the investee, with control existing if, and only if, the Partnership has (a) power over the investee, (b) exposure, or rights, to variable returns from involvement with the investee and (c) the ability to use that power over the investee to affect the amount of the Partnership’s returns.

In determining if the Partnership has power over an investee, judgments are made when identifying which activities of the investee are relevant in significantly affecting returns of the investee and the extent of existing rights that give the Partnership the current ability to direct the relevant activities of the investee. Judgments are required to assess the Partnership's control over its non-wholly owned subsidiaries and investments in joint ventures. Judgments are made as to the amount of potential voting rights, the existence of contractual relationships that provide voting power and the ability for the Partnership to appoint directors. The Partnership enters into voting agreements which provide it the ability to contractually direct the relevant activities of the investee. In assessing if the Partnership has exposure, or rights, to variable returns from involvement with the investee, judgments are made concerning whether returns from an investee are variable and how variable those returns are on the basis of the substance of the arrangement, the size of those returns and the size of those returns relative to others, particularly in circumstances where the Partnership’s voting interest differs from the ownership interest in an investee. In determining if the Partnership has the ability to use its power over the investee to affect the amount of its returns, judgments are made when the Partnership is an investor as to whether it is a principal or agent and whether another entity with decision making rights is acting as the Partnership’s agent. If it is determined that the Partnership is acting as an agent, as opposed to a principal, the Partnership does not control the investee. See Note 2d(ii) for additional information.

(ii) Lease classification and term

At the inception of the charter, the classification of the lease as an operating lease or a finance lease may involve the use of judgment as to the determination of the lease term. Such judgment is required as the duration of certain of the Partnership's charters is unknown at commencement of the charter. The charterer may have the option to extend the charter or terminate the charter early. In addition, certain charters impose penalties on the charterer if it terminates the charter early and such penalties can vary in size depending on when, during the term of the charter, the termination right is exercised. Such penalties could impact the determination of the lease term and requires the use of judgment.

(iii) Determination if a contract contains a lease

Each vessel charter may, depending on its terms, contain a lease component, a non-lease component or both. Judgment is required in determining the composition of the lease and non-lease components of the Partnership's charters. The Partnership has determined the following for its charters:

FPSO Contracts

CoA(2)

Time Charter

Bareboat Charter

Voyage Charter (1)

Lease component

Yes

Depends

Non-lease component

Yes

Depends

(1)The Partnership believes that the conclusion as to whether or not a voyage charter contains a lease component rests principally on whether the customer has the substantive right to select and change the load and discharge ports. If the customer does not have this substantive right then the charter would not contain a lease component. The Partnership has categorized the charters for its shuttle tankers that are priced on spot market rates, and its towage vessels, as voyage charters Based on the conclusion above, the Partnership has determined that the contracts for its shuttle tankers classified as voyage charters normally contain a lease, wheras the contracts for its towage vessels do not normally contain a lease.

(2)The Partnership has determined that as the relevant decisions about how and for what purpose the vessel is used are not predetermined under a CoA, but the customer has the right to make those relevant decisions, then the customer directs the use of the vessel. Based on this conclusion, the customer has the substantive right to select and change the load and discharge ports under a CoA charter and therefore the Partnership believes that a CoA charter contains a lease component, in addition to a non-lease component.

The Partnership also generates revenues from the operation of VOC systems on certain of the Partnership’s shuttle tankers, and from the management of certain vessels on behalf of the disponent owners or charterers of these assets. The Partnership has determined that as the leasing of its VOC equipment is classified as a finance lease, the finance income associated with these leases are recognized as lease income. Additionally, as the contracts pertaining to the management of certain vessels on behalf of the disponent owners or charterers of these assets do not contain an identified asset, the Partnership believes that these do not contain a lease.

For charters which contain both, the Partnership has allocated the contract consideration between the lease component and non-lease component on a relative standalone selling price basis. Given that there are no observable standalone selling prices for either of these two components, judgment is required in determining the standalone selling price of each component. The standalone selling price of the non-lease component has been determined using a cost-plus approach, whereby the Partnership estimates the cost to operate the unit using internal estimates, plus a profit margin. The standalone selling price of the lease component has been determined using an adjusted market approach, whereby the Partnership calculates a rate excluding the operating component based on a market rate from published broker estimates, when available, or internal estimates when not available.

F-21

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(iv) Impairment

Judgment is applied when determining whether indicators of impairment exist when assessing the carrying values of the Partnership’s assets, the likelihood the Partnership will sell the vessel or equipment prior to the end of its useful life, the estimation of a cash generating unit’s future revenues and direct costs, and the determination of discount rates. The Partnership has determined that, as the cash inflows of the individual vessels in its CoA fleet are not largely independent from each other, the CoA fleet is treated as a single cash generating unit for impairment purposes.

Estimation uncertainty

(i) Decommissioning liabilities

Decommissioning costs will be incurred at the end of the operating life of one of the Partnership’s vessels. This obligation is often many years in the future and requires judgment to estimate. The estimate of decommissioning costs can vary in response to many factors including changes in relevant legal, regulatory, and environmental requirements, the emergence of new restoration techniques or experience at other production sites. Inherent in the calculations of these costs are assumptions and estimates including the ultimate settlement amounts, inflation factors, discount rates, and timing of settlements. See Notes 2s(i) and 15 for additional information.

(ii) Vessels and equipment - useful lives and residual value

The cost of the Partnership's vessels and equipment are depreciated on a straight-line basis over each asset's estimated useful life to an estimated residual value. The estimated useful life of the Partnership's vessels, including individual components, takes into account design life, commercial considerations and regulatory restrictions. The determination of the components, if any, of an asset and the estimated useful life of such asset or components involves judgment. See Note 2j for additional information.

(iii) Impairment

The recoverable amounts of each vessel, being defined as a cash-generating unit, is the higher of its fair value less cost of disposal and its value in use. The fair value less cost of disposal calculation is based on the discounted cash flow model and is the same as the value in use. Value in use calculations are based on contracted cash flows and estimates of uncontracted cash flows for the useful lives of each vessel, including residual values discounted by an estimated discount rate. Assumptions on uncontracted cash flows are based on several variables, such as comparing the specifications on a particular vessel with planned new projects around the world, assessment of investment levels to redeploy the vessel on a new field and assumptions on rates to be achieved from redeployment. The key assumptions used for the impairment testing of our fleet are described in Note 11.

All impairment assessment calculations demand a high degree of estimation. The Partnership must make complex assessment of the expected cash flows arising from such assets and the selection of discount rates. Changes to these estimates could have significant impact on the impairments recognized and future changes may lead to reversals of recognized impairments. See Notes 11 and 14 for additional information.

(iv) Taxes

The future realization of deferred tax assets depends on the existence of sufficient taxable income to utilize tax losses. This analysis requires, among other things, the use of estimates and projections in determining future reversals of temporary differences, forecasts of future profitability and evaluating potential tax-planning strategies.

(v) Going concern

The Partnership's assessment of its ability to continue operating on a going concern basis requires judgment and the estimation of the probability in obtaining additional sources of financing to meet its obligations and commitments and minimum liquidity requirements under its financial covenants. See note 2(b) for additional information.

(vi) COVID-19

In March 2020, the World Health Organization declared a global pandemic related to COVID-19. To date, there has been significant volatility in capital markets, commodity prices and foreign currencies, restrictions on the conduct of business in many jurisdictions, and the global movement of people and some goods has become restricted. The Partnership considered the impacts of these circumstances on the key critical judgments, estimates and assumptions that affect the reported and contingent amount of assets, liabilities, revenues and expenses, including whether any additional indicators of impairment were present for the year ended December 31, 2020. Based on the Partnership’s assessments, no additional impairments were required as at December 31, 2020 and the Partnership has not experienced any material business interruptions or financial impact as a result of the COVID-19 pandemic. The extent to which the COVID-19 pandemic may impact the the Partnership's results of operations and financial condition, including any future possible impairments, will depend on future developments, which are highly uncertain and cannot be predicted, including new information that may emerge concerning the severity of the virus or its variants, the effectiveness of vaccines and other actions to contain or treat its impact, among others. The Partnership will continue to monitor the situation and review its critical estimates and judgments as circumstances evolve.

w.Earnings (loss) per Limited Partnership Unit

The Partnership calculates basic earnings (loss) per unit by dividing net income (loss) attributable to limited partners by the weighted average number of limited partnership common units outstanding during the period. The net income (loss) attributable to limited partners is allocated between the Class A and Class B limited partners' based on their proportionate ownership percentages. Basic earnings (loss) per unit has been presented on an aggregate basis and includes net income (loss) attributable to Class A limited partners and net income (loss) attributable Class B limited partners, which, if disaggregated, would not have a material effect.

F-22

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

For the purpose of calculating diluted earnings (loss) per unit, the Partnership adjusts net income (loss) attributable to limited partners, and the weighted average number of limited partnership common units outstanding, for the effects of all dilutive potential limited partnership common units, consisting of restricted common units and any warrants exercisable for common units. Consequently, the weighted average number of common units outstanding is increased assuming conversion of the restricted units and exercise of the warrants using the treasury stock method. The computation of diluted earnings (loss) per unit does not assume the issuance of common units if the effect would be anti-dilutive.

x.Segments

The Partnership’s operating segments are components of the business for which discrete financial information is reviewed regularly by the Chief Operating Decision Maker (or CODM) to assess performance and make decisions regarding resource allocation. The Partnership has assessed the CODM to be its Chief Executive Officer. As at December 31, 2020, the Partnership’s operating segments are the FPSO, Shuttle tanker, FSO, UMS and Towage segments.

y.Employee Pension Plans

The Partnership has defined contribution pension plans covering the majority of its employees. Pension costs associated with the Partnership’s required contributions under its defined contribution pension plans are based on a percentage of employees’ salaries and are charged to earnings in the year incurred. During the year ended December 31, 2020, the amount of cost recognized for the Partnership’s defined contribution pension plans was $5.5 million (December 31, 2019 - $5.2 million).

The Partnership also has defined benefit pension plans covering a small number of active and retired employees in Norway. The Partnership accrues the costs and related obligations associated with its defined benefit pension plans based on actuarial computations using the projected benefits obligation method and management’s best estimates of expected plan investment performance, salary escalation, and other relevant factors. For the purpose of calculating the expected return on plan assets, those assets are valued at fair value. The overfunded or underfunded status of the defined benefit pension plans is recognized as assets or liabilities in the consolidated statements of financial position. The Partnership recognizes as a component of Other comprehensive income (loss), the gains or losses that arise during a period but that are not recognized as part of net periodic benefit costs. The pension assets have been guaranteed a minimum rate of return by the provider, thus reducing potential exposure to the Partnership to the extent the provider honors its obligations. The Partnership's funded status relating to its defined benefit pension plans was a shortfall of $0.7 million as at December 31, 2020 (December 31, 2019 - surplus of $0.3 million)

z.Future changes in Accounting Policies

i.Interest Rate Benchmark Reform — Phase 2 (Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16)

In August 2020, the International Accounting Standards Board published Interest Rate Benchmark Reform — Phase 2 (Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16) (or Phase 2 Amendments), effective January 1, 2021, with early adoption permitted. The Phase 2 Amendments provide additional guidance to address the issues that will arise during the transition of benchmark interest rates and primarily relate to the modification of financial assets, financial liabilities and lease liabilities where the basis for determining the contractual cash flow changes as a result of the replacement of an existing interest rate benchmark, allowing for prospective application of the new applicable benchmark interest rate, and to the application of hedge accounting, providing an exception such that changes in the designation of hedge accounting relationships that are needed to reflect the changes required by the benchmark interest rate reform do not result in the discontinuation of hedge accounting. The Partnership is adopting the Phase 2 Amendments on January 1, 2021 and does not expect this adoption to have a significant impact on the Partnership’s consolidated financial statements.

Progress towards implementation of alternative benchmark interest rates

The Partnership is exposed to the impact of interest rate changes, primarily through its floating-rate borrowings that require it to make interest payments based on LIBOR. The Partnership uses interest rate swaps to reduce its exposure to market risk from changes in interest rates.

The Partnership plans to transition the majority of its LIBOR-linked contracts to risk-free rates through amendments to fallback clauses in its floating-rate credit facilities and debt instruments which would change the basis for determining the interest rate cash flows from LIBOR to a risk-free rate at an agreed point in time. This is expected to be implemented during 2021.

Interest rate benchmark transition for non-derivative financial liabilities

As at December 31, 2020, the Partnership had $1.8 billion of outstanding LIBOR-referenced borrowings summarized as follows:


	Principal	Weighted-average term	Transition Progress
	$	(years)
Revolving Credit Facilities	439,600	3.07	Expected to amend fallback clauses during 2021.
Term Loans	1,201,013	4.63	Expected to amend fallback clauses during 2021.
Public Bonds	200,000	3.80	Expected to amend fallback clauses during 2021.
Total	1,840,613	4.16

Interest rate benchmark transition for derivatives

As at December 31, 2020, the Partnership had an outstanding notional balance of $1.2 billion of LIBOR-referenced interest rate swap agreements.

For all of the Partnership’s LIBOR-referenced derivatives, the International Swaps and Derivative Association’s fallback clauses were made available in late-2020 and the Partnership and its counterparties expect to adhere to this protocol. This ensures that all legacy trade will, on the cessation of LIBOR, follow the fallback clause provided in the protocol.

F-23

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

ii.Classification of Liabilities as Current or Non-current (Amendments to IAS 1)

In January 2020, the International Accounting Standards Board finalized amendments to IAS 1 to clarify the classification of liabilities. The amendments affect only the presentation of liabilities in the statement of financial position and not the amount or timing of recognition of any asset, liability income or expenses, or the information that entities disclose about those items. They:

•clarify that the classification of liabilities as current or non-current should be based on rights that are in existence at the end of the reporting period and align the wording in all affected paragraphs to refer to the "right" to defer settlement by at least twelve months and make explicit that only rights in place "at the end of the reporting period" should affect the classification of a liability;

•clarify that classification is unaffected by expectations about whether an entity will exercise its right to defer settlement of a liability; and

•make clear that settlement refers to the transfer to the counterparty of cash, equity instruments, other assets or services.

The amendments are effective for annual reporting periods beginning on or after January 1, 2023 and are to be applied retrospectively. Earlier application is permitted. The Partnership is currently assessing the impact as a result of the amendment however, the adoption is not expected to have a significant impact on the Partnership's consolidated financial statements.

3.Transition to IFRS

The Partnership adopted IFRS effective September 30, 2020. Prior to the adoption of IFRS, the Partnership prepared its financial statements in accordance with its previous GAAP. As a result, the 2019 comparative information has been adjusted from amounts previously reported in the Partnership’s financial statements prepared in accordance with its previous GAAP. IFRS 1 – First-time Adoption of International Financial Reporting Standards (or IFRS 1) requires first-time adopters to apply IFRS retrospectively. The Partnership’s transition date is January 1, 2019 (or the Transition Date) and a consolidated statement of financial position has been prepared as at that date. These consolidated financial statements, including all periods presented, have been prepared in accordance with the IFRS accounting policies described in Note 2.

a.Presentation of consolidated financial statements

A full reconciliation of the Partnership's consolidated statements of financial position reported under its previous GAAP to that prepared under IFRS is presented below:

F-24

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	As at January 1, 2019
	Previous		IFRS
	GAAP	Reclassifications(1)	Adjustments	IFRS
Previous GAAP	$	$	$	$	IFRS
ASSETS					ASSETS
Current					Current Assets
Cash and cash equivalents	225,040	—	—	225,040	Cash and cash equivalents
Restricted cash	8,540	1,028	—	9,568	Financial assets
Accounts receivable	141,903	1,807	—	143,710	Accounts and other receivable, net
Vessels held for sale	12,528	—	—	12,528	Vessels and equipment classified as held for sale
	—	20,254	—	20,254	Inventory
Due from affiliates	58,885	—	—	58,885	Due from related parties
Prepaid expenses	32,199	(11,210)	—	20,989	Other assets
Other current assets	11,879	(11,879)	—	—
Total current assets	490,974	—	—	490,974	Total current assets
					Non-current assets
		2,075	—	2,075	Financial assets
		36,536	—	36,536	Accounts and other receivable, net
Vessels and equipment, at cost less accumulated depreciation	4,196,909	—	(648,408)	3,548,501	Vessels and equipment
Advances on newbuilding contracts and conversion costs	73,713	—	40,083	113,796	Advances on newbuilding __contracts
Investments in equity-accounted joint ventures	212,202	—	(3,383)	208,819	Equity-accounted investments
Deferred tax asset	9,168	—	—	9,168	Deferred tax assets
Due from affiliates	949	—	—	949	Due from related parties
Other assets	198,992	(38,611)	24,810	185,191	Other assets
Goodwill	129,145	—	(2,032)	127,113	Goodwill
	4,821,078	—	(588,930)	4,232,148	Total non-current assets
Total assets	5,312,052	—	(588,930)	4,723,122	Total assets
LIABILITIES AND EQUITY					LIABILITIES
Current					Current liabilities
Accounts payable	16,423	200,708	(3,651)	213,480	Accounts payable and other
Accrued liabilities	129,896	(129,896)	—	—
Deferred revenues	55,750	(55,750)	—	—
Current portion of derivative instruments	23,290	—	—	23,290	Other financial liabilities
Due to affiliates	183,795	—	—	183,795	Due to related parties
Current portion of long-term debt	554,336	—	—	554,336	Borrowings
Other current liabilities	15,062	(15,062)	—	—
Total current liabilities	978,552	—	(3,651)	974,901	Total current liabilities
					Non-current liabilities
Other long-term liabilities	236,616	(2,183)	30,299	264,732	Accounts payable and other
Derivatives instruments	94,354	—	50,513	144,867	Other financial liabilities
Long-term debt	2,543,406	—	—	2,543,406	Borrowings


