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Edith Robinson

4th Floor, Belvedere Building, 69 Pitts Bay Road, Pembroke, HM 08, Bermuda

Telephone: (441) 405-5560

Email: edie.robinson@teekay.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
Common Units		TOO		New York Stock Exchange
Series A Preferred Units		TOO PR A		New York Stock Exchange
Series B Preferred Units		TOO PR B		New York Stock Exchange
Series E Preferred Units		TOO PR E		New York Stock Exchange

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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 “Teekay Offshore,” “we,” “us” and “our” and similar terms refer to Teekay Offshore Partners 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 Teekay Offshore Partners L.P.

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

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

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

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

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

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

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

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

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

•	any offers of shuttle tankers, floating storage and off-take (or FSO) units, or floating production, storage and offloading (or FPSO) units and related contracts from Teekay Corporation (Teekay Corporation and/or any one or more of its affiliates or subsidiaries referred to herein as Teekay Corporation) and our accepting such offers;

•

the outcome and cost of claims and potential claims against us, including claims and potential claims by COSCO (Nantong) Shipyard (or COSCO) relating to Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd (or Logitel) and cancellation of Units for Maintenance and Safety (or UMS) newbuildings, by Damen Shipyard Group’s DSR Schiedam Shipyard (or Damen) relating to the Petrojarl I FPSO unit upgrade and related to Brookfield's acquisition by merger of all of our outstanding publicly held common units not already held by Brookfield;

•	the outcome of the investigation by Norwegian authorities of potential violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018 and its subsequent recycling;

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

•	results of operations and revenues and expenses;

•	offshore and tanker market fundamentals, including the balance of supply and demand in the offshore and tanker market and spot tanker charter rates;

•	our competitive advantage in the shuttle tanker market;

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

•	our expectations as to any impairment of our vessels;

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

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

•	the expected employment of the shuttle tanker newbuildings under our existing master agreement with Equinor ASA and the expected required capacity in our contract of affreightment (or CoA) fleet in the North Sea;

•	expected employment and trading of older shuttle tankers;

•	expected redelivery dates of in-chartered vessels;

•	the expectations as to the chartering of unchartered vessels;

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•	our expectations regarding competition in the markets we serve;

•	our entering into joint ventures or partnerships with companies;

•	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 future valuation of goodwill and potential impairment;

•	our compliance with covenants under our credit facilities;

•	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 and British Pound;

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

•	the adequacy of our insurance coverage;

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

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

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

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

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

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

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

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

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

Selected Financial Data

Set forth below is selected consolidated financial and other data of Teekay Offshore Partners L.P. and its subsidiaries for each of the five fiscal years ended December 31, 2019, which have been derived from our consolidated financial statements.

The following tables should be read together with, and are qualified in their entirety by reference to, (a) Item 5. Operating and Financial Review and Prospects, included herein, and (b) the historical consolidated financial statements and the accompanying notes and the Report of Independent Registered Public Accounting Firm thereon (which are included herein), with respect to the consolidated financial statements as at December 31, 2019 and December 31, 2018 and for each of the fiscal years in the three-year period ended December 31, 2019.

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In July 2015, we acquired from Teekay Corporation the Petrojarl Knarr FPSO unit, along with its operations and charter contract. The selected financial data and other financial information herein reflect this unit and the results of operations of the unit, referred to herein as the Dropdown Predecessor, as if we had acquired it when the unit began operations under the ownership of Teekay Corporation. The Petrojarl Knarr FPSO unit began operations on March 9, 2015. For a further description of the Dropdown Predecessor, please refer to our Annual Report on Form 20-F for the year ended December 31, 2017.

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (or GAAP).

					Year Ended December 31,
		2019			2018			2017			2016			2015
		(in thousands of U.S. Dollars, except per unit, unit and fleet data)
Income Statement Data:
Revenues		1,268,000			1,416,424			1,110,284			1,152,390			1,229,413
Operating (loss) income (1)		(91,037	)		111,737			(116,005	)		230,853			283,399
Net (loss) income		(350,895	)		(123,945	)		(299,442	)		44,475			100,143
Limited partners’ interest:
Net (loss) income		(378,770	)		(147,141	)		(339,501	)		(12,952	)		31,205
Net (loss) income per
Common unit - basic (2)		(0.92	)		(0.36	)		(1.45	)		(0.25	)		0.32
Common unit - diluted (2)		(0.92	)		(0.36	)		(1.46	)		(0.25	)		0.32
Cash distributions declared per common unit		0.00			0.04			0.24			0.44			2.18
Balance Sheet Data (at end of year):
Cash and cash equivalents		199,388			225,040			221,934			227,378			258,473
Restricted cash		106,868			8,540			28,360			114,909			60,520
Vessels and equipment (3)		3,768,775			4,270,622			4,687,494			4,716,933			4,743,619
Investments in equity accounted joint ventures		234,627			212,202			169,875			141,819			77,647
Total assets		4,923,267			5,312,052			5,637,795			5,718,620			5,744,166
Total debt		3,178,950			3,097,742			3,123,728			3,182,894			3,363,874
Total equity		1,072,066			1,459,124			1,473,528			1,138,596			967,848
Common units outstanding		411,148,991			410,314,977			410,045,210			147,514,113			107,026,979
Preferred units outstanding (4)		15,800,000			15,800,000			11,000,000			23,517,745			21,438,413
Cash Flow Data:
Net cash flow provided by (used for):
Operating activities		319,909			280,643			305,200			396,473			371,456
Financing activities		(58,018	)		(121,338	)		142,947			(93,415	)		286,663
Investing activities		(189,215	)		(176,019	)		(540,140	)		(279,764	)		(638,024	)
Other Financial Data:
Net revenues (5)		1,138,090			1,264,616			1,010,840			1,071,640			1,131,407
EBITDA (6)		206,909			466,799			162,618			492,648			475,590
Adjusted EBITDA (6)		671,898			782,521			522,394			570,572			615,775
Expenditures for vessels and equipment		201,439			233,736			533,260			294,581			664,667
Fleet data:
Average number of shuttle tankers (7)		27.8			30.3			31.7			32.5			33.8
Average number of FPSO units (7)		8.0			8.0			8.0			8.0			7.8
Average number of conventional tankers (7)		0.5			2.0			2.0			2.0			3.9
Average number of FSO units (7)		5.3			6.0			6.8			7.0			6.6
Average number of towing vessels (7)		10.0			9.9			7.9			6.3			4.3
Average number of units for maintenance and safety (7)		1.0			1.0			1.0			1.0			0.9

(1)Operating (loss) income includes, among other things, the following:

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		Year Ended December 31,
		2019			2018			2017			2016			2015
(Write-down) and gain on sale of vessels		(332,125	)		(223,355	)		(318,078	)		(40,079	)		(69,998	)

(2)	Please read Item 18 - Financial Statements: Note 16 - Total Capital and Net Income Per Common Unit.

(3)	Vessels and equipment consists of (a) vessels, at cost less accumulated depreciation and write-downs and (b) advances on newbuilding contracts.

(4)

Preferred units outstanding includes the Series A Preferred Units from April 23, 2013 through December 31, 2019, the Series B Preferred Units from April 13, 2015 through December 31, 2019, the Series C Preferred Units from July 1, 2015 through June 29, 2016, the Series C-1 and Series D Preferred Units from June 29, 2016 through September 25, 2017, and the Series E Preferred Units from January 18, 2018 through December 31, 2019.

(5)

Net revenues is a non-GAAP financial measure defined as revenues less voyage expenses. For additional information about this measure, please read Item 5 - Operating and Financial Review and Prospects - Management’s Discussion and Analysis of Financial Conditions and Results of Operations - Important Financial and Operational Terms and Concepts. We principally use net revenues because it measures vessel performance on a time-charter equivalent (or TCE) basis, which provides more meaningful information to us about the deployment of our vessels and their performance, than revenues, the most directly comparable financial measure under GAAP. Net revenue should not be considered as an alternative to revenues or any other measure of financial performance in accordance with GAAP. The following table reconciles net revenues with revenues:

		Year Ended December 31,
		2019			2018			2017			2016			2015
Revenues		1,268,000			1,416,424			1,110,284			1,152,390			1,229,413
Voyage expenses		(129,910	)		(151,808	)		(99,444	)		(80,750	)		(98,006	)
Net revenues		1,138,090			1,264,616			1,010,840			1,071,640			1,131,407

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

EBITDA represents net (loss) income before interest expense (net), income tax expense and depreciation and amortization. Adjusted EBITDA represents 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 vessel write-downs, gains or losses on sale of vessels, unrealized gains or losses on derivative instruments, foreign exchange gains or losses, losses on debt repurchases, and certain other income or expenses. Adjusted EBITDA also excludes realized gains or losses on interest rate swaps as our management, in assessing performance, views these gains or losses as an element of interest expense, realized gains or losses on derivative instruments resulting from amendments or terminations of the underlying instruments and equity income. Adjusted EBITDA is further adjusted to include our proportionate share of Adjusted EBITDA from our equity-accounted joint ventures and to exclude the non-controlling interests' proportionate share of the Adjusted EBITDA from our consolidated joint ventures.

These measures are used as supplemental financial performance measures by management and by external users of our financial statements, such as investors and our controlling unitholder.

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

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

The following table reconciles our historical EBITDA and Adjusted EBITDA to net (loss) income.

