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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
___________________________________
FORM 20-F
___________________________________
(Mark One)
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| ☐ | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
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| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2021
OR
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
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| ☐ | 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
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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
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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
4,909,063 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 | | | | | | | | |
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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 resume making cash distributions on our units;
•our future growth prospects, business strategy, 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 enter into new debt facilities, borrow additional amounts under existing facilities, refinance or extend existing debt obligations, to fund capital expenditures, to sell certain assets, to pursue growth projects and to negotiate extensions or redeployments of existing assets;
•measures taken to improve our debt maturity profile and enhance our liquidity and financial flexibility;
•our ability to maintain and expand long-term relationships with major oil companies, including our ability to service fields until they no longer produce, and the potential 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 III LLC, 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 an investigation by Norwegian authorities of potential violations of Norwegian pollution and export laws in connection with shuttle tanker export and subsequent recycling activities;
•our continued ability to enter into fixed-rate time charters and floating production, storage and offloading (or FPSO) contracts with customers;
•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 newbuilding;
•the expected employment of shuttle tanker newbuilding;
•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 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;
•our general and administrative expenses as a public company 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.[Reserved]
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 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;
•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 moderated by vaccines, 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 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, with steep declines as recently as in 2020, due to the uncertainty regarding demand created by the COVID-19 pandemic, before recovering well in 2021 and into 2022 as increasing COVID-19 vaccination rates, loosening pandemic-related restrictions, and a growing economy resulted in global demand rising faster than supply. 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 cancellable 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 could result in a significant loss of revenues and cash flow.
Three of our customers accounted for an aggregate of 55% and 53% of our consolidated revenues during the years ended December 31, 2021 and 2020, respectively. 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.
Following Russia’s invasion of Ukraine in February 2022, the U.S., several European Union nations, and other countries have announced sanctions against Russia. The sanctions announced by the U.S. and other countries against Russia include, among others, restrictions on selling or importing goods, services or technology in or from affected regions, travel bans and asset freezes impacting connected individuals and political, military, business and financial organizations in Russia, severing large Russian banks from U.S. and/or other financial systems, and barring some Russian enterprises from raising money in the U.S. market. The U.S., EU nations and other countries could impose wider sanctions and take other actions should the conflict further escalate. While it is difficult to anticipate the potential for any indirect impact the sanctions announced to date may have on our business and us, any further sanctions imposed or actions taken by the U.S., EU nations or other countries, and any retaliatory measures by Russia in response, such as restrictions on oil shipments from Russia, could lead to increased volatility in global oil demand which, could have a material adverse impact on our business, results of operations and financial condition.
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 years ended December 31, 2021 and 2020, we recognized impairment expenses, net of $116 million and $269 million, respectively. Further, during the year ended December 31, 2021, our equity in earnings in the joint venture includes an impairment expense of $36 million recognized within our Itajai Joint Venture on the Cidade de Itajai FPSO unit (December 31, 2020 - $nil). Refer to Item 18 – Financial Statements: Note 10 - Vessels and Equipment and Note 12 - Equity Accounted Investments. 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, including current or future tensions and the invasion of Ukraine by Russia, 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 affect demand for our services, contribute to high levels of volatility in charter rates or oil prices and affect capital markets and our access to capital. 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.
Our subsidiary, Altera Infrastructure Norway AS, is subject to an ongoing investigation relating to suspected violations of Norwegian pollution and export laws. The investigations are currently ongoing and relate to shuttle tanker exports from the Norwegian Continental Shelf in 2018. Whilst the Norwegian authorities continue their review of seized materials, we have, together with our advisors, continued to review materials connected with such export and, having not identified that any such process breached any export laws, continue to deny the allegations brought. Although we have not identified any such violations and deny the charges, no assurance can be made with respect to the results or timing of the ongoing review and investigations. Should the Norwegian authorities conclude that Altera Infrastructure Norway AS has breached relevant export restrictions, this may result in fines against the company as well as cause us wider reputational damage.
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.
An increasing concern for, and focus on climate change has promoted extensive existing and proposed international, national and local regulations intended to reduce greenhouse gas emissions (including from various jurisdictions and the IMO). These regulatory measures may include the adoption of cap and trade regimes, carbon taxes, increased efficiency standards and incentives or mandates for renewable energy. Compliance with these or other regulations and our efforts to participate in reducing greenhouse gas emissions will likely increase our compliance costs, require additional capital expenditures to reduce vessel emissions and require changes to our business.
Our business includes producing, transporting and storing oil and refined petroleum products. Regulatory changes and growing public concern about the environmental impact of climate change may lead to reduced demand for hydrocarbon products and decreased demand for our services, while increasing or creating greater incentives for use of alternative energy sources. We expect regulatory and consumer efforts aimed at combating climate change to intensify and accelerate. Although we do not expect demand for oil and gas to decline dramatically over the short-term, in the long-term, climate change initiatives will likely significantly affect demand for oil and gas and for alternatives. Any such change could adversely affect our ability to compete in a changing market and our business, financial condition and results of operations.
Increasing scrutiny and changing expectations from investors, lenders, customers and other market participants with respect to ESG policies and practices may impose additional costs on us or expose us to additional risks.
Companies across all industries are facing increasing scrutiny relating to their Environmental, Social and Governance (or ESG) policies. Investor advocacy groups, certain institutional investors, investment funds, lenders and other market participants are increasingly focused on ESG practices and, in recent years, have placed increasing importance on the implications and social cost of their investments. The increased focus and activism related to ESG and similar matters may hinder access to capital, as investors and lenders may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor, lender or other industry shareholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and their business, financial condition and stock price may be adversely affected.
We may face increasing pressures from investors, lenders, customers and other market participants, which are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. As a result, we may be required to implement more stringent ESG procedures or standards so that our existing and future investors remain invested in us and make further investments in us, or in order for customers to consider conducting future business with us, and so that we can continue to attract the employees needed to operate our business, especially given our business of producing, transporting and storing oil and refined petroleum products. In addition,
it is likely we will incur additional costs and require additional resources to monitor, report and comply with wide-ranging ESG requirements. The occurrence of any of the foregoing could have a material adverse effect on our business, financial condition and results of operations.
Risks Relating to Our Liquidity
We have limited current liquidity.
As at December 31, 2021, we had total liquidity of $190.9 million and a working capital deficit of $276.4 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, extension or other amendments, including amendment of financial covenants, of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnership's business interests, enter into sale-leaseback agreements, increasing equity, and other potential liability management transactions. However, there can be no assurance that any such sources of financing will be available to us on acceptable terms, if at all.
We have suspended, and are contractually restricted from making, quarterly cash distributions on our Preferred Units.
In July 2021, we suspended the payment of quarterly cash distributions on our outstanding common units and Preferred Units. In addition, no distributions on the Preferred Units will be permitted without noteholder consent while the 11.50% PIK Notes issued in the Brookfield Exchanges remain outstanding. However, all distributions on the Preferred Units will continue to accrue and must be paid in full before distributions to Class A and Class B common unitholders can be made.
If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our Preferred Units, which would have an adverse impact on the trading volume, liquidity and market price of our Preferred Units.
Our Preferred Units are currently listed on the NYSE, and we are therefore subject to certain of the NYSE’s continued listing requirements. If the Preferred Units were to be delisted from the NYSE for any reason, it could negatively impact us as it could reduce the liquidity and market price of the Preferred Units, reduce the number of investors willing to hold or acquire the Preferred Units, and negatively impact our ability to obtain future financing.
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 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. 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 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, 2021, our total borrowings were approximately $2.5 billion and our net debt to capitalization ratio was 97%. The payment of interest “in-kind” under our 11.50% PIK Notes and 12.50% PIK Notes held by Brookfield will reduce our interim debt service expenses but will increase the principal amount of our otherwise outstanding indebtedness. 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 the majority 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, which would likely result in a material adverse effect on our business and may impair our ability to continue as a going concern. 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, 2021, we were in compliance with all covenants relating to our consolidated borrowings.
Restrictions in our financing agreements currently, and in the future may continue to, 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, no distributions on the Preferred Units will be permitted without noteholder consent while the 11.50% PIK Notes issued in the Brookfield Exchanges remain outstanding. See “—We have suspended, and are contractually restricted from making, quarterly cash distributions on our Preferred Units.” Furthermore, our and our subsidiaries’ other 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 lease obligations subject us to interest rate risk, which could cause our debt service and lease obligations to increase.
We are subject to interest rate risk in connection with borrowings and 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. As of December 31, 2021, LIBOR is no longer published on a representative basis, with the exception of the most commonly used tenors of U.S. dollar (USD) LIBOR which will no longer be published on a representative basis after June 30, 2023. 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, and our financing agreements, 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. In addition, as of December 31, 2021, our total borrowings from and indebtedness owed to Brookfield and its affiliates totaled $797 million. Neither we nor our general partner or its officers and directors owe any fiduciary duties to holders of our preferred units or 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.
As reported in our Annual Report on Form 20-F for the fiscal year ended December 31, 2020, we had a material weakness in our internal control over financial reporting. While we have remediated this material weakness during the fiscal year ended December 31, 2021 and concluded that our internal control over financial reporting was effective as of December 31, 2021, such remediation does not guarantee that our remediated controls will continue to operate properly, or that we will not experience another material weakness in the future.
Internal controls related to the operation of technology systems are critical to maintaining adequate internal control over financial reporting. As disclosed in Item 15 “Controls and Procedures” of our Annual Report on Form 20-F for the fiscal year ended December 31, 2020 that we filed with the SEC on March 4, 2021, management had identified a material weakness evidencing an ineffective control environment relating to ineffective information technology general controls in the areas of user access over certain information technology systems that support our financial reporting processes. As a result, management concluded that our internal control over financial reporting was not effective as of December 31, 2020. As of December 31, 2021, this material weakness has been remediated and we have concluded that our internal control over financial reporting was effective. However, we recognize that maintaining adequate internal control over financial reporting will continue to require significant management attention and expense, and we cannot assure you that we will not identify similar material weaknesses in the future. If new material weaknesses are identified in our internal controls then the accuracy and timing of our financial reporting may be adversely affected, we may be unable to maintain compliance with securities law requirements regarding the timely filing of periodic reports or the NYSE listing requirements.
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 the 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 in which, after taking into account the income and assets of the corporation and, pursuant to a “look-through” rule, any other corporation or partnership in which the corporation directly or indirectly owns at least 25% of the stock or equity interests (by value) and any partnership in which the corporation directly or indirectly owns less than 25% of the equity interests (by value) to the extent the corporation satisfies an “active partner” test and does not elect out of “look through” treatment, 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 and our look-through subsidiaries’ 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 the 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 look-through 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 and our look-through subsidiaries’ assets, income or operations.
If we or 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 U.S. federal income 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, including in certain cases estimates, 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, further reducing the cash available for distribution. 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.
Tax laws, including tax rates, in the jurisdictions in which we operate may change as a result of macroeconomic or other factors outside of our control. For example, various governments and organizations such as the EU and Organization for Economic Co-operation and Development (the “OECD”) are increasingly focused on tax reform and other legislative or regulatory action to increase tax revenue.
In January 2019, the OECD announced further work in continuation of its Base Erosion and Profit Shifting project, focusing on two “pillars.” Pillar One provides a framework for the reallocation of certain residual profits of multinational enterprises to market jurisdictions where goods or services are used or consumed. Pillar Two consists of two interrelated rules referred to as Global Anti-Base Erosion Rules, which operate to impose a minimum tax rate of 15% calculated on a jurisdictional basis. In the third quarter of 2021, more than 130 countries tentatively signed on to a framework that imposes a minimum tax rate of 15%, among other provisions. Qualifying international shipping income is exempt from many aspects of this framework. The framework calls for law enactment by OECD and G20 members in 2022 to take effect in 2023 and 2024. On December 20, 2021, the OECD published model rules to implement the Pillar Two rules, which are generally consistent with agreement reached by the framework in October 2021. These changes, when enacted by various countries in which we do business, may increase our taxes in these countries. As this framework is subject to further negotiation, final approval by the G20, and implementation by each member country, the timing and ultimate impact of any such changes on our tax obligations are uncertain.
The U.S. presidential administration and members of the U.S. Congress have proposed significant changes in U.S. federal income tax law, regulation and government policy within the United States, which could affect us and our business. These proposals are being considered by the U.S. Congress, but the likelihood of these or other changes being enacted or implemented is unclear. We are currently unable to predict whether these or other changes will occur and, if so, the ultimate impact on our business. To the extent that such changes have a negative impact on us, our suppliers or our consumers, including as a result of related uncertainty, these changes may materially and adversely impact our business, financial condition, results of operations and cash flow.
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 22 - Equity.
As of December 31, 2021, 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 10 - Vessels and Equipment and Note 11 - Advances on Newbuilding Contracts for a description of our capital expenditures during 2021 and 2020 and capital expenditures currently in progress as at December 31, 2021.
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, 2021, our fleet was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Vessels |
| Owned Vessels | | Chartered-in Vessels | | Committed Newbuildings | | Total |
| FPSO Segment | 7 | (i) | | — | | | — | | | 7 | |
| Shuttle Tanker Segment | 22 | (ii) | | 1 | | | 1 | (iii) | | 24 | |
| FSO Segment | 3 | | | — | | | — | | | 3 | |
| UMS Segment | 1 | | | — | | | — | | | 1 | |
| Towage Segment | 10 | | | — | | | — | | | 10 | |
| Total | 43 | | | 1 | | | 1 | | | 45 | |
(i)Includes two FPSO units, the Cidade de Itajai and Pioneiro de Libra, in which our ownership interest is 50 percent.
(ii)Includes two shuttle tankers in which our ownership interest is 50 percent.
(iii)Includes one DP2 shuttle tanker newbuildings scheduled for delivery in March 2022, which will operate under an existing contract off the East Coast of Canada.
The tables below provide a breakdown of total assets by operating segment and non-current assets by region as at December 31, 2021, and revenues for the year ended December 31, 2021 by operating segment and region.
Operating Segments
| | | | | | | | | | | |
| Assets | | Revenues |
| (in thousands of U.S Dollars) | As at December 31, 2021 | | Year Ended December 31, 2021 |
| FPSO Segment | 963,625 | | | 489,878 | |
| Shuttle Tanker Segment | 2,093,467 | | | 513,495 | |
| FSO Segment | 198,703 | | | 75,405 | |
| UMS Segment | 58,900 | | | 895 | |
| Towage Segment | 308,621 | | | 80,134 | |
| Eliminations | — | | | (8,547) | |
| Corporate/Other | | | |
| Cash and cash equivalents and restricted cash | 255,756 | | | — | |
| Other assets | 5,652 | | | — | |
| | | |
| Total | 3,884,724 | | | 1,151,260 | |
Region
| | | | | | | | | | | |
| Non-Current Assets | | Revenues |
| (in thousands of U.S Dollars) | As at December 31, 2021 | | Year Ended December 31, 2021 |
Norway(1) | 1,856,112 | | | 630,708 | |
Brazil(1) | 775,764 | | | 176,646 | |
| Netherlands | 277,567 | | | 71,313 | |
| Canada | 365,608 | | | 109,366 | |
United Kingdom(1) | 69,606 | | | 115,031 | |
| | | |
| Other | 79,483 | | | 48,196 | |
| | | |
| Total | 3,424,140 | | | 1,151,260 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, the United Kingdom and Brazilian continental shelves respectively.
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, 2021, we owned five FPSO units, in which we have 100% ownership interests, three 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, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | May 2022 |
| Cidade de Itajai | | 80,000 | | 2012 | | 50% | | Bauna and Piracaba, Brazil | | Karoon | | February 2026 (1) |
| Petrojarl I | | 30,000 | | 1986 | | 100% | | Atlanta, Brazil | | Enauta | | May 2023 (2) |
| Piranema Spirit | | 30,000 | | 2007 | | 100% | | | | Lay-up | | |
| Petrojarl Varg | | 57,000 | | 1998 | | 100% | | | | Lay-up | | |
| Voyageur Spirit | | 30,000 | | 2008 | | 100% | | | | Lay-up | | |
| Total capacity | | 340,000 | | | | | | | | | | |
(1)The charterer has options to extend the contract to February 2028.
(2)Until May 2023, the charterer has termination rights with four months' notice subject to the payment of certain termination fees. In January 2022, the contract was extended by one year to May 2024, with one year option to May 2025.The extension has similar termination rights as the existing contract.
The table below provides a breakdown of revenues for our FPSO segment by region:
| | | | | | | | | | | | | | | | | |
| Year Ended |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| (in thousands of U.S Dollars) | $ | | $ | | $ |
Norway(1) | 298,191 | | | 266,970 | | | 289,669 | |
Brazil(1) | 76,656 | | | 88,234 | | | 121,124 | |
| | | | | |
| | | | | |
United Kingdom(1)(2) | 115,031 | | | 128,093 | | | 66,803 | |
| | | | | |
| | | | | |
| | | | | |
| Total | 489,878 | | | 483,297 | | | 477,596 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, the United Kingdom and Brazilian continental shelves respectively.
(2)Includes revenues earned through management services provided for FPSO units on behalf of disponent owners or charterers.
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 contracts of affreightment for various fields. The number of voyages performed under the contracts of affreightment depends mainly 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, which provides increased utilization for the fleet.
Shuttle tankers primarily operate in Brazil, the North Sea and off the East Coast of Canada. As of December 31, 2021, we owned 22 shuttle tankers, of which two are 50% owned, had one shuttle tanker under construction and chartered-in an additional shuttle tanker. Other shuttle tanker owners include Knutsen, AET and Viken MOL. 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, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, Capricorn, ConocoPhillips, DNO, Eni, Enquest, Equinor, Idemitsu,Ithaca, Lundin, M Vest Energy, Molgrowest, NEO Energy, OKEA, OMV, ONE Dyas, PGNiG, Premier Oil, Repsol Sinopec, Shell, Taqa Bratani, Vår Energi, Wintershall Dea(3)
| | |
| 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(2) | | CoA | | | |
| Petroatlantic | | 93,000 | | 2003 | | 100% | | DP2 | | North Sea | | CoA | | | |
| Petronordic | | 93,000 | | 2002 | | 100% | | DP2 | | North Sea | | CoA | | | |
| Ingrid Knutsen | | 111,600 | | 2013 | | In-chartered (until November 2022) | | DP2 | | North Sea | | CoA | | | |
| Altera Wind | | 103,500 | | 2021 | | 100% | | DP2 | | North Sea | | CoA | | | |
| Altera Wave | | 103,500 | | 2021 | | 100% | | DP2 | | North Sea | | CoA | | | |
| Samba Spirit | | 154,100 | | 2013 | | 100% | | DP2 | | Brazil | | TC | | Shell | | June 2023 |
| Lambada Spirit | | 154,000 | | 2013 | | 100% | | DP2 | | Brazil | | TC | | Shell | | August 2023 |
| Bossa Nova Spirit | | 155,000 | | 2013 | | 100% | | DP2 | | Brazil | | TC | | Shell | | November 2023 |
| Sertanejo Spirit | | 155,000 | | 2013 | | 100% | | DP2 | | Brazil | | TC | | Shell | | January 2024 |
| Beothuk Spirit | | 148,200 | | 2017 | | 100% | | DP2 | | Canada | | TC | | ExxonMobil, Canada Hibernia, Chevron, Husky, Mosbacher, Murphy, Nalcor, Equinor, Suncor(3) | | May 2030(6) |
| Norse Spirit | | 148,200 | | 2017 | | 100% | | DP2 | | Canada | | TC | | | May 2030(6) |
| Dorset Spirit | | 148,200 | | 2018 | | 100% | | DP2 | | Canada | | TC | | | May 2030(6) |
Altera Thule(7) | | 148,200 | | 2022 | | 100% | | DP2 | | Canada | | NB | | | May 2030(6) |
| Navion Gothenburg | | 152,200 | | 2006 | | 50%(4) | | DP2 | | Far-East | | Spot | | | | |
| Nordic Brasilia | | 151,300 | | 2004 | | 100% | | DP | | Far-East | | Spot | | | | |
| Nordic Rio | | 151,300 | | 2004 | | 50%(4) | | DP | | Far-East | | Spot | | | | |
| Aurora Spirit | | 129,830 | | 2020 | | 100% | | DP2 | | North Sea | | TC | | Equinor(5) | | March 2035 |
| Rainbow Spirit | | 129,830 | | 2020 | | 100% | | DP2 | | North Sea | | TC | | Equinor(5) | | March 2029 |
| Current Spirit | | 129,830 | | 2020 | | 100% | | DP2 | | North Sea | | TC | | Equinor(5) | | March 2023 |
| Total capacity | | 3,126,820 | | | | | | | | | | | | | | |
(1)“CoA” refers to contracts of affreightment, "TC" refers to time charters, "NB" refers to newbuilding vessel.
(2)The Amundsen Spirit shuttle tanker was temporarily contracted to assist the East Coast of Canada fleet during the winter months of late-2021 and early-2022.
(3)The charter agreements specify which shuttle tankers may be employed under the contract and the actual usage depends on the transport demand.
(4)Owned through a partnership in which we have a 50% ownership interest.
(5)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.
(6)The charterer may adjust the number of vessels servicing the East Coast of Canada contract by providing at least 24 months' notice.
(7)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 due to rougher weather conditions and oil production is at the highest as offshore installations perform turnarounds (a planned break in production) during the summer months. Turnarounds affect oil production as the installations may be partly or fully closed down for maintenance for shorter periods of time. This provides opportunities for repairs and maintenance on our vessels to be performed at the same time.
The table below provides a breakdown of revenues for our shuttle tanker segment by region: | | | | | | | | | | | | | | | | | |
| Year Ended |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| (in thousands of U.S Dollars) | $ | | $ | | $ |
Norway(1) | 280,974 | | | 288,279 | | | 280,577 | |
Brazil(1) | 99,990 | | | 101,694 | | | 117,127 | |
| | | | | |
| Canada | 109,366 | | | 110,366 | | | 97,176 | |
United Kingdom(1) | — | | | 4,507 | | | 35,934 | |
| | | | | |
| Other | 23,165 | | | 37,845 | | | 18,773 | |
| | | | | |
| Total | 513,495 | | | 542,691 | | | 549,587 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, the United Kingdom and Brazilian continental shelves respectively.
FSO Segment
FSO units provide on-site storage for oil field installations. An FSO unit is generally used in combination with fixed or floating production systems that do not have sufficient oil storage capacity. 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 contracts as an integrated part of the field development, which provides stable cash flows to us.
As of December 31, 2021, we owned three 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, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vessel | | Capacity (dwt) | | Built | | Ownership | | Field name and location | | Contract Type | | Charterer | | Contract End Date |
| Randgrid | | 124,500 | | 1995 | | 100% | | Gina Krog, Norway | | Time charter | | Equinor | | October 2022 (1) |
| Suksan Salamander | | 78,200 | | 1993 | | 100% | | Bualuang, Thailand | | Time charter | | Medco Energi | | August 2024 (1) |
| Falcon Spirit | | 124,500 | | 1986 | | 100% | | Al Rayyan, Qatar | | Time charter | | Qatar Petroleum | | May 2022 |
| Total capacity | | 327,200 | | | | | | | | | | | | |
(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, 2021 | | December 31, 2020 | | December 31, 2019 |
| (in thousands of U.S Dollars) | $ | | $ | | $ |
Norway(1) | 50,374 | | | 81,726 | | | 95,664 | |
United Kingdom(1) | — | | | 5,353 | | | 5,681 | |
| Australia | — | | | 5,640 | | | 17,413 | |
| Other | 25,031 | | | 21,148 | | | 21,359 | |
| | | | | |
| Total | 75,405 | | | 113,867 | | | 140,117 | |
(1) Reference to Norway and the United Kingdom are to income from activities occurring on the Norwegian and the United Kingdom continental shelves respectively.
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 following table provides additional information about our UMS as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vessel | | Berths | | Built | | Ownership | | Location | | Contract type | | | | |
| Arendal Spirit | | 500 | | 2015 | | 100% | | Norway | | Lay-up(1) | | | | |
| | | | | | | | | | | | | | |
(1)In February 2022, the Partnership signed an agreement with Energean Isreal Ltd. to redeploy the Arendal Spirit UMS on a 100 day firm contract with extension options.
The table below provides a breakdown of revenues for our UMS segment by region:
| | | | | | | | | | | | | | | | | |
| Year Ended |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| (in thousands of U.S Dollars) | $ | | $ | | $ |
Norway(1) | 895 | | | 1,828 | | | 2,940 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total | 895 | | | 1,828 | | | 2,940 | |
(1)Reference to Norway is to income from activities occurring on the Norwegian continental shelf.
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, 2021, we owned ten towage vessels.
The following table provides additional information about our towage vessels as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2021 | | December 31, 2020 | | December 31, 2019 |
| (in thousands of U.S Dollars) | $ | | $ | | $ |
| | | | | |
| | | | | |
| Netherlands | 80,134 | | | 45,991 | | | 74,726 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total | 80,134 | | | 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 long-term business strategy, "Nurture the core - transition for more", include the following:
•Harness the value of our existing business. Our customers 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 and grow our core business. At the core of this effort is the redeployment of our key assets and execution of selective new projects, focusing on increased return on capital and the development of further capital light and asset management solutions.
•Decarbonize our industry. We are committed to drive innovation to identify and accelerate reduction of emissions. Our aim is to continue to capitalize on and secure value for our customers through our leading position in shipping decarbonization. This effort will require strong partnerships with like-minded customers, suppliers and technology centers, in addition to a strong focus on data analytics and the added innovation and value that can be driven by the right data.
•Seize our opportunity in the Energy Transition. We seek to maximize value for our unitholders, through our commitment to the energy transition and the new business opportunities arising within sustainable offshore industries. Altera has a strong platform and capabilities well suited to pivot into targeted opportunities.
•Champion the power of Altera - our TEAM. We commit to people who are driven, flexible and want to play their biggest game, focusing on attracting and retaining ambitious people that are eager to change and drive improvements. We work within our Accountability Leadership
framework, always focused at being accountable, both as leaders and an organization. We will play our part in changing the world by driving sustainable behaviors, promoting diversity and inclusion and building on our positive social impact.
Customers
Our customers are predominantly global energy producers with whom we primarily have medium-to-long-term, fixed-rate contracts. Refer to Item 18 – Financial Statements: Note 26 - Segment Information - 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 for shuttle tankers and towage vessels or two and a half-year period for FSO and UMS units, all vessels undergo annual and intermediate surveys. For shuttle tankers and towage vessels the vessel's underwater areas are inspected as part of a dry dock at five year intervals. For FSO and UMS units the vessel’s underwater areas are inspected every 2.5 years. 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.
Our FPSO units also have class and flag as described above, but all class surveys and flag inspections are carried out afloat and on location for the full duration of the contract. In addition, all our FPSO units undergo extensive audits by the shelf state authorities of the countries we operate in. Most shelf states do these audits annually, while some do up to 4 audits per year. The main focus of the shelf states relates to our compliance with shelf state requirements and how we manage major accident hazards as well as health, safety and environmental requirements.
To assure ourselves that we comply with all relevant requirements and operate our FPSO units within the operational envelope, we carry out internal major accident hazards audits on our FPSO units annually.
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.
All ships are required to develop and implement Ship Energy Efficiency Management Plans (or SEEMPS) and new ships must be designed in compliance with minimum energy efficiency levels per capacity mile as defined by the Energy Efficiency Design Index, or EEDI. Under these measures, by 2025, all new ships build will be 30% more energy efficient than those built in 2014.
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. Tank vessels are subject to enhanced inspection programs for which we may need to make certain financial expenditures.
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 International Convention on the Control of Harmful Anti fouling Systems on Ships (the Anti fouling Convention) prohibits the use of organotin compound coatings to prevent the attachment of mollusks and other sea life to the hulls of vessels. Vessels of over 400 gross tons engaged in international voyages are required to undergo an initial survey before the vessel is put into service or before an International Anti fouling System Certificate is issued for the first time; and subsequent surveys when the anti fouling systems are altered or replaced. In 2023, amendments to the Anti-fouling Convention will come into effect which include controls on the biocide cybutryne; ships shall not apply or re-apply anti-fouling systems containing this substance from January 1, 2023.
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 July 19, 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 C-NLOPB). 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 C-NLOPB has also issued interpretive guidelines concerning compliance with the regulations, and compliance with C-NLOPB 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 C-NLOPB. 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 C-NLOPB guidelines are amended or replaced from time to time. New Canada-Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations entered into force on January 1, 2022.
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. 6.938/1981 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 1, 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.