		2,183	—	2,183	Deferred tax liabilities
	2,874,376	—	80,812	2,955,188	Total non-current liabilities
Total liabilities	3,852,928	—	77,161	3,930,089	Total liabilities
EQUITY					EQUITY
Limited partners - common units	883,090	—	(533,002)	350,088	Limited partners - common units


Limited partners - preferred units	384,274	—	—	384,274	Limited partners - preferred units
General partner	15,055	—	(4,084)	10,971	General partner
Warrants	132,225	—	(132,225)	—
Accumulated other comprehensive income	7,361	—	—	7,361	Accumulated other comprehensive income
Non-controlling interests	37,119	—	3,220	40,339	Non-controlling interests in subsidiaries
Total equity	1,459,124	—	(666,091)	793,033	Total equity
Total liabilities and equity	5,312,052	—	(588,930)	4,723,122	Total liabilities and equity

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	As at December 31, 2019
	Previous		IFRS	IFRS
	GAAP	Reclassifications(1)	Adjustments
Previous GAAP	$	$	$	$	IFRS
ASSETS					ASSETS
Current					Current Assets
Cash and cash equivalents	199,388	—	—	199,388	Cash and cash equivalents
Restricted cash	17,798	1,124	89,070	107,992	Financial assets
Accounts receivable	204,020	805	—	204,825	Accounts and other receivable, net
Vessels held for sale	15,374	—	—	15,374	Vessels and equipment classified as held for sale

	—	18,581	—	18,581	Inventory
Prepaid expenses	29,887	(13,043)	—	16,844	Other assets
Other current assets	7,467	(7,467)	—	—
Total current assets	473,934	—	89,070	563,004	Total current assets
					Non-current assets
Restricted cash - long-term	89,070	—	(89,070)	—	Financial assets
		17,276	—	17,276	Accounts and other receivable, net
Vessels and equipment, at cost less accumulated depreciation	3,511,758	—	(486,042)	3,025,716	Vessels and equipment
Advances on newbuilding contracts	257,017	—	40,083	297,100	Advances on newbuilding contracts
Investments in equity-accounted joint ventures	234,627	—	(2,411)	232,216	Equity-accounted investments
Deferred tax asset	7,000	—	—	7,000	Deferred tax assets

Other assets	220,716	(17,276)	15,373	218,813	Other assets
Goodwill	129,145	—	(2,032)	127,113	Goodwill
	4,449,333	—	(524,099)	3,925,234	Total non-current assets
Total assets	4,923,267	—	(435,029)	4,488,238	Total assets
LIABILITIES AND EQUITY					LIABILITIES
Current					Current liabilities
Accounts payable	56,699	206,756	9,163	272,618	Accounts payable and other
Accrued liabilities	140,976	(140,976)	—	—
Deferred revenues	53,728	(53,728)	—	—
Current portion of derivative instruments	18,956	2,741	—	21,697	Other financial liabilities
Due to related parties	20,000	—	1,306	21,306	Due to related parties
Current portion of long-term debt	353,238	—	—	353,238	Borrowings
Other current liabilities	14,793	(14,793)	—	—
Total current liabilities	658,390	—	10,469	668,859	Total current liabilities
					Non-current liabilities
Other long-term liabilities	223,877	(24,422)	23,204	222,659	Accounts payable and other
Derivatives instruments	143,222	21,289	—	164,511	Other financial liabilities
Long-term debt	2,825,712	—	5,562	2,831,274	Borrowings
		3,133	—	3,133	Deferred tax liabilities
	3,192,811	—	28,766	3,221,577	Total non-current liabilities
Total liabilities	3,851,201	—	39,235	3,890,436	Total liabilities
EQUITY					EQUITY
Limited partners - common units	505,394	—	(335,657)	169,737	Limited partners - common units


Limited partners - preferred units	384,274	—	—	384,274	Limited partners - preferred units
General partner	12,164	—	(2,577)	9,587	General partner
Warrants	132,225	—	(132,225)	—
Accumulated other comprehensive income	4,410	—	—	4,410	Accumulated other comprehensive income
Non-controlling interests	33,599	—	(3,805)	29,794	Non-controlling interests in subsidiaries
Total equity	1,072,066	—	(474,264)	597,802	Total equity
Total liabilities and equity	4,923,267	—	(435,029)	4,488,238	Total liabilities and equity

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(1)Concurrently with the adoption of IFRS, the Partnership implemented an accounting policy change related to the line items presented in its consolidated statements of financial position, in order to more closely align with the presentation adopted by its parent company, Brookfield. The reclassifications in the tables above are primarily as a result of this accounting policy change.

b.Elected optional exemptions from full retrospective application

IFRS 1 provides entities preparing their first consolidated financial statements in accordance with IFRS with several optional exemptions from full retrospective application of IFRS. The Partnership has applied certain of these optional exemptions as described below:

Business combinations

This exemption allows the Partnership to not apply IFRS 3 – Business Combinations retrospectively to past business combinations. The Partnership has elected to apply this exemption and therefore has not restated business combinations that took place prior to the Transition Date. Any goodwill arising on such business combinations before the Transition Date remains at the carrying value determined under its previous GAAP. Regardless of whether there is any indication that goodwill may be impaired, entities which are first-time adopters of IFRS shall test goodwill for impairment at the date of transition.

Share-based payment transactions

This exemption allows the Partnership to not apply IFRS 2 – Share-based Payments to equity instruments granted on or before November 7, 2002, or to equity instruments granted after November 7, 2002 and vested before the Transition Date. This exemption also allows the Partnership to not apply IFRS 2 – Share-based Payments to liabilities arising from share-based payment transactions that were settled before the Transition date. The Partnership has elected to apply this exemption and therefore not to apply IFRS 2 to equity instruments granted on or before November 7, 2002, to equity instruments granted after November 7, 2002 that had vested by the Transition Date and to liabilities arising from share-based payment transactions that were settled before the Transition Date.

Fair value as deemed cost

This exemption allows the Partnership to initially measure an item of property, plant and equipment, investment property, right-of-use assets or intangible asset at its fair value, or an amount determined by a previous GAAP revaluation, and use that amount as deemed cost as at the Transition Date on an asset-by-asset basis. The Partnership has elected to apply this exemption and measure all of its Vessels and equipment and Advances on newbuilding contracts at their fair value as at the Transition Date.

Assets and liabilities of subsidiaries, joint ventures and associates

This exemption allows the Partnership to measure the assets and liabilities in subsidiaries, joint ventures and associates, which transitioned to IFRS at a date earlier than the Transition Date for the Partnership, at the carrying amounts in those subsidiaries, joint ventures or associates financial statements, after adjusting for equity accounting adjustments and differences in accounting policies. The Partnership has elected to apply this exemption to its equity-accounted investments.

c.Mandatory exceptions to retrospective application of IFRS

In preparing these consolidated financial statements in accordance with IFRS 1, the Partnership has applied the following mandatory exceptions, which had an impact on the Partnership from full retrospective application of IFRS:

Derecognition of financial assets and liabilities

A first-time adopter is required to apply the derecognition requirements in IFRS 9 - Financial Instruments prospectively to transactions occurring on or after the Transition Date, but not retrospectively to financial assets or liabilities already derecognized prior to the Transition Date. The Partnership has applied this mandatory exception for the derecognition of financial assets and liabilities occurring on or after the Transition Date and has not applied this requirement retrospectively.

Impairment of financial assets

A first-time adopter is required to apply the impairment requirements of IFRS 9 - Financial Instruments. The Partnership has determined that an expected credit loss (ECL) provision is not material and therefore has not recognized an ECL provision as at the Transition Date.

Estimates

The Partnership's estimates in accordance with IFRS at the Transition Date are consistent with the estimates made at the same date in accordance with its Previous GAAP. Estimates made by the Partnership under its previous GAAP have been reassessed under IFRS as a result of changes in accounting policies. IFRS has a lower threshold for the recognition of a provision and requires the recognition of the mid-point of a range of estimates in situations where no single outcome within the range represents the best outcome, whereas the Partnership's previous GAAP required the recognition of the minimum amount of the range.

d.Reconciliation of Equity from previous GAAP to IFRS

The following is a reconciliation of the Partnership's equity reported in accordance with previous GAAP to its equity reported in accordance with IFRS as at the Transition Date:

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


		PARTNER'S EQUITY
		LIMITED PARTNERS
	Note	Common Units and Additional Paid-in Capital $	Preferred Units $	General Partner $	Warrants $	Accumulated Other Comprehensive Income $	Non- controlling Interests $	Total Equity $
As reported under previous GAAP - December 31, 2018		883,090	384,274	15,055	132,225	7,361	37,119	1,459,124
Transitional adjustments increasing (decreasing) reported amount:
Vessels and equipment	(i)	(646,673)	—	(4,955)	—	—	3,220	(648,408)
Advances on newbuilding contracts	(ii)	39,778	—	305	—	—	—	40,083
Equity-accounted investments	(iii)	(3,357)	—	(26)	—	—	—	(3,383)
Goodwill	(iv)	(2,017)	—	(15)	—	—	—	(2,032)
Provisions	(v)	(16,771)	—	(129)	—	—	—	(16,900)
Off-market contract	(vi)	14,947	—	115	—	—	—	15,062
Warrants	(vii)	81,091	—	621	(132,225)	—	—	(50,513)

As reported under IFRS - January 1, 2019		350,088	384,274	10,971	—	7,361	40,339	793,033

The following is a reconciliation of the Partnership's equity reported in accordance with previous GAAP to its equity reported in accordance with IFRS as at December 31, 2019:


		PARTNER'S EQUITY
		LIMITED PARTNERS
	Note	Common Units and Additional Paid-in Capital $	Preferred Units $	General Partner $	Warrants $	Accumulated Other Comprehensive Income $	Non- controlling Interests $	Total Equity $
As reported under previous GAAP - December 31, 2019		505,394	384,274	12,164	132,225	4,410	33,599	1,072,066
Transitional adjustments increasing (decreasing) reported amount:
Vessels and equipment	(i)	(478,567)	—	(3,670)	—	—	(3,805)	(486,042)
Advances on newbuilding contracts	(ii)	39,778	—	305	—	—	—	40,083
Equity-accounted investments	(iii)	(2,389)	—	(20)	—	—	—	(2,409)
Goodwill	(iv)	(2,017)	—	(15)	—	—	—	(2,032)
Provisions	(v)	(16,771)	—	(129)	—	—	—	(16,900)

Warrants	(vii)	131,221	—	1,004	(132,225)	—	—	—
Derecognition of financial liabilities	(viii)	(6,816)	—	(51)	—	—	—	(6,867)
Other		(96)	—	(1)	—	—	—	(97)
As reported under IFRS - December 31, 2019		169,737	384,274	9,587	—	4,410	29,794	597,802

(i)Vessels and equipment - Under the Partnership's previous GAAP, vessels and equipment were measured at cost less accumulated depreciation and adjusted for impairments. As part of the transition to IFRS, the Partnership elected to apply the fair value as deemed cost optional exemption to its vessels and equipment as at the Transition Date. The decrease in equity is the net difference between the fair value of vessels and equipment used as a deemed cost and the carrying amounts under the Partnership's previous GAAP. For the year ended December 31, 2019, the lower carrying values from this election decreased the related depreciation and amortization and impairment expense, net.

This decrease in deprecation and amortization as a result of the lower carrying values from this election was partially offset by the requirement, under IFRS, for the Partnership to componentize amounts initially recorded, in respect of vessels and equipment, into their significant components and depreciate each component separately over its expected useful life to its estimated residual value. The Partnership identified additional components relating to its FPSO units, FSO units and Towage vessels which had the impact of increasing depreciation and amortization expense, as these components were depreciated over a shorter estimated useful life.

Under the Partnership's previous GAAP, vessels and equipment were tested for impairment by first comparing the undiscounted cash flows generated by the asset or cash generating unit to the carrying amount. If this test indicated an impairment, the impairment expense was then

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

calculated by comparing the discounted cash flows or appraised values to the carrying amount of the asset or cash generating unit. Under IFRS, an impairment is recognized if the recoverable amount, determined as the higher of the estimated fair value less costs of disposal or the value in use, is less than the carrying value of the asset or cash generating unit, whereby the estimated fair value is either the discounted cash flows generated or an appraised value. As a result, the Partnership recorded impairment expenses on additional vessels and equipment under IFRS, when compared to its previous GAAP.

(ii)Advances on newbuilding contracts - Under the Partnership's previous GAAP, advances on newbuilding contracts were measured at cost. As part of the transition to IFRS, the Partnership elected to apply the fair value as deemed cost optional exemption to its advances on newbuilding contracts as at the Transition Date. The increase in equity is the net difference between the fair value used as deemed cost and the carrying amount under the Partnership's previous GAAP. When the vessels and equipment are delivered to the Partnership, this associated increase in the advances in newbuildings balance will be depreciated on a straight-line basis over the vessel and equipment's expected useful life to their estimated residual value.

(iii)Equity-accounted investments - The Partnership's equity-accounted investments, which are all joint ventures, transitioned to IFRS at a date earlier than the Transition Date for the Partnership. The Partnership elected the apply the optional exemption to measure the assets and liabilities in its equity-accounted investments at their carrying amount, after adjusting for equity accounting adjustments and differences in accounting policies. This exemption was applied by the Partnership as at the Transition Date and in all subsequent periods.

(iv)Goodwill - As at the Transition Date, the Partnership determined that the carrying amount of goodwill associated with its Towage segment was $nil following the performance of the goodwill impairment test on the Transition Date.

(v)Provisions - Estimates for provisions made by the Partnership under its previous GAAP were reassessed under IFRS, which requires a lower threshold for recognition and requires the recognition of the mid-point of a range of estimates in situations where no single outcome within the range represents the best outcome. As at the Transition Date, the provisions recognized by the Partnership decreased equity by $16.9 million when compared to its previous GAAP.

(vi)Off-market contract - As at the Transition Date, the carrying amount of an off-market contract liability pertaining to the Piranema Spirit FPSO unit was derecognized under IFRS due to the requirement to offset the off-market contract against the cost of the vessel and equipment under IFRS and the Partnership's election to apply the fair value as deemed cost optional exemption to its vessels and equipment as at the Transition Date.

(vii)Warrants - Warrants which the Partnership had previously issued were recorded at their fair value or relative fair value as at the date of issuance and were classified as an equity instrument under the Partnership's previous GAAP. As at the Transition Date, the Partnership classified these warrants as financial liability derivative instruments, which are measured at fair value through profit or loss under IFRS. This classification was applied by the Partnership as at the Transition Date and in all subsequent periods for which the warrants existed.

(viii)Derecognition of financial liabilities - The Partnership has applied the derecognition requirements in IFRS 9 - Financial Instruments prospectively to transactions occurring on or after the Transition Date, but not retrospectively to financial liabilities already derecognized prior to the Transition Date. Under IFRS, the amortized cost of a modified financial liability, in which the terms of the financial liability are not determined to be substantially modified, is recalculated as the present value of the estimated future contractual cash flows, discounted at the original effective interest rate. The resulting gains or losses are recognized in profit or loss. Under the Partnership's previous GAAP, such gains or losses were not recognized.

e.Reconciliation of Net Income and Comprehensive Income from previous GAAP to IFRS

Concurrently with the adoption of IFRS, the Partnership implemented an accounting policy change related to the presentation of total compensation expenses. Previously, compensation expenses relating to shore-based employees were included in general and administrative expenses, whereas in the consolidated statements of income (loss) presented in these consolidated financial statements, the Partnership has included such expenses as a component of direct operating costs.

The following is a reconciliation of the Partnership's net income (loss) and comprehensive income (loss) reported in accordance with its previous GAAP to its net income (loss) and comprehensive income (loss) in accordance with IFRS for the year ended December 31, 2019:

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	Note	Year ended December 31, 2019
Net income (loss) as reported under previous GAAP		(350,895)
Transitional adjustments increasing (decreasing) reported net income (loss):
Vessels and equipment	(i)	162,366
Equity-accounted investments	(ii)	974
Off-market contract	(iii)	(15,062)
Warrants	(iv)	50,513
Derecognition of financial liabilities	(v)	(6,867)
Other		(96)
Total adjustments		191,828
Net income (loss) as reported under IFRS		(159,067)
Attributable to:
Limited partners - common units		(181,424)
General partner		(1,384)
Limited partners - preferred units		32,150
Non-controlling interests in subsidiaries		(8,409)


									Year ended December 31, 2019
Other comprehensive income (loss) as reported under previous GAAP									(353,846)
Transitional adjustments increasing (decreasing) reported comprehensive income (loss):
Adjustments in net income (loss)									191,828
Other comprehensive income (loss) as reported under IFRS									(162,018)
Attributable to:
Limited partners - common units									(184,353)
General partner									(1,406)
Limited partners - preferred units									32,150
Non-controlling interests in subsidiaries									(8,409)

(i)Vessels and equipment - The Partnership elected to apply the fair value as deemed cost optional exemption to its vessels and equipment as at the Transition Date. The lower carrying values from this election decreased the related depreciation and amortization and impairment expense, net.