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		Year Ended December 31,
		2019			2018			2017			2016			2015
		(in thousands of US Dollars)
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net (loss) income”:
Net (loss) income		(350,895	)		(123,945	)		(299,442	)		44,475			100,143
Depreciation and amortization		349,379			372,290			309,975			300,011			274,599
Interest expense, net of interest income		200,598			195,797			152,183			139,354			122,205
Income tax expense (recovery)		7,827			22,657			(98	)		8,808			(21,357	)
EBITDA		206,909			466,799			162,618			492,648			475,590
Write-down and (gain) on sale of vessels		332,125			223,355			318,078			40,079			69,998
Realized and unrealized loss (gain) on derivative instruments		85,195			(12,808	)		42,853			20,313			73,704
Equity income (i)		(32,794	)		(39,458	)		(14,442	)		(17,933	)		(7,672	)
Foreign currency exchange (gain) loss		(2,193	)		9,413			14,006			14,805			17,467
Losses on debt repurchases (ii)		—			55,479			3,102			—			—
Other expense (income) - net		1,225			4,602			(14,167	)		21,031			(1,091	)
Realized (loss) gain on foreign currency forward contracts		(5,054	)		(1,228	)		900			(7,153	)		(13,799	)
Adjusted EBITDA from equity-accounted vessels (i)		97,849			92,637			33,360			30,246			27,320
Adjusted EBITDA attributable to non-controlling interests (iii)		(11,364	)		(16,270	)		(23,914	)		(23,464	)		(25,742	)
Adjusted EBITDA		671,898			782,521			522,394			570,572			615,775

(i)

Adjusted EBITDA from equity-accounted vessels, which is a non-GAAP measure and should not be considered as an alternative to equity income or any other measure of financial performance presented in accordance with GAAP, represents our proportionate share of Adjusted EBITDA (as defined above) from equity-accounted vessels. In addition, this measure does not have a standardized meaning, and may not be comparable to similar measures presented by other companies. We do not have control over the operations, nor do we have any legal claim to the revenue and expenses of our investments in equity-accounted joint ventures. Consequently, the income generated by our investments in equity-accounted joint ventures may not be available for use by us in the period that such income is generated. Our proportionate share of Adjusted EBITDA from equity-accounted vessels is summarized in the table below:

    

		Year Ended December 31,
		2019			2018			2017			2016			2015
Equity income		32,794			39,458			14,442			17,933			7,672
Depreciation and amortization		32,534			30,947			10,719			8,715			8,356
Interest expense, net of interest income		19,749			18,585			7,437			3,541			4,234
Income tax expense		250			442			103			372			161
EBITDA		85,327			89,432			32,701			30,561			20,423
Add (subtract) specific items affecting EBITDA:
Write-down and loss on sale of equipment		—			—			—			676			290
Realized and unrealized loss (gain) on derivative instruments		12,527			3,523			70			(805	)		6,607
Foreign currency exchange (gain) loss		(5	)		(318	)		589			(186	)		—
Adjusted EBITDA from equity-accounted vessels		97,849			92,637			33,360			30,246			27,320

(ii)

Losses on debt repurchases of $55.5 million for 2018, relates to the prepayment of our $200.0 million promissory note amended and transferred to Brookfield in September 2017 (or the Brookfield Promissory Note) and the repurchases of $225.2 million of the existing $300.0 million five-year senior unsecured bonds that matured in July 2019, and NOK 914 million of the existing NOK 1,000 million senior unsecured bonds that matured in January 2019. The losses on debt repurchases are comprised of an acceleration of non-cash accretion expense of $31.5 million, resulting from the difference between the $200.0 million settlement amount of the Brookfield Promissory Note at its par value and its carrying value of $168.5 million, and an associated early termination fee of $12.0 million paid to Brookfield, as well as 2.0% - 2.5% premiums on the repurchase of the bonds and the write-off of capitalized loan costs. The carrying value of the Brookfield Promissory Note was lower than face value due to it being recorded at its relative fair value based on the allocation of net proceeds invested by Brookfield on September 25, 2017.

Losses on debt repurchases of $3.1 million for 2017, relates to the repurchase of NOK 508 million of the remaining NOK 1,220 million senior unsecured bonds that matured in late-2018.

(iii)

Adjusted EBITDA attributable to non-controlling interests, which is a non-GAAP measure and should not be considered as an alternative to non-controlling interests in net (loss) income or any other measure of financial performance presented in accordance with GAAP, represents the non-controlling interests' proportionate share of Adjusted EBITDA (as defined above) from our consolidated joint ventures. In addition, this measure does

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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,
		2019			2018			2017			2016			2015
Net (loss) income attributable to non-controlling interests		(1,384	)		(7,161	)		3,764			11,858			13,911
Depreciation and amortization		10,525			14,617			13,324			12,327			10,727
Interest expense, net of interest income		1,470			2,064			1,549			1,456			1,383
EBITDA attributable to non-controlling interests		10,611			9,520			18,637			25,641			26,021
Add (subtract) specific items affecting EBITDA:
Write-down and (gain) loss on sale of vessels		746			6,711			5,400			(2,270	)		(742	)
Realized and unrealized loss on derivative instruments		—			—			—			53			199
Foreign currency exchange loss (gain)		7			39			(123	)		41			264
Other, net		—			—			—			(1	)		—
Adjusted EBITDA attributable to non-controlling interests		11,364			16,270			23,914			23,464			25,742

(7)	Average number of vessels consists of the average number of owned and chartered-in vessels that were in our possession during the period, including the Dropdown Predecessor. For 2019, 2018, 2017, 2016 and 2015 this includes two FPSO units in our equity accounted joint ventures, in which we have 50% ownership interests, at 100%.

Risk Factors

Some of the following risks relate principally to the industry in which we operate and to our business in general. Other risks relate principally to the securities market and to the ownership of our preferred units. The occurrence of any of the events described in this section could materially and adversely affect our business, financial condition, operating results and ability to pay distributions on, and the trading price of, our preferred units.

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

The source of our cash flow includes cash distributions from our subsidiaries. The amount of cash our subsidiaries can distribute to us principally depends upon the amount of cash they generate from their operations, which may fluctuate from quarter to quarter based on, among other things:

•	the rates they obtain from their FPSO contracts, charters, voyages, management fees and contracts of affreightment (whereby our subsidiaries carry a customer's crude oil production from offshore fields to terminal and ports for an agreed period of time);

•	the rates and the utilization of our towage fleet;

•	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 operating performance of our FPSO units, whereby receipt of incentive-based revenue from our FPSO units is dependent upon the fulfillment of the applicable performance criteria, including 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;

•	the level of their operating costs, such as the cost of crews and repairs and maintenance;

•	the number of off-hire days for their vessels and the timing of, and number of days required for, dry docking of vessels;

•	the rates, if any, at which our subsidiaries may be able to redeploy shuttle tankers in the spot market as conventional oil tankers during any periods of reduced or terminated oil production at fields serviced by contracts of affreightment;

•	the rates, if any, at which our subsidiaries may be able to redeploy vessels, particularly FPSO units, after they complete their charters or contracts and are redelivered to us;

•	the ability of our subsidiaries to contract our newbuilding vessels and the rates thereon (if any);

•	delays in the delivery of any newbuildings and the beginning of payments under charters relating to those vessels;

•	prevailing global and regional economic and political conditions;

•	currency exchange rate fluctuations; and

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

The actual amount of cash our subsidiaries have available for distribution also depends on other factors such as:

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•	the level of their capital expenditures, including for maintaining vessels or converting existing vessels for other uses and complying with regulations;

•	their debt service requirements and restrictions on distributions contained in their debt agreements;

•	fluctuations in their working capital needs;

•	their ability to make working capital or long-term borrowings; and

•	the amount of any cash reserves, including reserves for future capital expenditures, working capital and other matters, established by the board of directors of our general partner at its discretion.

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

Our ability to pay distributions on our units, and the amount of distributions that we may pay in the future, largely depends upon the distributions that we receive from our subsidiaries, and we may not have sufficient cash from operations to enable us to pay distributions.

The source of our earnings and cash flow includes cash distributions from our subsidiaries. Therefore, the amount of distributions we are able to make to our unitholders will fluctuate in large part based on the level of distributions made to us by our subsidiaries. Our subsidiaries may not make quarterly distributions at a level that will permit us to maintain or increase our quarterly distributions in the future.

Our ability to distribute to our unitholders any cash we may receive from our subsidiaries is or may be limited by a number of factors, including, among others:

 

•	interest expense and principal payments on any indebtedness we incur;

•	distributions on any preferred units we have issued or may issue;

•	capital expenditures related to committed projects;

•	changes in our cash flows from operations;

•	restrictions on distributions contained in any of our current or future debt agreements;

•	fees and expenses of us, our general partner, its affiliates or third parties we are required to reimburse or pay, including expenses we incur as a result of being a public company; and

•	reserves the board of directors of our general partner believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions, including reserves for future capital expenditures and for anticipated future credit needs.

Many of these factors reduce the amount of cash we may otherwise have available for distribution. The actual amount of cash that is available for distribution to our unitholders depends on several factors, many of which are beyond the control of us or our general partner.

We may issue additional equity securities in the future. The issuance of additional equity securities may be dilutive to unitholders and increases the risk that we will not have sufficient available cash to make cash distributions to our unitholders. The issuance of any securities with rights and preferences senior to those of existing units may reduce distributions on the existing securities.

Issuing additional equity securities in the future may result in unitholder dilution and increase the aggregate amount of cash required to make quarterly distributions. Issuing any securities with rights or preferences senior to those of existing units may reduce distributions on the existing securities.

We are required to distribute all of 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.

Subject to the limitations in our partnership agreement, we are required to distribute all of our available cash each quarter to our limited partners. “Available cash” is defined in our partnership agreement, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own), less the amount of cash reserves (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 (including reserves for future capital expenditures and for our anticipated credit needs);

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

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

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•	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.

In January 2019, we announced that we reduced our quarterly common unit cash distributions to zero in order to reinvest additional cash in our business and further strengthen our balance sheet. Since this time and for these same reasons, the common unit cash distribution has remained at zero each quarter. If we resume paying quarterly cash distributions on our common units in the future, these 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.