Although the 2013 Vessel General Permit (or VGP) program and U.S. National Invasive Species Act (or NISA) are currently in effect to regulate ballast discharge, exchange and installation, the Vessel Incidental Discharge Act (or VIDA) which was signed into law on December 4, 2018, requires that the U.S. Coast Guard develop implementation, compliance, and enforcement regulations regarding ballast water. On October 26, 2020, the EPA published a Notice of Proposed Rulemaking for Vessel Incidental Discharge National Standards of Performance under VIDA, and in November 2020, held virtual public meetings. The VIDA established a new framework for the regulation of vessel incidental discharges under the
CWA. 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). The EPA will regulate these ballast water discharges and other discharges incidental to the normal operation of certain vessels within United States waters pursuant to VIDA. The new regulations could require the installation of new equipment, which may cause us to incur substantial costs.
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 port for 45 consecutive days or more). All vessels calling at California ports are required to submit the "Annual Marine Invasive Reporting Form" and should have a 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.
IMO's MEPC 76 adopted amendments to Annex VI that will require ships to reduce their greenhouse gas emissions. Effective November 1, 2022, the Revised MARPOL Annex VI will enter into force. The Revised Annex VI includes carbon intensity measures (requirements for ships to calculate their Energy Efficiency Existing Ship Index (EEXI) following technical means to improve their energy efficiency and to establish their annual operational carbon intensity indicator and rating. MEPC 76 also adopted guidelines to support implementation of the amendments.
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.
On July 14, 2021, the European Commission published a package of draft proposals as part of its ‘Fit for 55’ environmental legislative agenda and as part of the wider EU Green Deal growth strategy. The Proposals are not yet in final form and may be subject to amendment. There are two key initiatives relevant to maritime arising from the Proposals: (a) a bespoke emissions trading scheme for maritime (Maritime ETS) which is due to commence in 2023 and which is to apply to all ships above a gross tonnage of 5,000; and (b) a FuelEU draft regulation which seeks to require all ships above a gross tonnage of 5,000 to carry on board a ‘FuelEU certificate of compliance’ from June 30, 2025 as evidence of compliance with the limits on the greenhouse gas intensity of the energy used on-board by a ship and with the requirements on the use of on-shore power supply (OPS) at berth. More specifically, Maritime ETS is to apply gradually over the period from 2023-2025. The cap under the ETS would be set by taking into account EU MRV system emissions data for the years 2018 and 2019, adjusted, from year 2021 and is to capture 100% of the emissions from intra-EU maritime voyages; 100% of emissions from ships at berth in EU ports; and 50% of emissions from voyages which start or end at EU ports (but the other destination is outside the EU). More recent proposed amendments signal that 100% of non-EU emissions may be caught if the IMO does not introduce a global market-based measure by 2028. Furthermore, the proposals envisage that all maritime allowances would be auctioned and there will be no free allocation. Both proposals are currently being negotiated and final drafts are expected in the summer of 2022.
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.
Many financial institutions that lend to the maritime industry have adopted the Poseidon Principles, which establish a framework for assessing and disclosing the climate alignment of ship finance portfolios. The Poseidon Principles set a benchmark for the banks who fund for the maritime sector, which is based on the IMO greenhouse gases strategy initially approved in April 2018 to reduce greenhouse gas emissions generated from shipping activity. As a result, the Poseidon Principles are expected to enable financial institutions to align their ship finance portfolios with responsible environmental behavior and incentivize international shipping's decarbonization
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, 2021.
D.Properties
See Item 4.B. - Business Overview.
E.Taxation of the Partnership
United States Taxation
The following is a discussion of material U.S. federal income tax considerations applicable to us. 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.
Election to be Taxed as a Corporation. We have elected to be taxed as a corporation for U.S. federal income tax purposes. As such, we are subject to U.S. federal income tax on our income to the extent it is from U.S. sources or otherwise is effectively connected with the conduct of a trade or business in the United States as discussed below.
Taxation of Operating Income. Based on our current operations, and the operations of our subsidiaries, a substantial portion of our gross income is from sources outside the United States and not subject to U.S. federal income tax. However, certain of our activities give rise to U.S. source income. Our U.S. source income generally is subject to U.S. federal income taxation.
For 2022, we do not expect that the U.S. federal income tax on our U.S. source income will be material based on the amount of U.S. source income we earned for 2021. The amount of such tax for which we are liable in any year will depend upon the amount of income we earn from voyages into or out of the United States in such year, however, which is not within our complete control.
Republic of the Marshall Islands Taxation
Because we and our controlled affiliates do not, and will not, carry on business, operations, or transactions in the Republic of the Marshall Islands, neither we nor our controlled affiliates are subject to income, capital gains, profits or other taxation under current Republic of the Marshall Islands law, other than taxes, fines, or fees due to (i) the incorporation, dissolution, continued existence, merger, domestication (or similar concepts) of legal entities registered in the Republic of the Marshall Islands, (ii) filing certificates (such as certificates of incumbency, merger, or redomiciliation) with the Republic of the Marshall Islands registrar, (iii) obtaining certificates of good standing from, or certified copies of documents filed with, the Republic of the Marshall Islands registrar, (iv) compliance with Republic of the Marshall Islands law concerning books and records and vessel ownership, such as tonnage tax, or (v) non-compliance with economic substance regulations or with requests made by the Republic of the Marshall Islands registrar of corporations relating to our books and records and the books and records of our subsidiaries. As a result, distributions by controlled affiliates to us are not subject to Republic of the Marshall Islands taxation.
Other Taxation
We and our subsidiaries are subject to taxation in certain non-U.S. jurisdictions because we or our subsidiaries are either organized, or conduct business or operations, in such jurisdictions. Tax laws in these or other jurisdictions may change or we may enter into new business transactions relating to such jurisdictions, which could affect our tax liability. Please read Item 18 - Financial Statements: Note 20 - Income Taxes.
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 our financial position as at December 31, 2021 and 2020, and our results of operations for the years ended December 31, 2021, 2020 and 2019. This information should be read in conjunction with the audited consolidated financial statements as at December 31, 2021 and 2020, and each of the years in the three years ended December 31, 2021, which are prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (or IFRS). Please refer to Item 18 - Financial Statements.
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, 2021, 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, 2021, our fleet was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Vessels |
| Owned Vessels | | Chartered-in Vessels | | Committed Newbuildings | | Total |
| FPSO Segment | 7 | (i) | | — | | | — | | | 7 | |
| Shuttle Tanker Segment | 22 | (ii) | | 1 | | | 1 | (iii) | | 24 | |
| FSO Segment | 3 | | | — | | | — | | | 3 | |
| UMS Segment | 1 | | | — | | | — | | | 1 | |
| Towage Segment | 10 | | | — | | | — | | | 10 | |
| Total | 43 | | | 1 | | | 1 | | | 45 | |
(i)Includes two FPSO units, the Cidade de Itajai and Pioneiro de Libra, in which our ownership interest is 50 percent and also includes three 100 percent-owned units which are currently in lay-up.
(ii)Includes two shuttle tankers in which our ownership interest is 50 percent. 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.
(iii)Includes one DP2 shuttle tanker newbuilding scheduled for delivery in March 2022, which will operate under an existing contract off the East Coast of Canada.
The table below provides a breakdown of total assets as at December 31, 2021 and total revenues for the year ended December 31, 2021, by operating segment:
| | | | | | | | | | | |
| Assets | | Revenues |
| (in thousands of U.S Dollars) | As at December 31, 2021 | | Year Ended
December 31, 2021 |
| FPSO Segment | 963,625 | | | 489,878 | |
| Shuttle Tanker Segment | 2,093,467 | | | 513,495 | |
| FSO Segment | 198,703 | | | 75,405 | |
| UMS Segment | 58,900 | | | 895 | |
| Towage Segment | 308,621 | | | 80,134 | |
| Eliminations | — | | | (8,547) | |
| Corporate/Other | | | |
| Cash and cash equivalents and restricted cash | 255,756 | | | — | |
| Other assets | 5,652 | | | — | |
| | | |
| Total | 3,884,724 | | | 1,151,260 | |
Outlook
Our near-to-medium term business strategy is primarily to optimize earnings from vessels on contract, to focus on extending contracts and redeploying existing assets on long-term charters, repaying or refinancing scheduled debt obligations and pursuing additional growth projects. Operating cash flows prior to changes in non-cash working capital items relating to operating activities decreased in 2021, as our operating cash flows are slightly weakened by key FPSO units which have come off contract in 2020 and 2021. However, we remain 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.
Global crude oil and gas prices had decreased significantly since mid-2014 before recovering in 2021 and early-2022 as increasing COVID-19 vaccination rates, loosening pandemic-related restrictions, and a growing economy resulted in global demand rising faster than supply. However, the volatility in the market has affected the energy and capital markets and may also adversely affect our business, financial condition and operating results. Potential effects of the COVID-19 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 charterers will be motivated 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 have come off contract or 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 redeploy our key assets and execute select new projects, focusing on increased return on capital and the development of further capital light and asset management solutions. 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. We are committed to drive innovation to identify and accelerate reduction of emissions and seek to maximize value for our unitholders, through our commitment to the energy transition and the new business opportunities arising within sustainable offshore industries.
Significant Developments
Contracts
In February 2022, we signed an agreement with Energean Isreal Ltd. to redeploy the Arendal Spirit UMS on a 100 day firm contract with extension options.
In February 2022, we entered into a front-end engineering design (or FEED) agreement with Equinor for redeployment of the Petrojarl Knarr FPSO unit on the Rosebank field.
In January 2022, we entered into a one-year firm contract extension with Enauta to May 2024 and a related one-year option for the Petrojarl I FPSO unit.
The Knarr FPSO is expected to cease production on the Knarr field in the North Sea around May 1, 2022, after which decommissioning activities related to the unit will commence.
In August 2021, Santos Ltd. announced the award to us of the FEED contract for the FPSO facility for the Dorado project.
Delivery of Shuttle Tanker Newbuildings
Our final newbuilding in a series of seven, the tanker Altera Thule, is expected to be delivered to us from yard in March 2022, which we plan to operate off the East Coast of Canada.
During the second quarter of 2021, our fifth and sixth LNG-fueled E-shuttle tankers, the Altera Wave and Altera Wind, commenced operations.
Liquidity Update
In February 2022, we amended an existing term loan relating to the financing of the Arendal Spirit UMS unit. As at December 31, 2021, this term loan had an outstanding balance of $26 million and matured in February 2022. Following the amendment, this term loan had an outstanding
balance of $9 million and matures in February 2023. The interest payments on the amended facility are based on LIBOR plus a margin of 2.0% per annum.
In January 2022, we entered into a $32 million revolving credit facility with Brookfield that matures in June 2022. Borrowings under the revolving credit facility bear interest at 10.0% annually.
In December 2021, we issued a new $180 million in 9.5% senior unsecured bonds (the 2025 Bonds) in the Norwegian bond market that mature in December 2025. We used the net proceeds of this issuance plus cash on hand to repurchase $181 million principal amount of outstanding 7.125% senior unsecured $250 million bonds maturing in August 2022.
In December 2021, our $70 million unsecured revolving credit facility provided by Brookfield, which was due in February 2022, and was fully drawn, was cancelled and replaced by the issuance to Brookfield of $70 million principal amount of 12.50% senior unsecured PIK notes due 2026 (or the 12.50% PIK Notes). Interest on the 12.50% PIK Notes is payable through the issuance of additional 12.50% PIK Notes.
On August 27, 2021, we exchanged with Brookfield, at par value, (a) an aggregate of $699 million of indebtedness with interest rates ranging from 5.0% to 11.5% and with maturities ranging from 2022 to 2024 (including $411 million of our 8.5% senior notes due 2023 (or the 8.5% Senior Notes) then held by Brookfield) for (b) an equal aggregate principal amount of newly issued 11.5% Senior Secured PIK Notes due 2026 of Altera Infrastructure Holdings L.L.C. (or Holdco) (or the 11.50% PIK Notes) (the actions taken in (a) and (b), collectively, the Brookfield Exchanges).
For additional information about the transactions described above with Brookfield, please refer to Item 18 - Financial Statements: Note 21 - Related Party Transactions and Note 31 - Subsequent Events.
In July 2021, we suspended the payment of quarterly cash distributions on our outstanding 7.25% Series A Cumulative Redeemable Preferred Units (the Series A Units), 8.50% Series B Cumulative Redeemable Preferred Units (the Series B Units) and 8.875% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the Series E Units and, together with the Series A Units and Series B Units, the Preferred Units) commencing with the distributions payable with respect to the period of May 15, 2021 to August 14, 2021. All distributions on the Preferred Units will continue to accrue and must be paid in full before distributions to Class A and Class B common unitholders can be made. No distributions on the Preferred Units will be permitted without noteholder consent while the new 11.50% PIK Notes issued in the Brookfield Exchanges remain outstanding.
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 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 million and $30 million, respectively, and mature in February 2022. As described above, as part of the Brookfield Exchanges: (i) the $70 million credit facility was replaced by $70 million principal amount of 12.50% PIK Notes and (ii) the $30 million facility was exchanged into $30 million principal amount of 11.50% PIK Notes.
Sales of Vessels
In February 2022, we entered into an agreement to sell the Petrojarl Varg FPSO unit to an energy company for re-use as a production facility as part of a new field development opportunity. We expect the sale to complete in March 2022.
In November 2021, we delivered the 2003-built Navion Stavanger shuttle tanker to its buyer for responsible recycling and received total proceeds of $10 million, which was the approximate carrying value of the vessel.
In August 2021, we delivered the 1999-built Navion Anglia shuttle tanker to its buyer for responsible recycling and received total proceeds of $6 million and recorded a gain on sale of the vessel of $1 million during the third quarter of 2021.
In June 2021, we delivered the 2001-built Stena Natalita shuttle tanker to its buyer for continued operations and received total proceeds of $8 million, which was the approximate carrying value of the vessel.
In June 2021, we delivered the 1999-built Navion Oceania shuttle tanker to its buyer for continued operations and received total proceeds of $11 million and recorded a gain on sale of the vessel of $3 million during the second quarter of 2021.
In May 2021, we delivered the 2001-built Navion Oslo shuttle tanker to its buyer for responsible recycling and received total proceeds of $3 million, which was the approximate carrying value of the vessel.
In April 2021, we delivered the 1987-built Dampier Spirit FSO to its buyer for responsible recycling and received total proceeds of $4 million and recorded a gain on sale of the vessel of $4 million during the second quarter of 2021.
Accounting Policy Update
In August 2021, we revised our accounting policy to classify all debt held by Brookfield as Due to related parties. Previously the accounting policy elected by us reflected our long-term debt within two line items, Borrowings and Due to related parties. We have reflected this change retrospectively by restating our comparative consolidated statement of financial position. Please refer to Item 18 – Financial Statements: Note 2i - Related Party Borrowings Reclassification for additional information.
Changes to Board of Directors and Committees
During 2021, the following changes were made to our general partner's board of directors and committees:
•In December 2021, Jim Reid resigned from the board of directors and from his position as a member of the Project & Opportunity Review Committee and as an observer of the Audit Committee;
•In December 2021, Gregory Morrison resigned from the board of directors and from his position as a member of the Corporate Governance Committee;
•In December 2021, Ralf Rank joined the board of directors and was also appointed as a member of the Project & Opportunity Review Committee and as an observer of the Audit Committee;
•In December 2021, Michael Rudnick joined the board of directors;
•In December 2021, Benedicte Bakke Agerup was appointed as a member of the Corporate Governance Committee;
•In December 2021, William L. Transier was appointed as a member of the Project & Opportunity Review Committee;
•In December 2021, Bill Utt resigned from his position as a member of the Project & Opportunity Review Committee;
•In June 2021, Nelson Silva was appointed as a member of the Project & Opportunity Review Committee; and
•In March 2021, Bill Utt resigned from his position as a member of the Audit Committee.
COVID-19
During 2021 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-to-long-term contracts that should not be materially affected by any 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 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, vaccination rates and the effectiveness of vaccines, pandemic-related restrictions and other actions to contain or treat its impact, among others. Accordingly, an estimate of the future impact cannot be made at this time.
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 | | One year or more | | One year or more | | Single voyage |
Hire rate basis (2) | Daily | | Typically daily | | Daily | | Daily | | Varies |
Voyage expenses (3) | Not applicable | | We pay | | Customer pays | | Customer pays | | We pay |
| Vessel operating expenses | We pay | | We pay | | 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 | | Not applicable | | Not applicable | | 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, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of U.S. Dollars, except percentages) | Year Ended December 31, | | % Change |
| 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| IFRS: | | | | | | | | | |
| Revenues | 1,151,260 | | | 1,182,110 | | | 1,252,938 | | | (2.6) | | (5.7) |
| Direct operating costs | (654,580) | | | (627,792) | | | (606,691) | | | 4.3 | | 3.5 |
| General and administrative expenses | (40,770) | | | (44,360) | | | (54,927) | | | (8.1) | | (19.2) |
| Depreciation and amortization | (313,120) | | | (316,317) | | | (358,474) | | | (1.0) | | (11.8) |
| Interest expense | (206,176) | | | (192,723) | | | (205,667) | | | 7.0 | | (6.3) |
| Interest income | 91 | | | 2,770 | | | 5,111 | | | (96.7) | | (45.8) |
| Equity-accounted income (loss) | 25,062 | | | 35,921 | | | 33,768 | | | (30.2) | | 6.4 |
| Impairment expense, net | (116,420) | | | (268,612) | | | (187,680) | | | (56.7) | | 43.1 |
| Gain (loss) on dispositions, net | 10,502 | | | 3,411 | | | 12,548 | | | 207.9 | | (72.8) |
| | | | | | | | | |
Realized and unrealized gain (loss) on derivative
instruments | 15,732 | | | (96,499) | | | (34,682) | | | (116.3) | | 178.2 |
| Foreign currency exchange gain (loss) | (825) | | | (7,861) | | | 2,193 | | | (89.5) | | (458.5) |
| Gain (loss) on modification of financial liabilities, net | (45,920) | | | — | | | (8,332) | | | 100.0 | | (100.0) |
| Other income (expenses), net | 48,323 | | | (10,472) | | | (1,345) | | | (561.4) | | 678.6 |
| Income (loss) before income tax (expense) benefit | (126,841) | | | (340,424) | | | (151,240) | | | (62.7) | | 125.1 |
| Income tax (expense) benefit | | | | | | | | | |
| Current | (4,603) | | | (6,543) | | | (4,666) | | | (29.7) | | 40.2 |
| Deferred | (5,006) | | | 804 | | | (3,161) | | | (722.6) | | (125.4) |
| Net income (loss) | (136,450) | | | (346,163) | | | (159,067) | | | (60.6) | | 117.6 |
| | | | | | | | | |
| Non-IFRS: | | | | | | | | | |
EBITDA(1) | 392,364 | | | 165,846 | | | 407,790 | | | 136.6 | | (59.3) |
Adjusted EBITDA(1) | 551,961 | | | 599,323 | | | 673,199 | | | (7.9) | | (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.
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues
Revenues decreased by $31 million, or 2.6%, for the year ended December 31, 2021, compared to 2020, primarily due the Voyageur Spirit FPSO unit ceasing its contract in June 2020, a reduction in charter rates under a contract extension for the Randgrid FSO unit during 2021, the Piranema Spirit FPSO unit completing its contract in April 2021, the redelivery to us of the Navion Anglia, Navion Bergen and Navion Gothenburg shuttle tankers during 2020, the termination of the Foinaven CoA contract in May 2021, lower rates in the conventional tanker market in which our shuttle tankers occasionally operate and the completion of the Dampier Spirit FSO unit and Apollo Spirit FSO unit charter contracts during 2020. This was partially offset by an increase due to oil price tariffs for the Petrojarl Knarr FPSO unit, higher average day rates and utilization in the towage fleet, various concept studies for clients, an increase in operating days under a master agreement with Equinor ASA, increase oil price incentive revenues for the Petrojarl I FPSO unit and compensation for contractual dry-docking obligations not performed by the charterer upon redelivery of the Navion Gothenburg shuttle tanker.
Direct Operating Costs
Direct operating costs increased by $27 million, or 4.3%, for the year ended December 31, 2021, compared to 2020, primarily due to higher fuel price and utilization of the towage fleet, various concept studies for clients, shuttle tanker newbuildings entering the fleet, timing of reimbursable bunker purchases, repairs and maintenance costs from the re-delivery to us of the Navion Gothenburg shuttle tanker in early-2021, certain vessels migrating from time-charter contracts to CoA contracts, internal towage services on the Petrojarl Foinaven FPSO in 2021 (offset in corporate segment/eliminations), repairs and maintenance costs on the Petrojarl I FPSO unit, providing operational services for the Petrojal Foinaven FPSO unit, and repairs and maintenance costs on the Knarr FPSO unit, partially offset by the decommissioning of the Dampier Spirit FSO unit during 2020, certain vessels leaving the fleet, less time-charter hire, the completion of the charter contract for the Voyageur Spirit FPSO unit in June 2020 and a reduction in management fees as the Petrojarl Foinaven FPSO unit commenced operations under a new operational service contract in March 2020 and management of the Banff FPSO unit ended in November 2020.
General and Administrative Expenses
General and administrative expenses was $41 million for the year ended December 31, 2021, which was generally consistent with $44 million for 2020.
Depreciation and Amortization
Depreciation and amortization decreased to $313 million for the year ended December 31, 2021, compared to $316 million for 2020, primarily due to sales and impairments of vessels and equipment partially offset by the deliveries of shuttle tanker newbuildings during 2021.
Interest Expense
Interest expense increased to $206 million for the year ended December 31, 2021, compared to $193 million for 2020, primarily due to increased interest rates and higher outstanding related party borrowings.
Equity-Accounted Income (Loss)
Equity-accounted income was $25 million for the year ended December 31, 2021, compared to income of $36 million for 2020. The decrease in equity-accounted income was primarily due to an impairment expense recognized on the Cidade de Itajai FPSO unit within our Itajai Joint Venture in 2021, partially offset by a reduction in interest expense and a $5.7 million realized and unrealized gain on derivative instruments held within our equity-accounted investments for the year ended December 31, 2021, compared to a $15.5 million realized and unrealized loss for the same period last year, primarily as a result of an increase in long-term LIBOR benchmark rates during the year ended December 31, 2021, compared to a decrease in long-term LIBOR benchmark rates during the year ended December 31, 2020.
Impairment Expense, Net
Impairment expense, net was $116 million for the year ended December 31, 2021, compared to $269 million for 2020. During 2021, the impairment expense, net was recorded on three vessels, of which two vessels, with an aggregate impairment expense of $108 million, was due to a change in the expected earnings or the future redeployment assumptions of the vessels. The remaining vessel, with an impairment expense of $8 million, was due to the highly probable sale of the vessel. 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 highly probable sales of the vessels.
Gain (Loss) on Dispositions, Net
Gain (loss) on dispositions, net was $11 million for the year ended December 31, 2021, compared to $3 million for 2020. During 2021, we sold six vessels and recognized a gain on disposition of $4 million relating to the Dampier Spirit FSO unit, $3 million relating to the Navion Oceania shuttle tanker unit and $1 million relating to the Navion Anglia shuttle tanker unit. In addition we recognised an additional gain of $3 million relating to the Apollo Spirit FSO unit, which was sold during 2020. The remaining three vessels were sold at their approximate carrying values. 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.
Realized and Unrealized Gain (Loss) on Derivative Instruments
As at December 31, 2021 and 2020, we had interest rate swap agreements with aggregate outstanding notional amounts of approximately $542 million and $1.2 billion, respectively, with fixed rates of approximately 2.5% and 3.5%, respectively. Short-term variable benchmark interest rates during the years ended December 31, 2021 and 2020 were generally 0.2% or less and 1.9% or less, respectively, and as such, we incurred realized losses of $164 million (which includes a $146 million realized loss relating to the termination and partial settlement of certain interest rate swaps and $18 million realized loss relating to scheduled payments) and $59 million (which includes a $27 million realized loss relating to the termination and partial settlement of certain interest rate swaps) during the years ended December 31, 2021 and 2020, respectively. We also recognized an unrealized gain on interest rate swaps of $180 million during the year ended December 31, 2021, due to swap terminations and increases in long-term LIBOR benchmark rates, compared to an unrealized loss of $42 million during the year ended December 31, 2020, due to swap terminations and decreases in long-term LIBOR benchmark rates.
Gain (Loss) on Modification of Financial Liabilities, Net
Gain (loss) on modification of financial liabilities, net was $(46) million for the year ended December 31, 2021, compared to $nil for 2020. This was due to the substantial modification of certain unsecured revolving credit facilities provided by Brookfield and refinancing activities related to the 2025 Bonds issued in December 2021.
Other Income (Expenses), Net
Other income (expenses), net increased by $59 million for the year ended December 31, 2021, compared to 2020, primarily due to the release of a $49 million accrual related to claims related to Logitel from COSCO and an $8 million decrease in restructuring costs. Please refer to Item 18 - Financial Statements: Note 16(a) - Provisions and Contingencies for information relating to the claims.
Foreign Currency Exchange Gain (Loss)
Foreign currency exchange gain (loss) was $(1) million for the year ended December 31, 2021, compared to $(8) million for 2020. 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. 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.
Income Tax (Expense) Benefit
Income tax (expense) benefit was $(10) million for the year ended December 31, 2021, compared to $(6) million for 2020. The increase was mainly driven by the derecognition of deferred tax assets in 2021, partially offset by lower current income tax expense. Refer to Item 18 - Financial Statements:
Adjusted EBITDA
Adjusted EBITDA decreased by $47 million for the year ended December 31, 2021, compared to 2020. Refer to "Results by Segment" below.
Comparison of the years ended December 31, 2020 and December 31, 2019
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, 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 2019.
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 highly probable 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 highly probable 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 18 - Other Financial Liabilities and 22 - 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.
Gain (Loss) on Modification of Financial Liabilities, Net
Gain (loss) on modification of financial liabilities, net was $nil for the year ended December 31, 2020, compared to $(8) million for 2019. This was mainly due to the modification of the $450 million shuttle revolver and an unsecured revolving credit facility with Brookfield in 2019.
Other Income (Expenses), Net
Other income (expenses), net decreased by $9 million for the year ended December 31, 2020, compared to 2019, primarily due to the $10 million increase in restructuring costs related to severance costs from the contract termination of the Dampier Spirit FSO unit and the severance costs associated with the transition of administrative services from Teekay Corporation to us in connection with the January 2020 Merger.
Income Tax (Expense) Benefit
Income tax (expense) benefit 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 21 – 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) benefit, 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; realized gain or loss on foreign currency forward contracts 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.
As at January 1, 2021, we modified the cost allocations between our operating segments. Our components of the business for which discrete financial information is reviewed to assess performance and make decisions regarding resource allocation is still based upon five operating segments. However, the allocation of certain expenditures, relating to direct operating costs and general and administrative expenses, has been modified to show the impact of certain corporate direct operating costs in the corporate segment before reallocation to the operating segments. Additionally, certain expenditures that relate directly to corporate activities will be retained within the corporate segment. Previously all of these expenditures were allocated directly to the five operating segments based on an estimated use of corporate resources. The 2020 and 2019 comparative information has been restated as a result of this change and the modifications have been deemed to not be material for all operating segments and all periods presented.
FPSO Segment
As at December 31, 2021, our FPSO fleet consisted of seven units (December 31, 2020 - seven units), including two units of which we own 50% through our joint ventures with Ocyan S.A. (or Ocyan) (December 31, 2020 - two units). The Petrojarl Varg, Voyageur Spirit and Piranema Spirit FPSO units are currently in lay-up (December 31, 2020 - Petrojarl Varg and Voyageur Spirit). 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 two FPSO units on behalf of the disponent owners or charterers of these units during 2021 (December 31, 2020 - three FPSO units).
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 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | % Change |
| (in thousands of U.S. Dollars, except percentages) | 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| Revenues | 489,878 | | | 483,297 | | | 477,596 | | | 1.4 | | 1.2 |
| Direct operating costs | (279,677) | | | (266,299) | | | (230,012) | | | 5.0 | | 15.8 |
General and administrative(1) | (30,521) | | | (39,753) | | | (44,701) | | | (23.2) | | (11.1) |
Adjusted EBITDA from equity-accounted investments(2) | 95,880 | | | 101,352 | | | 98,294 | | | (5.4) | | 3.1 |
| Adjusted EBITDA | 275,560 | | | 278,597 | | | 301,177 | | | (1.1) | | (7.5) |
| Depreciation and amortization | (92,208) | | | (93,677) | | | (109,865) | | | (1.6) | | (14.7) |
| Impairment expense, net | (116,420) | | | (156,674) | | | (136,631) | | | (25.7) | | 14.7 |
| Gain (loss) on dispositions, net | — | | | (92) | | | — | | | (100.0) | | 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.