This decrease in depreciation expense was partially offset by the Partnership componentizing amounts initially recorded, in respect of vessels and equipment, into their significant components and depreciating each component separately over its expected useful life to an estimated residual value. The Partnership identified additional components relating to its FPSO units, FSO units and Towage vessels, which had the impact of increasing depreciation and amortization expense, as these components were depreciated over a shorter estimated useful life.

Impairment expense, net was also impacted by a lower impairment recognition threshold under IFRS compared to the Partnership's previous GAAP. This resulted in an increase in the related impairment expense, net.

(ii)Equity-accounted investments - The difference in net income (loss) reflects the impact of the Partnership adopting the IFRS carrying values of its equity-accounted investments after adjusting for equity-accounting adjustments and differences in accounting policies.

(iii)Off-market contract - As described in Note 3(d)(vi), the carrying amount of the off-market contract liability recognized by the Partnership under its previous GAAP was derecognized as at the Transition Date to IFRS.

(iv)Warrants - As described in Note 3(d)(vii), under IFRS, the Partnership measured its warrants as financial liability derivative instruments, which are measured at fair value through profit or loss. The effect on net income (loss) relates to the fair value adjustments in the periods subsequent to the Transition Date to IFRS.

(v)Derecognition of financial liabilities - As described in Note 3(d)(viii), under IFRS, a modification gain or loss is recognized on non-substantially modified financial liabilities. The effect on net income (loss) relates to the recognition of the modification gain or loss and the related amortization over the term of the modified financial liability.

f.Reconciliation of Cash Flows from previous GAAP to IFRS

The following items are the differences in the Partnership's consolidated statements of cash flows reported in accordance with its previous GAAP compared to in accordance with IFRS:

(i)Net income (loss) - Includes the differences in net income (loss) between the Partnership's previous GAAP and IFRS as described in Note 3(e) for the year ended December 31, 2019.

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(ii)Dry-docking expenditures - Under the Partnership's previous GAAP, dry-dock expenditures were presented as an operating activity. Under IFRS, the Partnership has presented expenditures capitalized during the period a vessel is drydocked as an investing activity and expenditures expensed during the period a vessel is drydocked as an operating activity.

(iii)Lease liability repayments - Under the Partnership's previous GAAP, lease liability repayments were presented as an operating activity. Under IFRS, the lease liability repayments relating to the principal portion of the lease liability are presented as a financing activity.

(iv)Restricted cash - Under the Partnership's previous GAAP, the consolidated statement of cash flows was required to explain the change of the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents during the period. Under IFRS, the consolidated statement of cash flows explains the change of cash and cash equivalents during the period, and the Partnership has presented the movement in restricted cash as an investing activity.

4.Fair Value of Financial Instruments

The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In the absence of an active market, fair values are determined based on prevailing market rates for instruments with similar characteristics and risk profiles, or internal or external valuation models, such as discounted cash flow analysis, maximizing observable market inputs.

Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, the Partnership looks primarily to external readily observable market inputs such as interest rate yield curves and price and rate volatilities as applicable. Financial instruments classified as fair value through profit or loss (or FVTPL) are carried at fair value in the consolidated statements of financial position and changes in fair values are recognized in profit or loss.

The following tables provide the details of financial instruments and their associated classifications as at December 31, 2020, December 31, 2019 and January 1, 2019:


	December 31, 2020			December 31, 2019
Measurement Basis	FVTPL $	Amortized cost $	Total $	FVTPL $	Amortized cost $	Total $
Financial assets
Cash and cash equivalents	—	235,734	235,734	—	199,388	199,388
Financial assets (current and non-current)	6,497	133,389	139,886	1,123	106,869	107,992
Accounts and other receivable, net (current and non-current) (1)	—	212,316	212,316	—	215,951	215,951
Due from related parties (current and non-current)	—	9,980	9,980	—	—	—
Other assets (current and non-current) (2)	—	59,905	59,905	—	3,875	3,875
Total	6,497	651,324	657,821	1,123	526,083	527,206
Financial liabilities
Accounts payable and other (3)	—	81,850	81,850	—	124,684	124,684
Other financial liabilities (current and non- current) (4)	203,597	139,738	343,335	162,178	24,030	186,208
Due to related parties (current and non-current)	—	194,635	194,635	—	21,306	21,306
Borrowings (current and non-current)	—	3,170,977	3,170,977	—	3,184,512	3,184,512
Total	203,597	3,587,200	3,790,797	162,178	3,354,532	3,516,710

(1)Excludes tax receivable of $10.3 million as at December 31, 2020 (December 31, 2019 - $6.2 million).

(2)Includes investments in finance leases. Refer to Note 9 below.

(3)Includes accounts payable and lease liabilities. Refer to Note 15 below.

(4)Includes derivative instruments, obligations relating to finance leases and other financial liabilities. Refer to Note 19 below.

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	January 1, 2019
Measurement Basis	FVTPL $	Amortized cost $	Total $
Financial assets
Cash and cash equivalents	—	225,040	225,040
Financial assets (current and non-current) (1)	3,103	8,540	11,643
Accounts and other receivable, net (current and non-current) (2)	—	176,948	176,948
Due from related parties (current and non-current)	—	59,834	59,834
Other assets (current and non-current) (3)	—	4,793	4,793
Total	3,103	475,155	478,258
Financial liabilities
Accounts payable and other (4)	—	36,624	36,624
Other financial liabilities (current and non-current) (1)	168,157	—	168,157
Due to related parties (current and non-current)	—	183,795	183,795
Borrowings (current and non-current)	—	3,097,742	3,097,742
Total	168,157	3,318,161	3,486,318

(1)Refer to Derivative Financial Instruments in Note 19 below.

(2)Excludes tax receivable of $3.3 million.

(3)Includes investments in finance leases. Refer to Note 9 below.

(4)Includes accounts payable and lease liabilities. Refer to Note 15 below.

The fair value of all financial assets and liabilities as at December 31, 2020 approximated their carrying values, with the exception of the borrowings, where fair value which was determined using Level 1 and Level 2 inputs and resulted in a fair value of $3,104 million (December 31, 2019: $3,206 million and January 1, 2019: $3,060 million) versus a carrying value of $3,171 million (December 31, 2019: $3,185 million and January 1, 2019 $3,098 million). The fair value of the Partnership’s fixed-rate and variable-rate long-term debt is either based on quoted market prices or estimated using discounted cash flow analysis based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

Fair value hierarchical levels - financial instruments

There were no transfers between levels during the years ended December 31, 2020 and December 31, 2019. The following table categorizes financial assets and liabilities, which are carried at fair value through profit or loss on a recurring basis, based upon the level of input as at December 31, 2020, December 31, 2019 and January 1, 2019:


	December 31, 2020			December 31, 2019
	Level 1	Level 2	Level 3	Level 1	Level 2	Level 3
	$	$	$	$	$	$
Financial assets


Derivative instruments	—	6,497	—	—	1,123	—



Total	—	6,497	—	—	1,123	—
Financial liabilities


Derivative instruments	—	203,597	—	—	162,178	—



Total	—	203,597	—	—	162,178	—

F-32

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	January 1, 2019
	Level 1	Level 2	Level 3
	$	$	$
Financial assets


Derivative instruments	—	3,103	—
Total	—	3,103	—
Financial liabilities
Derivative instruments	—	117,644	50,513



Total	—	117,644	50,513

The following table summarizes the valuation techniques and key inputs used in the fair value measurement of Level 2 financial instruments:


Type of Asset / Liability	Carrying value			Valuation Techniques and Key Inputs
	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Derivative instruments	(197,100)	(161,055)	(114,541)	The fair value of derivative instruments incorporates observable forward exchange rates and forward interest rates from observable yield curves, respectively, at the end of the reporting period, and the current credit worthiness of both the Partnership and the derivative counterparties. The estimated amount is the present value of future cash flows.

The fair value of Level 3 financial assets and liabilities is determined using valuation models which require the use of unobservable inputs, including assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those unobservable inputs, the Partnership uses observable external market inputs such as price volatilities, as applicable, to develop assumptions regarding those unobservable inputs.

The following table summarizes the valuation techniques and significant unobservable inputs used in the fair value measurement of Level 3 financial instruments:

Type of Asset / Liability

Carrying value

Valuation techniques

Significant unobservable inputs

Relationship of unobservable inputs to fair value

December 31, 2020

December 31, 2019

January 1, 2019

Warrants(1)

—

(50,513)

Black-Scholes model

Volatility

Increases (decreases) in volatility increase (decrease) fair value

(1)Included in derivative instruments. See Note 19 for additional information.

The following table presents the change in the balance of financial liabilities classified as Level 3 as at December 31, 2020 and December 31, 2019:


	December 31, 2020	December 31, 2019
	$	$
Opening balance at beginning of year	—	50,513
Fair value change recorded in unrealized gain (loss) on derivative instruments	—	(50,513)
Closing balance at end of year	—	—

5.Financial Assets

F-33

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current
Restricted cash(1)	97,017	106,869	8,540
Derivative instruments(2)	6,497	1,123	1,028
Total current	103,514	107,992	9,568
Non-current
Restricted cash(1)	36,372	—	—
Derivative instruments(2)	—	—	2,075
Total non-current	36,372	—	2,075

(1)Restricted cash as at December 31, 2020 includes amounts held in escrow for a shuttle tanker newbuilding yard installment payment, a deposit related to the sale of a vessel, funds for loan facility repayments, withholding taxes and office lease prepayments (December 31, 2019 - amounts held in escrow for a shuttle tanker newbuilding yard installment payment, a guarantee for certain operating expenses, funds for scheduled loan facility repayments, withholding taxes and office lease prepayments. January 1, 2019 - amounts held in escrow as collateral on the Partnership's cross currency swaps, funds for a scheduled loan facility repayment, withholding taxes and office lease prepayments).

(2)See Note 19 for additional information

6.Accounts and Other Receivable, Net


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current
Accounts receivable - trade	162,848	170,357	135,527
Accounts receivable - non-trade (1)	40,104	21,000	—
Other non-trade receivable	19,677	13,468	8,183
Total current	222,629	204,825	143,710
Non-current
Accounts receivable - non-trade (1)	—	17,276	36,536
Total non-current	—	17,276	36,536

(1)Accounts receivable - non-trade relates to a settlement agreement with respect to various disputes relating to previously-terminated charter contracts for the HiLoad DP unit and the Arendal Spirit UMS payable in two separate installments, one of which was due to the Partnership by the end of 2020 and the other by the end of 2021.

7.Vessels and Equipment Classified as Held for Sale


		December 31, 2020	December 31, 2019	January 1, 2019
Vessel	Segment	$	$	$
Pattani Spirit (1)	FSO Segment	—	—	4,528
Nordic Spirit (1)	Shuttle Tanker Segment	—	—	8,000
Petrojarl Cidade de Rio das Ostras (1)	FPSO Segment	—	2,374	—
Navion Hispania (1)	Shuttle Tanker Segment	—	7,000	—
Stena Sirita (1)	Shuttle Tanker Segment	—	6,000	—
Dampier Spirit(2)	FSO Segment	—	—	—
Navion Anglia	Shuttle Tanker Segment	4,400	—	—
Navion Oslo	Shuttle Tanker Segment	3,100	—	—

		7,500	15,374	12,528

(1)Classification as a result of the expected sales of the vessels, which were completed during the second quarter of 2019 or first quarter of 2020 (see Note 8 for additional information).

(2)As at December 31, 2020, the Dampier Spirit FSO unit was classified as held for sale and had a carrying value of $nil.

The fair value of vessels and equipment classified as held for sale measured on a non-recurring basis was $7.5 million, $15.4 million and $12.5 million as at December 31, 2020, December 31, 2019 and January 1, 2019, respectively (see Note 11 for additional information).

8. Gain (Loss) on Dispositions, Net

F-34

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Period

Vessel

Segment

Net Proceeds

Gain (Loss) on Dispositions, Net

Q4-20

Apollo Spirit

FSO Segment

9,559

5,380

Q3-20

Navion Bergen

Shuttle Tanker Segment

3,385

(19)

Q2-20

HiLoad DP unit

Shuttle Tanker Segment

—

(1,388)

Q1-20

Petrojarl Cidade de Rio das Ostras

FPSO Segment

2,282

(92)

Q1-20

Navion Hispania

Shuttle Tanker Segment

6,715

(385)

Q1-20

Stena Sirita

Shuttle Tanker Segment

6,055

(85)

Gain (loss) on dispositions, net for the year ended December 31, 2020

3,411

Q2-19

Pattani Spirit

FSO Segment

15,741

11,213

Q2-19

Alexita Spirit

Shuttle Tanker Segment

8,700

835

Q2-19

Nordic Spirit

Shuttle Tanker Segment

8,900

500

Gain (loss) on dispositions, net for the year ended December 31, 2019

12,548

9.Other Assets


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current
Prepayments	10,101	11,306	11,944
Investment in finance leases(1)	8,267	990	858
Contract assets(2)	18,958	3,816	7,926
Other assets(3)	—	732	261
Total current	37,326	16,844	20,989
Non-current
Investment in finance leases(1)	51,638	2,885	3,935
Right-of-use assets(3)	35,313	68,019	20,200
Contract assets(2)	48,288	79,896	66,905
Other assets(2)	50,282	68,013	94,151
Total non-current	185,521	218,813	185,191

(1)Includes the VOC systems on certain of the Partnership's shuttle tankers. See Note 25 for additional information. The increase in the investment in finance leases, as at December 31, 2020, was primarily related to the VOC systems on the Partnership's shuttle tanker newbuildings which were delivered to the Partnership during the year ended December 31, 2020. See Note 12 for additional information.

(2)See Note 18 for additional information.

(3)See Note 10 for additional information.

10.Right-of-use Assets and Lease Liabilities

The following table presents the change in the balance of the Partnership's right-of-use assets for the years ended December 31, 2020 and 2019:



	December 31, 2020	December 31, 2019
	$	$
Gross Carrying Amount
Opening balance at beginning of year	75,104	20,200
Additions (cash and non-cash)	757	56,854
Dispositions	(24,794)	(1,950)
Closing balance at end of year	51,067	75,104
Accumulated Depreciation
Opening balance at beginning of year	(7,085)	—
Depreciation expense	(18,389)	(13,369)
Dispositions	9,720	6,284
Closing balance at end of year	(15,754)	(7,085)
Net book value	35,313	68,019

F-35

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

As at December 31, 2020, December 31, 2019 and January 1, 2019, the Partnership's right-of-use assets were as follows:


				As at December 31, 2020
	December 31, 2020	December 31, 2019	January 1, 2019	Weighted-average remaining lease term	Weighted-average implicit interest rate
	$	$	$	(years)	(%)
Vessels and equipment	21,971	52,852	10,545	2.0	3.3%
Office leases	13,342	15,167	9,655	5.4	5.5%
Total	35,313	68,019	20,200

Lease related items for which the Partnership was a lessee for the years ended December 31, 2020 and December 31, 2019, were as follows:



	Year Ended December 31,
	2020	2019
	$	$
Amounts recognized in profit and loss
Depreciation expense on right-of-use vessels and equipment	15,899	10,616
Depreciation expense on right-of-use office leases	2,490	2,753
Interest expense on lease liabilities	2,679	1,507
Short-term lease expense	4,314	15,965
	25,382	30,841

As at December 31, 2020, the undiscounted contractual maturities of the Partnership's lease liabilities were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Lease liabilities	38.9	15.4	14.2	2.7	2.5	2.0	2.1

11.Vessels and Equipment


	December 31, 2020	December 31, 2019
	$	$
Gross carrying amount:
Opening balance at beginning of year	3,531,827	3,548,501
Additions(1)	41,346	32,895
Dispositions(2)	(29,242)	(13,869)
Transferred from advances on newbuilding contracts	543,131	—
Vessels and equipment reclassified as held for sale(3)	(61,564)	(35,700)
Closing balance at end of year	4,025,498	3,531,827
Accumulated Depreciation and Impairment:
Opening balance at beginning of year	(506,111)	—
Depreciation and amortization(4)	(295,610)	(339,981)
Impairment expense, net(5)	(245,396)	(179,759)
Dispositions(2)	15,050	1,244
Vessels and equipment reclassified as held for sale(3)	35,984	12,385
Closing balance at end of year	(996,083)	(506,111)
Net book value	3,029,415	3,025,716

(1)Additions by segment for the year ended December 31, 2020 is as follows: FPSO $10.3 million, Shuttle Tanker $23.4 million, UMS $0.2 million and Towage $7.4 million (December 31, 2019 - FPSO $8.2 million, Shuttle Tanker $15.3 million, FSO $6.6 million, UMS $0.9 million and Towage $1.9 million). Additions include drydocks and overhauls, which are only included in the Partnership's Shuttle Tanker and Towage segments, and capital modifications.

(2)Includes the sale of vessels and the disposal upon the replacement of certain components of vessels and equipment.

(3)See Note 7 for additional information.

F-36

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(4)Excludes depreciation and amortization on the Partnership's right-of-use assets. See Note 10 for additional details.

(5)See below for additional information. Excludes impairment expense on vessels and equipment classified as held for sale during the year ended December 31, 2020 and 2019.

Certain sale and leaseback transactions in 2019 were classified as financing arrangements and did not result in derecognition of the underlying vessels and equipment as control was retained by the Partnership (see Note 12 for additional information).