We have limited current liquidity.

As at December 31, 2019, we had total liquidity of $304.4 million and a working capital deficit of $184.5 million. Our limited availability under existing credit facilities and our current working capital deficit could limit our ability to meet our financial obligations and growth prospects. We expect to manage our working capital deficit primarily with net operating cash flow, including extensions and redeployments of existing assets, debt financing and re-financings, and our existing liquidity. However, there can be no assurance that any such funding will be available to us on acceptable terms, if at all.

Current market conditions limit our access to capital and our growth prospects.

We have relied primarily upon bank financing and debt and equity offerings to fund our growth. Current depressed market conditions in the energy sector and for master limited partnerships may significantly reduce our access to capital, particularly equity capital. Debt financing or refinancing or equity offerings may not be available on acceptable terms, if at all, from external sources or from Brookfield. Incurring additional debt may increase our leverage, susceptibility to market downturns or adversely affect our ability to pursue future growth opportunities. Lack of access to debt or equity capital at reasonable rates could adversely affect our growth prospects and our ability to refinance debt, finance our operations and make distributions to our unitholders.

Our ability to repay or refinance our debt obligations and to fund our capital expenditures and estimated funding gaps 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.

To fund our existing and future debt obligations and capital expenditures, we will be required to use cash from operations, secure extensions and redeployments of existing assets and/or seek to access other financing sources, including re-financing or obtaining new loans/extending the maturities of existing loans. Our ability to draw on committed funding sources and potential funding sources 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 additional bank financing and generate sufficient cash flow to meet our debt, 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 additional assets or equity interests in certain assets or joint ventures;

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

•seeking bankruptcy protection.

Such measures might not be successful, and additional debt or equity capital may not be available on acceptable terms or enable us to meet our debt, capital expenditure and other obligations. Some of such measures may adversely affect our business and reputation. In addition, our financing agreements may restrict our ability to implement some of these measures. The sale of certain assets will reduce cash from operations and the cash available for distributions to unitholders.

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

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Primarily as a result of the working capital deficit and committed capital expenditures, over the one-year period following the issuance of our 2019 consolidated financial statements, we will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet our liquidity needs and our minimum liquidity requirements under our financial covenants. Additional potential sources of financing include refinancing or extension of debt facilities and redeployments of existing assets. We are actively pursuing the funding alternatives described above, which we consider probable of completion based on our history of being able to raise and refinance loan facilities. We are in various stages of completion on these matters.

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, 2019, our total debt was approximately $3.2 billion. We plan to increase our total debt relating to financing of our shuttle tanker newbuildings. If we are awarded contracts for additional offshore projects or otherwise acquire additional vessels or businesses, our consolidated debt may significantly increase. We may incur additional debt under these 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 expenditures, acquisitions 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 level 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, forcing 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.

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

Given volatility associated with our business and industry, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any such cash flow shortfall could negatively impact our business. A range of economic, competitive, business and industry factors, including those beyond our control, may affect our future financial performance, which in turn may affect our ability to generate cash flow from operations and to pay our debt obligations. If our cash flows and capital resources are insufficient to fund our debt service obligations and other commitments, we may be forced to reduce or delay planned investments and capital expenditures, sell assets, seek additional financing in the debt or equity markets or restructure or refinance our existing indebtedness. Our ability to restructure or refinance our existing indebtedness will depend on the condition of capital markets and our financial condition at such time. Any refinancing of our indebtedness could include higher interest rate obligations and may require us to comply with more onerous covenants, all of which in turn could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which in turn could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and may be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate those dispositions or obtain particular anticipated proceeds that we could have realized from them and any proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may result in us being unable to meet our debt service obligations.

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. For example, the arrangements may restrict the ability of us and our subsidiaries to:

•incur additional indebtedness or guarantee indebtedness;

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

•make dividends or distributions or repurchase or redeem our equity securities;

•prepay, redeem or repurchase certain debt;

•issue certain preferred units or similar equity securities;

•make certain negative pledges and grant certain liens;

•sell, transfer, assign or convey assets;

•enter into transactions with affiliates;

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•create unrestricted subsidiaries;

•make certain acquisitions and investments;

•enter into agreements restricting our subsidiaries' ability to pay dividends;

•make loans and certain investments; and

•enter into a new line of business.

One revolving credit facility is guaranteed by us for all outstanding amounts and contains covenants that require us to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $75.0 million and 5.0% of our total consolidated debt. One revolving credit facility is guaranteed by subsidiaries of ours, and contains covenants that require Teekay Shuttle Tankers L.L.C. (or ShuttleCo) to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $35.0 million and 5.0% of ShuttleCo's total consolidated debt, a minimum ratio of twelve months' historical EBITDA relative to total interest expense and installments of 1.20x, which can be mitigated by cash deposits, and a net debt to total capitalization ratio no greater than 75.0%. The revolving credit facilities are collateralized by first-priority mortgages granted on 17 of our vessels, together with other related security. Our ability to comply with covenants and restrictions contained in debt instruments 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.

Obligations under our credit facilities are secured by certain vessels, and if we are unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. We have two revolving credit facilities and seven term loans that require us to maintain vessel values to drawn principal balance ratios of a minimum range of 100% to 150%. As at December 31, 2019, these ratios ranged from 126% to 501% and we were in compliance with the minimum ratios required. The vessel values used in calculating these ratios are the appraised values provided by third parties where available, or prepared by us based on second-hand sale and purchase market data. Changes in the shuttle tanker, towage and offshore installation, UMS, FSO or FPSO markets could negatively affect these ratios.

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.

At December 31, 2019, we were in compliance with all covenants in our credit facilities and other long-term debt agreements.

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

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

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

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

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

•breach of certain financial covenants;

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

•default under other indebtedness;

•bankruptcy or insolvency events;

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

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

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

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase, as well as risks related to the phasing out of LIBOR.

We are subject to interest rate risk in connection with borrowings under our revolving facilities and secured term loan facilities, which bear interest at variable rates. Interest rate changes could impact the amount of our interest payments, and accordingly, our future earnings and cash flow, assuming other factors are held constant. We cannot assure that any hedging activities entered into by it will be effective in fully mitigating our interest rate risk from our variable rate indebtedness.

 

In addition, the LIBOR and certain other interest “benchmarks” may be subject to regulatory guidance and/or reform that could cause interest rates under our current and future debt agreements to perform differently than in the past or cause other unanticipated consequences. The

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United Kingdom’s Financial Conduct Authority, which regulates LIBOR, has announced that it intends to stop encouraging or requiring banks to submit LIBOR rates after 2021, and it is unclear if LIBOR will cease to exist or if new methods of calculating LIBOR will evolve. While the agreements governing our revolving facilities and secured term loan facilities 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 borrowings under our revolving facilities and secured term loan facilities 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 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 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 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.

In addition, actual maintenance capital expenditures vary significantly from quarter to quarter based on the number of vessels dry docked during that quarter. Certain repair and maintenance items are more efficient to complete while a vessel is in dry dock. Consequently, maintenance capital expenditures will typically increase in periods when there is an increase in the number of vessels dry docked. Significant maintenance capital expenditures reduce the amount of cash that we have available to make distributions to our unitholders.

We require substantial capital expenditures and generally are required to make significant installment payments for acquisitions of newbuilding vessels or for the conversion of existing vessels prior to their delivery and generation of revenue.

Currently, the total cost for our existing shuttle tankers is up to approximately $150 million, the cost for our existing FSO units is up to approximately $400 million and the cost for our existing FPSO units is up to approximately $1.5 billion, although actual costs vary significantly depending on the market price charged by shipyards, the size and specifications of the vessel, governmental regulations and maritime self-regulatory organization standards.

We regularly evaluate and pursue opportunities to provide marine transportation services and offshore oil production and storage services for new or expanding offshore projects.

Although delivery of the completed vessel will not occur until much later (approximately two to three years from the time the 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 on newbuildings prior to their delivery, in addition to incurring financing, miscellaneous construction and project management costs. If we finance these acquisition costs by issuing debt or equity securities, we may increase the aggregate amount of interest or cash required to make quarterly distributions to unitholders, if any, prior to generating cash from the operation of the newbuilding.

Our substantial capital expenditures may reduce our cash available for distribution to our unitholders. Funding of any capital expenditures with debt may significantly increase our interest expense and financial leverage, and funding of capital expenditures through issuing additional

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equity securities may result in significant unitholder dilution. Our failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, operating results and financial condition.

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

Values for shuttle tankers, FSO and FPSO units, towage and offshore installation vessels and UMS can fluctuate substantially over time due to a number of different factors, including:

•	prevailing economic conditions in oil and energy markets;

•	a substantial or extended decline in demand for oil;

•	increases in the supply of vessel capacity;

•	competition from more technologically advanced vessels;

•	the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, or otherwise; and

•	a decrease in oil reserves in the fields in which our FPSO units or other vessels are or might be deployed.

Vessel values 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 useful life and earnings require us to impair its value on our financial statements, we may need to recognize a significant charge against our earnings.

We have recognized write-downs on certain vessels and may recognize additional vessel write-downs in the future, which could adversely affect our operating results.

During 2019, we recognized a net write-down of vessels of $332.1 million, relating to our determination that five of our vessels were impaired and that their carrying values should be written down to their respective estimated fair values based on a discounted cash flow approach or using appraised values. Please read "Item 18 – Financial Statements: Note 18 – (Write-down) and Gain on Sale of Vessels." The non-cash charges related to these or other impairments or write-downs will reduce our operating results for the applicable period. We may recognize additional vessel write-downs in the future.