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues. Revenues increased by $7 million for 2021, compared to 2020, primarily due to:
•an increase of $36 million mainly due to oil price tariffs for the Petrojarl Knarr FPSO unit;
•an increase of $19 million due to providing operational services for the Foinaven FPSO unit, which commenced operations under a new contract in March 2020 and that was subsequently terminated in the second quarter of 2021;
•an increase of $17 million mainly due to various concept studies for clients; and
•an increase of $13 million mainly due to increased oil price incentive revenues for the Petrojarl I FPSO unit;
partially offset by
•a decrease of $33 million due to the Voyageur Spirit FPSO unit ceasing operations under its contract in June 2020;
•a decrease of $26 million due to the Piranema Spirit FPSO unit completing its contract in April 2021; and
•a decrease of $19 million mainly in management fees as the Petrojarl Foinaven FPSO unit commenced operations under a new operational service contract in March 2020 and management of the Banff FPSO ended in November 2020.
Direct operating costs. Direct operating costs increased by $13 million for 2021, compared to 2020, primarily due to:
•an increase of $17 million due to various concept studies for clients;
•an increase of $7 million due to internal towage services on the Petrojarl Foinaven FPSO in 2021 (offset in corporate segment/eliminations below);
•an increase of $6 million mainly due to repair and maintenance and other miscellaneous costs on the Petrojarl I FPSO unit; and
•an increase of $5 million due to providing operational services for the Petrojarl Foinaven FPSO unit, which commenced operations under a new contract in March 2020 that was subsequently terminated in the second quarter of 2021; and
•an increase of $3 million mainly due to repairs and maintenance on the Knarr FPSO;
partially offset by
•a decrease of $15 million due to the completion of the charter contract for the Voyageur Spirit FPSO unit in June 2020; and
•a decrease of $14 million in management fees as the Petrojarl Foinaven FPSO unit commenced operations under a new operational service contract in March 2020 and management of the Banff FPSO unit ended in November 2020.
General and administrative. General and administrative expenses decreased by $9 million for 2021, compared to 2020, primarily due the allocation of certain corporate costs across the operating segments.
Adjusted EBITDA from equity-accounted investments. Adjusted EBITDA from equity-accounted investments decreased by $5 million for 2021 compared to 2020, primarily due to an increase in the operational costs for the two 50% joint ventures.
Adjusted EBITDA. Adjusted EBITDA (including Adjusted EBITDA from equity-accounted joint ventures) decreased by $3 million for 2021, compared to 2020, primarily due to the increase in direct operating costs of $13 million, as described above, and a $5 million decrease in adjusted EBITDA from equity-accounted investments, as described above, partially offset by the increase in revenues of $7 million, as described above, and a $9 million decrease in general and administrative expenses, as described above.
Depreciation and amortization. Depreciation and amortization expense decreased by $1 million for 2021, compared to 2020, primarily due to the impairments of our FPSO units during 2021 and 2020, as described below.
Impairment expense, net. Impairment expense, net of $116 million for 2021 was related to a $73 million impairment of the Voyageur Spirit FPSO unit and a $35 million impairment recorded on the Piranema Spirit FPSO unit due to changes in the expected earnings of the units as a result of reassessments of the future redeployment opportunities for the units, and a $8 million impairment recorded on the Petrojarl Varg FPSO unit due to the highly probable sale of the unit.
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 highly probable sale of the unit.
Comparison of the years ended December 31, 2020 and December 31, 2019
Revenues. Revenues increased by $6 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 $36 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 $23 million for 2020, compared to 2019, primarily due to the increase in direct operating costs of $36 million, as described above, partially offset by the increase in
revenues of $6 million, as described above, a $5 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 highly probable sale of the unit.
Impairment expense, net of $137 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 highly probable sale of the unit.
Shuttle Tanker Segment
As at December 31, 2021, our shuttle tanker fleet consisted of 22 owned vessels (December 31, 2020 - 25 owned vessels) that operate under fixed-rate CoAs and time charters (December 31, 2020 - fixed-rate CoAs, time charters, and bareboat charters), including two shuttle tankers in which our ownership interest is 50 percent (December 31, 2020 - three shuttle tankers), one shuttle tanker newbuilding which is expected to deliver in March 2022 (December 31, 2020 - three shuttle tanker newbuildings, two of which delivered in 2021) and one in-chartered vessel (December 31, 2020 - 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.
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 from oil field installations, even in harsh weather conditions. Shuttle tankers were developed in the North Sea as an alternative to pipelines.
The following table presents certain of the shuttle tanker segment’s operating results for 2021, 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, | | % Change |
| 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| Revenues | 513,495 | | | 542,691 | | | 549,587 | | | (5.4) | | (1.3) |
| Direct operating costs | (245,753) | | | (237,165) | | | (230,946) | | | 3.6 | | 2.7 |
General and administrative(1) | (30,180) | | | (17,942) | | | (22,267) | | | 68.2 | | (19.4) |
| Realized loss on foreign currency forward contracts | — | | | (2,405) | | | (2,574) | | | (100.0) | | (6.6) |
Adjusted EBITDA attributable to non-controlling interests(2) | 162 | | | (10,988) | | | (10,861) | | | (101.5) | | 1.2 |
| Adjusted EBITDA | 237,724 | | | 274,191 | | | 282,939 | | | (13.3) | | (3.1) |
| Depreciation and amortization | (172,716) | | | (162,928) | | | (184,087) | | | 6.0 | | (11.5) |
| Impairment expense, net | — | | | (35,258) | | | (15,342) | | | (100.0) | | 129.8 |
| Gain (loss) on dispositions, net | 3,644 | | | (1,877) | | | 1,335 | | | (294.1) | | (240.6) |
| Calendar-Ship-Days | | | | | | | | | |
| Owned vessels | 8,932 | | | 8,988 | | | 9,345 | | | (0.6) | | (3.8) |
| Chartered-in vessels | 407 | | | 678 | | | 787 | | | (40.0) | | (13.9) |
| Total | 9,339 | | | 9,666 | | | 10,132 | | | (3.4) | | (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.
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues. Revenues decreased by $29 million for 2021, compared to 2020, primarily due to:
•a decrease of $24 million due to the redelivery to us of the Navion Anglia, Navion Bergen and Navion Gothenburg shuttle tankers during 2020;
•a decrease of $19 million due to termination of the Foinaven CoA contract in May 2021;
•a decrease of $17 million due to lower rates in the conventional tanker market in which our shuttle tankers occasionally operate; and
•a decrease of $5 million mainly due to less CoA days in Q4-21;
partially offset by
•an increase of $14 million due to an increase in operating days under a master agreement with Equinor ASA;
•an increase of $8 million due to compensation for contractual dry-docking obligations not performed by the charterer upon redelivery of the Navion Gothenburg shuttle tanker;
•an increase of $9 million due to the timing of reimbursable bunker purchases (offset in direct operating costs below); and
•an increase of $5 million due to reduced off hire days.
Direct operating costs. Direct operating costs increased by $9 million for 2021, compared to 2020, primarily due to:
•an increase of $12 million due to four shuttle tanker newbuildings entering the fleet in late-2020 and early-2021;
•an increase of $9 million due to the timing of reimbursable bunker purchases (offset in revenue above);
•an increase of $6 million due to repair and maintenance costs from the re-delivery to us of the Navion Gothenburg shuttle tanker in early-2021; and
•an increase of $5 million due to certain vessels migrating from time charter contracts to CoA contracts during the current year;
partially offset by
•a decrease of $17 million due to certain vessels leaving the fleet; and
•a decrease of $8 million due to less time-charter hire in 2021 compared to 2020.
General and administrative. General and administrative expenses increased by $12 million for 2021, compared to 2020, primarily due to the allocation of certain corporate costs across the operating segments.
Adjusted EBITDA attributable to non-controlling interests. Adjusted EBITDA attributable to non-controlling interests increased by $11 million for 2021, compared to 2020, primarily due to impairment expenses of $11 million in 2020 and nil in 2021.
Adjusted EBITDA. Adjusted EBITDA decreased by $36 million for 2021, compared to 2020, primarily due to the decrease in revenues of $29 million, as described above, increase in direct operating costs of $9 million, as described above, and increase in general and administrative costs of $12 million, as described above, partly offset by an increase in adjusted EBITDA attributable to non-controlling interests of $11 million, as described above.
Depreciation and amortization. Depreciation and amortization expense increased by $10 million for 2021, compared to 2020, primarily due to four shuttle tanker newbuildings entering the fleet in late-2020 and early-2021, partially offset by the sale and impairment of certain vessels.
Impairment expense, net. Impairment expense, net was $nil for 2021, as there were no impairments recorded for within the Shuttle Tanker Segment in 2021.
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 highly probable sale of the vessel, a $4 million impairment recorded on the Navion Bergen due to the highly probable 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 highly probable sale of the vessel.
The average size of our owned shuttle tanker fleet decreased for 2021, compared to 2020, primarily due to the sales of the Navion Oslo in May 2021, the Navion Oceania and Stena Natalita in June 2021, the Navion Anglia in August 2021 and the Navion Stavanger in November 2021, partially offset by the deliveries of the Altera Wave in January 2021 and Altera Wind in March 2021. One shuttle tanker newbuilding has been excluded from calendar-ship-days as the vessel is expected to be delivered to us in March 2022.
The average size of our chartered-in fleet decreased from two vessels to one for 2021, compared to 2020, primarily due to the redelivery of one vessel in September 2020.
Comparison of the years ended December 31, 2020 and December 31, 2019
Revenues. Revenues decreased by $7 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 $6 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 $9 million for 2020, compared to 2019, primarily due to the decrease in revenues of $7 million, described above.
Depreciation and amortization. Depreciation and amortization expense decreased by $21 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 highly probable sale of the vessel, a $4 million impairment recorded on the Navion Bergen due to the highly probable 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 highly probable 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 highly probable sale of the vessel and a $2 million impairment recorded on the Stena Sirita due to the highly probable 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 vessels in November 2019 and September 2020, respectively.
FSO Segment
As at December 31, 2021, our FSO fleet consisted of three units that operate under fixed-rate time charters or fixed-rate bareboat charters, for which we have 100% ownership interests (December 31, 2020 - four units).
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 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | % Change |
| (in thousands of U.S. Dollars, except percentages) | 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| Revenues | 75,405 | | | 113,867 | | | 140,117 | | | (33.8) | | (18.7) |
| Direct operating costs | (30,292) | | | (45,448) | | | (40,457) | | | (33.3) | | 12.3 |
General and administrative(1) | (4,360) | | | (8,459) | | | (6,946) | | | (48.5) | | 21.8 |
Adjusted EBITDA attributable to non-controlling interests(2) | 9 | | | 311 | | | (500) | | | (97.1) | | (162.2) |
| Adjusted EBITDA | 40,762 | | | 60,271 | | | 92,214 | | | (32.4) | | (34.6) |
| Depreciation and amortization | (25,247) | | | (37,971) | | | (43,311) | | | (33.5) | | (12.3) |
| Impairment expense, net | — | | | (53,749) | | | — | | | (100.0) | | — |
| Gain (loss) on dispositions, net | 6,858 | | | 5,380 | | | 11,213 | | | 27.5 | | (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.
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues. Revenues decreased by $38 million for 2021, compared to 2020, primarily due to:
•a decrease of $32 million due to lower charter rates under a contract extension for the Randgrid FSO unit during 2021; and
•a decrease of $9 million due to the completion of the Dampier Spirit FSO unit and Apollo Spirit FSO unit charter contracts during 2020;
partially offset by
•an increase of $4 million due to Suksan Salamander FSO commencing a new operating and maintenance contract during 2021.
Direct operating costs. Direct operating costs decreased by $15 million for 2021, compared to 2020, primarily due to the decommissioning of the Dampier Spirit FSO unit during 2020.
Adjusted EBITDA. Adjusted EBITDA decreased by $20 million for 2021, compared to 2020, primarily due to the decrease in revenues, as described above, partially offset by the decrease in direct operating costs, as described above.
Depreciation and amortization. Depreciation and amortization decreased by $13 million for 2021, compared to 2020, primarily due to the impairment of the Randgrid FSO unit during 2020.
Impairment expense, net. Impairment expense, net was $nil for 2021, as there were no impairments recorded for within the FSO Segment in 2021.
Impairment expense, net. Impairment expense, net of $54 million for 2020 was related to impairments of $45 million recorded on the Randgrid FSO unit, as a result of a change in the expected earnings of the unit, and $7 million on the Dampier Spirit FSO unit and $2 million on the Apollo Spirit FSO unit due to the highly probable sales of the vessels.
Gain (loss) on dispositions, net. Gain (loss) on dispositions, net was $7 million for 2021, due to the sale of the Dampier Spirit FSO unit and the additional gain recorded after the official recycling of the Apollo Spirit FSO unit sold in late-2020. Gain (loss) on dispositions, net was $5 million for 2020, due to the sale of the Apollo Spirit FSO unit in late-2020.
Comparison of the years ended December 31, 2020 and December 31, 2019
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 $5 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 of $45 million on the Randgrid FSO unit, as a result of a change in the expected earnings of the unit, and $7 million on the Dampier Spirit FSO unit and $2 million on the Apollo Spirit FSO unit due to the highly probable sales of the vessels.
Impairment expense, net. Impairment expense, net was $nil for 2019, as there were no impairments recorded for within the FSO Segment in 2019.
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, 2021, our UMS fleet consisted of one unit (December 31, 2020 - one unit), the Arendal Spirit UMS, in which we own a 100% interest. As at December 31, 2021 the Arendal Spirit UMS was in lay-up (December 31, 2020 - lay-up). In February 2022, we signed an agreement with Energean Isreal Ltd. to redeploy the Arendal Spirit UMS on a 100 day firm contract with extension options.
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 following table presents certain of the UMS segment’s operating results for 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | % Change |
| (in thousands of U.S. Dollars, except percentages) | 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| Revenues | 895 | | | 1,828 | | | 2,940 | | | (51.0) | | (37.8) |
| Direct operating costs | (3,069) | | | (5,810) | | | (1,292) | | | (47.2) | | 349.7 |
General and administrative(1) | (5,252) | | | (3,564) | | | (6,100) | | | 47.4 | | (41.6) |
| | | | | | | | | |
| Adjusted EBTIDA | (7,426) | | | (7,546) | | | (4,452) | | | (1.6) | | 69.5 |
| Depreciation and amortization | (2,258) | | | (2,328) | | | (3,415) | | | (3.0) | | (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).
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues and Adjusted EBITDA. Revenues and Adjusted EBITDA for 2021 were generally consistent compared to 2020.
Comparison of the years ended December 31, 2020 and December 31, 2019
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 was $nil for 2020, as there were no impairments recorded within the UMS Segment in 2020.
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, 2021, our towage fleet consisted of ten long-distance towage and offshore installation vessels (December 31, 2020 - 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 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | % Change |
| (in thousands of U.S. Dollars, except percentages) | 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| Revenues | 80,134 | | | 45,991 | | | 74,726 | | | 74.2 | | (38.5) |
| Direct operating costs | (67,632) | | | (45,636) | | | (68,013) | | | 48.2 | | (32.9) |
General and administrative(1) | (2,346) | | | (7,640) | | | (1,475) | | | (69.3) | | 418.0 |
| Adjusted EBITDA | 10,156 | | | (7,285) | | | 5,238 | | | (239.4) | | 239.1 |
| Depreciation and amortization | (17,821) | | | (17,923) | | | (17,796) | | | (0.6) | | 0.7 |
| Impairment expense, net | — | | | (22,931) | | | — | | | (100.0) | | 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).
Comparison of the years ended December 31, 2021 and December 31, 2020
Revenues. Revenues increased by $34 million for 2021, compared to 2020, primarily due to higher average day rates and utilization in the towage fleet.
Direct operating costs. Direct operating costs increased by $22 million for 2021, compared to 2020, primarily due to higher fuel price and utilization of the towage fleet as described above.
General and administrative. General and administrative expenses decreased by $5 million for 2021, compared to 2020, primarily due to the allocation of certain corporate costs across the operating segments.
Adjusted EBITDA. Adjusted EBITDA increased by $17 million for 2021, compared to 2020, primarily due to the increase in revenues of $34 million, as described above, and a $5 million decrease in general and administrative expenses, partially offset by the $22 million increase in direct operating costs.
Impairment expense, net. Impairment expense, net was $nil for 2021, as there were no impairments recorded within the Towage Segment in 2021.
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.
Comparison of the years ended December 31, 2020 and December 31, 2019
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. Direct operating costs decreased by $22 million, for 2020, compared to 2019, primarily due to lower utilization of the towage fleet as described above.
Adjusted EBITDA. Adjusted EBITDA decreased by $13 million for 2021, compared to 2020, primarily due to the decrease in revenues of $29 million and increase in general and administrative expenses of $6 million, as described above, partially offset by the $22 million decrease in direct operating costs, 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.
Impairment expense, net. Impairment expense, net was $nil for 2019, as there were no impairments recorded within the Towage Segment in 2019.
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 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | % Change |
| (in thousands of U.S. Dollars, except percentages) | 2021 | | 2020 | | 2019 | | 2021 vs 2020 | | 2020 vs 2019 |
| 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; realized gain or loss on foreign currency forward contracts; 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 income (loss) for the years ended December 31, 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | |
| (in thousands of U.S. Dollars) | Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| Net income (loss) | (136,450) | | | (346,163) | | | (159,067) | |
| Less: | | | | | |
| Depreciation and amortization | (313,120) | | | (316,317) | | | (358,474) | |
| Interest expense | (206,176) | | | (192,723) | | | (205,667) | |
| Interest income | 91 | | | 2,770 | | | 5,111 | |
| Income tax (expense) benefit | | | | | |
| Current | (4,603) | | | (6,543) | | | (4,666) | |
| Deferred | (5,006) | | | 804 | | | (3,161) | |
| EBITDA | 392,364 | | | 165,846 | | | 407,790 | |
| Less: | | | | | |
| Equity-accounted income (loss) | 25,062 | | | 35,921 | | | 33,768 | |
| Impairment expense, net | (116,420) | | | (268,612) | | | (187,680) | |
| Gain (loss) on dispositions, net | 10,502 | | | 3,411 | | | 12,548 | |
| Realized and unrealized gain (loss) on derivative instruments | 15,732 | | | (96,499) | | | (34,682) | |
| Foreign currency exchange gain (loss) | (825) | | | (7,861) | | | 2,193 | |
| Gain (loss) on modification of financial liabilities, net | (45,920) | | | — | | | (8,332) | |
| Other income (expenses), net | 48,323 | | | (10,472) | | | (1,345) | |
Adjusted EBITDA attributable to non-controlling interests(2) | (171) | | | 10,677 | | | 11,361 | |
| Add: | | | | | |
| Realized gain (loss) on foreign currency forward contracts | — | | | (1,310) | | | (5,054) | |
Adjusted EBITDA from equity-accounted investments(1) | 95,880 | | | 101,352 | | | 98,294 | |
| Adjusted EBITDA | 551,961 | | | 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) | 2021 | | 2020 | | 2019 |
| Equity-accounted income (loss) | 25,062 | | | 35,921 | | | 33,768 | |
| Less: | | | | | |
| Depreciation and amortization | (31,604) | | | (32,414) | | | (32,288) | |
| Interest expense, net | (7,705) | | | (14,307) | | | (19,469) | |
| Income tax (expense) benefit | | | | | |
| Current | (484) | | | (317) | | | (250) | |
| | | | | |
| EBITDA | 64,855 | | | 82,959 | | | 85,775 | |
| Less: | | | | | |
| Impairment expense, net | (36,096) | | | — | | | — | |
| Realized and unrealized gain (loss) on derivative instruments | 5,661 | | | (15,484) | | | (12,527) | |
| Foreign currency exchange gain (loss) | (590) | | | (2,909) | | | 8 | |
| Adjusted EBITDA from equity-accounted vessels | 95,880 | | | 101,352 | | | 98,294 | |
| | | | | |
(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) | 2021 | | 2020 | | 2019 |
| Net income (loss) attributable to non-controlling interests in subsidiaries | (6,527) | | | (7,154) | | | (8,409) | |
| Less: | | | | | |
| Depreciation and amortization | (6,163) | | | (6,087) | | | (11,394) | |
| Interest expense | (369) | | | (902) | | | (1,576) | |
| Interest income | 1 | | | 16 | | | 106 | |
| EBITDA | 4 | | | (181) | | | 4,455 | |
| Less: | | | | | |
| Impairment expense, net | — | | | (11,394) | | | (6,905) | |
| Gain (loss) on dispositions, net | 168 | | | 633 | | | — | |
| Foreign currency exchange gain (loss) | 7 | | | (97) | | | (1) | |
| Adjusted EBITDA attributable to non-controlling interests | (171) | | | 10,677 | | | 11,361 | |
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. Operating cash flows prior to changes in non-cash working capital items relating to operating activities decreased in 2021, as our operating cash flows are slightly weakened by key FPSO units which have come off contract in 2020 and 2021. However, we remain 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.
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 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.
As at December 31, 2021, our interest-bearing obligations include bonds, commercial bank debt, a senior secured PIK note provided by Brookfield, an unsecured PIK note provided by Brookfield, and obligations related to leases. The contractual payments relating to these obligations for the next twelve months are $420 million, and $3 billion thereafter. Refer to Item 18 – Financial Statements: Note 19 - Borrowings, Item 18 – Financial Statements: Note 21 - Related Party Transactions and Item 18 – Financial Statements: Note 11 - Advances on Newbuilding Contracts for terms upon which future interest payments are determined.
As at December 31, 2021, our other financial liabilities include interest rate swaps and foreign currency forward contracts. The contractual payments relating these obligations for the next twelve months are $65 million, and $191 million thereafter. Refer to Item 18 – Financial Statements: Note 18 - Other Financial Liabilities for a summary of the terms of our derivative instruments which economically hedge certain of our floating rate interest-bearing obligations.
As at December 31, 2021, our contractual obligation relating to lease liabilities consists of the undiscounted contractual maturities of our lease liabilities. The contractual payments relating to these obligations for the next twelve months are $15 million, and $12 million thereafter. Refer to Item 18 – Financial Statements: Note 9 - Right of Use Assets and Lease Liabilities.
As at December 31, 2021, our contractual obligation relating to newbuilding contracts consists of the estimated remaining payments for the acquisition of one shuttle tanker newbuilding. The contractual payments relating to these obligations for the next twelve months are $74 million, and $nil thereafter. We secured $105.6 million of borrowings relating to this shuttle tanker newbuilding, which as at December 31, 2021 had an undrawn balance of $63.4 million. Refer to Item 18 – Financial Statements: Note 11 - Advances on Newbuilding Contracts.
Our estimated future dry dock expenditures for the next twelve months are $19 million, and $395 million thereafter.
The following table presents our liquidity as at December 31, 2021 and 2020:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Cash and cash equivalents | 190,942 | | | 235,734 | |
Total liquidity(1) | 190,942 | | | 235,734 | |
| Working capital surplus (deficit) | (276,408) | | | (230,494) | |
(1)Defined as cash, cash equivalents and undrawn revolving credit facilities
The working capital deficit of $276 million as at December 31, 2021, has increased from $230 million as at December 31, 2020. The increase in the working capital deficit was primarily due to a $95 million decrease in accounts and other receivable, net, an $84 million decrease in financial assets primarily relating to amounts held in escrow for a shuttle tanker newbuilding yard installment payment as at December 31, 2020, a $45 million decrease in cash and cash equivalents, and a $45 million increase in borrowings. This was partially offset by a $164 million decrease in other financial liabilities primarily relating to the termination or amendment of certain interest rate swaps during the year ended December 31, 2021, and a $37 million decrease in accounts payable and other.
Primarily as a result of the working capital deficit and committed capital expenditures, during the one-year period from December 31, 2021, 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. During the year ended December 31, 2021, we completed various measures to improve our debt maturity profile and enhance our liquidity and financial flexibility. Refer to Item 18 – Financial Statements: Note 19 - Borrowings, Item 18 - Financial Statements: Notes 21a and b - Related Party Transactions and Item 18 – Financial Statements: Note 22 - Equity for additional information. Additional potential sources of financing that we are actively pursuing, during the one-year period include entering into new debt facilities, borrowing additional amounts under existing facilities, the refinancing, extension or other amendments, including amendment of financial covenants, of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnership's business interests, enter into sale-leaseback agreements, increasing equity, and other potential liability management transactions. 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 twelve months. In January 2022, we entered into a revolving credit facility with Brookfield. The borrowings available under the revolving credit facility are $32.0 million and mature in June 2022. However, there can be no assurance that our liquidity from operations will meet our expectations, which could be negatively affected by items outside of our control, including macroeconomic conditions, or that our efforts to raise liquidity will be successful. For more information, refer to “Item 18 – Financial Statements: Note 2b - Going concern" and “Item 3D. – Risk Factors — Risks Relating to Our Liquidity — 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.”
As at December 31, 2021, we had total borrowings outstanding of $2,496 million compared to $2,800 million as at December 31, 2020. The borrowings consisted of the following:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| U.S. Dollar Revolving Credit Facilities | 308,887 | | | 439,600 | |
| U.S. Dollar Term Loans | 1,282,848 | | | 1,426,370 | |
| U.S. Dollar Bonds | 725,072 | | | 726,826 | |
| U.S. Dollar Non-Public Bonds | 179,462 | | | 206,870 | |
| Total principal | 2,496,269 | | | 2,799,666 | |
The use of proceeds from 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 Partnership and/or ship-owning subsidiaries from, among other things: minimum liquidity, 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 accounts (see Item 18 - Financial Statements: Note 19 - Borrowings), 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. As at December 31, 2021, we were in compliance with all covenants relating to our consolidated borrowings.
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) | 2021 | | 2020 | | 2019 |
| Net operating cash flow | 215,295 | | | 282,319 | | | 350,882 | |
| Net financing cash flow | (157,244) | | | 234,364 | | | (71,101) | |
| Net investing cash flow | (102,826) | | | (476,023) | | | (304,532) | |
Operating Cash Flows
Net cash flow from operating activities decreased to $215 million for 2021, compared to $282 million for 2020, primarily due to the negative movement of $209 million for the unrealized (gain) loss on derivative instruments, $152 million for impairment expense, net, and $51 million for provisions and other, partially offset by the positive movement of $210 million for net income (loss), $100 million for the changes in non-cash working capital, net, $25 million for other non-cash items and $15 million for equity-accounted (income) loss, net of distributions received.
Net cash flow from operating activities also decreased for 2021 compared to 2020, due to a decrease in revenues, an increase in direct operating costs, an increase in interest paid and an increase in realized losses on interest rate swaps, partially offset by a decrease in general and administrative expenses. Refer to "Consolidated Results of Operations" above.
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 2021 compared to a contribution of $13 million during 2020. The decrease in non-cash working capital items for the year ended December 31, 2020, compared to 2019 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
Our proceeds from borrowings, net of financing costs, were $268 million in 2021, $304 million in 2020 and $472 million in 2019.
Net proceeds from borrowings related to the sale and leaseback of vessels were $71 million, $119 million and $22 million in 2021, 2020 and 2019, respectively. These proceeds were used to fund installment payments on the certain of the shuttle tanker newbuildings. Our scheduled repayments of our borrowings related to the sale and leaseback of vessels were $11 million, $1 million and $nil in 2021, 2020 and 2019, respectively.
We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments and our prepayments of our borrowings were $579 million in 2021, compared to $329 million in 2020. The increase in repayments and prepayments is mainly due to a $181 million repurchase of our $250 million unsecured shuttle bond during 2021, a $34 million prepayment on one debt facility during 2021 and a $16 million prepayment on our $450 million shuttle revolver.
Our scheduled repayments and prepayments of our borrowings were $329 million in 2020, compared to $410 million in 2019. The decrease in repayments and prepayments 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 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 during 2021, provided for borrowings of up to $225 million. During 2021, we entered into three additional unsecured credit facilities with Brookfield which provided borrowings of $17 million, $30 million and $70 million, respectively. During 2021, we drew down $147 million and prepaid $30 million related to these credit facilities. During 2020, we drew down $205 million related to the existing credit facility. During 2019, we prepaid $200 million and drew down $95 million related to the existing credit facility. As at December 31, 2021, our unsecured revolving credit facilities with Brookfield had been replaced by the 11.50% PIK Notes and 12.50% PIK Notes. Refer to item item 18 - Financial Statements: Note 21 - Related Party Transactions for additional information.