Impairment expense, net

The following tables contais a summary of Partnership’s impairment expense, net for the years ended December 31, 2020 and 2019, by vessel and by segment:

F-37

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Period

Vessel

Segment

Event

Fair Value Hierarchical Level

Valuation Techniques and Key Inputs

Impairment Expense
$

Q4 2020

Randgrid

FSO

Change in expected earnings of the vessel

Level 3

Discounted cash flow valuation

45,444

Q4 2020

Petrojarl Varg

FPSO

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

30,506

Q4 2020(1)

Navion Oslo

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

7,665

Q3 2020(2)

Apollo Spirit

FSO

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

1,620

Q3 2020(1)

Navion Anglia

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

3,100

Q2 2020(1)

Dampier Spirit

FSO

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

6,685

Q2 2020(2)

Navion Bergen

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

1,715

Q1 2020

ALP Forward

Towage

Change in the expected earnings of the vessels

Level 3

Discounted cash flow valuation

8,361

Q1 2020

ALP Winger

Towage

12,479

Q1 2020

ALP Ippon

Towage

1,360

Q1 2020

ALP Ace

Towage

731

Q1 2020

Petrojarl I

FPSO

Change in the expected earnings of the vessel

Level 3

Discounted cash flow valuation

42,367

Q1 2020

Petrojarl Varg

FPSO

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

27,202

Q1 2020

Petrojarl Knarr

FPSO

Change in expected earnings of the vessel

Level 3

Discounted cash flow valuation

56,599

Q1 2020

Navion Stavanger

Shuttle Tanker

Change in expected earnings of the vessel

Level 3

Discounted cash flow valuation

3,606

Q1 2020

Navion Gothenburg

Shuttle Tanker

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

16,772

Q1 2020(2)

Navion Bergen

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

2,400

Impairment expense, net for the year ended December 31, 2020

268,612

Q4 2019

Arendal Spirit

UMS

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

24,220

Q4 2019

Voyageur Spirit

FPSO

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

97,752

Q4 2019(2)(3)

Petrojarl Cidade de Rio das Ostras

FPSO

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

4,382

Q3 2019(2)(3)

Stena Sirita

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

1,506

Q2 2019

Arendal Spirit

UMS

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

11,487

Q2 2019

Petrojarl Varg

FPSO

Change in future redeployment assumptions

Level 3

Discounted cash flow valuation

33,991

Q2 2019

Navion Gothenburg

Shuttle Tanker

Significant repairs required to continue operations

Level 3

Discounted cash flow valuation

12,304

Q2 2019(2)(3)

Petrojarl Cidade de Rio das Ostras

FPSO

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

506

Q2 2019(2)(3)

Navion Hispania

Shuttle Tanker

Expected sale of the vessel

Level 2

Fair value less cost to sell using an appraised valuation

1,532

Impairment expense, net for the year ended December 31, 2019

187,680

(1)Vessels and equipment were classified as held for sale as at December 31, 2020.

(2)Vessels and equipment were sold during the year ended December 31, 2020.

(3)Vessels and equipment were classified as held for sale as at December 31, 2019.

For vessels measured based on a discounted cash flow valuation an increase in the discount rate of 0.5% would result in an increased impairment expense of $20.1 million and $19.1 million as at December 31, 2020 and December 31, 2019, respectively.

The fair value of vessels and equipment measured on a non-recurring basis was $140.5 million and $177.0 million as at December 31, 2020 and December 31, 2019, respectively.

F-38

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following table summarizes the significant unobservable inputs used in the Level 3 fair value measurements for the discounted cash flow valuations used for the Partnership's vessels and equipment:


Period	Vessel	Segment	Period of Projected Cash Flows (years)	Growth Rate(1) (%)	Discount Rate (%)

Q4 2020	Randgrid	FSO	2.8 - 11.8	2.00 - 3.50	8.86
Q1 2020	ALP Forward	Towage	13.0	3.00	10.50
Q1 2020	ALP Winger	Towage	12.5	3.00	10.50
Q1 2020	ALP Ippon	Towage	12.0	3.00	10.50
Q1 2020	ALP Ace	Towage	11.3	3.00	10.50
Q1 2020	Petrojarl I	FPSO	3.1 - 5.1	3.00	10.13
Q1 2020	Petrojarl Varg	FPSO	1.3 - 9.8	1.00 - 2.50	10.13
Q1 2020	Petrojarl Knarr	FPSO	12.4 - 15.4	3.00	10.13
Q1 2020	Navion Stavanger	Shuttle Tanker	3.3	2.60 - 3.50	8.25
Q1 2020	Navion Gothenburg	Shuttle Tanker	5.9	2.50	8.25
Q4 2019	Arendal Spirit	UMS	1.2 - 25.1	1.60 - 2.50	9.60
Q4 2019	Voyageur Spirit	FPSO	15.8 - 19.8	3.00	9.60
Q2 2019	Arendal Spirit	UMS	25.6	1.60 - 2.50	11.00
Q2 2019	Petrojarl Varg	FPSO	13.0	1.00 - 2.50	10.00
Q2 2019	Navion Gothenburg	Shuttle Tanker	6.5 - 6.7	2.00	8.00

(1)The growth rates indicated in the table above are the implicit rates used in the discounted cash flow valuations, however, cash flows have been adjusted for contractual revenues and expected offhire due to repairs and maintenance or drydocking.

As at December 31, 2020, the Partnership had five vessels and equipment, with a carrying value of $190.2 million, which were in lay-up (December 31, 2019 - six vessels and equipment with a carrying value of $168.4 million, January 1, 2019 - seven vessels and equipment with a carrying value of $292.5 million)

12.Advances on Newbuilding Contracts


	December 31, 2020	December 31, 2019
	$	$
Opening balance at beginning of year	297,100	113,796
Additions	368,588	169,704
Capitalized borrowing costs	4,778	13,600
Transferred to vessels and equipment	(543,131)	—
Closing balance at end of year	127,335	297,100

The Partnership had entered into shipbuilding contracts for the construction of seven shuttle tanker newbuildings for an estimated fully built up cost of $969.2 million. As at December 31, 2020, four of these vessels had been delivered to the Partnership. An additional vessel was delivered to the Partnership in January, 2021 and the remaining two vessels are expected to be delivered through 2022. As at December 31, 2020, gross payments made towards these commitments were $720.7 million. The Partnership has secured $733.5 million of borrowings or long-term financing under sale and leaseback transactions relating to these shuttle tanker newbuildings (see Notes 19 and 20 for additional information).

As at December 31, 2020, the contractual maturities of the Partnership's obligations under its newbuilding contracts were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Newbuilding contracts	248.5	175.5	73.0	—	—	—	—

As at December 31, 2020, the contractual maturities of the Partnership's obligations relating to the finance leases under the sale and leaseback transactions were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Obligations related to finance leases	141.6	7.9	7.5	7.5	7.5	7.5	103.7

13.Equity-Accounted Investments

F-39

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The Partnership has investments in two separate joint ventures, whereby the parties that have joint control of the arrangement have the rights to the net assets of the joint arrangement. Please refer to note 2d(ii) - Joint ventures.

Libra Joint Venture

The Partnership's investment in the Libra Joint Venture (as defined below) includes its investments in the below entities:

Name of Joint Venture

State or Jurisdiction of Incorporation

Proportion of Ownership Interest

OOG-TK Libra GmbH

Austria

50%

OOG-TK Libra GmbH & Co KG

Austria

50%

OOGTK Libra Operator Holdings Limited

Cayman Islands

50%

OOGTK Libra Producao de Petroleo Ltda

Brazil

50%

TK-Ocyan Libra Oil Services Ltd.

Cayman Islands

50%

In October 2014, the Partnership sold a 1995-built shuttle tanker to OOG-TK Libra GmbH & Co KG (or Libra Joint Venture), a 50/50 joint venture between the Partnership and Ocyan S.A. (or Ocyan) which vessel was converted to an FPSO unit for the Libra field in Brazil. The FPSO unit commenced operations in late-2017. Included in the joint venture is a ten-year plus construction period loan facility, which as at December 31, 2020 had an outstanding balance of $529.1 million (December 31, 2019 - $586.5 million). The interest payments of the loan facility are based on LIBOR, plus a margin of 2.65%. The final payment under the loan facility is due October 2027. In addition, the Libra Joint Venture entered into ten-year interest rate swap agreements, with an aggregate notional amount of $483.5 million as at December 31, 2020 (December 31, 2019 - $536.1 million), which amortize quarterly over the term of the agreements. These interest rate swap agreements exchange the receipt of LIBOR-based interest for the payment of a weighted average fixed rate of 2.52%. These interest rate swap agreements are not designated as qualifying cash flow hedging relationships for accounting purposes.

Itajai Joint Venture

The Partnership's investment in the Itajai Joint Venture (as defined below) includes its investments in the below entities:

Name of Joint Venture

State or Jurisdiction of Incorporation

Proportion of Ownership Interest

OOG-TKP FPSO GmbH

Austria

50%

OOG-TKP FPSO GmbH & Co KG

Austria

50%

OOG-TKP Oil Services Ltd.

Cayman Islands

50%

OOG-TKP Operator Holdings Limited

Cayman Islands

50%

OOG-TKP Producao de Petroleo Ltda

Brazil

50%

In June 2013, the Partnership acquired its interest in OOG-TKP FPSO GmbH & Co KG (or Itajai Joint Venture), a 50/50 joint venture between the Partnership and Ocyan, which owns the Cidade de Itajai FPSO unit currently operating in Brazil. Included in the joint venture is a term loan facility, which was amended during the year ended December 31, 2020 and as at December 31, 2020 had an outstanding balance of $53.4 million (December 31, 2019 - $105.9 million). The interest payments on the amended loan facility are based on LIBOR, plus a margin of 3.50%. The final payment under the amended loan facility is due April 2022. As part of the amendment of the loan facility, the joint venture terminated the associated interest rate swap agreements and as at December 31, 2020, the joint venture held no interest rate swap agreements (December 31, 2019 - total interest rate swap agreements with a notional balance of $105.9 million).

The Partnership relies on the expertise and relationships that its joint ventures and joint venture partners may have with current and potential customers to jointly pursue FPSO projects and provide assistance in competing in new markets.

As at December 31, 2020 and 2019, and January 1, 2019, the Partnership had total investments of $241.7 million, $232.2 million and $208.8 million, respectively, in its equity-accounted investments. No indicators of impairment existed as at December 31, 2020 and 2019, nor January 1, 2019.

The following tables presents summarized financial information assuming a 100% ownership interest in the Partnership’s equity-accounted investments.

F-40

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	December 31, 2020						December 31, 2019						January 1, 2019
	Libra Joint Venture		Itajai Joint Venture		Total		Libra Joint Venture		Itajai Joint Venture		Total		Libra Joint Venture		Itajai Joint Venture		Total
	$		$		$		$		$		$		$		$		$
Current assets	123,576		29,605		153,181		126,154		33,565		159,719		114,949		34,314		149,263
Non-current assets	765,239		278,113		1,043,352		813,330		306,178		1,119,508		877,719		308,064		1,185,783
Current liabilities	83,028		43,681		126,709		80,321		46,741		127,062		87,392		47,403		134,795
Non-current liabilities	567,474		18,888		586,362		611,457		76,277		687,734		668,689		113,923		782,612
Net assets	238,313		245,149		483,462		247,706		216,725		464,431		236,587		181,052		417,639
Ownership interest	50	%	50	%	50	%	50	%	50	%	50	%	50	%	50	%	50	%
Equity-accounted investments	119,157		122,575		241,731		123,853		108,363		232,216		118,294		90,526		208,819
Cash and cash equivalents	8,450		10,396		18,846		7,972		10,556		18,528		66,217		23,417		89,634
Current financial liabilities	66,223		35,533		101,756		62,676		35,954		98,630		58,281		31,782		90,063
Non-current financial liabilities	495,861		18,546		514,407		530,588		71,836		602,424		579,156		105,382		684,538


					Year ended December 31,
	2020		2020		2020		2019		2019		2019
	Libra Joint Venture		Itajai Joint Venture		Total		Libra Joint Venture		Itajai Joint Venture		Total
	$		$		$		$		$		$
Revenues	181,734		82,170		263,904		181,172		84,275		265,447
Depreciation and amortization	(48,408)		(16,419)		(64,827)		(47,282)		(16,371)		(63,653)
Interest expense	(20,493)		(8,373)		(28,866)		(34,798)		(6,938)		(41,736)
Interest income	83		170		253		203		—		203
Income tax (expense) recovery	(100)		(534)		(634)		(166)		(330)		(496)
Net income (loss) and other comprehensive income (loss)	43,882		27,960		71,842		34,686		32,850		67,536
Ownership interest	50	%	50	%	50	%	50	%	50	%	50	%
Equity-accounted income (loss)	21,941		13,980		35,921		17,343		16,425		33,768
Dividends received by the Partnership	27,492		2,250		29,742		15,405		2,250		17,655

The Partnership's investment in equity-accounted investments and its interest in the net income of its equity-accounted investments are included in the Partnership's FPSO segment.

14.Goodwill

The Partnership has identified the shuttle tanker segment as the group of cash generating units to which the Partnership's goodwill relates.

The carrying amount of goodwill for the shuttle tanker segment was $127.1 million as at December 31, 2020 and 2019, and January 1, 2019. The Partnership conducted its annual goodwill impairment evaluation during 2020 and 2019, and on January 1, 2019, and concluded that no impairment had occurred as the recoverable amount, based on the fair value less cost of disposal using a discounted cash flow model incorporating significant unobservable inputs, exceeded the carrying amount of goodwill. The estimates regarding the expected future cash flows and discount rates are Level 3 fair value inputs based on various assumptions including existing contracts, future vessel redeployment rates, financial forecasts and industry trends. The Partnership has not previously recorded any impairment expense related to the carrying amount of goodwill for the shuttle tanker segment.

The key assumptions used in the estimation of the recoverable amount are set out below. The values assigned to the key assumptions represent the Partnership's assessment of future trends in the relevant industries and have been based on historical data from both external and internal sources.


	2020	2019	January 1, 2019
Discount rate	6.73%	8.25%	8.25%
Exit multiple	8.0	8.0	8.0

Discount rate

F-41

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The discount rate is a post-tax measure, with a possible debt leveraging of 70% for 2020 (2019 - 57%, January 1, 2019 - 60%) estimated based on the observed leveraging within the industry and the long-term target leverage of the Partnership, at market interest rates of 3.9% for 2020 (2019 - 6.5%, January 1, 2019 - 7.1%).

Exit Multiple

The cash flow projections include specific estimates for generally six years and a terminal value thereafter. The terminal value is estimated using an EBITDA multiple generally applied to the year-six EBITDA and discounted using the discount rates described above. The EBITDA multiple was determined based on an average of the EBITDA multiples used by the Partnership's industry peers and is therefore determined to be consistent with the assumptions that a market participant would make.

The Partnership has identified that a reasonably possible change in these key assumptions could cause the carrying amount to exceed the recoverable amount. The following table shows the amount by which these two assumptions would need to change individually for the estimated recoverable amount to be equal to the carrying amount.


	2020	2019	January 1, 2019
Discount rate	3.23%	1.31%	0.38%
Exit multiple	(1.7)	(0.7)	(0.2)

15.Accounts Payable and Other


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current
Accounts payable	46,022	56,699	16,423
Accrued liabilities(1)	143,660	133,435	122,428
Provisions(4)	7,522	7,540	7,468
Deferred revenues(2)	91,392	53,728	55,750
Lease liabilities(3)	13,818	21,216	11,411

Total current	302,414	272,618	213,480
Non-current
Deferred revenues(2)	11,616	84,077	145,852
Lease liabilities(3)	22,010	46,769	8,790
Provisions(4)	60,179	60,366	78,992
Decommissioning liability(5)	33,901	31,420	29,302
Other	965	27	1,796
Total non-current	128,671	222,659	264,732

(1)See Note 16 for additional information.

(2)See Note 18 for additional information.

(3)See Note 10 for additional information.

(4)See Note 17 for additional information.

(5)Decommissioning liability relates to the Partnership’s requirement to remove the sub-sea mooring and riser system associated with the Randgrid FSO unit and restore the environment surrounding the facility. The liability represents the estimated cost to remove this equipment and restore the environment and takes into account the estimated timing of the cost to be incurred in future periods. The liability for the year ended December 31, 2020 was determined using a risk-free rate between 0.3% and 0.4% (December 31, 2019 - 1.6% and 2.5%) and an inflation rate of 2.5% (December 31, 2019 - 2.5%).

16.Accrued Liabilities


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Interest including interest rate swaps	50,714	48,047	44,887
Payroll and benefits	44,167	36,807	34,828
Audit, legal and other general expenses	16,383	24,831	14,158
Voyage and vessel expenses	31,107	19,829	25,475
Income and other tax payable	1,289	3,921	3,080
	143,660	133,435	122,428

F-42

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

17.Provisions and Contingencies


	December 31, 2020	December 31, 2019
	$	$
Opening balance at beginning of year	67,906	86,460
Additional provisions recognized	12,033	2,161
Reduction arising from payments / derecognition	(12,238)	(20,715)
Closing balance at end of year	67,701	67,906

Occasionally the Partnership has been, and expects to continue to be, subject to legal proceedings and claims in the ordinary course of its business, principally personal injury and property casualty claims. Certain of these claims have been assessed by the Partnership as having a remote possibility of any outflow from settlement and are therefore not included in the disclosures below. In addition to the claims described below, as at December 31, 2020, approximately $10.1 million has been accrued by the Partnership and its subsidiaries relating to other various legal claims.

a)In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS (or Logitel), a Norway-based company focused on high-end UMS. At the time of the transaction, affiliates of Logitel were parties to construction contracts for three UMS newbuildings ordered from the COSCO (Nantong) Shipyard (or COSCO) in China. The Partnership took delivery of one of the UMS newbuildings, the Arendal Spirit UMS, in February 2015.