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

We have derived, and we believe we will continue to derive, a substantial majority of revenues and cash flow from a limited number of customers. Royal Dutch Shell Plc (or Shell, formerly BG Group Plc) and Equinor ASA (or Equinor, formerly Statoil ASA) accounted for approximately 25% and 13%, respectively, of our consolidated revenues during 2019. Shell, Petroleo Brasileiro S.A. (or Petrobras) and Equinor accounted for approximately 23%, 18% and 13%, respectively, of our consolidated revenues during 2018. Shell, Petrobras, Equinor and Premier Oil plc (or Premier Oil, formerly E.ON Ruhgras UK GP Limited or E.ON) accounted for approximately 31%, 17% 10% and 10%, respectively, of our consolidated revenues during 2017. No other customer accounted for 10% or more of revenues during any of these periods.

We could lose a customer or the benefits of a contract if:

•	the customer fails to make payments because of its financial inability, disagreements with us or otherwise;

•	we agree to reduce the payments due to us under a contract because of the customer’s inability to continue making the original payments;

•	the customer exercises certain rights to terminate the contract; or

•	the customer terminates the contract because we fail to deliver the vessel within a fixed period of time, the vessel is lost or damaged beyond repair, there are serious deficiencies in the vessel or prolonged periods of off-hire, or we default under the contract.

If we lose a key customer, we may be unable to obtain replacement long-term charters or contracts of affreightment and may become subject, with respect to any shuttle tankers redeployed on conventional oil tanker trades, to the volatile spot market, which is highly competitive and subject to significant price fluctuations. 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 due from them could have a material adverse effect on our business, operating results and financial condition. Or future growth depends on the ability to expand relationships with existing customers and obtain new customers.

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

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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, which could 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.

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

We currently are paid partly in Norwegian Krone, British Pound and Brazilian Real under some of our charters and FPSO contracts. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Krone, British Pound and Brazilian Real may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses, which may affect our operating results. We have entered into foreign currency forward contracts to economically hedge portions of our forecasted expenditures denominated in Norwegian Krone and Euro.

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 expect to enter into additional, joint venture arrangements with third parties to expand our fleet and access growth opportunities. In particular, we rely on the expertise and relationships that our 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.

Our ability to compete for offshore oil marine transportation, processing, offshore accommodation, support for maintenance and modification projects, towage and offshore installation and storage projects and to enter into new charters or contracts of affreightment 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 joint venture partners and their reputation and relationships in the shipping and offshore industries. If Brookfield or our joint venture partners suffer material damage to their reputation or relationships, it may harm the ability of us or other subsidiaries to:

•renew existing charters and contracts of affreightment upon their expiration;

•obtain new charters and contracts of affreightment;

•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.

If our ability to do any of the things described above is impaired, it could have a material adverse effect on our business, operating results and financial condition.

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

A decline in oil prices may adversely affect our business, operating results and financial condition, 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 volume-based contracts of affreightment, production-based and oil price-based components of our FPSO unit contracts or life-of-field contracts;

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

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

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

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

Our growth depends on continued growth in demand for offshore oil transportation and processing and storage services.

Our long-term growth strategy focuses on expansion in the shuttle tanker and FPSO segment. Accordingly, our growth depends on continued growth in world and regional demand for these offshore services, which could be negatively affected by a number of factors, such as:

•	decreases in the actual or projected price of oil, which could lead to a reduction in or termination of production of oil at certain fields we service or a reduction in exploration for or development of new offshore oil fields;

•	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;

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•	decreases in the consumption of oil due to increases in its price relative to other energy sources, other factors making consumption of oil less attractive or energy conservation measures;

•	availability of new, alternative energy sources; and

•

negative global or regional economic or political conditions, particularly in oil consuming regions, which could reduce energy consumption or its growth. Reduced demand for offshore marine transportation, processing, storage services, offshore accommodation or towage and offshore installation services would have a material adverse effect on our future growth and could harm our business, operating results and financial condition.

We may be unable to make or realize expected benefits from acquisitions, and implementing our growth strategy through acquisitions may harm our business, financial condition and operating results.

Our long-term growth strategy includes selectively acquiring or constructing shuttle tankers and FPSO units as needed for approved projects only after charters for the projects have been awarded to us, rather than ordering vessels on a speculative basis. Historically, there have been very few purchases of existing vessels and businesses in the FPSO segment. The relatively small number of independent FPSO fleet owners may contribute to a limited number of acquisition opportunities for FPSO units in the near term. In addition, competition from other companies, many of which have significantly greater financial resources than do we could reduce our acquisition opportunities or cause us to pay higher prices.

Any acquisition of a vessel or business may not be profitable at or after the time of acquisition and may not generate cash flow sufficient to justify the investment. In addition, our acquisition growth strategy exposes us to risks that may harm our business, financial condition and operating results, including risks that we may:

•fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

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

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

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

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

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

Unlike newbuilding vessels, existing vessels typically do not carry warranties as to their condition. While we generally inspect existing vessels prior to purchase, such an inspection would normally not provide us with as much knowledge of a vessel’s condition as we would possess if it had been built for us and operated by us during its life. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built. These costs could decrease our cash flow and reduce our liquidity.

In addition, we may not be successful if we seek to enter new markets, which may have competitive dynamics that differ from markets in which we already participate, and we may be unsuccessful in gaining acceptance in any such markets from customers or competing against other companies with more experience or larger fleets or resources in these markets. We also may not be successful in employing the Petrojarl Varg FPSO unit or the Arendal Spirit UMS, each of which is currently in lay-up, on contracts sufficient to recover our investment in the vessels.

Because payments under our contracts of affreightment 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, utilization of our shuttle tanker fleet, the success of our shuttle tanker business and the revenue from our FPSO units depends upon continued production from existing or new oil fields, which is beyond our control and generally declines naturally over time.

A portion of our shuttle tankers operates under contracts of affreightment. Payments under these contracts of affreightment, which depend upon the level of oil production at the fields we service under the contracts. Payments made to us under certain of our FPSO contracts are partially based on an incentive component, which is determined by the volume of oil produced. 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.

The rate of oil production at fields we service may decline from existing levels. If such a reduction occurs, the spot market rates in the conventional oil tanker trades at which we may be able to redeploy the affected shuttle tankers may be lower than the rates previously earned by the vessels under the contracts of affreightment. Low spot market rates for the shuttle tankers or any idle time prior to the commencement of a new contract or our inability to redeploy any of our FPSO units at an acceptable rate may have an adverse effect on our business and operating results.

The duration of some of our shuttle tanker, FSO and FPSO contracts is the life of the relevant oil field or is subject to extension by the field operator or vessel charterer.

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Some of our shuttle tanker contracts have a “life-of-field” duration, which means that the contract continues 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 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 shuttle tanker, FSO and FPSO 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. If we are unable to promptly redeploy any affected vessels at rates at least equal to those under the contracts, if at all, our operating results will be harmed. Any potential redeployment may not be under long-term contracts, which may affect the stability of our cash flow.

The redeployment risk of FPSO units is high given their lack of alternative uses and significant costs.

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. One of our FPSO production service contracts will expire in 2020 and, unless extended, a contract will expire in 2021 and a further two contracts will expire in 2022. 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.

The results of our shuttle tanker and FPSO operations in the North Sea are subject to seasonal fluctuations.

Due to harsh winter weather conditions, oil field operators in the North Sea typically schedule oil platform and other infrastructure repairs and maintenance during the summer months. As the North Sea is one of our primary existing offshore oil markets, this seasonal repair and maintenance activity schedule contributes to quarter-to-quarter volatility in our operating results, due to the fact that oil production is typically lower in the second and third quarters in this region compared with production in the first and fourth quarters.

Since a portion of our North Sea shuttle tankers operate under contracts of affreightment, where revenue is based on the volume of oil transported, the results of these North Sea shuttle tanker operations are generally reflective of the seasonal pattern of transportation demand. Additionally, our North Sea FPSO units, the Petrojarl Knarr and Voyageur Spirit FPSO units, operate higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our units, which generally reduces oil production. When we redeploy affected shuttle tankers as conventional oil tankers during platform maintenance and repair periods, the overall financial results for the North Sea shuttle tanker operations may be negatively affected as the rates in the conventional oil tanker markets are usually lower than contract of affreightment rates. In addition, we generally seek to coordinate a portion of the general fleet dry-docking schedule with this seasonality, which may in turn result in lower revenues and increased dry-docking expenses during the summer months.

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 will face substantial competition.

One of our principal objectives is to enter into additional long-term, fixed-rate time charters and contracts of affreightment, including the redeployment of our assets as their current charter contracts expire. The process of obtaining new long-term time charters and contracts of affreightment is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. Shuttle tanker, FSO, FPSO, towage and offshore installation vessel and UMS contracts are awarded based upon a variety of factors relating to the vessel operator, including:

•industry relationships and reputation for customer service and safety;

•experience and quality of ship operations;

•quality, experience and technical capability of the crew;

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

•	construction management experience, including the ability to obtain on-time delivery of new vessels or conversions according to customer specifications;

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

•competitiveness of the bid in terms of overall price.

We expect competition for providing services for potential offshore projects from other experienced companies, including state-sponsored entities. Our competitors may have greater financial resources than us. This 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.

Delays in the operational start-up of FPSO units or deliveries of newbuilding vessels could harm our operating results.

The operational start-up of FPSO units, the completion of final performance tests of FPSO units, or the deliveries of any newbuilding vessels we may order or undertake could be delayed, which would delay our receipt of revenues under the charters or other contracts related to the units or vessels. In addition, under some charters we may enter into, if the operational start-up or our delivery of the newbuilding vessel to

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our customer is delayed, we may be required to pay liquidated damages during the delay. For prolonged delays, the customer may terminate the charter and, in addition to the resulting loss of revenues, we may be responsible for substantial liquidated damages.