Lease payments on our vessel in-charter leases and office leases during 2021, 2020 and 2019 were $15 million, $20 million and $15 million, respectively.
Capital contribution by non-controlling interests were $18 million, $nil and $2 million during 2021, 2020 and 2019, respectively, while distributions to non-controlling interests were $11 million, $5 million and $4 million during 2021, 2020 and 2019, respectively.
Cash distributions paid to our preferred unitholders totaled $16 million in 2021, $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. In July 2021, we suspended the payment of quarterly cash distributions on our outstanding Series A, Series B and Series E Preferred Units commencing with the distributions payable with respect to the period of May 15, 2021 to August 14, 2021. In addition, no distributions on the Preferred Units will be permitted without noteholder consent while the 11.5% PIK Notes issued in the Brookfield Exchanges remain outstanding. All distributions on the Preferred Units will continue to accrue and must be paid in full before distributions to Class A and Class B common unitholders can be made. Refer to item item 18 - Financial Statements: Note 22 - Equity for additional information.
Investing Cash Flows
During 2021, net cash flow used for investing activities was $103 million, primarily due to $211 million of vessel and equipment additions, mainly relating to $177 million of installment payments for the shuttle tanker newbuildings and $30 million of drydocking expenditure and certain capital modifications, partially offset by $45 million from the sales of vessels and equipment and a $69 million decrease in restricted cash primarily related to a $74 million reduction to amounts held in escrow for the final installment payment for one of the above mentioned shuttle tanker newbuilds, partially offset by cash sweep requirements under an amended third-party loan agreement.
During 2020, net cash flow used for investing activities was $476 million, primarily due to $480 million of vessels 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 acquired relating to 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.
C.Research and Development, Patents and Licenses, etc.
Not applicable.
D.Trend Information
Refer to Item 5.A.- Operating Results.
E.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.
Climate related risks. We could face the impact of an accelerated energy transition driven by climate change. Our strategy, capital allocation and selection of projects are guided by our vision to lead the industry to a sustainable future and climate related risks are key drivers for it. The effect on our compliance costs, capital expenditures, cash flow from operation and other assumptions are inherently uncertain and may differ from actual amounts. The risks will however remain as key considerations for impairment testing, estimation of remaining useful life and provisions for future periods.
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, 2021, 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 | | 2 | | 582,980 | |
| Shuttle Tanker Segment | | 3 | | 55,901 | |
| FSO Segment | | 1 | | 101,719 | |
| UMS Segment | | 1 | | 58,368 | |
| Towage Segment | | 2 | | 15,974 | |
For the units within the FPSO, FSO and UMS segments, there are uncertainties in the assumptions for redeployments where there is no signed contract in place. When estimating the recoverable amount, we make assumptions for the uncontracted cash flows over the useful life for each unit. These are estimated based on our market knowledge, experience and return on invested capital. These assumptions are used to create scenarios with different cash flows for each unit. Based on the attractiveness of the various assets, the assumptions can include extensions on current contracts, new contracts, sale or a recycling option. The recoverable amount is a weighted average of all the scenarios.
As at December 31, 2021, due to uncertainty in the redeployment market for FPSO, FSO and UMS units and short remaining contract lengths, we identified impairment triggers for all of our FPSO fleet, one of our FSO units, and our one UMS unit. The asset values of the Voyageur Spirit FPSO and the Piranema Spirit FPSO were impaired as at December 31, 2021. For the remaining FPSO units, one FSO unit, and one UMS unit, the tests did not result in a recoverable value lower than the carrying value and were therefore not impaired. These units are considered at high risk of future impairment in the table above.
Our impairment tests are sensitive to changes in key assumptions such as discount rate, assumed contract rates and the weight applied to the various scenarios. For the remaining FPSO units, one FSO unit, and one UMS unit for-which the impairment tests as at December 31, 2021 did not result in an impairment:
•An increase of 0.5% for the discount rate would result in an impairment of $21 million.
•An additional one-year before redeployment of the units in the weighted scenarios would result in an impairment of $67 million.
•A 10% reduction in rate/sales proceeds from the weighted scenarios on the same units would result in an impairment of $52 million.
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 recycling 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 recycling 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.
F.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, 2021.
| | | | | | | | | | | | | | |
| Name | | Age | | Position |
| Benedicte Bakke Agerup | | 57 | | Director (1) |
| Ian Craig | | 69 | | Director (2) |
| Craig Laurie | | 50 | | Director (3) |
| Ralf Rank | | 44 | | Director (4) |
| Michael Rudnick | | 38 | | Director |
| Nelson Silva | | 66 | | Director (5) |
| Ingvild Sæther | | 53 | | Director and President & Chief Executive Officer, Altera Infrastructure Group Ltd. (6) |
| William L. Transier | | 67 | | Director (7) |
| Denis Turcotte | | 60 | | Director (8) |
| Bill Utt | | 64 | | Chairman of the board of directors (9) |
| | | | |
| | | | |
| | | | |
(1)Member of the Audit Committee, Corporate Governance 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)Observer to the Audit Committee and member of Project & Opportunity Review Committee.
(5)Member of the Audit Committee, Project & Opportunity Review Committee and Conflicts Committee.
(6)Member of the Executive Oversight Committee.
(7)Member of the Audit Committee (Chair) and the Project & Opportunity Review Committee.
(8)Member of the Corporate Governance Committee and Executive Oversight Committee (Chair).
(9)Chair of the Corporate Governance Committee and member of 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 Wilh. 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.
Ralf Rank was appointed as a director of our general partner in December 2021. Mr Rank is a Managing Partner in Brookfield’s Private Equity Group. Mr. Rank joined Brookfield in 2007 and currently serves as Head of Strategy for the private equity group. Mr. Rank has held a number of senior roles in Brookfield’s renewable power, infrastructure and private equity businesses, including Chief Investment Officer, Power & Utilities; CEO Brookfield Renewable Europe and Managing Partner, European private equity. Prior to joining Brookfield, Mr. Rank was Associate Director, Investment Banking at Scotia Capital Inc. with an industry specialization in infrastructure, power and utilities. Mr. Rank holds a Bachelor of Applied Science (Mechanical Engineering) and a Minor in Economics from the University of Waterloo and has received the Chartered Financial Analyst designation.
Michael Rudnick was appointed as a director of our general partner in December 2021. Mr Rudnick is a Senior Vice President in Brookfield's Private Equity Group. Mr. Rudnick is responsible for global transaction structuring and execution for Brookfield's Special Investment Fund. Prior to joining Brookfield, Mr. Rudnick was a Vice President at H/2 Capital Partners and an associate at Paul, Weiss, Rifkind, Wharton & Garrison LLP. Mr. Rudnick holds a Juris Doctor degree from Benjamin N. Cardozo School of Law and Bachelor of Arts degree from Emory University.
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 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. Mr. Transier served as chairman of the board of directors and chairman of the audit and governance committees of Battalion Oil Corporation from October 2019 to May 2021. 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. Mr. Transier was recently recognized by the Dallas Business Journal as an Outstanding Director for excellence in corporate governance.
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, 2021:
| | | | | | | | | | | | | | |
| Name | | Age | | Position |
| Ingvild Sæther | | 53 | | President and Chief Executive Officer, Altera Infrastructure Group Ltd. |
| Jan Rune Steinsland | | 62 | | Chief Financial Officer, Altera Infrastructure Group Ltd. |
| Duncan Donaldson | | 42 | | 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., a service provider to us, in September 2018. He joined Altera 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 from 2006 to 2013 and at the financial group Acta Holding from 2000 to 2006, as well as serving in several management positions at ExxonMobil from 1988 to 2000. 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 21 - 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 2021, 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. Additionally, if the directors are required to meet out of continent, all directors are paid an additional $2,500 per meeting for travel fees.
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.
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.
Key Employee Compensation Plan
During November 2021, the general partner adopted a Key Employee Compensation Plan in addition to the existing Executive Long-Term Incentive Plan. The purpose of the Key Employee Compensation Plan is to align the interests of the Company and eligible key employees of the Company and its subsidiaries. Eligible Participants under the Plan are eligible to receive a Retention Bonus and a Performance Bonus based on continuing employment through certain vesting dates and a Performance Bonus which is subject to performance against established criteria.
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. For additional information regarding the composition of our board of directors, refer to Item 6A - Directors and Senior Management.
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, 2021, 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), Nelson Silva, Ian Craig and Benedicte Bakke Agerup, all independent directors. Ralf Rank 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, Craig Laurie and Benedicte Bakke Agerup.
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), Ralf Rank, William L. Transier and Nelson Silva.
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, 2021, approximately 1,700 seagoing employees served on our vessels, compared to approximately 1,700 as of December 31, 2020 and approximately 1,900 as of December 31, 2019. As at December 31, 2021, our subsidiaries employed approximately 550 staff who served on shore in technical, commercial and administrative roles in various countries compared to approximately 550 staff as at December 31, 2020 and approximately 450 staff as at December 31, 2019. The increase in onshore employees from 2019 to 2020 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 (NMOA), Norwegian Union of Marine Engineers (NUME) 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.
In addition, we have entered into the following tariff agreements for the Polish seafarers:
•Polish Seafarers' Union (P.S.U) affiliate to the ITF (for ships registered in The Bahamas)
•NIS CBA (Norwegian International ship register) - NSA and Polish Seafarers' Union, National Maritime Section Nszz Solidarnosc
For our Philippine seafarers, we have entered into the following tariff agreements:
•Philippine Seafarers' Union (PSU) (for ships registered in The Bahamas)
•NIS CBA (Norwegian International ship register) - NSA and The Associated Marine Officers and Seamen's Union of the Philippines (AMOSUP)
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-Al), 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, related to the overall strategy of the company, 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, and 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 have also implemented an Accountability Leadership framework which creates clear roles and accountabilities, clarity on decision making and 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, 2021, 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, 2021, 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.
Refer to Item 7B. - Certain Relationships and Related Party Transactions - Transactions with Brookfield.
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, Ralf Rank, Michael Rudnick and Denis Turcotte are directors of our general partner. Messrs. Laurie, Rank, and Turcotte are Managing Partners and Mr. Rudnick is Senior Vice President in Brookfield's Private Equity Group.
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 Inc 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.Loans from Brookfield
Refer to Item 18. - Financial Statements: Note 21(a) and (b) - Related Party Transactions for a description of our outstanding related party borrowings with Brookfield.
c.2018 Purchase of Senior Unsecured Bonds by Brookfield
Refer to Item 18. - Financial Statements: Note 21(a) - 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 Notes, and related transactions.
Other
Refer to Item 18. - Financial Statements: Note 21 - 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 16 - Provisions and Contingencies for a description of certain claims made against us.
Cash Distribution Policy
We currently do not make quarterly distributions on our common or preferred units. Subject to the limitations in our partnership agreement, our general partner may elect to distribute with respect to our common units 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.
In July 2021, we suspended the payment of quarterly cash distributions on our Preferred Units. In addition, no distributions on the Preferred Units will be permitted without noteholder consent while the 11.5% PIK Notes issued in the Brookfield Exchanges remain outstanding. All distributions on the Preferred Units will continue to accrue and must be paid in full before distributions to Class A and Class B common unitholders can be made.
Refer to Item 18. – Financial Statements: Note 22 - Equity for additional information.
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 2.9 (Description of Securities Registered Under Section 12 of the Exchange Act) and incorporated herein by reference.
C.Material Contracts
Attached or incorporated by reference as exhibits to this Annual Report are the contracts we consider to be both material and not entered into in the ordinary course of business. Descriptions are included in Note 19 (“Borrowings”) to our consolidated financial statements included in this Annual Report with respect to our credit facilities and Note 21 (“Related Party Transactions”) with respect to certain contracts with Brookfield. Other than these contracts, we have not entered into any other material contracts in the two years immediately preceding the date of this Annual Report that contain obligations yet to be performed, other than contracts entered into in the ordinary course of business.
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 holding their units in retirement accounts and other tax-deferred accounts,
•persons that acquired our units in a compensatory transaction,
•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, 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, pursuant to a “look-through” rule, any other corporation or partnership in which the corporation directly or indirectly owns at least 25% of the stock or equity interests (by value) and any partnership in which the corporation directly or indirectly owns less than 25% of the equity interests (by value) to the extent the corporation satisfies an “active partner” test and does not elect out of “look through” treatment, 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 and our look-through subsidiaries’ 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 the 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 and any publicly-traded look-through subsidiary may be treated as reflecting the value of our assets, any publicly-traded look-through subsidiaries’ assets, respectively, at any given time. Therefore, a decline in the market value of our units, or the stock or units of any of a publicly-traded look-through subsidiary, which is not within our control, may impact the determination of
whether we are a PFIC. Nevertheless, based on our and our look-through 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 look-through 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 and maintain 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 our subsidiaries, 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 (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), 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. In addition, a Non-U.S. Holder that is a foreign corporation for U.S. federal income tax purposes may be subject to branch profits tax at a rate of 30% (or lower applicable treaty rate) on the after-tax earnings and profits attributable to such distributions.
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 (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), 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. In addition, a Non-U.S. Holder that is a foreign corporation for U.S. federal income tax purposes may be subject to branch profits tax at a rate of 30% (or lower applicable treaty rate) on the after-tax earnings and profits attributable to such gain.
Information Reporting and Backup Withholding
In general, distributions taxable as dividends with respect to, or the proceeds from a sale, redemption or other taxable 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 will not, carry on 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 28c. - 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 the 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, our disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.
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.
We conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements even when determined to be effective and can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. However, based on the evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2021.
This Annual Report is not required to, and does not include, an attestation report of the Partnership’s registered public accounting firm.
Changes in Internal Control Over Financial Reporting
As of December 31, 2020, we identified a material weakness in our internal control over financial reporting, as defined in the standards established by the Sarbanes-Oxley Act of 2002. This material weakness related to user access management within the IT environment.
During the fiscal year ended December 31, 2021, we executed on efforts designed to remediate the identified material weakness. Specifically, we:
•provided additional training to relevant personnel to strengthen competence at the relevant levels across the organization regarding risks and internal controls;
•improved the operation of controls over IT user access and the level of privileges assigned to IT users; and
•increased coordination and monitoring activities related to the execution of the IT user access management controls.
We have tested and evaluated the implementation of new or revised processes and internal controls, in addition to all other financially relevant processes and internal controls, to ascertain whether they are designed and operating effectively to provide reasonable assurance that they will prevent or detect material errors in our financial statements and have concluded that the material weakness related to user access management within the IT environment has been remediated as of December 31, 2021.
Other than stated above, there were no changes in our internal control over financial reporting during the year ended December 31, 2021 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
We have adopted a Code of Conduct that applies to all of 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 2021 and 2020 were Ernst & Young AS. See Item 16F. Change in Registrant’s Certifying Accountant for additional information. The following table shows the fees we incurred for services provided by our principal accountants for 2021 and 2020.
| | | | | | | | | | | | | |
| 2021 | | 2020(1) | | |
| (in thousands of U.S. Dollars) | $ | | $ | | |
Audit Fees (2) | 1,722 | | | 2,159 | | | |
Audit-Related Fees (3) | 60 | | | 36 | | | |
Tax Fees (4) | 200 | | | 329 | | | |
| Total | 1,982 | | | 2,524 | | | |
(1)Includes fees we incurred for services provided by Ernst & Young LLP (Canada).
(2)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.
(3)Audit-related fees relate to other accounting consultations.
(4)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 2021.
Item 16D. Exemptions from the Listing Standards for Audit Committees
Mr. Ralf Rank, who serves on the Audit Committee of our board of directors as an observer, is a Managing Partner 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. Rank 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. Rank’s service on the Audit Committee. We do not believe that Mr. Rank’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) during 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | |
| (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 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:
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| Consolidated Financial Statements | |
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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:
| | | | | |
| Certificate of Limited Partnership of Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), dated August 30, 2006. (1) |
| Amended and Restated Certificate of Limited Partnership of Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), dated March 23, 2020. |
| Certificate of Amendment of the Amended and Restated Certificate of Limited Partnership of Altera Infrastructure L.P., dated December 1, 2020. |
| Seventh Amended and Restated Agreement of Limited Partnership of Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.) dated January 22, 2020. (2) |
| First Amendment to Seventh Amended and Restated Agreement of Limited Partnership of Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), dated March 24, 2020. |
| Second Amendment to Seventh Amended and Restated Agreement of Limited Partnership of Altera Infrastructure L.P., dated October 27, 2020. (3) |
| Certificate of Formation of Altera Infrastructure GP L.L.C. (fka. Teekay Offshore GP L.L.C.), dated August 25, 2006. (1) |
| Certificate of Amendment of Limited Liability Company Agreement of Altera Infrastructure GP L.L.C. (fka. Teekay Offshore GP L.L.C.), dated March 23, 2020. |
| Third Amended and Restated Limited Liability Company Agreement of Altera Infrastructure GP L.L.C., dated March 24, 2020. |
| First Amendment to Third Amended and Restated Limited Liability Company Agreement of Altera Infrastructure GP L.L.C., dated November 30, 2020. |
| 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. (4) |
| 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. (5) |
| Indenture, dated as of July 2, 2018, among Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), Altera Infrastructure Finance Corp. (fka. Teekay Offshore Finance Corp.) and The Bank of New York Mellon, as trustee. (6) |
| First Supplemental Indenture, dated as of May 30, 2014, among Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), Altera Infrastructure Finance Corp. (fka. Teekay Offshore Finance Corp.) and The Bank of New York Mellon, as trustee. (7) |
| Second Supplemental Indenture, dated as of July 3, 2018, among Altera Infrastructure L.P. (fka. Teekay Offshore Partners, L.P.), Altera Infrastructure Finance Corp. (fka. Teekay Offshore Finance Corp.) and The Bank of New York Mellon, as trustee. (6) |
| Indenture, dated as of August 27, 2021, among Altera Infrastructure Holdings L.L.C., Altera Infrastructure L.P. and U.S. Bank National Association, as trustee. (8) |
| First Supplemental Indenture, dated as of January 14, 2022, among Altera Infrastructure Holdings L.L.C., Altera Infrastructure L.P. and U.S. Bank National, as trustee. |
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| Second Supplemental Indenture, dated as of January 14, 2022, among Altera Infrastructure Holdings L.L.C., Altera Infrastructure L.P. and U.S. Bank National, as trustee. |
| Description of Securities Registered Under Section 12 of the Exchange Act. (9) |
| Agreement, dated December 14, 2021, among Altera Shuttle Tankers L.L.C. and Brookfield TK Loan 2 L.P., for a U.S. $70,000,000 Unsecured PIK notes. |
| Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.) 2006 Long-Term Incentive Plan. (1) |
| Form of Amended and Restated Omnibus Agreement. (1) |
| Agreement, dated September 8, 2017, for U.S. $600,000,000 Secured Revolving Credit Facility, between Altera Shuttle Tankers L.L.C. (fka. Teekay Shuttle Tankers L.L.C.) and Den Norske Bank Capital L.L.C. and various other banks. (10) |
| Registration Rights Agreement, dated September 25, 2017, by and between Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), Teekay Corporation and Brookfield TK TOLP L.P. (10) |
| Master Services Agreement, dated September 25, 2017, by and between Teekay Corporation, Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.) and Brookfield TK TOLP L.P. (10) |
| Agreement and Plan of Merger, dated as of September 30, 2019, by and among Altera Infrastructure L.P. (fka. Teekay Offshore Partners L.P.), Brookfield TK Acquisition Holdings LP, Brookfield TK Merger Sub LLC, Altera Infrastructure GP L.L.C. (fka. Teekay Offshore GP L.L.C.) and the other parties thereto. (11) |
| 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) |
| Rule 13a-14(a)/15d-14(a) Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd. |
| Rule 13a-14(a)/15d-14(a) Certification of Jan Rune Steinsland, Chief Financial Officer of Teekay Offshore Group Ltd. |
| 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. |
| 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. |
| Letter of Ernst & Young LLP (Canada), dated March 4, 2021, regarding change in independent registered public accounting firm.(9) |
| 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, 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 exhibit 1.2 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 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.
(5)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.
(6)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.
(7)Previously filed as exhibit 4.2 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on May 30, 2014, and hereby incorporated by reference to such Report.
(8)Previously filed as exhibit 4.1 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 30, 2021, and hereby incorporated by reference to such
(9)Previously filed as exhibits 2.6 and 15.1 to our Report on Form 20-F (File No. 1-33198), filed with the SEC on March 4, 2021, and hereby incorporated by reference to such Report.
(10)Previously filed as exhibits 4.4, 10.5 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.
(11)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 9, 2022 | | | | 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 statement of financial position of Altera Infrastructure L.P. and subsidiaries (the “Partnership”) as of December 31, 2021 and 2020, the related consolidated statements of income (loss), statements of comprehensive income (loss), statements of changes in equity and statements of cash flows for each of the two years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.
We also audited the adjustments described in Note 2.x that were applied to restate the 2019 consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review or apply any procedures to the 2019 consolidated financial statements of the Partnership other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2019 consolidated financial statements taken as a whole.
Change in Accounting Principle
As discussed in Note 2.i to the consolidated financial statements, the Partnership has elected to change its method for accounting for the classification of related party borrowings and related accrued interest in 2021.
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 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 2.b to the consolidated financial statements, the Partnership has a significant working capital deficit as of December 31, 2021. The Partnership will need to obtain additional sources of financing to meet its obligations and commitments, minimum liquidity requirements and debt service coverage ratio 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 certain of its significant stakeholders to obtain additional sources of financing and to refinance or extend certain borrowings, 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 and debt service coverage ratio under its financial covenants. Management’s cash flow forecasts assume refinancing or extensions of existing loans, additional drawing on existing facilities, increasing equity, liquidity support from its owners, and other liability management transactions. 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 cash inflow from sale of vessels. We independently assessed the sensitivity and impact of reasonably possible changes in the 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.
In relation to management’s plans for loan refinancing, and the liquidity support from its shareholders, we tested that signed agreements after balance sheet date were consistent with management’s forecast. Furthermore, we assessed management’s assertion that their plans can 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 certain vessels included in the cash flow forecast, for a sample of the vessels, we recalculated expected proceeds based on planned recycling destination and current recycling prices based on external market reports or offers received. We assessed the adequacy of the Partnership’s going concern disclosures included in note 2.b in the consolidated financial statements. |
| | |
| | | | | | | | |
| | Impairment of vessels |
| Description of the Matter | | On December 31, 2021, 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 $2,869.4 million, net of impairment losses of $116.4 million recognized in the consolidated statement of loss during the period.
As explained in note 2.l to the consolidated financial statements, management assesses, at each reporting date, whether there are indications that assets or cash-generating units are impaired.
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, the sales or residual value 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 the value-in-use calculation is sensitive to changes in 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 the determination of charter rates post-contract expiry, the possibilities for redeployment, the sale or residual value 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, amongst others, to involve our valuation specialists to assist in the review of the Partnership’s model, method, and the discount rate.
We tested the reasonableness of the charter rates post-contract expiry and redeployment assumptions by, amongst others, comparing them to both historical information 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 the management were supported by the external industry outlook reports. We also analyzed how the economic factors such as future demand and supply for the Partnership’s vessels have been incorporated into the management’s assumptions for redeployment of both idle vessels and vessels with contracts expiring before the end of useful life. For the sales price or residual value, we compared the sales price with external market reports for sale of similar vessels, recalculated expected proceeds based on planned recycling destination and current recycling prices based on external market reports or compared to offers received.
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 assistance of our valuation specialists, we also developed a range of independent estimates comparing those to the discount rate selected by the 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 2.l, 2.v, and 10 in the consolidated financial statements. |
/s/ Ernst & Young AS
We have served as the Partnership’s auditor since 2020.
Stavanger, Norway
March 9, 2022
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, before the effects of the adjustments to retrospectively apply the change in accounting described in Note 2.x, the accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows, and changes in equity of Altera Infrastructure L.P. and subsidiaries (the “Partnership”) for the year ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”)(the 2019 financial statements before the effects of the restatements discussed in Note 2.x are not presented herein). In our opinion, the consolidated financial statements, before the effects of the adjustments to retrospectively apply the change in accounting described in Note 2.x, present fairly, in all material respects, the financial performance, cash flows and changes in equity of the Partnership for the year ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in accounting described in Note 2.x and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by Ernst & Young AS.
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
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, |
| | | 2021 | | 2020 Restated(1) | | 2020 Restated(1) |
| Notes | | $ | | $ | | $ |
| ASSETS | | | | | | | |
| Current assets | | | | | | | |
| Cash and cash equivalents | 3 | | 190,942 | | 235,734 | | 199,388 |
| Financial assets | 4 | | 19,400 | | 103,514 | | 107,992 |
| Accounts and other receivable, net | 5 | | 127,453 | | 222,629 | | 204,825 |
| Vessels and equipment classified as held for sale | 6 | | 5,800 | | 7,500 | | 15,374 |
| Inventory | | | 26,601 | | 16,308 | | 18,581 |
| Due from related parties | 21 | | 978 | | 9,980 | | — |
| Other assets | 8 | | 43,668 | | 37,326 | | 16,844 |
| Total current assets | | | 414,842 | | 632,991 | | 563,004 |
| Non-current assets | | | | | | | |
| Financial assets | 4 | | 45,740 | | 36,372 | | — |
| Accounts and other receivable, net | 5 | | — | | — | | 17,276 |
| Vessels and equipment | 10 | | 2,869,395 | | 3,029,415 | | 3,025,716 |
| Advances on newbuilding contracts | 11 | | 51,918 | | 127,335 | | 297,100 |
| Equity-accounted investments | 12 | | 237,469 | | 241,731 | | 232,216 |
| Deferred tax assets | 20 | | — | | 5,153 | | 7,000 |
| | | | | | | |
| Other assets | 8 | | 138,247 | | 185,521 | | 218,813 |
| Goodwill | 13 | | 127,113 | | 127,113 | | 127,113 |
| Total non-current assets | | | 3,469,882 | | 3,752,640 | | 3,925,234 |
| Total assets | | | 3,884,724 | | 4,385,631 | | 4,488,238 |
| LIABILITIES | | | | | | | |
| Current liabilities | | | | | | | |
| Accounts payable and other | 14 | | 249,297 | | 286,295 | | 256,114 |
| Other financial liabilities | 18 | | 34,679 | | 198,985 | | 21,697 |
| Borrowings | 19,21 | | 407,274 | | 362,079 | | 353,238 |
| Due to related parties | 21 | | — | | 16,126 | | 37,810 |
| Total current liabilities | | | 691,250 | | 863,485 | | 668,859 |
| Non-current liabilities | | | | | | | |
| Accounts payable and other | 14 | | 49,253 | | 128,671 | | 222,659 |
| Other financial liabilities | 18 | | 188,658 | | 144,350 | | 164,511 |
| Borrowings | 19,21 | | 2,056,753 | | 2,397,638 | | 2,407,649 |
| Due to related parties | 21 | | 797,432 | | 605,888 | | 423,625 |
| Deferred tax liabilities | 20 | | 700 | | 700 | | 3,133 |
| Total non-current liabilities | | | 3,092,796 | | 3,277,247 | | 3,221,577 |
| Total liabilities | | | 3,784,046 | | 4,140,732 | | 3,890,436 |
| EQUITY | | | | | | | |
| Limited partners - common units | 22 | | — | | — | | 169,737 |
| Limited partners - Class A common units | 22 | | (4,539) | | (2,505) | | — |
| Limited partners - Class B common units | 22 | | (314,153) | | (157,897) | | — |
| Limited partners - preferred units | 22 | | 392,248 | | 376,512 | | 384,274 |
| General partner | 22 | | 5,603 | | 6,828 | | 9,587 |
| Accumulated other comprehensive income | | | 2,811 | | 4,071 | | 4,410 |
| Non-controlling interests in subsidiaries | 23 | | 18,708 | | 17,890 | | 29,794 |
| Total equity | | | 100,678 | | 244,899 | | 597,802 |
| Total liabilities and equity | | | 3,884,724 | | 4,385,631 | | 4,488,238 |
| | | | | | | |
| The accompanying notes are an integral part of the consolidated financial statements. |
(1) See Note 2i for further details.