In June 2016, the Partnership canceled the UMS construction contracts for the two remaining UMS newbuildings, the Stavanger Spirit and the Nantong Spirit. As a result of this cancellation, during 2016, the Partnership wrote-off $43.7 million of assets related to these newbuildings and reversed contingent liabilities of $14.5 million associated with the delivery of these assets. An estimate of the potential damages for the cancellation of the Stavanger Spirit newbuilding contract is based on the amount due for the final yard installment of approximately $170 million less the estimated fair value of the Stavanger Spirit. Given the unique design of the vessel as well as the lack of recent sale and purchase transactions for this type of asset, the value of this vessel, and thus ultimately the amount of potential damages that may result from the cancellation, is uncertain. During December 2017, Logitel Offshore Rig II Pte Ltd., the single-purpose subsidiary relating to the Stavanger Spirit, received a notice of arbitration from COSCO to arbitrate all disputes arising from the cancellation of the construction contract of the Stavanger Spirit UMS and during March 2018, COSCO commenced arbitration against Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd. claiming $186.2 million plus interest, damages and costs. Pursuant to the Stavanger Spirit newbuilding contract and related agreements, COSCO only has recourse to the single-purpose subsidiary that was a party to the Stavanger Spirit newbuilding contract and its immediate parent company, Logitel Offshore Pte. Ltd., for damages incurred. Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd. are disputing this claim.

The Partnership's estimate of potential damages for the cancellation of the Nantong Spirit newbuilding contract is based upon estimates of a number of factors, including accumulated costs incurred by COSCO, sub-supplier contract cancellation costs, as well as how such costs are treated under the termination provisions in the contract. The Partnership estimates that the amount of potential damages faced by it in relation to the cancellation of the Nantong Spirit contract could range between $10 million and $40 million. Pursuant to the Nantong Spirit newbuilding contract, COSCO only has recourse to the single-purpose subsidiary that was a party to the Nantong Spirit newbuilding contract. During June 2017, Logitel Offshore Rig III LLC, the single-purpose subsidiary relating to the Nantong Spirit, received a claim from COSCO for $51.9 million for the unpaid balance for work completed, cancellation costs and damages, and during the third quarter of 2017, COSCO commenced arbitration against Logitel Offshore Rig III LLC. Logitel Offshore Rig III LLC is disputing this claim.

As at December 31, 2020, the Partnership's subsidiaries have accrued $57.6 million in the aggregate related to the above claims related to Logitel from COSCO.

b)During 2019, certain entities and individuals, which together claim to hold approximately 5,000,000 of the Partnership’s common units, filed complaints in the United States District Court for the Southern District of New York naming as defendants the Partnership, the general partner, current and former members of the board of directors of the general partner, certain senior management of the Partnership, Brookfield and Brookfield Asset Management Inc. In October 2019, a joint stipulation was filed by the plaintiffs to consolidate the separate complaints. The plaintiffs purported to assert claims on behalf of a class of holders of the Partnership’s common units in relation to Brookfield’s unsolicited non-binding proposal, made in May 2019, pursuant to which Brookfield would acquire all of the Partnership’s issued and outstanding common units that Brookfield did not already own in exchange for $1.05 in cash per common unit. On October 1, 2019, the Partnership entered into an agreement with Brookfield to acquire by merger all of the outstanding publicly held common units not already held by Brookfield in exchange for $1.55 in cash per common unit (or, as an alternative, other equity consideration) and on January 22, 2020, Brookfield completed the merger of all of the outstanding publicly held and listed common units representing the Partnership's limited partner interests held by parties other than Brookfield (see Note 23 for additional information). On January 28, 2020, the same plaintiffs filed an amended complaint in which the plaintiffs purport to allege further claims in respect of the merger process and the ultimate agreed consideration of $1.55 in cash per common unit or alternative equity consideration.

The complaints allege breaches of the Partnership’s limited partnership agreement and, in the alternative, breaches of an implied covenant of good faith and fair dealing. The complaints seek damages in an unspecified amount and an award to the plaintiffs of their costs and expenses incurred in the action, including their attorneys’ fees. The Partnership believes that there is no merit to these claims.

The Partnership filed a motion to dismiss the claims on March 12, 2020, upon which a ruling is awaited. On October 29, 2020, one of the lead plaintiffs filed, unsolicited, a notice of voluntary dismissal, effectively withdrawing its particular claim.

F-43

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

18.Contracts in Progress

Contract Assets and Liabilities

Certain customer contracts that the Partnership enters into will result in situations where the customer will pay consideration for performance to be provided in the following month or months. These receipts are a contract liability and are presented within accounts payable and other as deferred revenues until performance is provided. In other cases, the Partnership will provide performance in the month or months prior to it being entitled to invoice for such performance. This results in such receipts being reflected as a contract asset that is presented within other assets. In addition to these short-term timing differences between the timing of revenue recognition and when the entity’s right to consideration in exchange for goods or services is unconditional, the Partnership has long-term charter arrangements whereby it has received payments that are larger in the early periods of the arrangements and long-term charter arrangements whereby it will receive payments that are larger in the latter periods of the arrangements. The following table presents the contract assets and contract liabilities on the Partnership's consolidated statements of financial position associated with these long-term charter arrangements from contracts with customers:


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Contract assets
Current	18,958	3,816	7,926
Non-current	48,288	79,896	66,905
	67,246	83,712	74,831
Contract liabilities
Current	91,392	53,728	55,750
Non-current	11,616	84,077	145,852
	103,008	137,805	201,602

During the year ended December 31, 2020, the Partnership recognized revenue of $43.7 million (December 31, 2019 - $53.1 million), which was included in contract liabilities on December 31, 2019 (January 1, 2019).

Contract Costs

In certain cases, the Partnership incurs pre-operational costs that relate directly to a specific customer contract and that generate or enhance resources of the Partnership to satisfy future performance obligations, and where such costs are expected to be recovered via the customer contract. These costs include costs incurred to mobilize an offshore asset to an oil field, pre-operational costs incurred to prepare for commencement of operations of an offshore asset or costs incurred to reposition a vessel to a location where a charterer will take delivery of the vessel. In certain cases, the Partnership will need to make judgments about whether costs relate directly to a specific customer contract and whether costs were factored into the pricing of a customer contract and thus expected to be recovered. Such deferred costs are amortized into direct operating costs over the duration of the customer contract. Amortization of such costs for the Partnership for the years ended December 31, 2020 and 2019 were $22.8 million and $20.9 million, respectively.

The balances of assets recognized from the costs to fulfill a contract with a customer classified as other assets, split between current and non-current portions, on the Partnership's consolidated statements of financial position, by main category, excluding balances in the Partnership’s equity-accounted investments, are as follows:


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Pre-operational costs	7,750	12,836	24,031
Offshore asset mobilization costs	21,509	35,632	51,302
Vessel repositioning costs	11,565	13,379	15,188
	40,824	61,847	90,521

19.Other Financial Liabilities

F-44

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current
Derivative instruments	189,647	18,956	23,290
Obligations relating to finance leases(1)	8,839	255	—
Other	499	2,486	—
Total current	198,985	21,697	23,290
Non-current
Derivative instruments	13,950	143,222	144,867
Obligations relating to finance leases(1)	130,400	21,289	—
Total non-current	144,350	164,511	144,867

(1)See Note 12 for additional information. The financing liability accrues interest at a fixed rate of 5.5% until the related newbuilding vessels are delivered to the Partnership.

Derivative Financial Instruments

The Partnership’s activities expose it to a variety of financial risks, including liquidity risk, interest rate risk, foreign currency risk and credit risk. The Partnership selectively uses derivative financial instruments principally to manage certain of these risks.

The aggregate amount of the Partnership's derivative financial instrument positions is as follows:


	December 31, 2020		December 31, 2019		January 1, 2019
	Financial Asset	Financial Liability	Financial Asset	Financial Liability	Financial Asset	Financial Liability
	$	$	$	$	$	$
Interest rate swaps	—	203,597	—	161,630	3,103	108,552
Foreign currency forward contracts	6,497	—	1,123	548	—	4,650
Cross currency swaps	—	—	—	—	—	4,442
Warrants	—	—	—	—	—	50,513
Total	6,497	203,597	1,123	162,178	3,103	168,157
Total current	6,497	189,647	1,123	18,956	1,028	23,290
Total non-current	—	13,950	—	143,222	2,075	144,867

Interest Rate Risk

The Partnership enters into interest rate swaps, which exchange a receipt of floating interest for a payment of fixed interest, to reduce the Partnership’s exposure to interest rate variability on its outstanding floating-rate debt. The Partnership has not designated, for accounting purposes, any of its interest rate swaps held during the years ended December 31, 2020 and 2019 as hedges of variable rate debt. Certain of the Partnership's interest rate swaps are secured by vessels.

As at December 31, 2020, the Partnership and its consolidated subsidiaries were committed to the following interest rate swap agreements:


	Interest Rate Index	Notional Amount $	Fair Value / Carrying Amount of Asset (Liability)(1) $	Weighted- Average Remaining Term (years)	Fixed Interest Rate (%)(2)
U.S. Dollar-denominated interest rate swaps(3)(4)	LIBOR	647,368	(156,743)	0.50	4.0	%
U.S. Dollar-denominated interest rate swaps(5)(6)	LIBOR	526,541	(46,854)	1.40	2.9	%

		1,173,909	(203,597)

(1)Excludes accrued interest of $4.6 million.

(2)Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2020, ranged between 0.90% and 6.50%.

(3)Notional amount remains constant over the term of the swap, unless the swap is partially terminated.

(4)Includes four interest rate swaps, which as at December 31, 2020, had a total current notional amount of $547.4 million and a total fair value liability of $155.7 million. These interest rate swaps include early termination provisions, which if exercised, would terminate these interest rate swaps in 2021.

(5)Principal amount reduces quarterly or semi-annually.

(6)Includes one interest rate swap, which as at December 31, 2020, had a total current notional amount of $143.3 million and a total fair value liability of $28.9 million. This interest rate swap includes early termination provisions, which if exercised, would terminate this interest rate swap in 2021.

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

During the year ended December 31, 2020, the effective portion of previously designated and qualifying cash flow hedges recorded in accumulated other comprehensive income during the term of the hedging relationship and reclassified to earnings and reported in interest expense was a gain of $0.8 million (December 31, 2019 - gain of $0.7 million).

As at December 31, 2020, the Partnership had multiple interest rate swaps and foreign currency forward contracts governed by certain master agreements. Each of the master agreements provides for the net settlement of all derivatives subject to that master agreement through a single payment in the event of default or termination of any one derivative. The fair value of these derivatives is presented on a gross basis in the Partnership’s consolidated statements of financial position. As at December 31, 2020, these derivatives had an aggregate fair value asset amount of $6.5 million and an aggregate fair value liability amount of $147.5 million (December 31, 2019 - an aggregate fair value asset amount of $1.1 million and an aggregate fair value liability amount of $118.2 million, January 1, 2019 - an aggregate fair value asset amount of nil and an aggregate fair value liability amount of $91.1 million).

Total realized and unrealized gain (loss) on the Partnership's derivative financial instruments that are not designated, for accounting purposes, as hedges are recognized in earnings and reported in realized and unrealized gain (loss) on derivative instruments in the consolidated statements of income (loss) for the years ended December 31, 2020 and 2019 as follows:


	Year Ended December 31,
	2020	2019
	$	$
Realized gain (loss) on derivative instruments

Interest rate swaps	(59,143)	(29,185)
Foreign currency forward contracts	(1,310)	(5,054)
	(60,453)	(34,239)
Unrealized gain (loss) on derivative instruments
Interest rate swaps	(41,967)	(56,182)
Foreign currency forward contracts	5,921	5,226
Warrants (1)	—	50,513
	(36,046)	(443)
Total realized and unrealized gain (loss) on derivative instruments	(96,499)	(34,682)

(1)See below for additional information.

The Partnership is exposed to credit loss in the event of non-performance by the counterparties, all of which are financial institutions, to the foreign currency forward contracts and the interest rate swap agreements. In order to minimize counterparty risk, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

Other Information Regarding Derivative Financial Instruments

Series D Detachable Warrants

In June 2016, the Partnership issued 4,500,000 warrants with an exercise price of $4.55 per unit (the $4.55 Warrants) and 2,250,000 warrants with an exercise price of $6.05 per unit (the $6.05 Warrants) (collectively, the Warrants) to a group of investors and subsidiaries of Teekay Corporation.

In September 2017, the exercise price of the $6.05 Warrants was reduced to $4.55 per unit. As at December 31, 2019, the Warrants had a seven-year term and were exercisable any time after six months following their issuance date. The Warrants could be settled either in cash or common units at the Partnership’s option.

The Warrants were classified as derivative financial instruments in the Partnership's consolidated statement of financial position with 6,750,000 Warrants outstanding at December 31, 2019.

On January 22, 2020, Brookfield completed the Merger (see Note 23 for additional information) of all of the outstanding publicly held and listed common units representing the Partnership's limited partner interests held by parties other than Brookfield. As a result of this transaction, and the fact that the exercise price of each of the outstanding Warrants exceeded the cash consideration of $1.55 per common unit, each of the Warrants was automatically canceled and ceased to exist. No consideration was delivered in respect thereof.

As at December 31, 2019, as a result of the pending Merger, the fair value measurement of the Warrants using Level 3 unobservable inputs was $nil.

Brookfield Warrants

In September 2017, the Partnership issued to Brookfield and Teekay Corporation 62.4 million and 3.1 million warrants, respectively (the Brookfield Warrants), with each warrant exercisable for one common unit. As part of a separate transaction, Brookfield concurrently transferred 11.4 million Brookfield Warrants to Teekay Corporation.

The Brookfield Warrants entitled the holders to acquire one common unit for each Brookfield Warrant for an exercise price of $0.01 per common unit, which was exercisable until September 25, 2024 if the Partnership's common unit volume-weighted average price was equal to or greater than $4.00 per common unit for 10 consecutive trading days.

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

In July 2018, Brookfield, through an affiliate, exercised its option to acquire an additional 2% of ownership interests in the Partnership's general partner from an affiliate of Teekay Corporation in exchange for 1.0 million Brookfield Warrants. In May 2019, Brookfield acquired all of Teekay Corporation's remaining interests in the Partnership including 17.3 million common unit equivalent warrants.

As at December 31, 2019, Brookfield held all of the 65.5 million Brookfield Warrants.

On January 22, 2020, Brookfield completed the Merger (see Note 23 for additional information) of all of the outstanding publicly held and listed common units representing the Partnership's limited partner interests held by parties other than Brookfield. As a result of this transaction, and the fact that the exercise price of each of the outstanding Brookfield Warrant exceeded the cash consideration of $1.55 per common unit, each of the Brookfield Warrants was automatically canceled and ceased to exist. No consideration was delivered in respect thereof.

As at December 31, 2019, as a result of the pending Merger, the fair value measurement of the Brookfield Warrants using Level 3 unobservable inputs was $nil.

The following table presents the notional amounts underlying the Partnership's derivative financial instruments by term to maturity as at December 31, 2020:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Fair value through profit or loss
Interest rate swaps	1,173.9	763.1	389.1	3.8	3.8	3.8	10.3
Foreign currency forward contracts	54.1	54.1	—	—	—	—	—
Total	1,228.0	817.2	389.1	3.8	3.8	3.8	10.3

20.Borrowings


				Weighted average term			Weighted average rate
	December 31, 2020	December 31, 2019	January 1, 2019	December 31, 2020	December 31, 2019	January 1, 2019	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$	(years)	(years)	(years)	(%)	(%)	(%)
Revolving Credit __Facilities	439,600	513,200	523,125	3.07	4.05	3.44	2.81	4.50	5.82
Term Loans	1,426,370	1,399,309	1,443,125	5.51	5.79	6.04	2.69	4.12	4.76
Public Bonds	1,138,086	1,075,000	1,034,769	2.56	3.47	3.99	7.88	8.18	7.96
Non-Public Bonds	206,870	241,145	141,158	5.04	5.88	5.07	6.13	5.98	4.88
Total	3,210,926	3,228,654	3,142,177	4.10	4.75	4.89	4.77	5.67	6.00
Less: deferred financing __costs and other	(39,949)	(44,142)	(44,435)
Total borrowings	3,170,977	3,184,512	3,097,742
Less current portion	(362,079)	(353,238)	(554,336)
Long-term portion	2,808,898	2,831,274	2,543,406

Revolving Credit Facilities

As at December 31, 2020, the Partnership had two revolving credit facilities (December 31, 2019 - two, January 1, 2019 - two), which, as at such date, provided for total borrowings of up to $439.6 million (December 31, 2019 - $513.2 million, January 1, 2019 - $523.1 million) and were fully drawn (December 31, 2019 - fully drawn).