The operational start-up of FPSO units or completion and deliveries of newbuildings or of vessel conversions or upgrades could be delayed because of:

•quality or engineering problems, the risk of which may be increased with FPSO units due to their technical complexity;

•changes in governmental regulations or maritime self-regulatory organization standards;

•work stoppages or other labor disturbances at the shipyard;

•bankruptcy or other financial crisis of the shipbuilder;

•a backlog of orders at the shipyard;

•political or economic disturbances;

•weather interference or catastrophic events, such as a major earthquake or fire;

•requests for changes to the original vessel specifications;

•shortages of or delays in the receipt of necessary construction materials, such as steel;

•inability to finance the construction or conversion of the vessels; or

•inability to obtain requisite permits or approvals.

If the operational start-up of an FPSO unit or the delivery of a newbuilding vessel is materially delayed, it could adversely affect our operating results and financial condition.

Charter rates for towage and offshore installation vessels may fluctuate substantially over time and may be lower when we are attempting to charter our towage and offshore installation vessels, which could adversely affect operating results. Any changes in charter rates for shuttle tankers, FSO or FPSO units and UMS could also adversely affect redeployment opportunities for those vessels.

Our ability to charter our towage and offshore installation vessels will depend, among other things, on the state of the towage market. Towage contracts are highly competitive and are based on the level of projects undertaken by the customer base. There also exists some volatility in charter rates for shuttle tankers, FSO and FPSO units and UMS, which could affect our ability to charter or recharter these vessels at acceptable rates, if at all.

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 resale value or useful lives of our vessels, require a reduction in cargo capacity, ship modifications or operational changes or restrictions, lead to decreased availability of insurance coverage for environmental matters or result in the denial of access to certain jurisdictional waters or ports, or detention in, certain ports. Under local, national and foreign laws, as well as international treaties and conventions, failure to comply with such regulations could result in the imposition of material fines and penalties 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. In addition, failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations, including, in certain instances, seizure or detention of our vessels. An incident involving environmental contamination could also harm the Partnership's reputation and business.

In January 2020, Økokrim (the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime) and the local Stavanger police raided the premises of our subsidiary Teekay Shipping Norway AS in Stavanger, Norway, based on a search and seizure warrant issued pursuant to suspected violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018. Although we have not identified any such violations and deny the charges, such violations of Norwegian pollution and export laws, where they do exist, have the potential to trigger financial penalties, with

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a number of factors taken into consideration when assessing the size of the penalty to be enforced, including the financial capacity of the company, any preventative measures taken, the gravity of the offense and the benefit derived from the violation.

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

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

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

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 in Southeast Asia, the Middle East or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, 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.

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

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

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;

•mechanical failures;

•grounding, capsizing, fire, explosions and collisions;

•piracy;

•cyber attacks;

•human error; and

•war and terrorism.

A portion of our shuttle tanker fleet and our towage fleet, two FSO units, the Voyageur Spirit and Petrojarl Knarr FPSO units, and three FPSO units we manage on behalf of the disponent owners or charterers of these assets operate in the North Sea. Harsh weather conditions in this region and other regions in which our vessels operate may increase the risk of collisions, oil spills, or mechanical failures.

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

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•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 from charters or contracts of affreightment;

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

•governmental fines, penalties or restrictions on conducting business;

•higher insurance rates; and

•damage to our reputation and customer relationships generally.

Any of the foregoing could have a material adverse effect on our business, financial condition or operating results. In addition, any damage to, or environmental contamination involving, oil production facilities serviced by our vessels could suspend that service and thereby result in loss of revenues.

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 shuttle tankers, FSO and FPSO units, towage and offshore installation vessels, and UMS, is inherently risky. All risks may not be adequately insured against, and any particular claim may not be paid by insurance. In addition, all but three of our vessels, the Petrojarl Knarr FPSO unit, the Itajai FPSO unit and the Pioneiro de Libra FPSO unit (or Libra FPSO unit), are not insured against loss of revenues resulting from vessel off-hire time, 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 time 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.

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.

We may experience operational problems with vessels that could result in a loss of revenue and/or increased costs.

Shuttle tankers, FSO and FPSO units, towage and offshore installation vessels and UMS are complex and their operations are technically challenging. Marine transportation and oil production operations are subject to mechanical risks and problems as well as environmental risks. Operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these factors could harm our business, financial condition or operating results.

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

War, military tension, revolutions, piracy and terrorist attacks, or increases in such events or activities, could create or increase instability in the world’s financial and commercial markets. This may significantly increase political and economic instability in some of the geographic markets in which we operate or may operate in the future, and may contribute to high levels of volatility in charter rates or oil prices. Hijacking as a result of an act of piracy against any of our vessels, or an increase in cost or unavailability of insurance for such vessels, could have a material adverse impact on our business, financial condition or operating results

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. 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 impact the use of shuttle tankers under contracts of affreightment, towage and offshore installation vessels under voyage charters and FPSO units under FPSO contracts, which would harm our cash flow and business.

Acts of piracy on ocean-going vessels have continued to be a risk, which could adversely affect our business.

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Acts of piracy have historically affected ocean-going vessels trading in regions of the world such as the South China Sea, Gulf of Guinea and the Indian Ocean off the coast of Somalia. While there continues to be a significant risk of piracy in the Gulf of Aden and Indian Ocean, recently there have been increases in the frequency and severity of piracy incidents off the coast of West Africa. 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. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition and operating results.

Public health threats could have an adverse effect on our operations and financial results.

Public health threats and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world near where we operate, could adversely impact our operations, the operations of our customers, suppliers and the global economy, including the worldwide demand for crude oil and the level of demand for our services. Any quarantine of personnel, restrictions on travel to or from countries in which we operate, or inability to access certain areas could adversely affect our operations. Travel restrictions, operational problems or large-scale social unrest in any part of the world in which we operate, or any reduction in the demand for our services caused by public health threats in the future, may impact our operations and adversely affect our business, financial condition and operating results. Shutdowns of, or restrictions placed on, shipyards as a result of such outbreaks, could lead to project delays both in respect of our own vessels under construction and those vessels of our customers in relation to which we provide services, such as long-distance towage.

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.

Our failure to comply with data privacy laws could damage our customer relationships and expose us to litigation risks and potential fines.

Data privacy is subject to frequently changing rules and regulations, which sometimes conflict among the various jurisdictions and countries in which we provide services and continue to develop in ways which we cannot predict, including with respect to evolving technologies such as cloud computing. The European Union has adopted the General Data Privacy Regulation (or GDPR), a comprehensive legal framework to govern data collection, use and sharing and related consumer privacy rights which took effect in May 2018. The GDPR includes significant penalties for non-compliance. Our failure to adhere to or successfully implement processes in response to changing regulatory requirements in this area could result in legal liability or impairment to our reputation in the marketplace, which could in turn have a material adverse effect on our business, financial condition or operating results.

Many seafaring employees are covered by collective bargaining agreements and the failure to renew those agreements or any future labor agreements may disrupt operations and adversely affect our cash flows.

A significant portion of seafarers that crew certain of our vessels and Norwegian-based onshore operational staff that provide services to us are employed under collective bargaining agreements. We may become subject to additional labor agreements in the future. We may suffer labor disruptions if relationships deteriorate with the seafarers or the unions that represent them. The collective bargaining agreements may not prevent labor disruptions, particularly when the agreements are being renegotiated. Salaries are typically renegotiated annually or bi-annually for seafarers and annually for onshore operational staff and higher compensation levels will increase our costs of operations. Although these negotiations have not caused labor disruptions in the past, any future labor disruptions could harm our operations and could have a material adverse effect on our business, operating results and financial condition.

We and certain of our joint venture partners may be unable to attract and retain qualified, skilled employees or crew necessary to operate our business, or may have to pay substantially increased costs for its employees and crew.

Our success depends in large part on our ability to attract and retain highly skilled and qualified personnel. In crewing our vessels, we require technically skilled employees with specialized training who can perform physically demanding work. Any inability we experience in the future to hire, train and retain a sufficient number of qualified employees could impair our ability to manage, maintain and grow our business.

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

As the date of this Annual Report, affiliates of Brookfield holds 98.7% of our outstanding common units and a 100% interest in our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its members. Furthermore, certain directors of our general partner are directors of affiliates of our general partner. Conflicts of interest may arise between Brookfield and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our

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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 their respective affiliates (other than our general partner) to pursue a business strategy that favors us or utilizes our assets, and Brookfield’s respective directors have fiduciary duties to make decisions in the best interests of the shareholders of Brookfield, which may be contrary to our interests;

•	five directors of our general partner serve as officers, management or directors of Brookfield or its affiliates;

•	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 its fiduciary duty to our unitholders;

•

our general partner has restricted its liability and reduced its fiduciary duties 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 the modified standard of fiduciary duties 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.

The fiduciary duties of directors of our general partner may conflict with those of the officers and directors of Brookfield and Teekay Corporation.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, six directors of our general partner also serve as officers, management or directors of Brookfield (five directors) or Teekay Corporation (one director) and/or other affiliates of Brookfield or Teekay Corporation. Consequently, these directors may encounter situations in which their fiduciary obligations to Brookfield or Teekay Corporation, or their other affiliates, on one hand, and us, 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.

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 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.

Our partnership agreement restricts our general partner’s fiduciary duties 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 the Republic of the 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

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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.

Fees and cost reimbursements, which our general partner determines for services provided to us, may be substantial and reduce our cash available for distribution to our unitholders and for debt service.

We reimburse our general partner for all expenses it incurs on our behalf. Our general partner can determine when certain costs are reimbursed. The reimbursement of expenses to our general partner could adversely affect our ability to pay cash distributions to unitholders and debt service.