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 | | Year Ended | | |
| | | December 31, | | December 31, | | December 31, | | |
| | | 2021 | | 2020 | | 2019 | | |
| Notes | | $ | | $ | | $ | | |
| Revenues | 24 | | 1,151,260 | | 1,182,110 | | 1,252,938 | | |
| Direct operating costs | 25 | | (654,580) | | (627,792) | | (606,691) | | |
| General and administrative expenses | 26 | | (40,770) | | (44,360) | | (54,927) | | |
| Depreciation and amortization | 26 | | (313,120) | | (316,317) | | (358,474) | | |
| Interest expense | 19,21 | | (206,176) | | (192,723) | | (205,667) | | |
| Interest income | | | 91 | | 2,770 | | 5,111 | | |
| Equity-accounted income (loss) | 12 | | 25,062 | | 35,921 | | 33,768 | | |
| Impairment expense, net | 10 | | (116,420) | | (268,612) | | (187,680) | | |
| Gain (loss) on dispositions, net | 7 | | 10,502 | | 3,411 | | 12,548 | | |
| | | | | | | | | |
| Realized and unrealized gain (loss) on derivative instruments | 18,21 | | 15,732 | | (96,499) | | (34,682) | | |
| Foreign currency exchange gain (loss) | | | (825) | | (7,861) | | 2,193 | | |
| Gain (loss) on modification of financial liabilities, net | 21,29 | | (45,920) | | — | | (8,332) | | |
| Other income (expenses), net | 21,30 | | 48,323 | | (10,472) | | (1,345) | | |
| Income (loss) before income tax (expense) benefit | | | (126,841) | | (340,424) | | (151,240) | | |
| Income tax (expense) benefit | | | | | | | | | |
| Current | 20 | | (4,603) | | (6,543) | | (4,666) | | |
| Deferred | 20 | | (5,006) | | 804 | | (3,161) | | |
| Net income (loss) | | | (136,450) | | (346,163) | | (159,067) | | |
| Attributable to: | | | | | | | | | |
| Limited partners - common units | | | (160,218) | | (368,341) | | (181,424) | | |
| General partner | | | (1,225) | | (2,771) | | (1,384) | | |
| Limited partners - preferred units | | | 31,520 | | 32,103 | | 32,150 | | |
| Non-controlling interests in subsidiaries | 23 | | (6,527) | | (7,154) | | (8,409) | | |
| | | (136,450) | | (346,163) | | (159,067) | | |
| Basic and diluted earnings (loss) per limited partner common unit | 22 | | (0.39) | | (0.90) | | (0.44) | | |
| | | | | | | | | |
| The accompanying notes are an integral part of the consolidated financial statements. | | | | |
2ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands of U.S. Dollars) | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended | | Year Ended | | Year Ended | | |
| | | December 31, | | December 31, | | December 31, | | |
| | | 2021 | | 2020 | | 2019 | | |
| Notes | | $ | | $ | | $ | | |
| Net income (loss) | | | (136,450) | | (346,163) | | (159,067) | | |
| Other comprehensive income (loss) | | | | | | | | | |
| Items that will not be reclassified subsequently to net income (loss): | | | | | | | | | |
| Pension adjustments, net of taxes | | | 233 | | 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 | 18 | | (750) | | (811) | | (689) | | |
| To equity-accounted income (loss): | | | | | | | | | |
| Realized gain on qualifying cash flow hedging instruments | 12 | | (743) | | (966) | | (600) | | |
| Total other comprehensive income (loss) | | | (1,260) | | (339) | | (2,951) | | |
| Comprehensive income (loss) | | | (137,710) | | (346,502) | | (162,018) | | |
| Attributable to: | | | | | | | | | |
| Limited partners - common units | | | (161,468) | | (368,677) | | (184,353) | | |
| General partner | | | (1,235) | | (2,774) | | (1,406) | | |
| Limited partners - preferred units | | | 31,520 | | 32,103 | | 32,150 | | |
| Non-controlling interests in subsidiaries | 23 | | (6,527) | | (7,154) | | (8,409) | | |
| | | (137,710) | | (346,502) | | (162,018) | | |
| | | | | | | | | |
| The accompanying notes are an integral part of the consolidated financial statements. |
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
$ | | | | | | Preferred
Units
# | | Preferred
Units
$ | | General
Partner
$ | | Accumulated Other Comprehensive Income
$ | | Non-
controlling
Interests
$ | | Total
Equity
$ | |
| Balance as at January 1, 2021 | | | 5,217 | | | (2,505) | | | 405,932 | | | (157,897) | | | | | | | 15,489 | | | 376,512 | | | 6,828 | | | 4,071 | | | 17,890 | | | 244,899 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | | — | | | (2,034) | | | — | | | (158,184) | | | | | | | — | | | 31,520 | | | (1,225) | | | — | | | (6,527) | | | (136,450) | | |
| Other comprehensive income (loss) | | | — | | | — | | | — | | | — | | | | | | | — | | | — | | | — | | | (1,260) | | | — | | | (1,260) | | |
| Distributions declared: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Preferred Units - Series A ($0.9062 per unit) | | | — | | | — | | | — | | | — | | | | | | | — | | | (5,326) | | | — | | | — | | | — | | | (5,326) | | |
| Preferred Units - Series B ($1.0626 per unit) | | | — | | | — | | | — | | | — | | | | | | | — | | | (5,216) | | | — | | | — | | | — | | | (5,216) | | |
| Preferred Units - Series E ($1.1094 per unit) | | | — | | | — | | | — | | | — | | | | | | | — | | | (5,218) | | | — | | | — | | | — | | | (5,218) | | |
| Other distributions | | | — | | | — | | | — | | | — | | | | | | | — | | | — | | | — | | | — | | | (2,605) | | | (2,605) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Contribution of capital from Brookfield | | | — | | | — | | | — | | | 1,928 | | | | | | | — | | | — | | | — | | | — | | | — | | | 1,928 | | |
| Distribution to non-controlling interests | | | — | | | — | | | — | | | — | | | | | | | — | | | — | | | — | | | — | | | (8,000) | | | (8,000) | | |
| Contribution from non-controlling interests | | | — | | | — | | | — | | | — | | | | | | | — | | | — | | | — | | | — | | | 17,950 | | | 17,950 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Repurchase of preferred units | | | — | | | — | | | — | | | — | | | | | | | (1) | | | (24) | | | — | | | — | | | — | | | (24) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance as at December 31, 2021 | | | 5,217 | | | (4,539) | | | 405,932 | | | (314,153) | | | | | | | 15,488 | | | 392,248 | | | 5,603 | | | 2,811 | | | 18,708 | | | 100,678 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| The accompanying notes are an integral part of the consolidated financial statements. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | 22 | | 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. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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. | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of U.S. Dollars) | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended | | Year Ended | | Year Ended |
| | | December 31, | | December 31, | | December 31, |
| | | 2021 | | 2020 | | 2019 |
| Notes | | $ | | $ | | $ |
| Operating Activities | | | | | | | |
| Net income (loss) | | | (136,450) | | | (346,163) | | | (159,067) | |
| Adjusted for the following items: | | | | | | | |
| Depreciation and amortization | 10 | | 313,120 | | | 316,317 | | | 358,474 | |
| Equity-accounted (income) loss, net of distributions received of $33,428 (2020 - $29,742; 2019 - $17,655) | 12 | | 8,368 | | | (6,532) | | | (16,113) | |
| Impairment expense, net | 10 | | 116,420 | | | 268,612 | | | 187,680 | |
| (Gain) loss on dispositions, net | 7 | | (10,502) | | | (3,411) | | | (12,548) | |
| Unrealized (gain) loss on derivative instruments | 18 | | (173,195) | | | 36,045 | | | 443 | |
| Deferred income tax expense (benefit) | 20 | | 5,006 | | | (804) | | | 3,161 | |
| Provisions and other items | 16 | | (54,698) | | | (3,503) | | | (1,547) | |
| Other non-cash items | | | 59,937 | | | 34,629 | | | (22,942) | |
| Changes in non-cash working capital, net | 27 | | 87,289 | | | (12,871) | | | 13,341 | |
| Net operating cash flow | | | 215,295 | | | 282,319 | | | 350,882 | |
| Financing Activities | | | | | | | |
| Proceeds from borrowings | 19 | | 276,120 | | | 312,149 | | | 492,517 | |
| Repayments of borrowings and settlement of related derivative instruments | 18,19 | | (579,180) | | | (329,073) | | | (410,429) | |
| Financing costs related to borrowings | 19 | | (7,720) | | | (8,023) | | | (20,752) | |
| Proceeds from borrowings related to sale and leaseback of vessels | 11 | | 71,400 | | | 119,073 | | | 23,800 | |
| Repayments of borrowings related to sale and leaseback of vessels | 11 | | (11,335) | | | (1,190) | | | — | |
| Financing costs related to borrowings from sale and leaseback of vessels | 11 | | (584) | | | (187) | | | (2,256) | |
| Proceeds from borrowings from related parties | 21 | | 147,000 | | | 205,000 | | | 95,000 | |
| Prepayment of borrowings from related parties | 21 | | (30,000) | | | — | | | (200,000) | |
| Lease liability repayments | 9 | | (14,506) | | | (20,332) | | | (14,695) | |
| Capital contribution by non-controlling interests | | | 17,950 | | | — | | | 1,500 | |
| | | | | | | |
| Distributions to limited partners and preferred unitholders | 22 | | (15,760) | | | (32,103) | | | (32,150) | |
| Distributions to non-controlling interests | 23 | | (10,605) | | | (4,750) | | | (3,636) | |
| Repurchase of preferred units | 22 | | (24) | | | (6,200) | | | — | |
| Net financing cash flow | | | (157,244) | | | 234,364 | | | (71,101) | |
| Investing Activities | | | | | | | |
| Additions | | | | | | | |
| Vessels and equipment | 10,11 | | (211,448) | | | (479,981) | | | (231,658) | |
| Equity-accounted investments | 12 | | (4,847) | | | (3,948) | | | (7,886) | |
| Dispositions | | | | | | | |
| Vessels and equipment | 7 | | 44,894 | | | 27,996 | | | 33,341 | |
| Changes in restricted cash | 4 | | 68,575 | | | (26,520) | | | (98,329) | |
| Acquisition of company (net of cash acquired of $6.4 million) | | | — | | | 6,430 | | | — | |
| Net investing cash flow | | | (102,826) | | | (476,023) | | | (304,532) | |
| Cash and cash equivalents | | | | | | | |
| Change during the year | | | (44,775) | | | 40,660 | | | (24,751) | |
| Impact of foreign exchange on cash | | | (17) | | | (4,314) | | | (901) | |
| Balance, beginning of the year | | | 235,734 | | | 199,388 | | | 225,040 | |
| Balance, end of the year | | | 190,942 | | | 235,734 | | | 199,388 | |
| | | | | | | |
Supplemental cash flow information (Note 27) | | | | | | | |
| The accompanying notes are an integral part of the consolidated financial statements. | | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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) 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 dated January 22, 2020 and as amended on March 24, 2020 and 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.
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 9, 2022.
b.Going concern
As at December 31, 2021, the Partnership had a working capital deficit of $276.4 million primarily relating to the scheduled maturities and repayments of $407.3 million of outstanding borrowings and the settlement of $34.7 million of other financial liabilities, primarily interest rate swaps, during the 12 months ending December 31, 2022, which amounts were classified as current liabilities as at December 31, 2021. The Partnership also anticipates making payments related to commitments to fund the vessel under construction through 2022 of $74.0 million; however, the Partnership has secured long-term financing related to the vessel.
The working capital deficit of $276.4 million as at December 31, 2021 has increased from $230.5 million as at December 31, 2020. The increase in the working capital deficit was primarily due to a $95.2 million decrease in accounts and other receivable, net, an $84.1 million decrease in financial assets, a $44.8 million decrease in cash and cash equivalents, and a $45.2 million increase in borrowings. This was partially offset by a $164.3 million decrease in other financial liabilities, and a $37.0 million decrease in accounts payable and other.
During the year ended December 31, 2021, the Partnership completed various measures to improve its debt maturity profile and enhance its liquidity and financial flexibility, including but not limited to exchanging $769.3 million of Brookfield debt with 2022 to 2024 maturities into debt with interest paid in kind and with a 2026 maturity, discontinuing distributions on the Series A, Series B and Series E Preferred Units, issuing $180.0 million of new 2025 bonds in the shuttle tanker segment and refinancing the Petrojarl I FPSO unit. See Notes 19, 21a and b, and 22 for additional information. While these measures improved the Partnership's liquidity position, the Partnership continues to explore its liquidity management opportunities and seek to improve and extend its debt profile.
In addition to the successfully completed initiatives during 2021, it is still critical that 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. These requirements include but are not limited to maintaining a minimum liquidity in an amount equal to the greater of $75 million and 5% of total debt as well as maintaining within the Partnership's wholly-owned subsidiary, Altera Shuttle Tankers L.L.C., a minimum liquidity in an amount equal to the greater of $35 million and 5% of total debt and a net debt to total capitalization ratio of no greater than 75%.
Additional potential sources of financing that the Partnership is actively pursuing, during the one-year period to December 31, 2022, include entering into new debt facilities, borrowing additional amounts under existing facilities, the refinancing, extension or other amendments, including amendment of financial covenants, of certain borrowings and interest rate swaps, selling certain assets, seeking joint venture partners for the Partnership's business interests, enter into sale-leaseback agreements, increasing equity, and other potential liability management transactions. Additional potential sources of amounts generated from operations include the extensions and redeployments of existing assets, higher utilization of the operating fleet, increased rates for vessels operating in the spot market, increased oil price-based tariffs from certain FPSOs and working capital optimizations.
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. See Note 31a for additional information.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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, 2022.
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 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, 2021:
| | | | | | | | | | | | | | |
| 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 L.L.C. | | 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 L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
| | | | | | | | | | | | | | |
| 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 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% |
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| 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% |
| Arendal Spirit UK Limited | | United Kingdom | | 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 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% |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
| | | | | | | | | | | | | | |
| Siri Holdings LLC | | Marshall Islands | | 100% |
| Teekay Australia Offshore Holdings Pty Ltd. | | Australia | | 100% |
| Teekay FSO Finance Pty Ltd. | | Australia | | 100% |
| Teekay Hiload LLC | | Marshall Islands | | 100% |
| Altera Global Shared Services (Philippines) Inc. | | Philippines | | 100% |
| Tide Spirit AS | | Norway | | 100% |
| Tiro Sidon UK L.L.P. | | United Kingdom | | 100% |
| Altera Infrastructure Siri AS | | Norway | | 100% |
| TPO Siri LLC | | Marshall Islands | | 100% |
| Varg LLC | | Marshall Islands | | 100% |
| | | | |
| Voyageur LLC | | Marshall Islands | | 100% |
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The following table presents details of non-wholly owned subsidiaries of the Partnership as at December 31, 2021:
| | | | | | | | | | | | | | |
| 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% |
For the 50% owned entities above the Partnership has determined that the 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 as at December 31, 2021:
| | | | | | | | | | | | | | |
| 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 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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.
The following table presents the details of the Partnership's inventory as at December 31, 2021 and 2020:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Fuel oil | 23,203 | | | 13,528 | |
| Materials and consumables | 3,398 | | | 2,780 | |
| Total inventory | 26,601 | | | 16,308 | |
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 fair value, which generally is the agreed upon exchange value and are recognized in the consolidated financial statements. Related party transactions are further described in Note 21.
Related Party Borrowings Reclassification
The accounting policy elected historically by the Partnership has reflected its long-term debt within two line items, Borrowings and Due to related parties. Borrowings has included publicly listed debt held by third parties and by Brookfield. The related party component of publicly listed Borrowings has been historically disclosed in the notes to the financial statements.
On August 27, 2021, the Partnership completed a refinancing with Brookfield (or the Brookfield Exchanges) (see Note 21a for additional information) and voluntarily revised the Partnership's accounting policy to classify all debt held by Brookfield, regardless of the nature of the instrument as Due to related parties. The Partnership believes it is more relevant to show all related party debt on the same financial statement line item.
The Partnership has reflected this change retrospectively by restating its comparative consolidated statement of financial position. Following the change, debt will continue to be included in two line items, Borrowings, which will include only debt held by third-party counterparties and Due to related parties, which will include all debt where Brookfield or other affiliates are the ultimate counterparty, regardless of whether a debt instrument is publicly listed. Additionally, all accrued interest on related party debt will be reflected within the Due to related parties line item rather than within Accounts payable and other, as previously reported.
The following tables provides a reconciliation of the resulting reclassifications directly related to the change in accounting policy discussed above to the Partnership's consolidated statements of financial position:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 | | | | As at |
| December 31, 2020 | | | | December 31, 2020 |
| As Previously Reported | | Reclassifications | | Restated |
| $ | | $ | | $ |
| Accounts payable and other | 302,414 | | (16,119) | | 286,295 |
| Due to related parties | 7 | | 16,119 | | 16,126 |
| Total current liabilities | 302,421 | | — | | 302,421 |
| Borrowings | 2,808,898 | | (411,260) | | 2,397,638 |
| Due to related parties | 194,628 | | 411,260 | | 605,888 |
| Total non-current liabilities | 3,003,526 | | — | | 3,003,526 |
| Total liabilities | 3,305,947 | | — | | 3,305,947 |
| | | | | | | | | | | | | | | | | |
| As at | | | | As at |
| December 31, 2019 | | | | January 1, 2020 |
| As Previously Reported | | Reclassifications | | Restated |
| $ | | $ | | $ |
| Accounts payable and other | 272,618 | | (16,504) | | 256,114 |
| Due to related parties | 21,306 | | 16,504 | | 37,810 |
| Total current liabilities | 293,924 | | — | | 293,924 |
| Borrowings | 2,831,274 | | (423,625) | | 2,407,649 |
| Due to related parties | — | | 423,625 | | 423,625 |
| Total non-current liabilities | 2,831,274 | | — | | 2,831,274 |
| Total liabilities | 3,125,198 | | — | | 3,125,198 |
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 recycling 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 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 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. This is due to the fact that the cash inflows from an individual vessel operating in the CoA fleet are not largely independent of the cash inflows from other vessels operating in the CoA fleet, i.e., the individual vessels are not the smallest identifiable group and therefore it is concluded that the CoA fleet is 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 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.
The Partnership’s primary source of revenues is chartering its vessels and offshore units to its customers. The Partnership utilizes 5 primary forms of contracts, consisting of FPSO contracts, CoA, time-charter contracts, bareboat charter contracts and voyage charter contracts.
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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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), which permits an entity, with a contract that has an original expected duration of one year or less, to not disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the period. The Partnership does not engage in any specific activities to minimize residual value risk due to the short-term nature of the contracts.
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.
(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, which permits an entity to recognize revenue based on the amount it has a right to invoice.
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. Sometimes 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 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 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
Gains or losses are recognized in the consolidated statements of income (loss) when a financial asset or liability is remeasured due to a modification of terms that does not result in derecognition or when derecognition occurs and the modified financial instrument is recorded at fair value.
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.
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, 2021, the Partnership recorded an ECL of $0.6 million (December 31, 2020 - $1.4 million).
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 the profit or loss. 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 3.
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, the Netherlands, the Philippines and Thailand.
(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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(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 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 as a contract asset within Other assets . 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 deferred 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 including in calculation of the gain (loss) associated with the modification and remeasurement of the financial instrument resulting recognition of interest expense using the effective interest rate.
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 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 | | Yes | | Yes | | Yes | | Depends |
| Non-lease component | Yes | | Yes | | Yes | | No | | 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 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.
(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 units 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 14 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 10.
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 10 and 13 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, 2021. Based on the Partnership’s assessments, no additional impairment indicators were identified as at December 31, 2021 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 Partnership's results of operations and financial condition, including any future possible impairments, will depend on future developments, which are highly uncertain and
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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.
(vii) Climate Change
The Partnership could face the impact of an accelerated energy transition driven by climate change. The Partnership's strategy, capital allocation and selection of projects are guided by the vision to lead the industry to a sustainable future and climate related risks are key drivers for it. The effect on the Partnership's compliance costs, capital expenditures, cash flow from operation and other assumptions are inherently uncertain and may differ from actual amounts. The Partnership did not experience any impact from an accelerated energy transition driven by climate change on the financial results as at December 31, 2021. The risks will however remain as key considerations for impairment testing, estimation of remaining useful life and provisions for future periods.
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.
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, 2021, the Partnership’s operating segments are the FPSO, Shuttle Tanker, FSO, UMS and Towage segments.
As at January 1, 2021, the Partnership modified the cost allocations between its operating segments. The Partnership's components of the business for which discrete financial information is reviewed to assess performance and make decisions regarding resource allocation is still based upon five operating segments. However, the allocation of certain expenditures, relating to direct operating costs and general and administrative expenses, has been modified to show the impact of certain corporate direct operating costs in the corporate segment before reallocation to the operating segments. Additionally, certain expenditures that relate directly to corporate activities will be retained within the corporate segment. Previously all of these expenditures were allocated directly to the five operating segments based on an estimated use of corporate resources. The 2020 and 2019 comparative information has been restated as a result of this change and the modifications have been deemed to not be material for all operating segments and all periods presented.
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, 2021, the amount of cost recognized for the Partnership’s defined contribution pension plans was $6.6 million (December 31, 2020 - $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 $0.8 million as at December 31, 2021 (December 31, 2020 - a shortfall of $0.7 million).
z.New standards, interpretations, amendments and policies adopted by the Partnership
The Partnership has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
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. 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 adopted the Phase 2 Amendments on January 1, 2021. The adoption of the amendments did not have a significant impact on the Partnership’s consolidated financial
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
statements as at and for the year ended December 31, 2021. The Partnership's risk management strategy has not changed as a result of these matters.
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. During March 2021, ICE Benchmark Administration, an administrator of regulated benchmarks, announced that it has delayed the cessation of the publication of the overnight, one, three, six and 12 month USD LIBOR until June 30, 2023.
Interest rate benchmark transition for non-derivative financial liabilities
As at December 31, 2021, the Partnership had $1.6 billion of outstanding LIBOR-referenced borrowings summarized as follows:
| | | | | | | | | | | | | | | | | |
| Principal | | Weighted-average term | | Transition Progress |
| $ | | (years) | | |
| Revolving Credit Facilities | 308,887 | | | 2.34 | | Expected to amend fallback clauses prior to cessation of publication of LIBOR. |
| Term Loans | 1,079,586 | | | 3.92 | |
| Public Bonds | 200,000 | | | 2.80 | |
| Total | 1,588,473 | | | 3.48 | | |
Interest rate benchmark transition for derivatives
As at December 31, 2021, the Partnership had an outstanding notional balance of $541.6 million 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. Such adherence would result in all legacy trade under the derivatives following, on the cessation of LIBOR, the fallback clause provided in the protocol.
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.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, 2021 and 2020:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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, 2021 | | December 31, 2020 |
| Measurement Basis | FVTPL
$ | | Amortized cost
$ | | Total
$ | | FVTPL
$ | | Amortized cost
$ | | Total
$ |
| Financial assets | | | | | | | | | | | |
| Cash and cash equivalents | — | | | 190,942 | | | 190,942 | | | — | | | 235,734 | | | 235,734 | |
| Financial assets (current and non-current) | 325 | | | 64,815 | | | 65,140 | | | 6,497 | | | 133,389 | | | 139,886 | |
Accounts and other receivable, net (current and non-current)(1) | — | | | 120,940 | | | 120,940 | | | — | | | 212,316 | | | 212,316 | |
| Due from related parties (current and non-current) | — | | | 978 | | | 978 | | | — | | | 9,980 | | | 9,980 | |
Other assets (current and non-current)(2) | — | | | 53,158 | | | 53,158 | | | — | | | 59,905 | | | 59,905 | |
| Total | 325 | | | 430,833 | | | 431,158 | | | 6,497 | | | 651,324 | | | 657,821 | |
| Financial liabilities | | | | | | | | | | | |
Accounts payable and other(3) | — | | | 62,414 | | | 62,414 | | | — | | | 81,850 | | | 81,850 | |
Other financial liabilities (current and non- current)(4) | 24,229 | | | 199,108 | | | 223,337 | | | 203,597 | | | 139,738 | | | 343,335 | |
| Due to related parties (current and non-current) | — | | | 797,432 | | | 797,432 | | | — | | | 622,014 | | | 622,014 | |
| Borrowings (current and non-current) | — | | | 2,464,027 | | | 2,464,027 | | | — | | | 2,759,717 | | | 2,759,717 | |
| Total | 24,229 | | | 3,522,981 | | | 3,547,210 | | | 203,597 | | | 3,603,319 | | | 3,806,916 | |
(1)Excludes tax receivable of $6.5 million as at December 31, 2021 (December 31, 2020 - $10.3 million).
(2)Includes investments in finance leases. Refer to Note 8 below.
(3)Includes accounts payable and lease liabilities. Refer to Note 14 below.
(4)Includes derivative instruments, obligations relating to leases and other financial liabilities. Refer to Note 18 below.
Included in cash and cash equivalents as at December 31, 2021 is $190.9 million of cash (December 31, 2020 - $235.7 million) and $NaN of cash equivalents (December 31, 2020 - $NaN).
The fair value of all financial assets and liabilities as at December 31, 2021 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 $2,362 million (December 31, 2020: $2,753 million) versus a carrying value of $2,464 million (December 31, 2020: $2,760 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.
In addition, within the December 31, 2020 Due to related parties (current and non-current) balance shown above $411.3 million of the outstanding senior unsecured bonds held by Brookfield were fair valued using Level 1 and Level 2 inputs and resulted in a fair value of $351.4 million.
Fair value hierarchical levels - financial instruments
There were no transfers between levels during the years ended December 31, 2021 and December 31, 2020. 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, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 |
| $ | | $ | | $ | | $ | | $ | | $ |
| Financial assets | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Derivative instruments | — | | | 325 | | | — | | | — | | | 6,497 | | | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Total | — | | | 325 | | | — | | | — | | | 6,497 | | | — | |
| Financial liabilities | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Derivative instruments | — | | | 24,229 | | | — | | | — | | | 203,597 | | | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Total | — | | | 24,229 | | | — | | | — | | | 203,597 | | | — | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 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, 2021 | | December 31, 2020 | |
| $ | | $ | |
| Derivative instruments | | (23,904) | | | (197,100) | | | 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. |
4.Financial Assets
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Current | | | |
Restricted cash(1) | 19,075 | | 97,017 |
Derivative instruments(2) | 325 | | 6,497 |
| Total current | 19,400 | | 103,514 |
| Non-current | | | |
Restricted cash(1) | 45,740 | | 36,372 |
Derivative instruments(2) | — | | — |
| Total non-current | 45,740 | | 36,372 |
(1)Restricted cash as at December 31, 2021 includes funds for loan facility repayments, withholding taxes and office lease prepayments (December 31, 2020 - 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).
(2)See Note 18 for additional information
5.Accounts and Other Receivable, Net | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | |
| $ | | $ | | |
| Current | | | | | |
| Accounts receivable - trade | 110,301 | | 162,848 | | |
Accounts receivable - non-trade(1) | — | | 40,104 | | |
| Other non-trade receivable | 17,152 | | 19,677 | | |
| Total current | 127,453 | | 222,629 | | |
| Non-current | | | | | |
Accounts receivable - non-trade(1) | — | | — | | |
| Total non-current | — | | — | | |
(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 2 separate installments, one of which was due to the Partnership by the end of 2020 and the other by the end of 2021.
6.Vessels and Equipment Classified as Held for Sale | | | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, 2021 | | December 31, 2020 | | |
| Vessel | | Segment | | $ | | $ | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Dampier Spirit(1)(2) | | FSO Segment | | — | | | — | | | |
Navion Anglia(1) | | Shuttle Tanker Segment | | — | | | 4,400 | | | |
Navion Oslo(1) | | Shuttle Tanker Segment | | — | | | 3,100 | | | |
| Petrojarl Varg | | FPSO Segment | | 5,800 | | | — | | | |
| | | | 5,800 | | | 7,500 | | | |
(1)Classification as a result of the highly probable sale of the vessels, which were completed during the first quarter of 2020, second quarter of 2021 or third quarter of 2021 (see Note 7 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
The fair value of vessels and equipment classified as held for sale measured on a non-recurring basis was $5.8 million and $7.5 million as at December 31, 2021 and December 31, 2020, respectively (see Note 10 for additional information).