Term Loans

As at December 31, 2020, the Partnership had term loans outstanding secured by 25 vessels, which totaled $1.4 billion (December 31, 2019 - secured by 24 vessels, which totaled $1.4 billion, January 1, 2019 - secured by 25 vessels, which totaled $1.4 billion). The term loans reduce over time with quarterly or semi-annual payments and have varying maturities through 2034. As at December 31, 2020, all of these term loans were guaranteed by the Partnership, a subsidiary of the Partnership or the other owner in the Partnership's non-wholly owned subsidiaries.

In June 2020, the Partnership extended a $40 million commercial tranche of a term loan, relating to the financing of the Petrojarl Knarr FPSO unit, until June 2023. The interest rate swaps related to this term loan were also extended until June 2022. In relation to the extensions, certain deposit arrangements and reductions in negative mark-to-market values of the interest rate swaps were agreed with the lenders.

In October 2020, the Partnership completed a $106 million upsizing of an existing term loan, relating to the partial financing of a newbuilding shuttle tanker currently under construction for operation off the East Coast of Canada.

Public and Non-Public Bonds

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

As at December 31, 2020, the Partnership had public bonds outstanding which totaled $1.1 billion (December 31, 2019 - $1.1 billion, January 1, 2019 - $1.0 billion) and non-public bonds outstanding which totaled $206.9 million (December 31, 2019 - $241.1 million, January 1, 2019 - $141.2 million). The public bonds have varying maturities through 2024 and the non-public bonds reduce over time with semi-annual payments and varying maturities through 2027. As at January 1, 2019, the Partnership had Norwegian Krone 86 million of senior unsecured bonds outstanding, equivalent to $10.0 million, that matured in January 2019.

In August 2020, the Partnership issued an additional $75.0 million of its senior unsecured green bonds that mature in October 2024. These bonds were issued at 96.5% of par value of the pre-existing senior unsecured green bonds and increases the total amount outstanding to $200.0 million. The interest payments on the bonds are based on LIBOR plus a margin of 6.50%.

In September 2020, the Partnership announced that it intended to commence repurchasing certain of its $700.0 million five-year senior unsecured bonds that mature in July 2023, which were issued in July 2018. As at December 31, 2020, the Partnership had repurchased $13.0 million of these bonds.

As at December 31, 2020, the contractual maturities of the Partnership's borrowings were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Borrowings:
Secured debt - scheduled repayments	1,279.0	294.2	231.6	207.9	160.1	124.9	260.3
Secured debt - repayments on maturity	793.8	69.0	70.5	274.6	182.0	—	197.7
Bond repayments	1,138.1	—	251.1	687.0	200.0	—	—
Total borrowings	3,210.9	363.2	553.2	1,169.5	542.1	124.9	458.0
Unsecured revolving credit facility - due to related parties(1)	229.0	—	—	—	229.0	—	—

(1)See Note 22a for additional information.

The Partnership is currently in compliance with all covenant requirements of its revolving credit facilities, term loans and bonds.

21.Income Taxes

Income taxes are recognized for the amount of taxes payable by the Partnership’s subsidiaries and for the impact of deferred income tax assets and liabilities related to such subsidiaries.

The significant components of the Partnership’s deferred tax assets and liabilities as at December 31, 2020 and 2019, and January 1, 2019, are as follows:


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Tax losses carried forward	5,153	7,000	9,168
Other timing differences	(700)	(3,133)	(2,183)
Total net deferred tax assets (liabilities)	4,453	3,867	6,985
Reflected in the statement of financial position as follows:
Deferred tax assets	5,153	7,000	9,168
Deferred tax liabilities	700	3,133	2,183
Net deferred tax assets (liabilities)	4,453	3,867	6,985

The recognition of the deferred tax assets is based on the expectation that sufficient taxable income will be available through future taxable income supported by forecast.

The net deferred tax assets (liabilities) movements are as follows:


	December 31, 2020	December 31, 2019
	$	$
Opening net deferred tax assets (liabilities) balance at beginning of year	3,867	6,985
Deferred income tax (expense) recovery	804	(3,161)
Other	(218)	43
Closing net deferred tax assets (liabilities) balance at end of year	4,453	3,867

The following table details the expiry date, if applicable, of the unrecognized deferred tax assets:

F-48

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
One year from reporting date	92	205	111
Two years from reporting date	122	84	129
Three years from reporting date	162	111	98
After three years from reporting date	108,788	97,475	103,564
Do not expire	153,573	134,311	134,931
Total	262,737	232,186	238,833

The major components of income tax expense for the years ended December 31, 2020 and 2019 are as follows:


	Year Ended December 31, 2020 $	Year Ended December 31, 2019 $
Current income tax (expense) recovery	(6,543)	(4,666)
Deferred income tax (expense) recovery:
Origination and reversal of temporary differences	2,889	(1,035)
Recovery (expense) arising from previously unrecognized (derecognized) tax assets	(2,085)	(2,126)
Total deferred income taxes	804	(3,161)
Income tax (expense) recovery	(5,739)	(7,827)

The Partnership operates in countries that have differing tax laws and rates. Consequently, a consolidated weighted average tax rate will vary from year to year according to the source of earnings or losses by country and the change in applicable tax rates. The below reconciliation has been prepared using a composite statutory-rate for jurisdictions where the Partnership’s subsidiaries operate:


	Year Ended December 31, 2020 $		Year Ended December 31, 2019 $
Income (loss) before income tax (expense) recovery	(340,424)		(151,240)
Net income (loss) not subject to taxes	(155,010)		(194,675)
Net income (loss) subject to taxes	(185,414)		43,435
Applicable statutory tax rate	1	%	11	%
Net income (loss) subject to taxes at applicable statutory tax rates	(1,222)		4,885
Permanent differences	2,219		(1,976)
Adjustments related to currency differences	172		(360)
Derecognition of deferred tax assets and other	4,570		5,278
Tax expense (recovery) related to current year	5,739		7,827

The unrecognized tax benefits movements are as follows:


	December 31, 2020	December 31, 2019
	$	$
Opening unrecognized tax benefits balance at beginning of year	232,186	238,833

Increases for positions related to the current year	30,551	(6,647)

Closing unrecognized tax benefits balance at end of year	262,737	232,186

22.Related Party Transactions

The key management personnel that are principally responsible for the operations of the Partnership are as follows:

F-49

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


Name						Position
Ingvild Sæther						President and Chief Executive Officer, Altera Infrastructure Group Ltd.
Jan Rune Steinsland						Chief Financial Officer, Altera Infrastructure Group Ltd.
Duncan Donaldson						General Counsel, Altera Infrastructure Group Ltd.

During the year ended December 31, 2020, total compensation expenses of these three key management personnel of the Partnership was $2.2 million (December 31, 2019 - $2.0 million).

The Partnership is a party to the following transactions with related parties:

a)As at December 31, 2020, the Partnership had an undrawn balance of $nil (December 31, 2019 - $105.0 million, January 1, 2019 - $nil) relating to an unsecured revolving credit facility, which subsequent to May 8, 2019, was provided solely by Brookfield and prior to May 8, 2019 was provided by Brookfield and Teekay Corporation, and provided for borrowings of up to $125.0 million. In August 2020, the Partnership agreed to amend the existing credit facility with Brookfield, to increase the borrowings available under the unsecured revolving credit facility from $125.0 million to $200.0 million and extend its term from October 1, 2020 to October 31, 2024 and in November 2020 the Partnership agreed to further amend the existing credit facility with Brookfield, to increase the borrowings available under the unsecured revolving credit facility from $200.0 million to $225.0 million. The agreement provides the Partnership the option to defer interest payments of up to $25.0 million until maturity. The Partnership determined that each amendment to the unsecured revolving credit facility was a substantial modification resulting in the derecognition of the original liability and the recognition of the modified arrangement at its fair value. As the interest rate under the new modified facility was deemed to be at below market terms (the interest payments on the revolving credit facility are based on LIBOR plus a margin of 5.00% per annum, with interest payable monthly), based on the Partnership's assessment taken from its public bonds and preferred units, the Partnership determined that Brookfield was acting in its capacity as an equity owner and the $37.1 million decrease between the carrying value of the original facility and the fair value of the modified arrangement was classified as an equity contribution in the Partnership's consolidated statements of changes in equity. The difference between the fair value and the nominal amount of the modified arrangement will be recognized as an adjustment to interest expense over the remaining term of the loan using the effective interest rate method. Any outstanding principal balances are due on the maturity date. The revolving credit facility contains covenants that require the Partnership to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $75.0 million and 5.0% of the Partnership’s total consolidated debt. As at December 31, 2020, the Partnership was in compliance with these covenants. For additional information on the change in the balance of borrowings from related parties, refer to note 28.

b)On July 2, 2018, the Partnership issued, in a U.S. private placement, a total of $700.0 million of five-year senior unsecured bonds that mature in July 2023. The interest payments on the bonds are fixed at a rate 8.50% (see Note 20 for additional information). Brookfield purchased $500.0 million of these bonds and as at December 31, 2020, Brookfield held $411.3 million of these bonds (December 31, 2019 - $423.6 million, January 1, 2019 - $475.0 million), which is included in the non-current portion of borrowings on the Partnership's consolidated statements of financial position.

The Partnership also reimburses its general partner for expenses incurred by the general partner that are necessary or appropriate for the conduct of the Partnership’s business. Effective May 8, 2019, Teekay Corporation and its wholly-owned subsidiaries were no longer related parties of the Partnership; however, the Partnership continues to provide certain services to Teekay Corporation. During the period to May 8, 2019, two shuttle tankers and three FSO units of the Partnership were employed on long-term time-charter-out or bareboat contracts with subsidiaries of Teekay Corporation. The Partnership's related party transactions recognized in the consolidated statements of income (loss) were as follows for the periods indicated:


	Year Ended December 31,
	2020 $	2019 $
Revenues(1)	8,079	42,628
Direct operating costs(2)	—	(2,535)
General and administrative expenses(3)	(1,134)	(8,811)
Depreciation and amortization	(209)	—
Interest expense(4)(5)	(43,831)	(46,101)
Realized and unrealized gain (loss) on derivative instruments(6)	—	49,832
Other income (expenses), net(7)	—	(1,949)

(1)Includes revenue from services provided to the Partnership's equity-accounted investments and from time-charter-out or bareboat contracts with subsidiaries of Teekay Corporation, including management fees for ship management services provided by the Partnership to a subsidiary of Teekay Corporation prior to May 8, 2019.

(2)Includes ship management and crew training services provided by Teekay Corporation prior to May 8, 2019.

(3)Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and for reimbursements to Teekay Corporation for costs incurred on the Partnership’s behalf prior to May 8, 2019 and reimbursements to the general partner for costs incurred on the Partnership’s behalf.

(4)Includes interest expense of $35.0 million for the year ended December 31, 2020 (December 31, 2019 - $38.5 million), incurred on a portion of five-year senior unsecured bonds held by Brookfield (see Note 22b for additional information).

(5)Includes interest expense of $7.3 million for the year ended December 31, 2020 (December 31, 2019 - $8.3 million) and a net interest accretion expense of $1.4 million for the year ended December 31, 2020 (December 31, 2019 - interest accretion income of $0.6 million) incurred on the unsecured revolving credit facility provided by Brookfield and, prior to May 8,2019, Teekay Corporation (see Note 22a for additional information).

F-50

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(6)Relates to unrealized gain (loss) on warrants held by Brookfield and Teekay Corporation prior to May 8, 2019 (see Note 19 for additional information).

(7)Relates to a loss on refinancing of the unsecured revolving credit facility provided by Brookfield during the year ended December 31, 2019.

As at December 31, 2020, the carrying value of amounts due from related parties totaled $10.0 million (December 31, 2019 - $nil, January 1, 2019 - $58.9 million) and as at December 31, 2020, consisted only of amounts receivable from the Partnership's general partner. As at December 31, 2020, the carrying value of amounts due to related parties totaled $194.6 million (December 31, 2019 - $21.3 million, January 1, 2019 - $183.8 million). As at December 31, 2020, the amounts due to related parties consisted only of the unsecured revolving credit facility provided by Brookfield (see note 22a).

23.Equity

As at December 31, 2020, the Partnership's capital structure was comprised of three classes of partnership units; Class A common units, Class B common units and preferred limited partnership units, in addition to the general partnership interest. The Partnership may issue additional securities at any time and from time to time for such consideration and on such terms and conditions as the General Partner shall determine, without the approval of any Limited Partners.

Limited Partners' Rights

Significant rights of the Class A Common Unitholders include the following:

•The Class A Common Unitholders are entitled to receive, to the extent permitted by law, such distributions as may from time to time be declared by the general partner’s board of directors. Upon any liquidation, dissolution or winding up of the Partnership’s affairs, whether voluntary or involuntary, the Class A Common Unitholders are entitled to receive distributions of the Partnership’s assets, after it has satisfied or made provision for its debts and other obligations and for payment to the holders any class or series of limited partner interests (including the Partnership’s preferred units) having preferential rights to receive distributions of Partnership assets.

•No limited partner has any management power over the Partnership’s business and affairs; the general partner conducts, directs and manages the Partnership's activities.

•The Class A Common Units have no voting rights except as required by the Marshall Islands Limited Partnership Act, but only to the extent that such voting rights under such Act may not be waived.

•Class A Unitholders have certain pre-emptive rights, entitling them to purchase a portion of certain issuances of additional common units (or other securities that have rights and preferences that rank pari passu with the common units).

•The Class A Common Units are subject to certain redemption provisions in connection with any Brookfield Sales Event (as defined in the Partnership’s partnership agreement).

•No Class A Common Unitholder may sell, assign, convey, pledge, transfer or otherwise dispose of any Class A Common Units other than in connection with a Brookfield Sales Event (as defined in the Partnership's partnership agreement), and any sale, assignment, conveyance, pledge, transfer or other disposition of Class A Common Units in violation of the Partnership's partnership agreement, other than by operation of law (including intestacy), shall be null and void.

Significant rights of the Class B Common Unitholders include the following:

•Right to receive distributions of Available Cash (as defined in the Partnership’s partnership agreement) similar to those applicable to the Class A Common Unitholders.

•No limited partner has any management power over the Partnership’s business and affairs; the general partner conducts, directs and manages the Partnership's activities.

•The Class B Common Units are entitled to vote on various matters, as specified in the Partnership’s partnership agreement.

•The general partner may be removed if such removal is approved by the Class B Common Unitholders holding at least 66.67% of the outstanding units voting as a single class, including units held by the general partner and its affiliates.

On January 22, 2020, Brookfield completed its acquisition by merger (or the Merger) of all of the outstanding publicly held and listed common units representing the Partnership's limited partner interests held by parties other than Brookfield (or unaffiliated unitholders) pursuant to an agreement and plan of merger (or the Merger Agreement) among the Partnership, the general partner and certain members of Brookfield. Under the terms of the Merger Agreement, (a) a newly formed subsidiary of Brookfield merged with and into the Partnership, with the Partnership surviving as a wholly owned subsidiary of Brookfield and the Partnership's general partner, and (b) common units held by unaffiliated unitholders were converted into the right to receive $1.55 in cash per common unit (or the cash consideration), other than common units held by unaffiliated unitholders who, as an alternative to receiving the cash consideration, elected to forego the cash consideration and instead receive one of the Partnership's newly designated unlisted Class A Common Unit per common unit held immediately prior to the Merger (or the equity consideration). The Class A Common Units are economically equivalent to the Class B Common Units held by Brookfield following the Merger, but have limited voting rights and limited transferability.

At December 31, 2020, Brookfield held 100% of the Class B Common Units, representing 98.7% of the outstanding common units and 100% of the general partner interest. All of the Partnership's Class A Common Units, representing 1.3% of the Partnership’s outstanding common units, were held by entities other than Brookfield and its affiliates. At December 31, 2020, all of the Partnership’s outstanding Series A Cumulative Redeemable Preferred Units (or the Series A Preferred Units), Series B Cumulative Redeemable Preferred Units (or the Series B Preferred Units) and Series E

F-51

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (or the Series E Preferred Units) were held by entities other than Brookfield and its affiliates.

As a result of the Merger, the Partnership's common units that previously existed, were exchanged for either Class A Common Units or Class B Common Units. The net assets ascribed to the previously existing common units immediately preceding the Merger were allocated to the Class A Common Units or Class B Common Units based on their proportionate ownership percentages.

As a result of the Merger, each of the Partnership's outstanding warrants (the Warrants) were automatically canceled and ceased to exist. No consideration was delivered in respect thereof. Pursuant to the terms of the Merger Agreement, the Partnership's outstanding preferred units were unchanged and remain outstanding following the Merger.

Incentive Distribution Rights

As a result of the Merger, the general partner's incentive distribution rights, which granted the holder varying distributions based on the amount of quarterly cash distributions per common unit, were canceled and ceased to exist.

Series A, B and E Preferred Units

In April 2013, the Partnership issued 6.0 million 7.25% Series A Preferred Units in a public offering with an aggregate redemption amount of $150.0 million, for net proceeds of $144.8 million. Pursuant to the partnership agreement, distributions on the Series A Preferred Units to preferred unitholders are cumulative from the date of original issue and are payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. At any time on or after April 30, 2018, the Series A Preferred Units may be redeemed by the Partnership at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to the date of redemption. These units are listed on the New York Stock Exchange under the symbol "ALIN PR A".