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

Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders did not elect our general partner or its board of directors and have no right to elect our general partner or its board of directors on an annual or other continuing basis. Brookfield, which own our general partner, appoint our general partner’s board of directors. Our general partner makes all decisions on our behalf. If the unitholders are dissatisfied with the performance of our general partner, they have little or no ability to remove our general partner.

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.

Unitholders may have liability to repay distributions.

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

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 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, court cases in the Republic of the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited partnership statute. Accordingly, we cannot predict whether Republic of the Marshall Islands courts would reach the same conclusions as Delaware courts. For example, the rights of our unitholders and the fiduciary 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.

As a Marshall Islands partnership with several of our subsidiaries being Marshall Islands entities, our operations may be subject to economic substance requirements of the European Union, which could harm our business.

Finance ministers of the European Union (or EU) rate jurisdictions for tax transparency, governance, real economic activity and corporate tax rate. Countries that do not adequately cooperate with the finance ministers are put on a “grey list” or a “blacklist”. Various countries, including the Republic of the Marshall Islands, have been on the blacklist from time to time. The Marshall Islands has been removed from this list. EU member states have agreed upon a set of measures, which they can choose to apply against the listed countries, including increased monitoring

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and audits, withholding taxes, special documentation requirements and anti-abuse provisions. The European Commission has stated it will continue to support member states' efforts to develop a more coordinated approach to sanctions for the listed countries in 2019. EU legislation prohibits EU funds from being channeled or transited through entities in countries on the blacklist. It is not assured that jurisdictions in which we operate will not be put on the blacklist going forward. If so, the effect of the EU blacklist, and any noncompliance by us with any legislation adopted by applicable countries, could have a material adverse effect on our business, financial condition and operating results.

The Marshall Islands have enacted economic substance laws and regulations with which we are obligated to comply. We believe that we and our subsidiaries are compliant with the Marshall Islands economic substance requirements and do not currently expect that these requirements will have a material adverse effect on our business, financial condition and operating results. However, if there were a change in the requirements or interpretation thereof, or if there were an unexpected change to our operations, any such change could result in noncompliance with the economic substance legislation and therefore could result in fines or other penalties, increased monitoring and audits, and dissolution of the noncompliant entity, which could have an adverse effect on our business, financial condition or operating results.

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 located outside of the United States. Our business is operated primarily from our offices in Bermuda, Norway, Brazil, the United Kingdom, Singapore and the Netherlands. In addition, our general partner is a Republic of the 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 Republic 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.

We are subject to litigation related to the merger with Brookfield.

 

Brookfield, we, and directors of our general partner and certain members of senior management are subject to class action litigation challenging the Merger. The plaintiffs in such litigation may make further efforts to seek monetary relief from Brookfield or us. We cannot predict the outcome of the existing or any additional potential litigation, nor can we predict the amount of time and expense that will be required to resolve such litigation. The costs of defending the litigation, even if resolved in favor of Brookfield, us, directors of our general partner and members of senior management, could be substantial and such litigation could distract us from pursuing potentially beneficial business opportunities. Please read Item 18 - Financial Statements: Note 14(d) - Commitments and Contingencies.

Tax Risks

In addition to the following risk factors, you should read "Item 4E – Taxation of the Partnership", "Item 10 – Additional Information – Material United States Federal Income Tax Considerations" and "Item 10 – Additional Information – Non-United States Tax Considerations" for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our units.

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

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a “passive foreign investment company” (or PFIC), for such purposes in any taxable year for which either (i) at least 75% of its gross income consists of “passive income,” or (ii) at least 50% of the average value of the entity’s assets is attributable to assets that produce or are held for the production of “passive income.” For purposes of these tests, “passive income” includes dividends, interest, gains from the sale or exchange of investment property and rents and royalties (other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business). By contrast, income derived from the performance of services does not constitute “passive income.”

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

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

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read Item "10 – Additional Information: Material United States Federal Income Tax Considerations –- United States Federal Income Taxation of U.S. Holders – Consequences of Possible PFIC Classification."

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

We or our subsidiaries are subject to tax in certain jurisdictions in which we or our subsidiaries are organized, own assets or have operations, which reduces the amount of our cash available for distribution. In computing our tax obligations in these jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions, the applicable authorities will agree with our positions. A successful challenge by a tax authority could result in additional tax imposed on us or our subsidiaries. We have established reserves in our financial statements that we believe are adequate to cover our liability for any such additional taxes. We cannot assure you, however, that such reserves will be sufficient to cover any additional tax liability that may be imposed on our subsidiaries. In addition, changes in our operations or ownership could result in additional tax being imposed on us or on our subsidiaries in jurisdictions in which operations are conducted.

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

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

No ruling has been requested with respect to the tax consequences of the Merger.

Although it is intended that the Company and holders of the Company’s preferred units will generally not recognize any gain or loss as a result of the Merger, no ruling has been or will be requested from the IRS, with respect to the tax consequences of the Merger.

Unitholders will be allocated our taxable income and gains through the time of the Merger and will not receive any additional distributions attributable to that income.

 

Unitholders will be allocated their proportionate share of our taxable income and gain for the period ending at the time of the Merger. Unitholders will have to report, and pay taxes on, such income even though they will not receive any additional cash distributions attributable to such income.

Item 4.	Information on the Partnership

A.	Overview, History and Development

Overview and History

We are a leading international midstream services provider to the offshore oil 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 Republic of the Marshall Islands limited partnership in August 2006 by Teekay Corporation (NYSE: TK), a portfolio manager and project developer in the marine midstream space. We are structured as a master limited partnership.

In September 2017, affiliates of Brookfield Business Partners L.P. (NYSE: BBU) (TSX: BBU.UN) purchased from an affiliate of Teekay Corporation a 49% interest in our general partner and purchased additional common units, representing an approximately 60% interest in our total common units outstanding, 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.

In May 2019, we received an unsolicited non-binding proposal from Brookfield to acquire all issued and outstanding publicly held common units representing limited partnership interests of us that Brookfield does not already own in exchange for $1.05 in cash per common unit. The Conflicts Committee of our general partner's board of directors, consisting only of non-Brookfield affiliated directors, evaluated the proposed offer on behalf of the owners of the non-Brookfield owned limited partnership interests, and on October 1, 2019, we announced that we entered into an agreement and plan of merger with Brookfield (or Merger Agreement). 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 our limited partner interests held by parties other than Brookfield (or unaffiliated unitholders) pursuant to the Merger Agreement among us, our general partner and certain members of Brookfield.

Under the terms of the Merger Agreement, a newly formed subsidiary of Brookfield merged with and into us, with us surviving as a wholly owned subsidiary of Brookfield and our general partner, and with common units held by unaffiliated unitholders being converted into the right

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to receive $1.55 in cash per common unit (or the cash consideration), other than common units held by unaffiliated unitholders who elected to receive the equity consideration (as defined below). 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 (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.

As of December 31, 2019, the public held a total of 26.9% of our outstanding common units and Brookfield held 73.1% of our outstanding common units and 100% of the general partner interest.

As a result of the Merger, 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 as of the closing of the Merger, are held by the unaffiliated unitholders who elected to receive the equity consideration in respect of their common units. Pursuant to the terms of the Merger Agreement, our outstanding preferred units were unchanged and remain outstanding following the Merger.

On January 23, 2020, the NYSE filed a Form 25 with the United States Securities and Exchange Commission (the SEC) notifying the SEC of the delisting of our common units on the NYSE and the deregistration of the common units. The deregistration will become effective 90 days after the filing of the Form 25 or such shorter period as may be determined by the SEC.

Our near-to-medium term business strategy is primarily to focus on extending contracts and redeploying existing assets on long-term charters, repaying or refinancing scheduled debt obligations and pursuing additional growth projects.

Our long-term growth strategy focuses on expanding our fleet of shuttle tankers and FPSO units under medium-to-long term charter contracts. Over the long-term, we intend to continue our practice of primarily acquiring vessels as needed for approved projects only after the medium-to-long-term charters for the projects have been awarded to us, rather than ordering vessels on a speculative basis. We have entered and may enter into joint ventures and partnerships with companies that may provide increased access to such charter opportunities or may engage in vessel or business acquisitions. We seek to leverage the expertise, relationships and reputation of Brookfield to pursue these growth opportunities in the offshore sectors and may consider other opportunities to which our competitive strengths are well suited. Our operating fleet primarily trades on medium to long-term, stable contracts.

As of December 31, 2019, our fleet consisted of:

•

FPSO Units. Our FPSO fleet consisted of six units, in which we have 100% ownership interests, four of which are operating under FPSO contracts with major energy companies in Norway, United Kingdom and Brazil and two of which are currently in lay-up. We also have two FPSO units, in which we have 50% ownership interests, which are operating under contracts in Brazil. We use the FPSO units to provide production, processing and storage services to oil companies operating offshore oil field installations. The FPSO contracts have an average remaining term of approximately 3.2 years, excluding extension options. As of December 31, 2019, our FPSO units had a total production capacity of approximately 0.4 million barrels of oil per day.

•

Shuttle Tankers. Our shuttle tanker fleet consisted of 26 vessels that operate under fixed-rate contracts of affreightment (or CoAs), time charters and bareboat charters, seven shuttle tanker newbuildings, which are expected to deliver through early-2022, and the HiLoad DP unit, which is currently in lay-up. Of these 34 shuttle tankers, four are owned through 50%-owned subsidiaries and two were chartered-in. The remaining vessels are owned 100% by us. All of our operating shuttle tankers, with the exception of two shuttle tankers that are currently trading as conventional tankers and the HiLoad DP unit, provide transportation services to energy companies in the North Sea, Brazil and the East Coast of Canada under CoAs, time charters or bareboat charters. Our shuttle tankers occasionally service the conventional spot tanker market. The average term of the CoAs, weighted based on each CoA's vessel demand, is 3.4 years. The time charters and bareboat charters have an average remaining contract term of approximately 4.5 years. As of December 31, 2019, our shuttle tanker fleet, including newbuildings, had a total cargo capacity of approximately 4.2 million dead-weight tonnes (or dwt).