7.Gain (Loss) on Dispositions, Net | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Vessel | | Segment | | Net Proceeds | | Gain (Loss) on Dispositions, Net |
| Q4-21 | | Navion Stavanger | | Shuttle Tanker Segment | | 9,915 | | (2) | |
| Q3-21 | | Navion Anglia | | Shuttle Tanker Segment | | 6,144 | | 1,397 | |
| Q2-21 | | Dampier Spirit | | FSO Segment | | 3,970 | | 3,970 | |
| Q2-21 | | Navion Oceania | | Shuttle Tanker Segment | | 10,618 | | 2,576 | |
| Q2-21 | | Navion Oslo | | Shuttle Tanker Segment | | 3,160 | | (29) | |
| Q2-21 | | Stena Natalita | | Shuttle Tanker Segment | | 8,198 | | (299) | |
Q2-21(1) | | Apollo Spirit | | FSO Segment | | 2,889 | | 2,889 | |
| Gain (loss) on dispositions, net for the year ended December 31, 2021 | | 10,502 | |
| | | | | | | | |
| 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 | |
(1)The Apollo Spirit FSO was sold in December 2020 and a gain on sale of $5.4 million was recorded as at December 31, 2020. An additional gain of $2.9 million was recorded in June 2021 after the official recycling of the vessel was completed based on a recycling rate agreed upon with the buyer per the terms of the contract.
8.Other Assets
| | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | |
| $ | | $ | | |
| Current | | | | | |
| Prepayments | 9,590 | | | 10,101 | | | |
Investment in finance leases(1) | 9,162 | | | 8,267 | | | |
Contract assets(2) | 24,916 | | | 18,958 | | | |
| | | | | |
| Total current | 43,668 | | | 37,326 | | | |
| Non-current | | | | | |
Investment in finance leases(1) | 43,996 | | | 51,638 | | | |
Right-of-use assets(3) | 25,386 | | | 35,313 | | | |
Contract assets(2) | 37,597 | | | 48,288 | | | |
Other assets(2) | 31,268 | | | 50,282 | | | |
| Total non-current | 138,247 | | | 185,521 | | | |
(1)Includes the VOC systems on certain of the Partnership's shuttle tankers. See Note 24 for additional information.
(2)See Note 17 for additional information.
(3)See Note 9 for additional information.
9.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, 2021, 2020 and 2019:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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, 2021 | | December 31, 2020 | | December 31, 2019 | | | | | | |
| | $ | | $ | | $ | | | | | | |
| Gross Carrying Amount | | | | | | | | | | | | |
| Opening balance at beginning of year | | 51,067 | | | 75,104 | | | 20,200 | | | | | | | |
| Additions (cash and non-cash) | | 4,190 | | | 757 | | | 56,854 | | | | | | | |
| Dispositions | | — | | | (24,794) | | | (1,950) | | | | | | | |
| Closing balance at end of year | | 55,257 | | | 51,067 | | | 75,104 | | | | | | | |
| Accumulated Depreciation | | | | | | | | | | | | |
| Opening balance at beginning of year | | (15,754) | | | (7,085) | | | — | | | | | | | |
| Depreciation expense | | (14,117) | | | (18,389) | | | (13,369) | | | | | | | |
| Dispositions | | — | | | 9,720 | | | 6,284 | | | | | | | |
| Closing balance at end of year | | (29,871) | | | (15,754) | | | (7,085) | | | | | | | |
| Net book value | | 25,386 | | | 35,313 | | | 68,019 | | | | | | | |
As at December 31, 2021 and 2020, the Partnership's right-of-use assets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | As at December 31, 2021 |
| December 31, 2021 | | December 31, 2020 | | Weighted-average remaining lease term | | Weighted-average implicit interest rate |
| $ | | $ | | (years) | | (%) |
| Vessels and equipment | 10,956 | | | 21,971 | | | 1.0 | | 3.3% |
| Office leases | 14,430 | | | 13,342 | | | 4.7 | | 5.2% |
| Total | 25,386 | | | 35,313 | | | | | |
Lease related items for which the Partnership was a lessee for the years ended December 31, 2021, December 31, 2020 and December 31, 2019, were as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Year Ended December 31, | | |
| 2021 | | 2020 | | 2019 | | | | |
| $ | | $ | | $ | | | | |
| Amounts recognized in profit and loss | | | | | | | | | |
| Depreciation expense on right-of-use vessels and equipment | 11,015 | | | 15,899 | | | 10,616 | | | | | |
| Depreciation expense on right-of-use office leases | 3,102 | | | 2,490 | | | 2,753 | | | | | |
| Interest expense on lease liabilities | 1,291 | | | 2,679 | | | 1,507 | | | | | |
| Short-term lease expense | 2,713 | | | 4,314 | | | 15,965 | | | | | |
| 18,121 | | | 25,382 | | | 30,841 | | | | | |
As at December 31, 2021, 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 | | 27.0 | | | 15.1 | | | 3.3 | | | 3.2 | | | 2.7 | | | 1.7 | | | 1.0 | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
10.Vessels and Equipment
| | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 | |
| $ | | $ | | $ | |
| Gross carrying amount: | | | | | | |
| Opening balance at beginning of year | 4,025,498 | | | 3,531,827 | | | 3,548,501 | | |
Additions(1) | 30,185 | | | 41,346 | | | 32,895 | | |
Dispositions(2) | (85,424) | | | (29,242) | | | (13,869) | | |
| Transferred from advances on newbuilding contracts | 253,301 | | | 543,131 | | | — | | |
Vessels and equipment reclassified as held for sale(3) | (148,600) | | | (61,564) | | | (35,700) | | |
| Closing balance at end of year | 4,074,960 | | | 4,025,498 | | | 3,531,827 | | |
| Accumulated Depreciation and Impairment: | | | | | | |
| Opening balance at beginning of year | (996,083) | | | (506,111) | | | — | | |
Depreciation and amortization(4) | (296,380) | | | (295,610) | | | (339,981) | | |
Impairment expense, net(5) | (108,092) | | | (245,396) | | | (179,759) | | |
Dispositions(2) | 60,518 | | | 15,050 | | | 1,244 | | |
Vessels and equipment reclassified as held for sale(3) | 134,472 | | | 35,984 | | | 12,385 | | |
| Closing balance at end of year | (1,205,565) | | | (996,083) | | | (506,111) | | |
| Net book value | 2,869,395 | | | 3,029,415 | | | 3,025,716 | | |
(1)Additions by segment for the year ended December 31, 2021 is as follows: FPSO $nil, Shuttle Tanker $24.8 million, UMS $0.9 million and Towage $4.5 million (December 31, 2020 - 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 6 for additional information.
(4)Excludes depreciation and amortization on the Partnership's right-of-use assets. See Note 9 for additional details.
(5)See below for additional information. Excludes impairment expense on vessels and equipment classified as held for sale during the years ended December 31, 2021, 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 11 for additional information).
Impairment expense, net
The following tables contains a summary of Partnership’s impairment expense, net for the years ended December 31, 2021, 2020 and 2019, by vessel and by segment:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 2021 | | Petrojarl Varg | | FPSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 8,328 | |
| Q4 2021 | | Voyageur Spirit | | FPSO | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 73,447 | |
| Q4 2021 | | Piranema Spirit | | FPSO | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 34,645 | |
| Impairment expense, net for the year ended December 31, 2021 | | 116,420 | |
| Q4 2020 | | Randgrid | | FSO | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 45,444 | |
| Q4 2020 | | Petrojarl Varg | | FPSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 30,506 | |
Q4 2020(1) | | Navion Oslo | | Shuttle Tanker | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 7,665 | |
Q3 2020(2) | | Apollo Spirit | | FSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 1,620 | |
Q3 2020(1) | | Navion Anglia | | Shuttle Tanker | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 3,100 | |
Q2 2020(1) | | Dampier Spirit | | FSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 6,685 | |
Q2 2020(2) | | Navion Bergen | | Shuttle Tanker | | Sale of the vessel considered highly probable | | 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 | | Value in use using a 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 | | Value in use using a discounted cash flow valuation | | 42,367 | |
| Q1 2020 | | Petrojarl Varg | | FPSO | | Change in future redeployment assumptions | | Level 3 | | Value in use using a discounted cash flow valuation | | 27,202 | |
| Q1 2020 | | Petrojarl Knarr | | FPSO | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 56,599 | |
| Q1 2020 | | Navion Stavanger | | Shuttle Tanker | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 3,606 | |
| Q1 2020 | | Navion Gothenburg | | Shuttle Tanker | | Change in future redeployment assumptions | | Level 3 | | Value in use using a discounted cash flow valuation | | 16,772 | |
Q1 2020(2) | | Navion Bergen | | Shuttle Tanker | | Sale of the vessel considered highly probable | | 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 | | Value in use using a discounted cash flow valuation | | 24,220 | |
| Q4 2019 | | Voyageur Spirit | | FPSO | | Change in future redeployment assumptions | | Level 3 | | Value in use using a discounted cash flow valuation | | 97,752 | |
Q4 2019(2)(3) | | Petrojarl Cidade de Rio das Ostras | | FPSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 4,382 | |
Q3 2019(2)(3) | | Stena Sirita | | Shuttle Tanker | | Sale of the vessel considered highly probable | | 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 | | Value in use using a discounted cash flow valuation | | 11,487 | |
| Q2 2019 | | Petrojarl Varg | | FPSO | | Change in future redeployment assumptions | | Level 3 | | Value in use using a discounted cash flow valuation | | 33,991 | |
| Q2 2019 | | Navion Gothenburg | | Shuttle Tanker | | Significant repairs required to continue operations | | Level 3 | | Value in use using a discounted cash flow valuation | | 12,304 | |
Q2 2019(2)(3) | | Petrojarl Cidade de Rio das Ostras | | FPSO | | Sale of the vessel considered highly probable | | Level 2 | | Fair value less cost to sell using an appraised valuation | | 506 | |
Q2 2019(2)(3) | | Navion Hispania | | Shuttle Tanker | | Sale of the vessel considered highly probable | | 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(3)Vessels and equipment were classified as held for sale as at December 31, 2019.
The fair value of vessels and equipment measured on a non-recurring basis was $38.9 million and $140.5 million as at December 31, 2021 and 2020, respectively.
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
(%) | | Sensitivity Analysis - Increase in impairment expense due to 0.5% increase in discount rate
(in million USD) |
| | | | | | | | | | | | |
| Q4 2021 | | Voyageur Spirit | | FPSO | | 2 - 13 | | 2.50 - 3.00 | | 9.01 | | 1.0 |
| Q4 2021 | | Piranema Spirit | | FPSO | | 1 - 13.5 | | 2.50 - 3.00 | | 9.01 | | 0.3 |
| Q4 2020 | | Randgrid | | FSO | | 2.8 - 11.8 | | 2.00 - 3.50 | | 8.86 | | 2.0 |
| Q1 2020 | | ALP Forward | | Towage | | 13 | | 3.00 | | 10.50 | | 0.3 |
| Q1 2020 | | ALP Winger | | Towage | | 12 | | 3.00 | | 10.50 | | 0.2 |
| Q1 2020 | | ALP Ippon | | Towage | | 12 | | 3.00 | | 10.50 | | 0.2 |
| Q1 2020 | | ALP Ace | | Towage | | 11.3 | | 3.00 | | 10.50 | | 0.2 |
| Q1 2020 | | Petrojarl I | | FPSO | | 3.1 - 5.1 | | 3.00 | | 10.13 | | 1.2 |
| Q1 2020 | | Petrojarl Varg | | FPSO | | 1.3 - 9.8 | | 1.00 - 2.50 | | 10.13 | | 1.0 |
| Q1 2020 | | Petrojarl Knarr | | FPSO | | 12.4 - 15.4 | | 3.00 | | 10.13 | | 15.4 |
| Q1 2020 | | Navion Stavanger | | Shuttle Tanker | | 3.3 | | 2.60 - 3.50 | | 8.25 | | 0.2 |
| Q1 2020 | | Navion Gothenburg | | Shuttle Tanker | | 5.9 | | 2.50 | | 8.25 | | 0.4 |
| Q4 2019 | | Arendal Spirit | | UMS | | 1.2 - 25.1 | | 1.60 - 2.50 | | 9.60 | | 2.3 |
| Q4 2019 | | Voyageur Spirit | | FPSO | | 15.8 - 19.8 | | 3.00 | | 9.60 | | 4.3 |
| Q2 2019 | | Arendal Spirit | | UMS | | 25.6 | | 1.60 - 2.50 | | 11.00 | | 4.7 |
| Q2 2019 | | Petrojarl Varg | | FPSO | | 13 | | 1.00 - 2.50 | | 10.00 | | 7.1 |
| Q2 2019 | | Navion Gothenburg | | Shuttle Tanker | | 6.5 - 6.7 | | 2.00 | | 8.00 | | 0.7 |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
(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.
For the units within the FPSO, FSO and UMS segments, there are uncertainties in the assumptions for redeployments where there is no signed contract in place. When estimating the recoverable amount, the Partnership makes assumptions for the uncontracted cash flows over the useful life for each unit. These are estimated based on the Partnership's market knowledge, experience and return on invested capital. These assumptions are used to create scenarios with different cash flows for each unit. Based on the attractiveness of the various assets, the assumptions can include extensions on current contracts, new contracts, sale or a recycling option. The recoverable amount is a weighted average of all the scenarios.
As at December 31, 2021, due to uncertainty in the redeployment market for FPSO, FSO and UMS units and short remaining contract lengths, the Partnership identified impairment triggers for all of its FPSO fleet, one of its FSO units, and its one UMS unit. The asset values of the Voyageur Spirit FPSO and the Piranema Spirit FPSO were impaired as at December 31, 2021. For the remaining FPSO units, one FSO unit, and one UMS unit, the tests did not result in a recoverable value lower than the carrying value and were therefore not impaired.
The Partnership's impairment tests are sensitive to changes in key assumptions such as discount rate, assumed contract rates and the weight applied to the various scenarios. For the remaining FPSO units, one FSO unit, and one UMS unit for-which the impairment tests as at December 31, 2021 did not result in an impairment:
•An increase of 0.5% for the discount rate would result in an impairment of $21.2 million.
•An additional one-year before redeployment of the units in the weighted scenarios would result in an impairment of $66.7 million.
•A 10% reduction in rate/sales proceeds from the weighted scenarios on the same units would result in an impairment of $52.3 million.
As at December 31, 2021, the Partnership had 4 vessels and equipment, with a carrying value of $103.1 million, which were in lay-up (1 of which was classified as held for sale - $5.8 million) (December 31, 2020 - 5 vessels and equipment with a carrying value of $190.2 million (2 of which were classified as held for sale - $4.4 million)). See Note 6 for additional information.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
11.Advances on Newbuilding Contracts | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Opening balance at beginning of year | 127,335 | | | 297,100 | |
| Additions | 176,964 | | | 368,588 | |
| Capitalized borrowing costs | 920 | | | 4,778 | |
| Transferred to vessels and equipment | (253,301) | | | (543,131) | |
| Closing balance at end of year | 51,918 | | | 127,335 | |
Since 2017, the Partnership has entered into shipbuilding contracts for the construction of 7 shuttle tanker newbuildings for an estimated fully built up cost of $965.6 million. As at December 31, 2021, 6 of these vessels had been delivered to the Partnership and the remaining vessel is expected to be delivered in 2022. As at December 31, 2021, gross payments made towards these commitments were $891.7 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 18 and 19 for additional information).
As at December 31, 2021, 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(1) | | 74.0 | | | 74.0 | | | — | | | — | | | — | | | — | | | — | |
(1)The Partnership secured $105.6 million of borrowings relating to this shuttle tanker newbuilding, which as at December 31, 2021 had an undrawn balance of $63.4 million (see Note 19 for additional information).
As at December 31, 2021, the contractual maturities of the Partnership's obligations relating to the 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 leases | | 201.7 | | | 11.3 | | | 11.3 | | | 11.3 | | | 11.3 | | | 11.3 | | | 145.2 | |
As at December 31, 2021, the Partnership had leases secured by 2 vessels (December 31, 2020 - 2 vessels) with a combined carrying value of $240.6 million (December 31, 2020 - $101.9 million).
12.Equity Accounted Investments
The Partnership has investments in 2 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, 2021 had an outstanding balance of $471.8 million (December 31, 2020 - $529.1 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 $430.8 million as at December 31, 2021 (December 31, 2020 - $483.5 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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'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, 2021 had an outstanding balance of $14.4 million (December 31, 2020 - $53.4 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, 2021, the joint venture held no interest rate swap agreements (December 31, 2020 - the joint venture held no interest rate swap agreements).
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, 2021 and 2020, the Partnership had total investments of $237.5 million and $241.7 million, respectively, in its equity-accounted investments.
During the year ended December 31, 2021, the Partnership's equity in earnings in the joint venture includes an impairment expense of $36.1 million recognized within the Partnership's Itajai Joint Venture on the Cidade de Itajai FPSO. There were no indicators of impairment nor were there any impairments recorded as at December 31, 2020, within either of the Partnership's two joint ventures.
The following table summarizes the impairment expense within the Partnership's Itajai Joint Venture:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Vessel | | Segment | | Event | | Fair Value Hierarchical Level | | Valuation Techniques and Key Inputs | | Impairment Expense
$ |
| Q4 2021 | | Cidade de Itajai | | FPSO | | Change in expected earnings of the vessel | | Level 3 | | Value in use using a discounted cash flow valuation | | 36,096 | |
The following table summarizes the significant unobservable inputs used in the Level 3 fair value measurement of the principle asset within the Itajai Joint Venture:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Vessel | | Segment | | Period of Projected Cash Flows
(years) | | Growth Rate(1) (%) | | Discount Rate
(%) | | Sensitivity Analysis - Increase in impairment expense due to 0.5% increase in discount rate
(in million USD) |
| | | | | | | | | | | | |
| Q4 2021 | | Cidade de Itajai | | FPSO | | 6.1 - 11.1 | | 1.50 -14.50 | | 9.01 | | 2.0 |
(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.
The following tables presents summarized financial information assuming a 100% ownership interest in the Partnership’s equity-accounted investments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 | | December 31, 2020 |
| Libra Joint Venture | | Itajai Joint Venture | | Total | | Libra Joint Venture | | Itajai Joint Venture | | Total |
| $ | | $ | | $ | | $ | | $ | | $ |
| Current assets | 119,700 | | | 31,210 | | | 150,910 | | | 123,576 | | | 29,605 | | | 153,181 | |
| Non-current assets | 719,339 | | | 191,680 | | | 911,019 | | | 765,239 | | | 278,113 | | | 1,043,352 | |
| Current liabilities | 82,515 | | | 21,489 | | | 104,004 | | | 83,028 | | | 43,681 | | | 126,709 | |
| Non-current liabilities | 482,986 | | | 1 | | | 482,987 | | | 567,474 | | | 18,888 | | | 586,362 | |
| Net assets | 273,538 | | | 201,400 | | | 474,938 | | | 238,313 | | | 245,149 | | | 483,462 | |
| Ownership interest | 50% | | 50% | | 50% | | 50% | | 50% | | 50% |
| Equity-accounted investments | 136,769 | | | 100,700 | | | 237,469 | | | 119,157 | | | 122,575 | | | 241,731 | |
| Cash and cash equivalents | 9,311 | | | 6,717 | | | 16,028 | | | 8,450 | | | 10,396 | | | 18,846 | |
Current financial liabilities(1) | 64,146 | | | 15,297 | | | 79,443 | | | 66,223 | | | 35,533 | | | 101,756 | |
Non-current financial liabilities(1) | 420,414 | | | — | | | 420,414 | | | 495,861 | | | 18,546 | | | 514,407 | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(1)Excludes provisions, trade and other payables.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31, | | Year ended December 31, | | Year ended December 31, | | | | | | |
| 2021 | | 2021 | | 2021 | | 2020 | | 2020 | | 2020 | | 2019 | | 2019 | | 2019 | | | | | | |
| | Libra Joint Venture | | Itajai Joint Venture | | Total | | Libra Joint Venture | | Itajai Joint Venture | | Total | | Libra Joint Venture | | Itajai Joint Venture | | Total | | | | | | |
| $ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | | | | | | |
| Revenues | 180,796 | | | 82,754 | | | 263,550 | | | 181,734 | | | 82,170 | | | 263,904 | | | 181,172 | | | 84,275 | | | 265,447 | | | | | | | |
| Depreciation and amortization | (44,099) | | | (19,109) | | | (63,208) | | | (48,408) | | | (16,419) | | | (64,827) | | | (47,282) | | | (16,371) | | | (63,653) | | | | | | | |
| Interest expense | (15,234) | | | (1,595) | | | (16,829) | | | (20,493) | | | (8,373) | | | (28,866) | | | (34,798) | | | (6,938) | | | (41,736) | | | | | | | |
| Interest income | 199 | | | 1,219 | | | 1,418 | | | 83 | | | 170 | | | 253 | | | 203 | | | — | | | 203 | | | | | | | |
| Income tax (expense) benefit | (612) | | | (356) | | | (968) | | | (100) | | | (534) | | | (634) | | | (166) | | | (330) | | | (496) | | | | | | | |
| Net income (loss) and other comprehensive income (loss) | 90,046 | | | (39,922) | | | 50,124 | | | 43,882 | | | 27,960 | | | 71,842 | | | 34,686 | | | 32,850 | | | 67,536 | | | | | | | |
| Ownership interest | 50% | | 50% | | 50% | | 50% | | 50% | | 50% | | 50% | | 50% | | 50% | | | | | | |
| Equity-accounted income (loss) | 45,023 | | | (19,961) | | | 25,062 | | | 21,941 | | | 13,980 | | | 35,921 | | | 17,343 | | | 16,425 | | | 33,768 | | | | | | | |
| Dividends received by the Partnership | 29,055 | | | 4,373 | | | 33,428 | | | 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.
13.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, 2021 and 2020. The Partnership conducted its annual goodwill impairment evaluation during 2021 and 2020, 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.
| | | | | | | | | | | |
| 2021 | | 2020 |
| Discount rate | 7.29% | | 6.73% |
| Exit multiple | 8.0 | | 8.0 |
Discount rate
The discount rate is a post-tax measure, with a possible debt leveraging of 70% for 2021 (2020 - 70%) estimated based on the observed leveraging within the industry and the long-term target leverage of the Partnership, at market interest rates of 4.2% for 2021 (2020 - 3.9%).
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.
| | | | | | | | | | | |
| 2021 | | 2020 |
| Discount rate | 3.98% | | 3.23% |
| Exit multiple | (1.6) | | (1.7) |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
14.Accounts Payable and Other | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Current | | | |
| Accounts payable | 36,954 | | | 46,022 | |
Accrued liabilities(1) | 132,797 | | | 127,541 | |
Provisions(4) | 9,598 | | | 7,522 | |
Deferred revenues(2) | 55,617 | | | 91,392 | |
Lease liabilities(3) | 14,331 | | | 13,818 | |
| | | |
| Total current | 249,297 | | | 286,295 | |
| Non-current | | | |
Deferred revenues(2) | 358 | | | 11,616 | |
Lease liabilities(3) | 11,129 | | | 22,010 | |
Provisions(4) | 3,404 | | | 60,179 | |
Decommissioning liability(5) | 33,309 | | | 33,901 | |
| Other | 1,053 | | | 965 | |
| Total non-current | 49,253 | | | 128,671 | |
(1)See Note 15 for additional information.
(2)See Note 17 for additional information.
(3)See Notes 9 and 27 for additional information.
(4)See Note 16 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, 2021 was determined using a risk-free rate between 0.6% and 1.0% (December 31, 2020 - 0.3% and 0.4%) and an inflation rate of 2.5% (December 31, 2020 - 2.5%).
15.Accrued Liabilities
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Interest including interest rate swaps | 27,554 | | | 34,595 | |
| Payroll and benefits | 40,020 | | | 44,167 | |
| Audit, legal and other general expenses | 16,446 | | | 16,383 | |
| Voyage and vessel expenses | 46,139 | | | 31,107 | |
| Income and other tax payable | 2,638 | | | 1,289 | |
| 132,797 | | | 127,541 | |
16.Provisions and Contingencies | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Opening balance at beginning of year | 67,701 | | | 67,906 | |
| Additional provisions recognized | 152 | | | 12,033 | |
| Reduction arising from payments / derecognition | (54,851) | | | (12,238) | |
| Closing balance at end of year | 13,002 | | | 67,701 | |
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, 2021, approximately $4.7 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 3 UMS newbuildings ordered from the COSCO (Nantong) Shipyard (or COSCO) in China. The Partnership took delivery of 1 of the UMS newbuildings, the Arendal Spirit UMS, in February 2015.
In June 2016, the Partnership canceled the UMS construction contracts for the 2 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. 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 original estimate of the potential damages for the cancellation of the Stavanger Spirit newbuilding contract was 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 in 2016, the value of this vessel, and thus ultimately the amount of potential damages that may result from the cancellation, is uncertain.
The Partnership's original estimate of potential damages for the cancellation of the Nantong Spirit newbuilding contract was 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. 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, 2021, pursuant to the level of maturity in settlement discussions held with COSCO, the Partnership has released $49.3 million of accrued provisions relating to these claims. As at December 31, 2021, the Partnership's subsidiaries have accrued $8.3 million in the aggregate related to the above COSCO claims related to Logitel.
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 22 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.
On October 29, 2020, one of the lead plaintiffs filed, unsolicited, a notice of voluntary dismissal, effectively withdrawing its particular claim. On March 25, 2021, the court awarded a dismissal against all parties, with the exception of the Partnership. The case isl now proceeding to trial. The Partnership intends to proceed with an application for summary judgment, which will not occur until the fourth quarter of 2022 at the earliest.
17.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, 2021 | | December 31, 2020 |
| $ | | $ |
| Contract assets | | | |
| Current | 24,916 | | | 18,958 | |
| Non-current | 37,597 | | | 48,288 | |
| 62,513 | | | 67,246 | |
| Contract liabilities | | | |
| Current | 55,617 | | | 91,392 | |
| Non-current | 358 | | | 11,616 | |
| 55,975 | | | 103,008 | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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, 2021, the Partnership recognized revenue of $85.6 million, which was included in contract liabilities on December 31, 2020.
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, 2021, 2020 and 2019 were $19.3 million, $21.4 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, 2021 | | December 31, 2020 |
| $ | | $ |
| Pre-operational costs | 2,803 | | | 7,750 | |
| Offshore asset mobilization costs | 8,978 | | | 21,509 | |
| Vessel repositioning costs | 10,583 | | | 11,565 | |
| 22,364 | | | 40,824 | |
18.Other Financial Liabilities
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Current | | | |
| Derivative instruments | 23,688 | | | 189,647 | |
Obligations relating to leases(1) | 10,991 | | | 8,839 | |
| Other | — | | | 499 | |
| Total current | 34,679 | | | 198,985 | |
| Non-current | | | |
| Derivative instruments | 541 | | | 13,950 | |
Obligations relating to leases(1) | 188,117 | | | 130,400 | |
| Total non-current | 188,658 | | | 144,350 | |
(1)See Notes 11 and 27 for additional information. The financing liability accrued interest at a fixed rate of 5.5% until the related newbuilding vessels were delivered to the Partnership during the first quarter of 2021, after which they accrue interest at a variable rate of LIBOR plus 2.85%.
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 to manage certain of these risks.
The aggregate amount of the Partnership's derivative financial instrument positions is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| Financial Asset | | Financial Liability | | Financial Asset | | Financial Liability |
| $ | | $ | | $ | | $ |
| Interest rate swaps | — | | | 23,470 | | | — | | | 203,597 | |
| Foreign currency forward contracts | 325 | | | 758 | | | 6,497 | | | — | |
| | | | | | | |
| | | | | | | |
| Total | 325 | | | 24,228 | | | 6,497 | | | 203,597 | |
| Total current | 325 | | | 23,688 | | | 6,497 | | | 189,647 | |
| Total non-current | — | | | 541 | | | — | | | 13,950 | |
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, 2021, 2020 and 2019 as hedges of variable rate debt. Certain of the Partnership's interest rate swaps are secured by vessels.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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, 2021, 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)(5) | LIBOR | | 152,903 | | | (6,715) | | | 0.55 | | 2.6 | % |
U.S. Dollar-denominated interest rate swaps(6)(7)(8) | LIBOR | | 388,745 | | | (16,755) | | | 0.75 | | 2.5 | % |
| | | | | | | | | |
| | | 541,648 | | | (23,470) | | | | | |
(1)Excludes accrued interest of $1.8 million.
(2)Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2021, ranged between 1.1% and 6.5%.
(3)Notional amount remains constant over the term of the swap, unless the swap is partially terminated.
(4)Includes 1 interest rate swap, which as at December 31, 2021, had a total current notional amount of $100.0 million and a total fair value liability of $1.3 million. This interest rate swap is due to terminate in the third quarter of 2022.
(5)Includes 1 interest rate swap, which as at December 31, 2021, had a total current notional amount of $52.9 million and a total fair value liability of $5.9 million. This interest rate swap includes mandatory termination provisions which terminate this interest rate swap in the first quarter of 2022.