In April 2015, the Partnership issued 5.0 million 8.50% Series B Preferred Units in a public offering with an aggregate redemption amount of $125.0 million, for net proceeds of $120.8 million. Pursuant to the partnership agreement, distributions on the Series B Preferred Units to preferred unitholders are cumulative from the date of original issue and are payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. At any time on or after April 20, 2020, the Series B Preferred Units may be redeemed by the Partnership at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to the date of redemption. These units are listed on the New York Stock Exchange under the symbol "ALIN PR B".

In January 2018, the Partnership issued 4.8 million 8.875% Series E Preferred Units in a public offering for net proceeds of $116.0 million. Pursuant to the partnership agreement, distributions on the Series E Preferred Units to preferred unitholders are cumulative from the date of original issue, payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. Distributions are payable on the Series E Preferred Units (i) from and including the original issue date to, but excluding, February 15, 2025 at a fixed rate equal to 8.875% per annum of the stated liquidation preference of $25.00 per unit and (ii) from and including February 15, 2025, at a floating rate equal to three-month LIBOR plus 6.407%. These units are listed on the New York Stock Exchange under the symbol "ALIN PR E".

In September 2020, the Partnership announced that it intended to repurchase certain of its outstanding Series A, B and E Preferred Units. As at December 31, 2020, the Partnership had repurchased 123,467 of the Series A Preferred Units, 89,981 of the Series B Preferred Units and 96,977 of the Series E Preferred units, for a total cash payment of $6.2 million that resulted in a net gain on repurchase of $1.6 million, which was recorded in the Partnership's Consolidated Statement of Changes in Equity as an equity contribution to the Class A and Class B common unitholders, as well as the general partner.

Net Income (Loss) Per Limited Partner Unit

The general partner’s and common unitholders’ interests in net income (loss) are calculated as if all net income (loss) were distributed, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net income (loss); rather, it provides that, with respect to any quarter, the general partner may elect to distribute Available Cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter less, among other things, the amount of cash reserves established by the general partner’s board of directors to provide for the proper conduct of the Partnership’s business, including, among other things, any accumulated distributions on, or redemptions of, the Series A, Series B and Series E Preferred Units. Unlike available cash, net income (loss) is affected by non-cash items such as depreciation and amortization, unrealized gain or loss on derivative instruments and unrealized foreign currency translation gain and loss.

For all periods presented in these consolidated financial statements, no common unit equivalent warrants or restricted units were included in the computation of limited partners’ interest in net income (loss) per common unit - diluted, as their effect was anti-dilutive.

The weighted average number of total common units were as follows for the periods indicated:


	Year Ended December 31,
	2020	2019
Weighted average number of total common units	411,148,991	410,727,035

Preferred Unit Distributions

The distributions payable or paid on the preferred units for the year ended December 31, 2020 were $32.1 million (December 31, 2019 - $32.2 million).

F-52

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

On January 28, 2021, the general partner of the Partnership declared the following distributions payable on February 16, 2021 to all preferred unitholders on record on February 8, 2021:

•Series A Preferred Units - $0.4531 per unit

•Series B Preferred Units - $0.5313 per unit

•Series E Preferred Units - $0.5547 per unit

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities and liquidation amounts on the Series A, Series B and Series E Preferred Units will be distributed to the common unitholders and the general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation in accordance with the partnership agreement.

24.Non-Wholly Owned Subsidiaries

The following tables present the assets and liabilities from the Partnership’s investments in non-wholly owned subsidiaries as at December 31, 2020, December 31, 2019 and January 1, 2019, as well as of revenues, net income, other comprehensive income and distributions for the year ended December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Current assets	38,902	30,977	19,937
Non-current assets	48,960	88,457	128,628
Current liabilities	44,109	24,371	18,732
Non-current liabilities	—	28,847	41,502


	Year Ended December 31,
	2020	2019
	$	$
Revenues	47,050	55,655
Net income (loss) and other comprehensive income (loss)	(12,759)	(15,106)

Distributions paid to non-controlling interests	(4,750)	(3,636)

The Partnership's investments in non-wholly owned subsidiaries are in its shuttle tanker and FSO segments.

25.Revenues

a)Revenues by type

The Partnership’s primary source of revenues is chartering its vessels and offshore units to its customers. The Partnership utilizes five primary forms of contracts, consisting of FPSO contracts, CoAs, time-charter contracts, bareboat charter contracts and voyage charter contracts. All of the Partnership's revenues relate to services transferred over a period of time. During the year ended December 31, 2020, the Partnership also generated revenues from the operation of VOC systems on certain of the Partnership’s shuttle tankers, and from the management of three FPSO units and one FSO unit (December 31, 2019 - three FPSO units, one FSO unit and two shuttle tankers) on behalf of the disponent owners or charterers of these assets.

The following tables contain the Partnership’s revenue for the years ended December 31, 2020 and 2019, by contract type and by segment:

F-53

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


Year Ended December 31, 2020	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Eliminations(1)	Total
Revenues from contracts with customers
FPSO contracts	156,804	—	—	—	—	—	156,804
CoAs	—	84,171	—	—	—	—	84,171
Time charters	—	96,607	25,566	—	—	—	122,173
Bareboat charters	—	—	—	—	—	—	—
Voyage charters	—	485	—	—	45,851	(5,564)	40,772
Management fees and other	133,524	2,822	4,153	1,828	140	—	142,467
	290,328	184,085	29,719	1,828	45,991	(5,564)	546,387
Other revenues
FPSO contracts	192,474	—	—	—	—	—	192,474
CoAs	—	145,804	—	—	—	—	145,804
Time charters	—	149,477	71,052	—	—	—	220,529
Bareboat charters	—	21,679	13,096	—	—	—	34,775
Voyage charters	—	37,845	—	—	—	—	37,845
Management fees and other	—	4,296	—	—	—	—	4,296
	192,474	359,101	84,148	—	—	—	635,723
Total revenues	482,802	543,186	113,867	1,828	45,991	(5,564)	1,182,110

(1) Includes revenues earned between segments of the Partnership, during the year ended December 31, 2020.


Year Ended December 31, 2019	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Conventional Tanker Segment	Total
Revenues from contracts with customers
FPSO contracts	192,573	—	—	—	—	—	192,573
CoAs	—	83,522	—	—	—	—	83,522
Time charters	—	110,951	47,106	—	—	—	158,057
Bareboat charters	—	—	—	—	—	—	—
Voyage charters	—	5,542	—	—	74,726	7,972	88,240
Management fees and other	71,295	9,289	3,177	2,940	—	—	86,701
	263,868	209,304	50,283	2,940	74,726	7,972	609,093
Other revenues
FPSO contracts	213,728	—	—	—	—	—	213,728
CoAs	—	104,756	—	—	—	—	104,756
Time charters	—	182,143	74,656	—	—	—	256,799
Bareboat charters	—	34,611	15,178	—	—	—	49,789
Voyage charters	—	18,773	—	—	—	—	18,773
Management fees and other	—	—	—	—	—	—	—
	213,728	340,283	89,834	—	—	—	643,845
Total revenues	477,596	549,587	140,117	2,940	74,726	7,972	1,252,938

b)Finance leases

Leasing of certain vessels and equipment and VOC equipment are accounted for as finance leases.

During the year ended December 31, 2020, the Partnership recorded finance income of $3.4 million on its investment in finance leases (December 31, 2019 - $0.4 million).

As at December 31, 2020, the minimum lease payments receivable under the Partnership's finance leases approximated $76.2 million (December 31, 2019 - $4.6 million, January 1, 2019 - $5.9 million), including unearned income of $16.3 million (December 31, 2019 - $0.7 million, January 1, 2019 - $1.1 million). As at December 31, 2020, future scheduled payments under the finance leases to be received by the Partnership were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Finance leases	76.2	12.8	12.8	12.1	11.5	11.5	15.5

F-54

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

c)Operating leases

As at December 31, 2020, the carrying amount of the Partnerships vessels and equipment subject to operating leases in which the Partnership is a lessor was $2.7 billion (December 31, 2019 - $2.5 billion, January 1, 2019 - $3.0 billion). As at December 31, 2020, the undiscounted contractual earnings receivable of the Partnership’s operating leases by expected period of receipt were as follows:


	Total	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter
	(in millions of U.S. Dollars)
Operating leases	2,673.3	673.6	441.1	321.8	243.5	232.7	760.6

26.Direct Operating Costs

Direct operating costs include all attributable expenses except interest, depreciation and amortization, impairment expense, other expenses, and taxes and primarily relate to cost of revenues. The following table lists direct operating costs for the year ended December 31, 2020 and 2019 by nature:


	Year Ended December 31,
	2020	2019
	$	$
Voyage expenses(1)	113,618	132,556
Operating expenses	268,999	229,400
Charter hire	18,325	33,202
Compensation	226,850	211,533
Total	627,792	606,691

(1)Expenses unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions.

27.Segment Information

For the year ended December 31, 2020, the Partnership's operations were organized into five (December 31, 2019 - six) operating segments: FPSO, shuttle tanker, FSO, UMS and towage. During the three months ended March 31, 2019, the Partnership redelivered its two in-chartered conventional tankers to their owners and ceased operations in the conventional tanker segment.

These operating segments are regularly reviewed by the Partnership's CODM for the purpose of allocating resources to the segment and to assess its performance. The key measure used by the CODM in assessing performance and in making resource allocation decisions is Adjusted EBITDA, which is calculated as net income (loss) before interest expense, interest income, income tax expense, and depreciation and amortization, adjusted to exclude certain items whose timing or amount cannot be reasonably estimated in advance or that are not considered representative of core operating performance. Such adjustments include impairment expenses, gain (loss) on dispositions, net, unrealized gain (loss) on derivative instruments, foreign currency exchange gain (loss) and certain other income or expenses. Adjusted EBITDA also excludes: realized gain or loss on interest rate swaps, as management, in assessing the Partnership's performance, views these gains or losses as an element of interest expense; realized gain or loss on derivative instruments resulting from amendments or terminations of the underlying instruments; and equity-accounted income (loss). Adjusted EBITDA also includes the Partnership's proportionate share of Adjusted EBITDA from its equity-accounted investments and excludes the non-controlling interests' proportionate share of Adjusted EBITDA. The Partnership does not have control over the operations of, nor does it have any legal claim to the revenues and expenses of its equity-accounted investments. Consequently, the cash flow generated by the Partnership’s equity-accounted investments may not be available for use by the Partnership in the period that such cash flows are generated.

Adjusted EBITDA is also used by external users of the Partnership's consolidated financial statements, such as investors and the Partnership’s controlling unitholder.

The following tables include the results for the Partnership’s reportable segments for the periods presented in these consolidated financial statements:

F-55

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


Year Ended December 31, 2020	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Corporate/Eliminations	Total
Revenues	482,802	543,186	113,867	1,828	45,991	(5,564)	1,182,110
Direct operating costs	(270,419)	(251,259)	(51,018)	(8,977)	(51,683)	5,564	(627,792)
General and administrative(1)	(28,590)	(10,891)	(2,889)	(397)	(1,593)	—	(44,360)

Realized loss on foreign currency forward contracts	—	—	—	—	—	(1,310)	(1,310)
Adjusted EBITDA from equity-accounted investments(2)	101,352	—	—	—	—	—	101,352
Adjusted EBITDA attributable to non-controlling interests	—	(10,989)	312	—	—	—	(10,677)
Adjusted EBITDA	285,145	270,047	60,272	(7,546)	(7,285)	(1,310)	599,323


Year Ended December 31, 2019	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Conventional Segment	Corporate/Eliminations	Total
Revenues	477,596	549,587	140,117	2,940	74,726	7,972	—	1,252,938
Direct operating costs	(235,335)	(245,833)	(43,234)	(5,825)	(67,160)	(9,304)	—	(606,691)
General and administrative(1)	(31,773)	(14,986)	(4,169)	(1,567)	(2,328)	(104)	—	(54,927)
Realized loss on foreign currency forward contracts	—	—	—	—	—	—	(5,054)	(5,054)
Adjusted EBITDA from equity-accounted investments(2)	98,297	—	—	—	—	—	—	98,297
Adjusted EBITDA attributable to non-controlling interests	—	(10,864)	(500)	—	—	—	—	(11,364)
Adjusted EBITDA	308,785	277,904	92,214	(4,452)	5,238	(1,436)	(5,054)	673,199

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to each segment based on estimated use of corporate resources).

(2)Adjusted EBITDA from equity-accounted investments represents the Partnership's proportionate share of Adjusted EBITDA from equity-accounted vessels.

The following table includes reconciliations of Adjusted EBITDA to net income (loss) for the periods presented in these consolidated financial statements:


	Year Ended December 31,
	2020	2019
	$	$
Adjusted EBITDA	599,323	673,199
Depreciation and amortization(1)	(316,317)	(358,474)
Interest expense	(192,723)	(205,667)
Interest income	2,770	5,111
Expenses and gains (losses) relating to equity-accounted investments(2)	(65,431)	(64,529)
Impairment expense, net(3)	(268,612)	(187,680)
Gain (loss) on dispositions, net(4)	3,411	12,548
Realized and unrealized gain (loss) on derivative instruments(5)	(95,189)	(29,628)
Foreign currency exchange gain (loss)	(7,861)	2,193
Other income (expenses), net	(10,472)	(9,677)
Adjusted EBITDA attributable to non-controlling interests	10,677	11,364


Income (loss) before income tax (expense) recovery	(340,424)	(151,240)
Income tax (expense) recovery
Current	(6,543)	(4,666)
Deferred	804	(3,161)
Net loss	(346,163)	(159,067)

(1)Depreciation and amortization by segment for the year ended December 31, 2020 is as follows: FPSO $94.3 million, Shuttle Tanker $163.9 million, FSO $38.0 million, UMS $2.3 million and Towage $17.9 million (December 31, 2019 - FPSO $109.9 million, Shuttle Tanker $184.1 million, FSO $43.3 million, UMS $3.4 million and Towage $17.8 million).

(2)Includes depreciation and amortization, interest expense, interest income, realized and unrealized gain (loss) on derivative instruments, foreign currency exchange gain (loss) and income tax (expense) recovery relating to equity-accounted investments. The sum of (a) Adjusted EBITDA from equity-accounted investments and (b) expenses and gains (losses) relating to equity-accounted investments from this table equals the amount of equity-accounted income (loss) included on the Partnership's consolidated statements of income (loss).

F-56

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(3)Impairment expense, net by segment for the year ended December 31, 2020 is as follows: FPSO $156.7 million, Shuttle Tanker $35.3 million, FSO $53.8 million and Towage $22.9 million (December 31, 2019 - FPSO $136.6 million, Shuttle Tanker $15.3 million and UMS $35.7 million). (see Note 11 for additional information).

(4)Gain (loss) on dispositions, net by segment for the year ended December 31, 2020 is as follows: FPSO $(0.1) million, Shuttle Tanker segment $(1.9) million and FSO $5.4 million (December 31, 2019 - Shuttle Tanker $1.3 million and FSO $11.2 million). (see Note 8 for additional information).

(5)Excludes the realized loss on foreign currency forward contracts.

Segment Assets

For the purpose of monitoring segment performance and allocating resources between segments, the CODM monitors the assets, including equity-accounted investments, attributable to each segment.

A reconciliation of the Partnership's asset by reportable operating segment as at December 31, 2020, December 31, 2019 and January 1, 2019 are as follows:


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
FPSO segment	1,220,084	1,481,797	1,723,693
Shuttle tanker segment	2,134,382	1,902,811	1,864,919
FSO segment	242,312	346,854	384,768
UMS segment	100,467	100,796	137,795
Towage segment	301,270	341,826	365,778
Conventional tanker segment	—	—	4,080
Corporate/Other
Cash and cash equivalents and restricted cash	369,123	306,256	233,580
Other assets	17,993	7,898	8,509

Total assets	4,385,631	4,488,238	4,723,122

Revenues from External Customers

The table below summarize the Partnership's segment revenue by geography based on the operating location of the Partnership's assets for the year ended December 31, 2020 and 2019:


Year Ended December 31, 2020	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Eliminations	Total
Revenues from contracts with customers
Norway	119,537	109,001	17,088	1,828	—	—	247,454
Brazil	48,484	25,578	—	—	—	—	74,062
Netherlands	—	—	—	—	45,991	(5,564)	40,427
Canada	—	48,097	—	—	—	—	48,097
United Kingdom	122,307	1,409	—	—	—	—	123,716
Australia	—	—	5,157	—	—	—	5,157
Other	—	—	7,474	—	—	—	7,474
Total revenues from contracts with customers	290,328	184,085	29,719	1,828	45,991	(5,564)	546,387
Other revenues
Norway	146,938	179,773	64,638	—	—	—	391,349
Brazil	39,750	76,116	—	—	—	—	115,866
Netherlands	—	—	—	—	—	—	—
Canada	—	62,269	—	—	—	—	62,269
United Kingdom	5,786	3,098	5,353	—	—	—	14,237
Australia	—	—	483	—	—	—	483
Other	—	37,845	13,674	—	—	—	51,519
Total other revenues	192,474	359,101	84,148	—	—	—	635,723
Total revenues	482,802	543,186	113,867	1,828	45,991	(5,564)	1,182,110

F-57

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


Year Ended December 31, 2019	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Conventional Segment	Total
Revenues from contracts with customers
Norway	153,483	124,512	28,131	2,940	—	—	309,066
Brazil	56,221	30,907	—	—	—	—	87,128
Netherlands	—	—	—	—	74,726	—	74,726
Canada	—	43,123	—	—	—	—	43,123
United Kingdom	54,164	10,762	—	—	—	—	64,926
Australia	—	—	14,137	—	—	—	14,137
Other	—	—	8,015	—	—	7,972	15,987
Total revenues from contracts with customers	263,868	209,304	50,283	2,940	74,726	7,972	609,093
Other revenues
Norway	136,186	156,065	67,533	—	—	—	359,784
Brazil	64,903	86,220	—	—	—	—	151,123
Netherlands	—	—	—	—	—	—	—
Canada	—	54,053	—	—	—	—	54,053
United Kingdom	12,639	25,172	5,681	—	—	—	43,492
Australia	—	—	3,276	—	—	—	3,276
Other	—	18,773	13,344	—	—	—	32,117
Total other revenues	213,728	340,283	89,834	—	—	—	643,845
Total revenues	477,596	549,587	140,117	2,940	74,726	7,972	1,252,938

For the year ended December 31, 2020, the Partnership recognized $0.1 million of revenues relating to lease income from variable lease payments not dependent on an index or rate (December 31, 2019 - $1.8 million).