•	FSO Units. Our FSO fleet consisted of four units, in which we have 100% ownership interests, and one unit, the Apollo Spirit, in which we have an 89% ownership interest. Our FSO units operate under fixed-rate contracts, with an average remaining term of approximately 2.6 years. As of December 31, 2019, our FSO units had a total cargo capacity of approximately 0.6 million dwt.

•	UMS. Our UMS fleet consisted of one unit, the Arendal Spirit UMS, in which we have a 100% ownership interest and which is currently in lay-up.

•	Towage and Offshore Installation Vessels. Our long-distance towage and offshore installation fleet consisted of ten operating vessels. We have 100% ownership interests in all our towage and offshore installation vessels. All of our operational towage and offshore installation vessels operate under voyage-charter and spot towage contracts.

Please read Item 18 – Financial Statements: Note 4 – Segment Reporting for a description of our capital expenditures during the three years ended December 31, 2019.

We were formed under the laws of the Republic of the Marshall Islands as Teekay Offshore Partners L.P. and maintain our principal executive offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Pembroke, HM 08, Bermuda. Our telephone number at such address is (441) 405-5560.

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.teekayoffshore.com. The information contained on our website is not part of this annual report.

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Potential Additional Shuttle Tanker, FSO and FPSO Projects

Please see Item 5. Operating and Financial Review and Prospects – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Potential Additional Shuttle Tanker, FSO and FPSO Projects for a description of possible future vessel acquisitions.

B.	Business Overview

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, 2019, we owned six FPSO units, in which we have 100% ownership interests, two of which are in lay-up, and two FPSO units in which we have 50% ownership interests. Most independent FPSO contractors have backgrounds in marine energy transportation, oil field services or oil field engineering and construction. Other major independent FPSO contractors are SBM Offshore N.V., BW Offshore, MODEC, Bumi Armada, Yinson Holdings, Bluewater and Rubicon Offshore International.

The following table provides additional information about our FPSO units as of December 31, 2019:

Vessel		Production Capacity (bbl/day)			Built		Ownership			Field name and location		Charterer		Contract End Date
Pioneiro de Libra (1)		50,000			2017		50	%		Libra, Brazil		Petrobras		November 2029
Petrojarl Knarr		63,000			2014		100	%		Knarr, Norway		Shell		March 2021 (2)
Cidade de Itajai (3)		80,000			2012		50	%		Bauna and Piracaba, Brazil		Petrobras		February 2022 (4)
Voyageur Spirit (5)		30,000			2008		100	%		Huntington, U.K.		Premier		April 2020
Piranema Spirit		30,000			2007		100	%		Piranema, Brazil		Petrobras		February 2022 (6)
Petrojarl I		46,000			1986		100	%		Atlanta, Brazil		Enauta		May 2023 (7)
Petrojarl Cidade de Rio das Ostras		25,000			2008		100	%				Lay-up
Petrojarl Varg		57,000			1998		100	%				Lay-up
Total capacity		381,000

(1)	The Pioneiro de Libra was converted to an FPSO unit in 2017. The original hull was built in 1995.

(2)	The contract has a 6-year duration with a firm period expiring in March 2021. From March 2021 to March 2024, the charterer has the annual option to extend the contract, with failure to exercise these options resulting in the payment of certain termination fees. The charterer has further options to extend the service contract from March 2025 to March 2035.

(3)	The Cidade de Itajai was converted to an FPSO unit in 2012. The original hull was built in 1985.

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

(5)	In January 2020, we received confirmation from the charterer of the Voyageur Spirit that the FPSO unit would be redelivered to us upon the completion of the contract in April 2020 and the subsequent decommissioning of the unit, which is expected to be completed in June 2020.

(6)	The charterer has termination rights with ten months' notice.

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

During 2019, approximately 43% of our consolidated net revenues were earned by our FPSO units, compared to approximately 42% in 2018 and 45% in 2017. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

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

Shuttle tankers primarily operate in Brazil, the North Sea and off the East Coast of Canada. As of December 31, 2019, we owned 32 shuttle tankers (including seven vessels under construction and the HiLoad DP unit), in which our ownership interests ranged from 50% to 100%, and chartered-in an additional two shuttle tankers. Other shuttle tanker owners include Knutsen, MOL and AET Tankers. We believe that we have competitive advantages in the shuttle tanker market as a result of the quality, type and dimensions of our vessels combined with our market share in the North Sea, Brazil and the East Coast of Canada.

The following tables provide additional information about our shuttle tankers, including newbuildings, as of December 31, 2019:

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Vessel

Capacity (dwt)

Built

Ownership

Positioning System

Operating Region

Contract Type(1)

Charterer

Contract End Date

Scott Spirit

109,300

2011

100%

DP2

North Sea

CoA

Aker BP,BP, ConocoPhillips, Dana, Dea, DNO, Dyas, Enquest, Equinor, Idemitsu,Itacha, Lundin, Molgrowest, Nautical, Neptune, OKEA, OMV, PGING, Premier Oil, Repsol Sinopec, Shell, Taqa Bratani, Total, Verus, Vår Energi, Wintershall Dea (2)

Amundsen Spirit

109,300

2010

100%

DP2

North Sea

CoA

Stena Natalita

108,100

2001

50%(3)

DP2

North Sea

CoA

Navion Oslo

100,300

2001

100%

DP2

North Sea

CoA

Navion Oceania

126,400

1999

100%

DP2

North Sea

CoA

Ingrid Knutsen

111,600

2013

In-chartered (until January 2024)

DP2

North Sea

CoA

Heather Knutsen

148,600

2005

In-chartered (until February 2021)

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

Peary Spirit

109,300

2011

100%

DP2

North Sea

TC

Equinor(4)

March 2023

Nansen Spirit

109,300

2010

100%

DP2

North Sea

TC

Equinor(4)

March 2020

Petroatlantic

93,000

2003

100%

DP2

North Sea

TC

Teekay Corporation

March 2022

Petronordic

93,000

2002

100%

DP2

North Sea

TC

Teekay Corporation

March 2022

Beothuk Spirit

148,200

2017

100%

DP2

Canada

TC

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

May 2030(5)

Norse Spirit

148,200

2017

100%

DP2

Canada

TC

May 2030(5)

Dorset Spirit

148,200

2018

100%

DP2

Canada

TC

May 2030(5)

Navion Anglia

126,400

1999

100%

DP2

Canada

TC

April 2020

Navion Gothenburg

152,200

2006

50%(3)

DP2

Brazil

BB

Petrobras(6)

July 2020

Navion Stavanger

148,700

2003

100%

DP2

Brazil

BB

Petrobras(6)

July 2020

Navion Bergen

105,600

2000

100%

DP2

Brazil

BB

Petrobras

April 2020

Nordic Brasilia

151,300

2004

100%

DP

Far-East

Spot

Nordic Rio

151,300

2004

50%(3)

DP

Far-East

Spot

Aurora Spirit(7)

129,830

2020

100%

DP2

North Sea

NB

Equinor(4)

March 2032

Rainbow Spirit(8)

129,830

2020

100%

DP2

North Sea

NB

Equinor(4)

March 2027

Tide Spirit(9)

129,830

2020

100%

DP2

North Sea

NB

Current Spirit(9)

129,830

2020

100%

DP2

North Sea

NB

Wind Spirit(9)

103,500

2020

100%

DP2

North Sea

NB

Wave Spirit(9)

103,500

2021

100%

DP2

North Sea

NB

Hull 2338(10)

148,200

2022

100%

DP2

Canada

NB

Navion Hispania(11)

126,200

1999

100%

DP2

Lay-up

Stena Sirita(11)

126,900

1999

50%(3)

DP2

Lay-up

HiLoad DP Unit(12)

n/a

2010

100%

DP

Lay-up

Total capacity

4,244,020

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

(2)	Not all of the contracts of affreightment or time-charter customers utilize every ship in the contract of affreightment or time-charter fleet.

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

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

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

(6)	Charterer has the right to purchase the vessel at end of the bareboat charter.

(7)	The vessel was delivered to us in January 2020.

(8)	The vessel was delivered to us in February 2020.

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(9)	The newbuildings will operate in the North Sea contract of affreightment fleet.

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

(11)	Vessel was sold in January 2020.

(12)	Self-propelled DP system that attaches to and keeps conventional tankers in position when loading from offshore installations.

On the Norwegian continental shelf, regulations have been imposed on the operators of offshore fields related to vaporized crude oil that is formed and emitted during loading operations and which is commonly referred to as Volatile Organic Compounds (or VOC). To assist the oil companies in their efforts to meet the regulations on VOC emissions from shuttle tankers, we have played an active role in establishing and participating in a unique co-operation among 22 owners of offshore fields in the Norwegian sector. The purpose of the co-operation is to implement VOC reduction systems on selected shuttle tankers to reduce and report VOC emissions according to Norwegian authorities’ requirements. Currently, we own VOC systems on 14 of our shuttle tankers, including newbuilding vessels on order. The oil companies that participate in the co-operation have also engaged us to undertake the day-to-day administration, technical follow-up and handling of payments through a dedicated clearing house function.