(6)Principal amount reduces quarterly or semi-annually.
(7)Includes 1 interest rate swap, which as at December 31, 2021, had a total current notional amount of $78.0 million and a total fair value liability of $11.2 million. This interest rate swap includes mandatory termination provisions which terminate this interest rate swap in the first quarter of 2022.
(8)Includes 3 interest rate swaps, which as at December 31, 2021, had a total current notional amount of $285.3 million and a total fair value liability of $6.0 million. These interest rate swaps include mandatory termination provisions which terminate these interest rate swaps in the second quarter of 2022.
During the year ended December 31, 2021, 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, 2020 - gain of $0.8 million, December 31, 2019 - gain of $0.7 million).
As at December 31, 2021, the Partnership had multiple interest rate swaps and foreign currency forward contracts governed by certain master agreements. 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, 2021, these derivatives had an aggregate fair value asset amount of $0.3 million and an aggregate fair value liability amount of $0.8 million (December 31, 2020 - an aggregate fair value asset amount of $6.5 million and an aggregate fair value liability amount of $147.5 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, 2021, 2020 and 2019 as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
| Realized gain (loss) on derivative instruments | | | | | |
| | | | | |
| Interest rate swaps | (164,216) | | | (59,143) | | | (29,185) | |
| Foreign currency forward contracts | 6,753 | | | (1,310) | | | (5,054) | |
| (157,463) | | | (60,453) | | | (34,239) | |
| Unrealized gain (loss) on derivative instruments | | | | | |
| Interest rate swaps | 180,127 | | | (41,967) | | | (56,182) | |
| Foreign currency forward contracts | (6,932) | | | 5,921 | | | 5,226 | |
Warrants (1) | — | | | — | | | 50,513 | |
| 173,195 | | | (36,046) | | | (443) | |
| Total realized and unrealized gain (loss) on derivative instruments | 15,732 | | | (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.
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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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 22 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 1 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.
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 22 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, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | 541.6 | | | 520.0 | | | 3.8 | | | 3.8 | | | 3.8 | | | 3.8 | | | 6.2 | |
| Foreign currency forward contracts | | 42.0 | | | 42.0 | | | — | | | — | | | — | | | — | | | — | |
| Total | | 583.6 | | | 562.0 | | | 3.8 | | | 3.8 | | | 3.8 | | | 3.8 | | | 6.2 | |
19.Borrowings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | Weighted average term | | Weighted average rate |
| December 31, 2021 | | December 31, 2020 | | December 31, 2021 | | December 31, 2020 | | December 31, 2021 | | December 31, 2020 |
| $ | | $ | | (years) | | (years) | | (%) | | (%) |
| Revolving Credit Facilities | 308,887 | | | 439,600 | | | 2.34 | | 3.07 | | 2.70 | | | 2.81 | |
| Term Loans | 1,282,848 | | | 1,426,370 | | | 4.77 | | 5.51 | | 2.71 | | | 2.69 | |
| Public Bonds | 725,072 | | | 726,826 | | | 2.40 | | 2.57 | | 8.10 | | | 7.53 | |
| Non-Public Bonds | 179,462 | | | 206,870 | | | 4.14 | | 5.04 | | 6.18 | | | 6.13 | |
| Total | 2,496,269 | | | 2,799,666 | | | 3.74 | | 4.33 | | 4.52 | | | 4.22 | |
| Less: deferred financing costs and other | (32,242) | | | (39,949) | | | | | | | | | |
| Total borrowings | 2,464,027 | | | 2,759,717 | | | | | | | | | |
| Less current portion | (407,274) | | | (362,079) | | | | | | | | | |
| Long-term portion | 2,056,753 | | | 2,397,638 | | | | | | | | | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
Revolving Credit Facilities
As at December 31, 2021, the Partnership had 2 revolving credit facilities outstanding secured by 12 vessels (December 31, 2020 - 2 revolving credit facilities outstanding secured by 16 vessels) with a combined carrying value of $566.8 million (December 31, 2020 - $798.0 million), which, as at such date, provided for total borrowings of up to $308.9 million (December 31, 2020 - $439.6 million) and were fully drawn (December 31, 2020 - fully drawn).
Term Loans
As at December 31, 2021, the Partnership had term loans outstanding secured by 23 vessels (December 31, 2020 - secured by 25 vessels) with a combined carrying value of $1.9 billion (December 31, 2020 - $2.1 billion), which, as at such date, provided for total borrowings of $1.3 billion (December 31, 2020 - $1.4 billion). The term loans reduce over time with quarterly or semi-annual payments and have varying maturities through 2034.
In February 2021, the Partnership refinanced an existing term loan relating to the financing of the Petrojarl I FPSO unit. 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.
Public and Non-Public Bonds
As at December 31, 2021, the Partnership had public bonds outstanding which totaled $725.1 million (December 31, 2020 - $726.8 million). The public bonds have varying maturities through 2025.
As at December 31, 2021, the Partnership had non-public bonds outstanding secured by 2 vessels (December 31, 2020 - secured by 2 vessels), with a combined carrying value of $156.9 million (December 31, 2020 - $168.7 million), which, as at such date provided for total borrowings of $179.5 million (December 31, 2020 - $206.9 million). The non-public bonds reduce over time with semi-annual payments and varying maturities through 2027.
In August 2021, a subsidiary of the Partnership entered into an agreement with Brookfield, which involved, among other things, the exchange of $411.3 million in aggregate principal amount of the Partnership's 8.50% Senior Notes due 2023 (or the 8.5% Senior Notes) for newly issued 11.50% Senior Secured PIK Notes due August 2026 of Holdco (or the 11.50% PIK Notes) in an equal aggregate principal amount. See Note 21a for a detailed description of the Brookfield Exchanges.
In December 2021, the Partnership's wholly-owned subsidiary Altera Shuttle Tankers L.L.C. issued $180.0 million in senior unsecured bonds in the Norwegian bond market that mature in December 2025. These bonds will be listed on the Oslo Stock Exchange. The interest payments on the bonds are fixed at a rate of 9.50%. The bonds are non-callable for three years and all distributions by Altera Shuttle Tankers L.L.C. have been suspended for the life of the bonds. These bonds were issued at a discount to par value of 3% and the proceeds plus cash on hand were used to repurchase $181.2 million of the Altera Shuttle Tankers LLC's pre-existing 7.125% senior unsecured $250.0 million bond maturing in August 2022.
As at December 31, 2021, 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 | | 1,033.3 | | | 247.3 | | | 223.6 | | | 160.5 | | | 126.6 | | | 90.4 | | | 184.9 | |
| Secured debt - repayments on maturity | | 737.9 | | | 92.0 | | | 274.6 | | | 173.6 | | | — | | | 197.7 | | | — | |
| Bond repayments | | 725.1 | | | 69.4 | | | 275.7 | | | 200.0 | | | 180.0 | | | — | | | — | |
| Total borrowings | | 2,496.3 | | | 408.7 | | | 773.9 | | | 534.1 | | | 306.6 | | | 288.1 | | | 184.9 | |
See Note 21 for information regarding the Partnership's borrowings due to related parties.
In addition to the secured vessels discussed above, the Partnership's loan agreements typically includes customary security provisions including assignment of insurance and earnings, pledged in favor of our lenders. As at December 31, 2021, the Partnership's pledged accounts consisted of $75.6 million in Cash and cash equivalents ($100.1 million - December 31, 2020), $59.7 million in Financial assets (current and non-current) ($48.8 million - December 31, 2020), $118.5 million in Accounts and other receivable, net (current and non-current) ($202.9 million - December 31, 2020) and $136.8 million in Equity-accounted investments ($119.2 million - December 31, 2020). As at December 31, 2021, the Partnership has obtained guarantee arrangements with certain financial institutions which in the event of default provide for $28.6 million of guarantee coverage ($21.6 million - December 31, 2020). The Partnership is currently in compliance with all covenant requirements of its revolving credit facilities, term loans and bonds.
20.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, 2021 and 2020, are as follows:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Tax losses carried forward | — | | | 5,153 | |
| Other timing differences | (700) | | | (700) | |
| Total net deferred tax assets (liabilities) | (700) | | | 4,453 | |
| Reflected in the statement of financial position as follows: | | | |
| Deferred tax assets | — | | | 5,153 | |
| Deferred tax liabilities | 700 | | | 700 | |
| Net deferred tax assets (liabilities) | (700) | | | 4,453 | |
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, 2021 | | December 31, 2020 |
| $ | | $ |
| Opening net deferred tax assets (liabilities) balance at beginning of year | 4,453 | | | 3,867 | |
| Deferred income tax (expense) benefit | (5,006) | | | 804 | |
| Other | (147) | | | (218) | |
| Closing net deferred tax assets (liabilities) balance at end of year | (700) | | | 4,453 | |
The following table details the expiry date, if applicable, of the unrecognized deferred tax assets:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| One year from reporting date | — | | | 92 | |
| Two years from reporting date | — | | | 122 | |
| Three years from reporting date | — | | | 162 | |
| After three years from reporting date | 103,579 | | | 108,788 | |
| Do not expire | 188,771 | | | 153,573 | |
| Total | 292,350 | | | 262,737 | |
The major components of income tax expense for the years ended December 31, 2021, 2020 and 2019 are as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended
December 31,
2021
$ | | Year Ended
December 31,
2020
$ | | Year Ended
December 31,
2019
$ |
| Current income tax (expense) benefit | (4,603) | | | (6,543) | | | (4,666) | |
| Deferred income tax (expense) benefit: | | | | | |
| Origination and reversal of temporary differences | 193,486 | | | 2,889 | | | (1,035) | |
| Benefit (expense) arising from previously unrecognized (derecognized) tax assets | (198,492) | | | (2,085) | | | (2,126) | |
| Total deferred income taxes | (5,006) | | | 804 | | | (3,161) | |
| Income tax (expense) benefit | (9,609) | | | (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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
prepared using a composite statutory-rate for jurisdictions where the Partnership’s subsidiaries operate:
| | | | | | | | | | | | | | | | | |
| Year Ended
December 31,
2021
$ | | Year Ended
December 31,
2020
$ | | Year Ended
December 31,
2019
$ |
| Income (loss) before income tax (expense) benefit | (126,841) | | | (340,424) | | | (151,240) | |
| Net income (loss) not subject to taxes | (6,194) | | | (155,010) | | | (194,675) | |
| Net income (loss) subject to taxes | (120,647) | | | (185,414) | | | 43,435 | |
| Applicable statutory tax rate | 14% | | 1% | | 11% |
| Net income (loss) subject to taxes at applicable statutory tax rates | (16,801) | | | (1,222) | | | 4,885 | |
| Permanent differences | (29,345) | | | 2,219 | | | (1,976) | |
| Adjustments related to currency differences | 147 | | | 172 | | | (360) | |
| Derecognition of deferred tax assets and other | 55,608 | | | 4,570 | | | 5,278 | |
| Tax expense (benefit) related to current year | 9,609 | | | 5,739 | | | 7,827 | |
The unrecognized tax benefits movements are as follows:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Opening unrecognized tax benefits balance at beginning of year | 262,737 | | | 232,186 | |
| | | |
| Increases for positions related to the current year | 29,613 | | | 30,551 | |
| | | |
| Closing unrecognized tax benefits balance at end of year | 292,350 | | | 262,737 | |
21.Related Party Transactions
The key management personnel that are principally responsible for the operations of the Partnership are as follows:
| | | | | | | | |
| 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. |
For the years ended December 31, 2021, 2020 and 2019 the total compensation expenses of these three key management personnel of the Partnership are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Salary
$ | | Bonus
$ | | Pension Benefits
$ | | Other Benefits
$ | | Total Compensation
$ |
| 2021 | 1,585 | | | 1,788 | | | 93 | | | 70 | | | 3,536 | |
| 2020 | 1,317 | | | 1,570 | | | 88 | | | 88 | | | 3,063 | |
| 2019 | 1,218 | | | 595 | | | 81 | | | 146 | | | 2,040 | |
The Partnership is a party to the following transactions with related parties:
a)On August 27, 2021, a wholly owned subsidiary of the Partnership, Altera Infrastructure Holdings L.L.C., as issuer, and the Partnership, as parent guarantor, entered into an agreement to exchange an aggregate of $699.3 million of indebtedness in the Partnership with interest rates ranging from 5.00% to 11.50% and with maturities ranging from 2022 to 2024 (the Brookfield Exchanges). The exchanges included $415.2 million in aggregate principal amount of the 8.50% Senior Notes, $236.9 million in aggregate principal amount of loans relating to an unsecured revolving credit facility provided by Brookfield, which was due to mature in October 2024, $30.0 million in aggregate principal amount of loans relating to an unsecured revolving credit facility provided by Brookfield, which was due to mature in February 2022, and $17.2 million in aggregate principal amount of loans relating to an unsecured revolving credit facility provided by Brookfield, which was due to mature in July 2022, in each case for newly issued 11.50% Senior Secured PIK Notes due August 2026 in an equal aggregate principal amount. As at December 31, 2021, the Partnership has accrued a total of $27.7 million of PIK interest, increasing the principal amount of the 11.50% PIK Notes in an amount equal to the interest. Any outstanding principal balances are due on the maturity date.
On July 2, 2018, the Partnership issued, in a U.S. private placement, a total of $700.0 million senior unsecured bonds due in July 2023. The interest payments on the bonds were fixed at a rate 8.50% (see Note 19 for additional information). Brookfield purchased $500.0 million of these bonds and as at the date of the Brookfield Exchanges, August 27, 2021, Brookfield held $411.3 million of these bonds (December 31, 2020 - $411.3 million). As part of the Brookfield Exchanges, Altera Infrastructure Holdings L.L.C. issued to Brookfield additional 11.50% PIK Notes in an aggregate principal amount equal to the $4.0 million then accrued and unpaid interest under the exchanged 8.50% Senior Notes. Consistent with the Partnership’s new accounting policy election in August 2021, these notes have been retrospectively reclassified from Borrowings (non-current) to Due to related parties (non-current) on the Partnership's consolidated statements of financial position. Please refer to Note 2i for additional information.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
As of August 27, 2021, the date of the Brookfield Exchanges, the Partnership had an undrawn balance of $nil (December 31, 2020 - $nil) relating to an unsecured revolving credit facility provided by Brookfield, which had previously provided for borrowings of up to $225.0 million and matured on October 31, 2024. The interest payments on the facility were based on LIBOR plus a margin of 5.00%. The facility provided the Partnership the option to defer interest payments of up to $25.0 million until maturity. As at August 27, 2021, the Partnership had deferred a total of $11.9 million of interest payments, which deferred interest was exchanged for the issuance to Brookfield as part of the Brookfield Exchanges of additional 11.50% PIK Notes with an aggregate principal amount of $11.9 million. The Partnership had previously determined that, as the interest rate under the revolving credit facility was deemed to be at below market terms, Brookfield was acting in its capacity as an equity owner and the Partnership recorded a $37.1 million decrease in the carrying value of the facility, which was classified as an equity contribution in the Partnership's consolidated statements of changes in equity during the year ended December 31, 2020. As a result of the Brookfield Exchanges, the Partnership determined that the 11.50% PIK Notes were issued at fair value and therefore the then-remaining unamortized discount of $28.0 million was recorded as a loss through Gain (loss) on modification of financial liabilities, net on the Partnership’s consolidated statements of income (loss) during the year ended December 31, 2021.
Prior to the Brookfield Exchanges, during the year ended December 31, 2021, the Partnership entered into an unsecured revolving credit facility provided by Brookfield, which had previously provided for borrowings of up to $30.0 million and as at the date of the Brookfield Exchanges, August 27, 2021, was fully drawn. The interest payments on the facility were based on LIBOR plus a margin of 5.00% and the facility matured in February 2022. Any outstanding principal balances were due on the maturity date. During the year ended December 31, 2021, the Partnership determined that the interest rate under the facility was deemed to be at below market terms and therefore, Brookfield was acting in its capacity as an equity owner. The Partnership recorded a $1.3 million decrease in the carrying value of the facility, which was classified as an equity contribution in the Partnership's consolidated statements of changes in equity during the year ended December 31, 2021. As a result of the Brookfield Exchanges, the Partnership determined that the 11.50% PIK Notes were issued at fair value and therefore the then-remaining unamortized discount of $0.5 million was recorded as a loss through Gain (loss) on modification of financial liabilities, net on the Partnership’s consolidated statements of income (loss) during the year ended December 31, 2021.
Prior to the Brookfield Exchanges, during the year ended December 31, 2021, a subsidiary of the Partnership entered into an unsecured revolving credit facility provided by Brookfield, which had previously provided for borrowings of up to $17.0 million and as at the date of the Brookfield Exchanges, August 27, 2021, was fully drawn. Borrowings under the facility bore interest solely in kind at a rate of 11.50% per annum. The facility had a maturity date of July 2022. Any outstanding principal balances were due on the maturity date. As part of the Brookfield Exchanges, Holdco issued to Brookfield additional 11.50% PIK Notes with an aggregate principal amount of $0.2 million, equal to the then accrued and unpaid interest under the term loan facility.
b)On December 14, 2021, a wholly owned subsidiary of the Partnership, Altera Shuttle Tankers L.L.C., entered into an agreement with Brookfield to issue $70.0 million aggregate principal amount unsecured PIK notes (or the 12.50% PIK Notes), which contemporaneously discharged the then-existing $70.0 million unsecured revolving credit facility which was fully drawn, accrued interest at a rate equal to LIBOR plus a margin of 5.00% and was due to mature in February 2022. Interest under the 12.50% Notes is payable in kind at a fixed rate of 12.50% and the facility matures in June 2026. The 12.50% PIK Notes are to be listed on The International Stock Exchange. Additional 12.50% PIK Notes may only be issued to satisfy the interest payable under the notes. As at December 31, 2021, the Partnership has accrued a total of $0.5 million of PIK interest, increasing the outstanding principal amount of the 12.50% PIK Notes in an amount equal to the interest. Any outstanding principal balances are due on the maturity date.
During the year ended December 31, 2021, the Partnership determined that the interest rate under the $70.0 million revolving credit facility described above was deemed to be at below market terms and therefore, Brookfield was acting in its capacity as an equity owner. The Partnership recorded a $0.6 million decrease in the carrying value of the facility, which was classified as an equity contribution in the Partnership's consolidated statements of changes in equity during the year ended December 31, 2021.
As at December 31, 2021, the contractual maturities of the Partnership's borrowings due to related parties were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total | | 1 Year | | 2 Years | | 3 Years | | 4 Years | | 5 Years | | Thereafter |
| | (in millions of U.S. Dollars) |
| Borrowings due to related parties: | | | | | | | | | | | | | | |
| 11.50% Senior Secured PIK notes | | 727.0 | | | — | | | — | | | — | | | — | | | 727.0 | | | — | |
| 12.50% Unsecured PIK notes | | 70.5 | | | — | | | — | | | — | | | — | | | 70.5 | | | — | |
| Total borrowings due to related parties | | 797.5 | | | — | | | — | | | — | | | — | | | 797.5 | | | — | |
As at December 31, 2021, the Partnership was in compliance with the covenant requirements of these facilities.
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. During the period prior 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
consolidated statements of income (loss) were as follows for the periods indicated:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| 2021
$ | | 2020
$ | | 2019
$ |
Revenues(1) | 9,414 | | | 8,079 | | | 42,628 | |
Direct operating costs(2) | — | | | — | | | (2,535) | |
General and administrative expenses(3) | (1,119) | | | (1,134) | | | (8,811) | |
| Depreciation and amortization | (209) | | | (209) | | | — | |
Interest expense(4)(5)(6) | (69,695) | | | (43,831) | | | (46,101) | |
Realized and unrealized gain (loss) on derivative instruments(7) | — | | | — | | | 49,832 | |
Gain (loss) on modification of financial liabilities, net(8) | (28,517) | | | — | | | (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 $22.8 million for the year ended December 31, 2021 (December 31, 2020 - $35.0 million, December 31, 2019 - $38.5 million), incurred on a portion of five-year senior unsecured bonds held by Brookfield (see Note 21a for additional information).
(5)Includes interest expense of $10.9 million for the year ended December 31, 2021 (December 31, 2020 - $7.3 million, December 31, 2019 - $8.3 million) and a net interest accretion expense of $7.7 million for the year ended December 31, 2021 (December 31, 2020 - a net interest accretion expense of $1.4 million, 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 21a for additional information).
(6)Includes interest expense of $27.7 million incurred on the 11.50% PIK Notes for the year ended December 31, 2021 (December 31, 2020 - $nil, December 31, 2019 - $nil) and interest expense of $0.5 million incurred on the 12.50% PIK Notes for the year ended December 31, 2021 (December 31, 2020 - $nil, December 31, 2019 - $nil). See Notes 21a and b for additional information.
(7)Relates to unrealized gain (loss) on warrants held by Brookfield and Teekay Corporation prior to May 8, 2019 (see Note 18 for additional information).
(8)Relates to a loss on refinancing of an unsecured revolving credit facility provided by Brookfield of $28.5 million during the year ended December 31, 2021 (December 31, 2020 - $nil, December 31, 2019 - $1.9 million). See Note 21a additional information.
As at December 31, 2021, the carrying value of amounts due from related parties totaled $1.0 million (December 31, 2020 - $10.0 million). As at December 31, 2021, the carrying value of amounts due to related parties totaled $797.4 million (December 31, 2020 - $622.0 million) and consisted only of11.50% PIK Notes and 12.50% PIK Notes issued to Brookfield (see Notes 21a and b).
22.Equity
As at December 31, 2021, 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,
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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, 2021, 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, 2021, all of the Partnership’s outstanding 7.25% Series A Cumulative Redeemable Preferred Units (or the Series A Preferred Units), 8.50% Series B Cumulative Redeemable Preferred Units (or the Series B Preferred Units) and 8.875% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (or the Series E Preferred Units and, together with the Series A Preferred Units and the Series B Preferred Units, the 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 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 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 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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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. As at December 31, 2021, the Partnership had additionally repurchased 956 of the Series B Preferred Units at an average price of $21.98 per unit, thus completing the repurchase program.
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, |
| | 2021 | | 2020 | | 2019 |
| Weighted average number of total common units | 411,148,991 | | | 411,148,991 | | | 410,727,035 | |
Preferred Unit Distributions
The distributions payable or paid on the preferred units for the year ended December 31, 2021 were $15.8 million (December 31, 2020 - $32.1 million; December 31, 2019 - $32.2 million), and the amount of cumulative preference dividends that has not been recognized for the year ended December 31, 2021 were $15.8 million (December 31, 2020 - $NaN; December 31, 2019 - $nil).
In July 2021, the Partnership suspended the payment of quarterly cash distributions on its outstanding Preferred Units, commencing with the distributions payable with respect to the period of May 15, 2021 to August 14, 2021. All distributions on the Preferred Units will continue to accrue and must be paid in full before distributions to Class A and Class B common unitholders can be made. No distributions on the Preferred Units will be permitted without noteholder consent while the newly issued 11.50% PIK Notes issued in the Brookfield Exchanges remain outstanding (see Note 21a).
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.
23.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, 2021 and 2020, as well as of revenues, net income, other comprehensive income and distributions for the years ended December 31, 2021, 2020 and 2019:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Current assets | 7,967 | | | 38,902 | |
| Non-current assets | 40,284 | | | 48,960 | |
| Current liabilities | 6,568 | | | 44,109 | |
| | | |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
| Revenues | 22,410 | | | 47,050 | | | 55,655 | |
| Net income (loss) and other comprehensive income (loss) | (10,830) | | | (12,759) | | | (15,106) | |
| | | | | |
| Distributions paid to non-controlling interests | (10,605) | | | (4,750) | | | (3,636) | |
The Partnership's investments in non-wholly owned subsidiaries are in its shuttle tanker and FSO segments. See Note 2d i) for further details.
24.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
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
Partnership's revenues relate to services transferred over a period of time. During the year ended December 31, 2021, the Partnership also generated revenues from the operation of VOC systems on certain of the Partnership’s shuttle tankers, and from the management of two FPSO units (December 31, 2020 - 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, 2021, 2020 and 2019, by contract type and by segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 | FPSO Segment | | Shuttle Tanker Segment | | FSO Segment | | UMS Segment | | Towage Segment | | | | Corporate/Eliminations(1) | | Total |
| Revenues from contracts with customers | | | | | | | | | | | | | | | |
| FPSO contracts | 145,461 | | — | | — | | — | | — | | | | — | | 145,461 |
| CoAs | — | | 85,190 | | — | | — | | — | | | | — | | 85,190 |
| Time charters | — | | 96,196 | | 32,323 | | — | | — | | | | (487) | | 128,032 |
| Bareboat charters | — | | — | | — | | — | | — | | | | — | | — |
| Voyage charters | — | | — | | — | | — | | 79,913 | | | | (8,821) | | 71,092 |
| Management fees and other | 150,274 | | 14,417 | | 1,843 | | 895 | | 221 | | | | 761 | | 168,411 |
| 295,735 | | 195,803 | | 34,166 | | 895 | | 80,134 | | | | (8,547) | | 598,186 |
| Other revenues | | | | | | | | | | | | | | | |
| FPSO contracts | 194,143 | | — | | — | | — | | — | | | | — | | 194,143 |
| CoAs | — | | 121,872 | | — | | — | | — | | | | — | | 121,872 |
| Time charters | — | | 160,767 | | 39,966 | | — | | — | | | | — | | 200,733 |
| Bareboat charters | — | | 9,604 | | 1,273 | | — | | — | | | | — | | 10,877 |
| Voyage charters | — | | 25,449 | | — | | — | | — | | | | — | | 25,449 |
| | | | | | | | | | | | | | | |
| 194,143 | | 317,692 | | 41,239 | | — | | — | | | | — | | 553,074 |
| Total revenues | 489,878 | | 513,495 | | 75,405 | | 895 | | 80,134 | | | | (8,547) | | 1,151,260 |
(1) Includes revenues earned between segments of the Partnership, during the year ended December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2020 | FPSO Segment | | Shuttle Tanker Segment | | FSO Segment | | UMS Segment | | Towage Segment | | | | Corporate/Eliminations(1) | | Total |
| Revenues from contracts with customers | | | | | | | | | | | | | | | |
| FPSO contracts | 156,804 | | — | | — | | — | | — | | | | — | | 156,804 |
| CoAs | — | | 83,676 | | — | | — | | — | | | | — | | 83,676 |
| Time charters | — | | 92,066 | | 25,566 | | — | | — | | | | — | | 117,632 |
| Bareboat charters | — | | — | | — | | — | | — | | | | — | | — |
| Voyage charters | — | | 1,637 | | — | | — | | 45,851 | | | | (5,564) | | 41,924 |
| Management fees and other | 134,019 | | 7,118 | | 4,153 | | 1,828 | | 140 | | | | — | | 147,258 |
| 290,823 | | 184,497 | | 29,719 | | 1,828 | | 45,991 | | | | (5,564) | | 547,294 |
| Other revenues | | | | | | | | | | | | | | | |
| FPSO contracts | 192,474 | | — | | — | | — | | — | | | | — | | 192,474 |
| CoAs | — | | 145,804 | | — | | — | | — | | | | — | | 145,804 |
| Time charters | — | | 152,866 | | 71,052 | | — | | — | | | | — | | 223,918 |
| Bareboat charters | — | | 21,679 | | 13,096 | | — | | — | | | | — | | 34,775 |
| Voyage charters | — | | 37,845 | | — | | — | | — | | | | — | | 37,845 |
| | | | | | | | | | | | | | | |
| 192,474 | | 358,194 | | 84,148 | | — | | — | | | | — | | 634,816 |
| Total revenues | 483,297 | | 542,691 | | 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.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 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 |
| | | | | | | | | | | | | | | |
| 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, 2021, the Partnership recorded finance income of $4.5 million on its investment in finance leases (December 31, 2020 - $3.4 million, December 31, 2019 - $0.4 million).
As at December 31, 2021, the minimum lease payments receivable under the Partnership's finance leases approximated $63.4 million (December 31, 2020 - $76.2 million), including unearned income of $11.8 million (December 31, 2020 - $16.3 million). As at December 31, 2021, 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 | | 63.4 | | | 12.8 | | | 12.1 | | | 11.5 | | | 11.5 | | | 11.5 | | | 4.0 | |
c)Operating leases
As at December 31, 2021, the carrying amount of the Partnership's vessels and equipment subject to operating leases in which the Partnership is a lessor was $2.5 billion (December 31, 2020 - $2.7 billion). As at December 31, 2021, 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 | | 1,827.8 | | | 544.5 | | | 252.2 | | | 174.0 | | | 149.9 | | | 146.6 | | | 560.6 | |
25.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 years ended December 31, 2021, 2020 and
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
2019 by nature:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
Voyage expenses(1) | 133,179 | | | 113,618 | | | 132,556 | |
| Operating expenses | 275,258 | | | 268,999 | | | 229,400 | |
| Charter hire | 10,995 | | | 18,325 | | | 33,202 | |
| Compensation | 235,148 | | | 226,850 | | | 211,533 | |
| Total | 654,580 | | | 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.