The following table presents revenues and percentage of consolidated revenues for customers that accounted for more than 10% of the Partnership’s consolidated revenues during the periods presented:


(U.S. Dollars in millions, except percentages)	Year Ended December 31, 2020	Year Ended December 31, 2019
Royal Dutch Shell Plc (1)	$319.4 or 27%	$311.3 or 25%
BP Plc (2)	$162.1 or 14%	— (4)
Equinor ASA (3)	$143.3 or 12%	$170.8 or 14%

(1)Shuttle tanker and FPSO segments.

(2)Shuttle tanker and FPSO segments.

(3)Shuttle tanker and FSO segments.

(4)Percentage of consolidated revenue was less than 10%.

Non-current Assets

The tables below summarize the Partnership's non-current assets by geography as at December 31, 2020, December 31, 2019 and January 1, 2019:


December 31, 2020	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Corporate/Other	Total
Norway	560,469	1,203,857	157,221	59,798	—	36,552	2,017,897
Brazil	443,559	385,647	—	—	—	—	829,206
Netherlands	—	—	—	—	288,823	—	288,823
Canada	—	355,497	—	—	—	—	355,497
United Kingdom	111,832	60,542	—	—	—	—	172,374

Other	—	32,353	56,490	—	—	—	88,843
Total non-current assets	1,115,860	2,037,896	213,711	59,798	288,823	36,552	3,752,640

F-58

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


December 31, 2019	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Corporate/Other	Total
Norway	765,980	882,811	236,060	79,276	—	1,008	1,965,135
Brazil	502,084	455,023	—	—	—	—	957,107
Netherlands	—	—	—	—	323,920	—	323,920
Canada	—	363,527	—	—	—	—	363,527
United Kingdom	119,247	81,349	5,002	—	—	—	205,598
Australia	—	—	14,687	—	—	—	14,687
Other	—	32,752	62,508	—	—	—	95,260
Total non-current assets	1,387,311	1,815,462	318,257	79,276	323,920	1,008	3,925,234


January 1, 2019	FPSO Segment	Shuttle Tanker Segment	FSO Segment	UMS Segment	Towage Segment	Corporate/Other	Total
Norway	863,122	767,751	265,252	137,168	—	178	2,033,471
Brazil	517,393	517,647	—	—	—	—	1,035,040
Netherlands	—	—	—	—	339,048	—	339,048
Canada	—	366,875	—	—	—	—	366,875
United Kingdom	230,495	101,389	7,400	—	—	—	339,284
Australia	—	—	16,190	—	—	—	16,190
Other	—	33,700	68,540	—	—	—	102,240
Total non-current assets	1,611,010	1,787,362	357,382	137,168	339,048	178	4,232,148

28.Supplemental Cash Flow Information


	Year Ended
	December 31, 2020	December 31, 2019
	$	$
Interest paid	174,827	204,074
Income taxes paid	7,368	4,859

Amounts paid and received for interest were reflected as operating cash flows in the consolidated statements of cash flow.

The changes in non-cash working capital items related to operating activities for the years ended December 31, 2020 and 2019 are as follows:


	Year Ended
	December 31, 2020	December 31, 2019
	$	$
Accounts and other receivable, net	(2,154)	(62,287)
Other assets	7,867	6,362
Accounts payable and other	(8,652)	68,165
Due from (to) related parties	(9,932)	1,101
Changes in non-cash working capital, net	(12,871)	13,341

The following table presents the change in the balance of borrowings arising from financing activities as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Opening balance of borrowings at beginning of year	3,184,512	3,097,742
Cash flows related to borrowings	(24,947)	61,336
Non-cash changes:
Deferred financing costs amortization	13,943	15,483
Other	(2,531)	9,951
Closing balance of borrowings at end of year	3,170,977	3,184,512

F-59

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following table presents the change in the balance of obligations related to finance leases arising from financing activities as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Opening balance of obligations relating to finance leases at beginning of year	21,544	—
Cash flows related to obligations relating to finance leases	117,696	21,547
Non-cash changes:
Other	(1)	(3)
Closing balance of obligations relating to finance leases at end of year	139,239	21,544

The following table presents the change in the balance of borrowings from related parties arising from financing activities as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Opening balance of borrowings from related parties at beginning of year	21,306	125,000
Cash flows related to borrowings from related parties	205,000	(105,000)
Non-cash changes:
Changes in fair value	(37,060)	1,949
Other(1)	5,382	(643)
Closing balance of borrowings from related parties at end of year	194,628	21,306

(1)Includes deferred interest payments and accretion income on the borrowings from related parties.

The following table presents the change in the balance of lease liabilities arising from financing activities as at December 31, 2020 and 2019:


	December 31, 2020	December 31, 2019
	$	$
Opening balance of lease liabilities at beginning of year	67,985	20,201
Cash flows related to lease liabilities	(20,332)	(14,695)
Non-cash changes:
Additions	757	63,349
Dispositions	(15,074)	(1,854)
Other	2,492	984
Closing balance of lease liabilities at end of year	35,828	67,985

29.Financial Risk Management

The Partnership recognizes that risk management is an integral part of a strong management practice.

The Partnership is exposed to the following risks: capital risk, liquidity risk, market risk (i.e. interest rate risk, foreign currency risk and commodity risk) and credit risk. The following is a description of these risks and how they are managed:

a.Capital risk management

The capital structure of the Partnership consists of borrowings, offset by cash and equity. The Partnership's equity consists of Class A common units, Class B common units, preferred units, the general partners interest, accumulated other comprehensive income and non-controlling interests in subsidiaries.

F-60

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


	December 31, 2020	December 31, 2019	January 1, 2019
	$	$	$
Borrowings	3,170,977	3,184,512	3,097,742
Obligations relating to finance leases	139,239	21,544	—
Due to related parties(1)	194,628	21,306	125,000
Less:
Cash and cash equivalents	235,734	199,388	225,040
Restricted cash	133,389	106,869	8,540
Net debt	3,135,721	2,921,105	2,989,162
Total equity	244,899	597,802	793,033
Total equity and net debt	3,380,620	3,518,907	3,782,195
Net debt to capitalization ratio	93%	83%	79%

(1)Includes borrowings from related parties. Refer to Note 20.

The Partnership manages its debt exposure by financing its operations with non-recourse borrowings in subsidiaries of the Partnership, ensuring a diversity of funding sources as well as managing its maturity profile. The Partnership also borrows in U.S. Dollars in order to mitigate its currency risk.

As disclosed in Note 20, the Partnership has various credit facilities in place. In certain cases, the facilities have financial covenants which are generally in the form of debt service coverage ratios, vessel values to drawn principal balance ratios and minimum liquidity requirements. The Partnership does not have any market capitalization covenants attached to any of its borrowings, nor does it have any other externally imposed capital requirements.

b.Liquidity risk management

The Partnership maintains sufficient financial liquidity to be able to meet its ongoing operating requirements. The Partnership's primary liquidity needs for the next twelve months are to pay existing committed capital expenditures, to make scheduled repayments of debt and related interest rate swaps, to pay debt service costs, to make quarterly distributions on outstanding preferred units, to pay direct operating costs and dry-docking expenditures, to fund general working capital requirements, to settle claims and potential claims against the Partnership and to manage its working capital deficit.

For further information on the Partnership's contractual obligations, including a maturity analysis, please refer to Notes 10, 12, 19 and 20. See Note 2b for the Partnership’s assessment of its ability to meet these obligations for at least the one-year period to December 31, 2021.

c.Market risk

Market risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by the Partnership will fluctuate because of changes in market prices. Market risk includes the risk of changes in interest rates, foreign currency exchange rates and changes in market prices due to factors other than interest rates or foreign currency exchange rates, such as changes in commodity prices or credit spreads.

Financial instruments held by the Partnership that are subject to market risk include borrowings and derivative instruments, such as interest rate swaps and foreign currency forward contracts.

Interest rate risk management

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Partnership is exposed to the impact of interest rate changes, primarily through its floating-rate borrowings that require it to make interest payments based on LIBOR. Significant increases in interest rates could adversely affect operating margins, results of operations and the Partnership's ability to service its debt. The Partnership uses interest rate swaps to reduce its exposure to market risk from changes in interest rates. The principal objective of these contracts is to minimize the risks and costs associated with the Partnership's floating-rate debt.

As at December 31, 2020, the Partnership had outstanding floating-rate debt balance of $1.8 billion and an outstanding notional balance of $1.2 billion of interest rate swaps. A 10 basis point decrease in the Partnership’s interest rates is expected to increase future cash flows by $0.7 million.

The Partnership is exposed to credit loss in the event of non-performance by the counterparties to the interest rate swap agreements. In order to minimize counterparty risk, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

For further information on the financial instruments held by the Partnership that are subject to interest rate risk, include borrowings and derivative instruments, please refer to Note 4, which includes the fair values of the interest rate risk sensitive financial instruments, and Notes 19 and 20, which include the expected cash flows from the interest rate risk sensitive financial instruments.

Foreign currency risk management

Foreign currency risk is the risk that the fair value or future cash flows of an exposure will fluctuate because of changes in foreign exchange rates. The net income impact to the Partnership of foreign currency risk associated with financial instruments is limited as its financial assets and liabilities

F-61

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

are generally denominated in the Partnership's functional currency. However, the Partnership is exposed to foreign currency risk on the net assets of its foreign currency denominated operations. The Partnership enters into foreign currency forward contracts to mitigate the impact from movements in foreign exchange rates against the U.S. dollar. The following tables set out the Partnership's currency exposure of financial instruments as at December 31, 2020, December 31, 2019 and January 1, 2019:


(in thousands of U.S. Dollars)	December 31, 2020
	USD	NOK	AUD	GBP	CAD	EUR	BRL	Other	Total
Financial assets
Current assets	470,906	31,940	123	48,068	8,914	1,651	3,536	4,672	569,810
Non-current assets	87,274	737	—	—	—	—	—	—	88,011
Total	558,180	32,677	123	48,068	8,914	1,651	3,536	4,672	657,821
Financial liabilities
Current liabilities	592,664	9,815	10,985	4,174	—	2,324	419	530	620,911
Non-current liabilities	3,159,205	5,043	—	3,548	192	541	914	443	3,169,886
Total	3,751,869	14,858	10,985	7,722	192	2,865	1,333	973	3,790,797


(in thousands of U.S. Dollars)	December 31, 2019
	USD	NOK	AUD	GBP	CAD	EUR	BRL	Other	Total
Financial assets
Current assets	301,862	36,271	5,400	9,014	6,509	26,335	25,390	7,194	417,975
Non-current assets	109,231	—	—	—	—	—	—	—	109,231
Total	411,093	36,271	5,400	9,014	6,509	26,335	25,390	7,194	527,206
Financial liabilities
Current liabilities	458,911	4,061	212	3,523	1,404	1,204	574	4,268	474,157
Non-current liabilities	3,031,105	6,597	—	3,894	209	639	109	—	3,042,553
Total	3,490,016	10,658	212	7,417	1,613	1,843	683	4,268	3,516,710


(in thousands of U.S. Dollars)	January 1, 2019
	USD	NOK	AUD	GBP	CAD	EUR	BRL	Other	Total
Financial assets
Current assets	352,211	41,662	4,962	4,907	6,807	3,793	16,088	5,282	435,712
Non-current assets	38,611	987	—	—	—	10	—	2,938	42,546
Total	390,822	42,649	4,962	4,907	6,807	3,803	16,088	8,220	478,258
Financial liabilities
Current liabilities	769,538	10,942	—	1,607	356	3,749	1,368	1,695	789,255
Non-current liabilities	2,688,059	9,004	—	—	—	—	—	—	2,697,063
Total	3,457,597	19,946	—	1,607	356	3,749	1,368	1,695	3,486,318

The Partnership’s exposures to foreign currencies and the sensitivity of net income and other comprehensive income, on a pre-tax basis, to a 10% change in the exchange rates relative to the United States dollar is summarized below:


(in thousands of U.S. Dollars)	December 31, 2020
	10% decrease	10% increase
Norwegian Krone	(1,782)	1,782
British Pound	(4,035)	4,035
Other	(255)	255


(in thousands of U.S. Dollars)	December 31, 2019
	10% decrease	10% increase
Norwegian Krone	(2,561)	2,561
British Pound	(160)	160
Other	(6,221)	6,221

F-62

ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2020, December 31, 2019 and January 1, 2019 and for the years ended December 31, 2020 and 2019

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Commodity price risk management

The Partnership is exposed to changes in forecasted bunker fuel costs for certain vessels being time-chartered-out and for vessels servicing certain CoAs. The Partnership may use bunker fuel swap contracts as economic hedges to protect against changes in bunker fuel costs. As at December 31, 2020, the Partnership was not committed to any bunker fuel swap contracts.

d.Credit risk

Credit risk is the risk of loss due to the failure of a borrower or counterparty to fulfill its contractual obligations.

The Partnership assesses the credit worthiness of each counterparty before entering into contracts and ensures that counterparties meet minimum credit quality requirements. The Partnership also evaluates and monitors counterparty credit risk for derivative financial instruments and endeavors to minimize counterparty credit risk through diversification.

All of the Partnership’s derivative financial instruments involve either counterparties that are banks or other financial institutions. The Partnership does not have any significant credit risk exposure to any single counterparty.

As at December 31, 2020, the Partnership had a significant amount of contractual payments, included in Accounts and other receivable, net in the Partnership's consolidated statement of financial position, which are more than 30 days past due. This amount mainly relates to an outstanding balance from a single counterparty. The Partnership has rebutted the presumption that the credit risk related to these contractual payments has increased significantly since initial recognition as the Partnership has no experience of past default with its debtors and no expectations of future losses as a result of default. In addition, as at December 31, 2020, the Partnership had a significant amount of contractual amounts owing to the same counterparty, for which, if required, the Partnership would expect to offset against the contractual payments overdue as a form of settlement. The Partnership does not expect that this will be necessary and is currently in the process of settling all balances with this counterparty.

Based on no experience of past default of the Partnership's debtors and no expectations of future losses as a result of default, the Partnership has determined its credit risk to be low. For the purposes of credit risk, the Partnership has applied a definition to the term default as an assessment that a counterparty is unlikely to pay, as well as an amount outstanding from a counterparty which is 90 days past due. As at December 31, 2020, the Partnership recorded an ECL of $1.4 million (December 31, 2019 - $nil. January 1, 2019 - $nil).

30.Other income (expenses), net

The table below summarize the Partnership's other income (expenses), net for the year ended December 31, 2020 and 2019:


	Year Ended December 31,
	2020	2019
	$	$
Restructuring costs(1)	(9,994)	(119)
Gain (loss) on modification of financial liabilities, net	—	(8,332)
Other, net	(478)	(1,226)
Total other income (expenses), net	(10,472)	(9,677)

(1)During the year ended December 31, 2020, the Partnership recognized restructuring costs of $10.0 million primarily related to severance costs from the contract termination of the Dampier Spirit FSO unit and severance costs associated with the transition of administrative services from Teekay Corporation to the Partnership.

31.Subsequent Events

a.In February 2021, the Partnership entered into two unsecured revolving credit facilities provided by Brookfield. The borrowings available under the two revolving credit facilities are $70.0 million and $30.0 million, respectively, and mature in February 2022. The interest payments on the revolving credit facilities are based on LIBOR plus a margin of 5.00% per annum, with interest payable one, two, three or six months after the drawdown on the facilities, at the election of the Partnership in consultation with Brookfield.

b.In February 2021, the Partnership refinanced an existing term loan relating to the financing of the Petrojarl I FPSO unit. As at December 31, 2020, this term loan had an outstanding balance of $34.2 million and matured in September 2021. The new facility provides for borrowings of $75.0 million, which reduces over time with monthly payments and matures in February 2024. The interest payments on the new facility are based on LIBOR plus a margin of 3.50% per annum, with interest payable one or three months after the drawdown on the new facility, at the election of the Partnership.

c.In February 2021, the Partnership terminated two and amended two of its interest rate swap agreements, which as at December 31, 2020, had a total notional amount of $600.3 million and a total fair value liability of $147.5 million. These interest rate swaps included early termination provisions, which if exercised, would terminate these interest rate swaps in February 2021. Following the terminations and amendments, the total notional amount relating to the two remaining interest rate swap agreements will be reduced to $132.0 million in April 2021. These agreements include mandatory termination provisions which terminate these interest rate swaps in February 2022.

F-63