26.Segment Information
For the year ended December 31, 2021, the Partnership's operations were organized into 5 (December 31, 2020 - 5, December 31, 2019 - 6, including the Conventional segment) 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; realized gain or loss on foreign currency forward contracts; 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 | FPSO Segment | | Shuttle Tanker Segment | | FSO Segment | | UMS Segment | | Towage Segment | | Corporate/Eliminations(4) | | Total |
| Revenues | 489,878 | | | 513,495 | | | 75,405 | | | 895 | | | 80,134 | | | (8,547) | | | 1,151,260 | |
| Direct operating costs | (279,677) | | | (245,753) | | | (30,292) | | | (3,069) | | | (67,632) | | | (28,157) | | | (654,580) | |
General and administrative(1) | (30,521) | | | (30,180) | | | (4,360) | | | (5,252) | | | (2,346) | | | 31,889 | | | (40,770) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Adjusted EBITDA from equity-accounted investments(2) | 95,880 | | | — | | | — | | | — | | | — | | | — | | | 95,880 | |
| Adjusted EBITDA attributable to non-controlling interests | — | | | 162 | | | 9 | | | — | | | — | | | — | | | 171 | |
| Adjusted EBITDA | 275,560 | | | 237,724 | | | 40,762 | | | (7,426) | | | 10,156 | | | (4,815) | | | 551,961 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2020 | FPSO Segment | | Shuttle Tanker Segment | | FSO Segment | | UMS Segment | | Towage Segment | | Corporate/Eliminations(4) | | Total |
| Revenues | 483,297 | | | 542,691 | | | 113,867 | | | 1,828 | | | 45,991 | | | (5,564) | | | 1,182,110 | |
| Direct operating costs | (266,299) | | | (237,165) | | | (45,448) | | | (5,810) | | | (45,636) | | | (27,434) | | | (627,792) | |
General and administrative(1) | (39,753) | | | (17,942) | | | (8,459) | | | (3,564) | | | (7,640) | | | 32,998 | | | (44,360) | |
| | | | | | | | | | | | | |
| Realized loss on foreign currency forward contracts | — | | | (2,405) | | | — | | | — | | | — | | | 1,095 | | | (1,310) | |
Adjusted EBITDA from equity-accounted investments(2) | 101,352 | | | — | | | — | | | — | | | — | | | — | | | 101,352 | |
| Adjusted EBITDA attributable to non-controlling interests | — | | | (10,988) | | | 311 | | | — | | | — | | | — | | | (10,677) | |
Adjusted EBITDA(3) | 278,597 | | | 274,191 | | | 60,271 | | | (7,546) | | | (7,285) | | | 1,095 | | | 599,323 | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 | | Corporate/Eliminations(4) | | Total |
| Revenues | 477,596 | | | 549,587 | | | 140,117 | | | 2,940 | | | 74,726 | | | 7,972 | | | — | | | 1,252,938 | |
| Direct operating costs | (230,012) | | | (230,946) | | | (40,457) | | | (1,292) | | | (68,013) | | | (9,304) | | | (26,667) | | | (606,691) | |
General and administrative(1) | (44,701) | | | (22,267) | | | (6,946) | | | (6,100) | | | (1,475) | | | (104) | | | 26,666 | | | (54,927) | |
| Realized loss on foreign currency forward contracts | — | | | (2,574) | | | — | | | — | | | — | | | — | | | (2,480) | | | (5,054) | |
Adjusted EBITDA from equity-accounted investments(2) | 98,294 | | | — | | | — | | | — | | | — | | | — | | | — | | | 98,294 | |
| Adjusted EBITDA attributable to non-controlling interests | — | | | (10,861) | | | (500) | | | — | | | — | | | — | | | — | | | (11,361) | |
Adjusted EBITDA(3) | 301,177 | | | 282,939 | | | 92,214 | | | (4,452) | | | 5,238 | | | (1,436) | | | (2,481) | | | 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.
(3)The 2020 and 2019 comparative information has been restated as a result of the Partnership's modification of its cost allocations between its operating segments. The modifications have been deemed to not be material for all operating segments and all periods presented. Refer to Note 2x) for further information.
(4)Includes revenues earned and direct operating costs incurred between segments of the Partnership of $9.2 million and $9.2 million, respectively, for the year ended December 31, 2021 (December 31, 2020 - $5.5 million and $5.6 million, respectively, December 31, 2019 - $nil and $nil, respectively)
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, |
| 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
| Adjusted EBITDA | 551,961 | | | 599,323 | | | 673,199 | |
Depreciation and amortization(1) | (313,120) | | | (316,317) | | | (358,474) | |
Interest expense(2) | (206,176) | | | (192,723) | | | (205,667) | |
| Interest income | 91 | | | 2,770 | | | 5,111 | |
Expenses and gains (losses) relating to equity-accounted investments(3) | (70,818) | | | (65,431) | | | (64,526) | |
Impairment expense, net(4) | (116,420) | | | (268,612) | | | (187,680) | |
Gain (loss) on dispositions, net(5) | 10,502 | | | 3,411 | | | 12,548 | |
Realized and unrealized gain (loss) on derivative instruments(6) | 15,732 | | | (95,189) | | | (29,628) | |
| Foreign currency exchange gain (loss) | (825) | | | (7,861) | | | 2,193 | |
| Gain (loss) on modification of financial liabilities, net | (45,920) | | | — | | | (8,332) | |
| Other income (expenses), net | 48,323 | | | (10,472) | | | (1,345) | |
| Adjusted EBITDA attributable to non-controlling interests | (171) | | | 10,677 | | | 11,361 | |
| | | | | |
| | | | | |
| Income (loss) before income tax (expense) benefit | (126,841) | | | (340,424) | | | (151,240) | |
| Income tax (expense) benefit | | | | | |
| Current | (4,603) | | | (6,543) | | | (4,666) | |
| Deferred | (5,006) | | | 804 | | | (3,161) | |
| Net income (loss) | (136,450) | | | (346,163) | | | (159,067) | |
(1)Depreciation and amortization by segment for the year ended December 31, 2021 is as follows: FPSO $92.2 million, Shuttle Tanker $172.7 million, FSO $25.2 million, UMS $2.3 million and Towage $17.8 million (December 31, 2020 - FPSO $93.7 million, Shuttle Tanker $162.9 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)Interest expense by segment for the year ended December 31, 2021 is as follows: FPSO $24.4 million, Shuttle Tanker $81.6 million, FSO $2.4 million, UMS $0.7 million, Towage $5.2 million and Corporate/Eliminations $91.9 million (December 31, 2020 - FPSO $35.7 million, Shuttle Tanker $71.2 million, FSO $6.7 million, UMS $1.2 million, Towage $7.2 million and Corporate/Eliminations $70.7 million; December 31, 2019 - FPSO $48.1 million, Shuttle Tanker $66.9 million, FSO $8.6 million, UMS $2.2 million, Towage $10.8 million, Corporate/Eliminations $69.1 million).
(3)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) benefit 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).
(4)Impairment expense, net by segment for the year ended December 31, 2021 is as follows: FPSO $116.4 million (December 31, 2020 - FPSO $156.7 million, Shuttle Tanker $35.3 million, FSO $53.7 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 10 for additional information).
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(5)Gain (loss) on dispositions, net by segment for the year ended December 31, 2021 is as follows: Shuttle Tanker $3.6 million and FSO $6.9 million (December 31, 2020 - FPSO $(0.1) million, Shuttle Tanker $(1.9) million and FSO $5.4 million, December 31, 2019 - Shuttle Tanker $1.3 million and FSO $11.2 million). (See Note 7 for additional information).
(6)Excludes the realized loss on foreign currency forward contracts for the years ended December 31, 2020 and December 31, 2019.
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, 2021 and 2020 are as follows:
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| FPSO segment | 963,625 | | | 1,221,316 | |
| Shuttle tanker segment | 2,093,467 | | | 2,115,080 | |
| FSO segment | 198,703 | | | 244,507 | |
| UMS segment | 58,900 | | | 100,254 | |
| Towage segment | 308,621 | | | 303,302 | |
| Conventional tanker segment | — | | | — | |
| Corporate/Other | | | |
| Cash and cash equivalents and restricted cash | 255,756 | | | 369,123 | |
| Other assets | 5,652 | | | 32,049 | |
| | | |
| Total assets | 3,884,724 | | | 4,385,631 | |
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 years ended December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 | FPSO Segment | | Shuttle Tanker Segment | | FSO
Segment | | UMS Segment | | Towage
Segment | | | | Corporate/Eliminations (2) | | Total |
| Revenues from contracts with customers | | | | | | | | | | | | | | | |
Norway(1) | 144,743 | | | 110,809 | | | 23,098 | | | 895 | | | — | | | | | 274 | | | 279,819 | |
Brazil(1) | 40,358 | | | 34,233 | | | — | | | — | | | — | | | | | — | | | 74,591 | |
| Netherlands | — | | | — | | | — | | | — | | | 80,134 | | | | | (8,821) | | | 71,313 | |
| Canada | — | | | 49,150 | | | — | | | — | | | — | | | | | — | | | 49,150 | |
United Kingdom(1) | 110,634 | | | — | | | — | | | — | | | — | | | | | — | | | 110,634 | |
| | | | | | | | | | | | | | | |
| Other | — | | | 1,611 | | | 11,068 | | | — | | | — | | | | | — | | | 12,679 | |
| Total revenues from contracts with customers | 295,735 | | | 195,803 | | | 34,166 | | | 895 | | | 80,134 | | | | | (8,547) | | | 598,186 | |
| Other revenues | | | | | | | | | | | | | | | |
Norway(1) | 153,448 | | | 170,165 | | | 27,276 | | | — | | | — | | | | | — | | | 350,889 | |
Brazil(1) | 36,298 | | | 65,757 | | | — | | | — | | | — | | | | | — | | | 102,055 | |
| | | | | | | | | | | | | | | |
| Canada | — | | | 60,216 | | | — | | | — | | | — | | | | | — | | | 60,216 | |
United Kingdom(1) | 4,397 | | | — | | | — | | | — | | | — | | | | | — | | | 4,397 | |
| | | | | | | | | | | | | | | |
| Other | — | | | 21,554 | | | 13,963 | | | — | | | — | | | | | — | | | 35,517 | |
| Total other revenues | 194,143 | | | 317,692 | | | 41,239 | | | — | | | — | | | | | — | | | 553,074 | |
| Total revenues | 489,878 | | | 513,495 | | | 75,405 | | | 895 | | | 80,134 | | | | | (8,547) | | | 1,151,260 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, United Kingdom and Brazilian continental shelves respectively.
(2) Includes revenues earned between segments of the Partnership, during the year ended December 31, 2021.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 (2) | | Total |
| Revenues from contracts with customers | | | | | | | | | | | | | | | |
Norway(1) | 120,032 | | | 109,413 | | | 17,088 | | | 1,828 | | | — | | | | | — | | | 248,361 | |
Brazil(1) | 48,484 | | | 25,578 | | | — | | | — | | | — | | | | | — | | | 74,062 | |
| Netherlands | — | | | — | | | — | | | — | | | 45,991 | | | | | (5,564) | | | 40,427 | |
| Canada | — | | | 48,097 | | | — | | | — | | | — | | | | | — | | | 48,097 | |
United Kingdom(1) | 122,307 | | | 1,409 | | | — | | | — | | | — | | | | | — | | | 123,716 | |
| Australia | — | | | — | | | 5,157 | | | — | | | — | | | | | — | | | 5,157 | |
| Other | — | | | — | | | 7,474 | | | — | | | — | | | | | — | | | 7,474 | |
| Total revenues from contracts with customers | 290,823 | | | 184,497 | | | 29,719 | | | 1,828 | | | 45,991 | | | | | (5,564) | | | 547,294 | |
| Other revenues | | | | | | | | | | | | | | | |
Norway(1) | 146,938 | | | 178,866 | | | 64,638 | | | — | | | — | | | | | — | | | 390,442 | |
Brazil(1) | 39,750 | | | 76,116 | | | — | | | — | | | — | | | | | — | | | 115,866 | |
| | | | | | | | | | | | | | | |
| Canada | — | | | 62,269 | | | — | | | — | | | — | | | | | — | | | 62,269 | |
United Kingdom(1) | 5,786 | | | 3,098 | | | 5,353 | | | — | | | — | | | | | — | | | 14,237 | |
| Australia | — | | | — | | | 483 | | | — | | | — | | | | | — | | | 483 | |
| Other | — | | | 37,845 | | | 13,674 | | | — | | | — | | | | | — | | | 51,519 | |
| Total other revenues | 192,474 | | | 358,194 | | | 84,148 | | | — | | | — | | | | | — | | | 634,816 | |
| Total revenues | 483,297 | | | 542,691 | | | 113,867 | | | 1,828 | | | 45,991 | | | | | (5,564) | | | 1,182,110 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, United Kingdom and Brazilian continental shelves respectively.
(2) 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 Segment | | | | Total |
| Revenues from contracts with customers | | | | | | | | | | | | | | | |
Norway(1) | 153,483 | | | 124,512 | | | 28,131 | | | 2,940 | | | — | | | — | | | | | 309,066 | |
Brazil(1) | 56,221 | | | 30,907 | | | — | | | — | | | — | | | — | | | | | 87,128 | |
| Netherlands | — | | | — | | | — | | | — | | | 74,726 | | | — | | | | | 74,726 | |
| Canada | — | | | 43,123 | | | — | | | — | | | — | | | — | | | | | 43,123 | |
United Kingdom(1) | 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(1) | 136,186 | | | 156,065 | | | 67,533 | | | — | | | — | | | — | | | | | 359,784 | |
Brazil(1) | 64,903 | | | 86,220 | | | — | | | — | | | — | | | — | | | | | 151,123 | |
| | | | | | | | | | | | | | | |
| Canada | — | | | 54,053 | | | — | | | — | | | — | | | — | | | | | 54,053 | |
United Kingdom(1) | 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 | |
(1)Reference to Norway, the United Kingdom and Brazil are to income from activities occurring on the Norwegian, United Kingdom and Brazilian continental shelves respectively.
For the year ended December 31, 2021, the Partnership recognized $nil of revenues relating to lease income from variable lease payments not dependent on an index or rate (December 31, 2020 - $0.1 million, December 31, 2019 - $1.8 million).
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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 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, 2021 | | Year Ended
December 31, 2020 | | Year Ended
December 31, 2019 |
Royal Dutch Shell Plc (1) | $349.2 or 30% | | $319.4 or 27% | | $311.3 or 25% |
BP Plc (1) | $173.0 or 15% | | $162.1 or 14% | | —(3) |
Equinor ASA (2) | $119.7 or 10% | | $143.3 or 12% | | $170.8 or 14% |
| | | | | |
| | | | | |
(1)Shuttle tanker and FPSO segments.
(2)Shuttle tanker and FSO segments.
(3)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, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | FPSO Segment | | Shuttle Tanker Segment | | FSO
Segment | | UMS Segment | | Towage
Segment | | | | Corporate/Other | | Total |
| Norway | 482,441 | | | 1,171,584 | | | 135,029 | | | 58,368 | | | — | | | | | 8,690 | | | 1,856,112 | |
| Brazil | 367,477 | | | 406,665 | | | — | | | — | | | — | | | | | 1,622 | | | 775,764 | |
| Netherlands | — | | | — | | | — | | | — | | | 277,567 | | | | | — | | | 277,567 | |
| Canada | — | | | 365,608 | | | — | | | — | | | — | | | | | — | | | 365,608 | |
| United Kingdom | 31,204 | | | 38,402 | | | — | | | — | | | — | | | | | — | | | 69,606 | |
| | | | | | | | | | | | | | | |
| Other | — | | | 29,037 | | | 50,446 | | | — | | | — | | | | | — | | | 79,483 | |
Total non-current assets(1) | 881,122 | | | 2,011,296 | | | 185,475 | | | 58,368 | | | 277,567 | | | | | 10,312 | | | 3,424,140 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | FPSO Segment | | Shuttle Tanker Segment | | FSO
Segment | | UMS Segment | | Towage
Segment | | Corporate/Other | | Total |
| Norway | 560,469 | | | 1,145,344 | | | 157,221 | | | 59,806 | | | — | | | — | | | 1,922,840 | |
| Brazil | 443,559 | | | 385,621 | | | — | | | — | | | — | | | — | | | 829,180 | |
| Netherlands | — | | | — | | | — | | | — | | | 288,823 | | | — | | | 288,823 | |
| Canada | — | | | 357,237 | | | — | | | — | | | — | | | — | | | 357,237 | |
| United Kingdom | 111,832 | | | 60,542 | | | — | | | — | | | — | | | — | | | 172,374 | |
| | | | | | | | | | | | | |
| Other | — | | | 32,353 | | | 56,490 | | | — | | | — | | | — | | | 88,843 | |
Total non-current assets(1) | 1,115,860 | | | 1,981,097 | | | 213,711 | | | 59,806 | | | 288,823 | | | — | | | 3,659,297 | |
(1)Excludes financial instruments and deferred tax assets.
27.Supplemental Cash Flow Information | | | | | | | | | | | | | | | | | |
| Year Ended |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| $ | | $ | | $ |
| Interest paid | 163,830 | | | 174,827 | | | 204,074 | |
| Income taxes paid | 3,950 | | | 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, 2021, 2020 and 2019 are as follows:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 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, 2021 | | December 31, 2020 | | December 31, 2019 | | | | |
| $ | | $ | | $ | | | | |
| Accounts and other receivable, net | 95,176 | | | (2,155) | | | (62,287) | | | | | |
| Other assets | (14,225) | | | 7,869 | | | 6,362 | | | | | |
| Accounts payable and other | 13,309 | | | (8,268) | | | 71,736 | | | | | |
| Due from (to) related parties | (6,971) | | | (10,317) | | | (2,470) | | | | | |
| Changes in non-cash working capital, net | 87,289 | | | (12,871) | | | 13,341 | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
The following table presents the change in the balance of borrowings arising from financing activities as at December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| $ | | $ | | $ |
| Opening balance of borrowings at beginning of year | 2,759,717 | | | 2,760,887 | | | 2,622,743 | |
| Cash flows related to borrowings | (310,780) | | | (24,947) | | | 61,336 | |
| Non-cash changes: | | | | | |
| Deferred financing costs amortization | 15,768 | | | 13,943 | | | 15,483 | |
Reclass from related parties(1) | — | | | 12,365 | | | 51,375 | |
| Other | (678) | | | (2,531) | | | 9,950 | |
| Closing balance of borrowings at end of year | 2,464,027 | | | 2,759,717 | | | 2,760,887 | |
(1)Relates to the sale of 8.50% Senior Notes held by Brookfield to non-related parties during the years ended December 31, 2020 and 2019. See Note 2i for additional information.
The following table presents the change in the balance of obligations related to leases arising from financing activities as at December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| $ | | $ | | $ |
| Opening balance of obligations relating to leases at beginning of year | 139,239 | | | 21,544 | | | — | |
| Cash flows related to obligations relating to leases | 59,481 | | | 117,696 | | | 21,547 | |
| Non-cash changes: | | | | | |
| Other | 388 | | | (1) | | | (3) | |
Closing balance of obligations relating to leases at end of year(1) | 199,108 | | | 139,239 | | | 21,544 | |
(1)See Note 18 for additional information.
The following table presents the change in the balance of borrowings from related parties arising from financing activities as at December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| $ | | $ | | $ |
| Opening balance of borrowings from related parties at beginning of year | 622,014 | | | 461,435 | | | 620,075 | |
| Cash flows related to borrowings from related parties | 117,000 | | | 205,000 | | | (105,000) | |
| Non-cash changes: | | | | | |
| Changes in fair value | 26,590 | | | (37,060) | | | 1,949 | |
| Funding working capital requirements | (16,119) | | | (385) | | | (3,571) | |
Other financing costs(1) | 47,791 | | | 5,350 | | | — | |
Reclass to borrowings(2) | — | | | (12,365) | | | (51,375) | |
| Other | 156 | | | 39 | | | (643) | |
| Closing balance of borrowings from related parties at end of year | 797,432 | | | 622,014 | | | 461,435 | |
(1)Includes deferred interest payments, accretion income, and PIK interest on borrowings from related parties.
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(2)Relates to the sale of 8.50% Senior Notes held by Brookfield to non-related parties during the years ended December 31, 2021 and 2019. See Note 2i for additional information.
The following table presents the change in the balance of lease liabilities arising from financing activities as at December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 | | December 31, 2019 |
| $ | | $ | | $ |
| Opening balance of lease liabilities at beginning of year | 35,828 | | | 67,985 | | | 20,201 | |
| Cash flows related to lease liabilities | (14,506) | | | (20,332) | | | (14,695) | |
| Non-cash changes: | | | | | |
| Additions | 4,190 | | | 757 | | | 63,349 | |
| Dispositions | — | | | (15,074) | | | (1,854) | |
| Other | (52) | | | 2,492 | | | 984 | |
Closing balance of lease liabilities at end of year(1) | 25,460 | | | 35,828 | | | 67,985 | |
(1)See Note 14 for additional information.
28.Financial Risk Management
The Partnership recognizes that financial 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.
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| $ | | $ |
| Borrowings | 2,464,027 | | 2,759,717 |
| Obligations relating to leases | 199,108 | | 139,239 |
Due to related parties(1) | 797,432 | | 622,014 |
| Less: | | | |
| Cash and cash equivalents | 190,942 | | 235,734 |
| Restricted cash | 64,815 | | 133,389 |
| Net debt | 3,204,810 | | 3,151,847 |
| Total equity | 100,678 | | 244,899 |
| Total equity and net debt | 3,305,488 | | 3,396,746 |
| Net debt to capitalization ratio | 97% | | 93% |
(1)Includes borrowings from related parties. Refer to Note 19.
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 19, 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 pay scheduled debt repayments, to pay debt service costs, 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 9, 11, 18 and 19. 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, 2022.
c.Market risk
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
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, 2021, the Partnership had outstanding floating-rate debt balance of $1.6 billion (December 31, 2020 - $1.8 billion) and an outstanding notional balance of $0.5 billion (December 31, 2020 - $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 $1.0 million (December 31, 2020 - $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, including borrowings and derivative instruments, please refer to Note 3, which includes the fair values of the interest rate risk sensitive financial instruments, and Notes 18 and 19, 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 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, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of U.S. Dollars) | December 31, 2021 |
| USD | | NOK | | AUD | | GBP | | CAD | | EUR | | BRL | | Other | | Total |
| Financial assets | | | | | | | | | | | | | | | | | |
| Current assets | 297,763 | | 19,349 | | — | | 14,084 | | 3,918 | | — | | 3,647 | | 2,661 | | 341,422 |
| Non-current assets | 89,018 | | 718 | | — | | — | | — | | — | | — | | — | | 89,736 |
| Total | 386,781 | | 20,067 | | — | | 14,084 | | 3,918 | | — | | 3,647 | | 2,661 | | 431,158 |
| Financial liabilities | | | | | | | | | | | | | | | | | |
| Current liabilities | 479,493 | | — | | 4,701 | | — | | 4,782 | | 3,208 | | 719 | | 335 | | 493,238 |
| Non-current liabilities | 3,047,747 | | 5,649 | | 3 | | — | | 55 | | — | | 517 | | — | | 3,053,971 |
| Total | 3,527,240 | | 5,649 | | 4,704 | | — | | 4,837 | | 3,208 | | 1,236 | | 335 | | 3,547,209 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 | 608,783 | | 9,815 | | 10,985 | | 4,174 | | — | | 2,324 | | 419 | | 530 | | 637,030 |
| Non-current liabilities | 3,159,205 | | 5,043 | | — | | 3,548 | | 192 | | 541 | | 914 | | 443 | | 3,169,886 |
| Total | 3,767,988 | | 14,858 | | 10,985 | | 7,722 | | 192 | | 2,865 | | 1,333 | | 973 | | 3,806,916 |
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:
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of U.S. Dollars) | December 31, 2021 | | | | | | | | | | | | | | |
| 10% decrease | | 10% increase | | | | | | | | | | | | | | |
| Norwegian Krone | (1,442) | | 1,442 | | | | | | | | | | | | | | |
| British Pound | (1,408) | | 1,408 | | | | | | | | | | | | | | |
| Other | 409 | | (409) | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| (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 |
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, 2021, 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.
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, 2021, the Partnership recorded an ECL of $0.6 million (December 31, 2020 - $1.4 million).
29.Gain (Loss) on Modification of Financial Liabilities, Net
The table below summarizes the Partnership's gain (loss) on modification of financial liabilities, net for the years ended December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
| | | | | |
Gain (loss) on modification of financial liabilities, net(1)(2) | (45,920) | | | — | | | (8,332) | |
| | | | | |
| Total gain (loss) on modification of financial liabilities, net | (45,920) | | | — | | | (8,332) | |
(1)During the year ended December 31, 2021, the Partnership recognized a loss on modification of financial liabilities of $45.9 million due to the substantial modification of certain unsecured revolving credit facilities provided by Brookfield (see Note 21a) and refinancing activities related to the $180.0 million unsecured bonds issued in December 2021 (see Note 19).
(2)During the year ended December 31, 2019, the Partnership recognized a loss on modification of financial liabilities of $8.3 million mainly due to the modification of the $450.0 million shuttle revolver and an unsecured revolving credit facility with Brookfield.
30.Other Income (Expenses), Net
The table below summarizes the Partnership's other income (expenses), net for the years ended December 31, 2021, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| $ | | $ | | $ |
Restructuring costs(1)(2) | (1,928) | | | (9,994) | | | (119) | |
| | | | | |
Other, net(3)(4) | 50,251 | | | (478) | | | (1,226) | |
| Total other income (expenses), net | 48,323 | | | (10,472) | | | (1,345) | |
ALTERA INFRASTRUCTURE L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)
(1)During the year ended December 31, 2021, the Partnership recognized restructuring costs of $1.9 million, primarily due severance costs associated with certain vessels coming off contract.
(2)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.
(3)During the year ended December 31, 2021, the Partnership released an accrual related to claims related to Logitel from COSCO of $49.3 million (see Note 16a).
(4)During the year ended December 31, 2021, the Partnership released a provision of $0.8 million related to its ECL (see Note 2p).
31.Subsequent Events
a.In January 2022, a wholly owned subsidiary of the Partnership, Altera Infrastructure Holdings L.L.C., entered into a revolving credit facility provided by Brookfield. The borrowings available under the revolving credit facility are $32.0 million and mature in June 2022. The interest payments on the facility are based on a fixed rate of 10.00% per annum, with interest payable on March 31, 2022 and June 15, 2022.
b.In January 2022, the Partnership agreed with Enauta to extend the Petrojarl I contract by one year, from May 2023 to May 2024, with an option to extend for an additional year through May 2025.
c.In February 2022, the Partnership amended an existing term loan relating to the financing of the Arendal Spirit UMS unit. As at December 31, 2021, this term loan had an outstanding balance of $25.7 million and matured in February 2022. Following the amendment, this term loan had an outstanding balance of $8.5 million and matures in February 2023. The interest payments on the amended facility are based on LIBOR plus a margin of 2.0% per annum.
d.In February 2022, the Partnership signed a FEED agreement with Equinor for redeployment of the Petrojarl Knarr FPSO unit on the Rosebank field.
e.In February 2022, the Partnership signed an agreement with Energean Isreal Ltd. to redeploy the Arendal Spirit UMS on a 100 day firm contract with extension options.
f.In February 2022, the Partnership entered into an agreement to sell the Petrojarl Varg FPSO unit to an energy company for re-use as a production facility as part of a new field development opportunity. The Partnership expects the sale to complete in March 2022.
g.Following Russia’s invasion of Ukraine in February 2022, the U.S., several European Union nations, and other countries have announced sanctions against Russia. While it is difficult to anticipate the potential for any indirect impact the sanctions announced to date may have on the Partnership's business and the Partnership, any further sanctions imposed or actions taken by the U.S., EU nations or other countries, and any retaliatory measures by Russia in response, such as restrictions on oil shipments from Russia, could lead to increased volatility in global oil demand which, could have a material adverse impact on the Partnership's business, results of operations and financial condition.