During 2019, approximately 41% of our consolidated net revenues were earned by the vessels in the shuttle tanker segment, compared to approximately 42% in 2018 and 45% in 2017. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

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

FSO Segment

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

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

As of December 31, 2019, we had five FSO units in which our ownership interests ranged from 89% to 100%. 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, 2019:

Vessel

Capacity (dwt)

Built

Ownership

Field name and location

Contract Type

Charterer

Contract End Date

Randgrid (1)(2)

124,500

1995

100%

Gina Krog, Norway

Time charter

Equinor

October 2020

Suksan Salamander (1)(3)

78,200

1993

100%

Bualuang, Thailand

Bareboat

Teekay Corporation

August 2024

Dampier Spirit (1)(3)

106,700

1987

100%

Stag, Australia

Time charter

Jadestone Energy

August 2024

Falcon Spirit (4)

124,500

1986

100%

Al Rayyan, Qatar

Time charter

Qatar Petroleum

May 2022

Apollo Spirit (3)(5)

129,000

1978

89%

Banff, U.K.

Bareboat

Teekay Corporation

July 2020

Total capacity

562,900

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

(2)	The vessel was converted into an FSO unit in 2017.

(3)	Charterer has option to purchase the unit.

(4)	Charterer has early termination rights for an 18-month notice period.

(5)	Charterer is required to charter the vessel for as long as the Petrojarl Banff FPSO unit produces in the Banff field in the North Sea.

During 2019, approximately 12% of our consolidated net revenues were earned by the vessels in the FSO segment, compared to 11% in 2018 and 7% in 2017. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

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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, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs. The UMS is available for world-wide operations, excluding operations on the Norwegian Continental Shelf, and includes a DP3 positioning system that is capable of operating in deep water and harsh weather. The Arendal Spirit is currently in lay-up.

The following table provides additional information about our UMS as of December 31, 2019:

Vessel

Berths

Built

Ownership

Location

Contract type

Arendal Spirit

500

2015

100

%

Norway

Lay-up

During 2019, approximately 0% of our consolidated net revenues was earned by the UMS segment compared to 3% in 2018 and 0% in 2017. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Towage and Offshore Installation Vessels 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, 2019, our towage fleet included ten long-distance towage and offshore installation vessels.

The following table provides additional information about our towage and offshore installation vessels as of December 31, 2019:

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
		2,619

During 2019, approximately 3% of our consolidated net revenues were earned by the vessels in the towage and offshore installation vessels segment compared to 2% in 2018 and 1% in 2017. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Business Strategies

Our primary business strategies include the following:

•

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

•

Focusing on Generating Stable and Recurring Cash Flows from Long-Term Contracts with Creditworthy Customers. We intend to maintain and grow our cash flows by focusing on strong customer relationships and actively seeking the extension and renewal of existing charter contracts, entering into new medium- to long-term fixed-rate charter contracts with current customers, and identifying new business opportunities with other creditworthy customers for our current fleet. By focusing primarily on maximizing returns from our existing asset base, we believe we can generate stable and reliable cash flows while providing customers with quick-to-market and lower

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cost solutions. We believe we are well-positioned to extend contracts and redeploy existing assets by leveraging our engineering and operational expertise with our global marketing organization and extensive customer relationships.

•

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

•	Project Management and Execution of Growth Projects. We continue to focus on executing on our existing shuttle tanker growth projects delivering between now and 2022, to provide stable cash flows.

Customers

Our customers are predominately global energy producers with whom we have long-term, fixed-rate contracts. Our largest customer measured by annual revenue is Shell, which is a global group of energy and petrochemical companies.

Shell and Equinor accounted for approximately 25% and 13%, respectively, of our consolidated revenues during 2019. Shell, Petrobras and Equinor accounted for approximately 23%, 18%, and 13% respectively, of our consolidated revenues during 2018. Shell, Petrobras, Equinor and Premier Oil accounted for approximately 31%, 17%, 10% and 10%, respectively, of our consolidated revenues during 2017. No other customer accounted for 10% or more of such consolidated revenues during 2019, 2018 or 2017.

Safety, Management of Vessel Operations and Administration

Safety and environmental compliance are our top operational priorities. We operate our vessels in a manner intended to protect the safety and health 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, such as groundings, fires, collisions and petroleum spills. Our Quality Assurance and Training Officers (or QATO) program focuses on conducting rigorous internal audits of our processes and provide our seafarers with on-board training. We have a behavior-based safety program called “Safety in Action” to improve the safety culture in our fleet. We are also committed to reducing our emissions and waste generation.

Key performance indicators facilitate regular monitoring of our operational performance. Targets are set on an annual basis to drive continuous improvement, and indicators are reviewed monthly to determine if remedial action is necessary to reach the targets.

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 14001 for Occupational Health and Safety and the Maritime Labor Convention 2006 (or MLC 2006) that became effective in 2013. The management system is certified by DNV-GL. It has also been separately approved by the Australian flag administrations. Although certification is valid for five years, compliance with the above mentioned standards is confirmed on a yearly basis by a rigorous auditing procedure that includes both internal audits as well as external verification audits by DNV-GL and applicable flag states.

We provide expertise in various functions critical to the operations of our vessels. We believe this arrangement affords a safe, efficient and cost-effective operation. Our subsidiaries also provide to us access to human resources, financial and other administrative functions pursuant to administrative services agreements.

Certain of our subsidiaries provide vessel 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 shipyard and projects during new-building and conversions;

•	insurance; and

•	financial management services.

These functions are supported by on-board and on-shore systems for maintenance, inventory, purchasing and budget management. In addition, day-to-day focus on cost control is applied to our operations.

We believe that the generally uniform design of some of our existing vessels and the adoption of common equipment standards provides operational efficiencies, including with respect to crew training and vessel management, equipment operation and repair, and spare parts ordering.

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Risk of Loss, Insurance and Risk Management

The operation of any ocean-going vessel 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. In addition, the transportation of crude oil and petroleum products is subject to the risk of spills and to business interruptions due to political circumstances in foreign countries, hostilities, labor strikes, sanctions and boycotts. The occurrence of any of these events may result in loss of revenues or increased costs.

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. The current range of our coverage for third party liability and pollution is $500 million to $1 billion per vessel per incident. We also carry insurance policies covering war risks (including piracy and terrorism).

Under bareboat charters, the customer is responsible for the insurance of the vessel. We believe that the current insurance coverage is adequate to protect against most of the accident-related risks involved in the conduct of our business and that we maintain appropriate levels of environmental damage and pollution coverage. However, we cannot assure that all covered risks are adequately insured against, that any particular claim will be paid or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future. More stringent environmental regulations at times in the past have resulted in increased costs for, and may result in the lack of availability of, insurance against the risks of environmental damage or pollution. All, but three of our vessels, the Petrojarl Knarr FPSO unit, the Itajai FPSO unit and the Libra FPSO unit, are not insured against loss of revenues resulting from vessel off-hire time, based on the cost of this insurance compared to our off-hire experience.

In Norway, the Norwegian Pollution Control Authority requires the installation of VOC emissions reduction units on most shuttle tankers serving the Norwegian continental shelf. Customers bear the cost of installing and operating the VOC equipment on board the shuttle tankers.

We have achieved certification under the standards reflected in ISO 9001 for quality assurance, ISO 14001 for environment management systems, OHSAS 18001, and the IMO’s International Management Code for the Safe Operation of Ships and Pollution Prevention on a fully integrated basis.

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 applicable classification society certifies that the vessel’s design and build conforms to the applicable class rules and meets the requirements of the applicable rules and regulations of the country of registry of the vessel and the international conventions to which that country is a signatory. The classification society also verifies throughout the vessel’s life that it continues to be maintained in accordance with those rules. To validate this, the vessels are surveyed by the classification society in accordance with the classification society rules, which in the case of our vessels follows a comprehensive five-year special survey cycle, renewed every fifth year. During each five-year period the vessel undergoes annual and intermediate surveys, the scrutiny and intensity of which is primarily dictated by the age of the vessel. We have enhanced the resiliency of the underwater coatings of each vessel hull and marked each vessel hull to facilitate underwater inspections by divers. The vessel's underwater areas are inspected in a dry dock at five year intervals. In-water inspection is carried out during the second or third annual inspection (i.e. during an intermediate survey). UMS, FSO and FPSO units are generally not dry docked; however, we may dry dock FSO units if we desire to qualify them for shipping classification.

In addition to class surveys, the vessel's flag state also verifies the condition of the vessel during annual flag state inspections, either independently or by additional authorization to class. Also, Port State Authorities of a vessel’s port of call are authorized under international conventions 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. DNV-GL typically carries out this task. We also follow an internal process of internal audits undertaken at each office and vessel annually.

We follow a comprehensive inspections scheme supported by our sea staff, shore-based operational and technical specialists and members of our QATO program. We carry out two internal inspections and one internal audit annually, which helps ensure us 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.

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Our customers often carry out inspections under the Ship Inspection Report Program (or SIRE Program), which is a significant safety initiative introduced by Oil Companies International Marine Forum (or OCIMF) to specifically address concerns about sub-standard vessels. The inspection results permit charterers to screen a vessel to ensure that it meets their general and specific risk-based shipping requirements.

We believe that the heightened environmental and quality concerns of insurance underwriters, regulators and charterers will generally lead to greater scrutiny, inspection and safety requirements on all vessels in the oil tanker markets and will accelerate the recycling or phasing out of older vessels throughout these markets.

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

Regulations

General

Our business and the operation of our vessels are significantly affected by international conventions and national, state and local laws and regulations in the jurisdictions in which our vessels operate, as well as in the country or countries of their registration. Because these conventions, laws and regulations change frequently, we cannot predict the ultimate cost of compliance or their impact on the resale price or useful life of our vessels. Additional conventions, laws, and regulations may be adopted that could limit our ability to do business or increase the cost of our doing business and that may materially affect our operations. We are required by various governmental and quasi-governmental agencies to obtain permits, licenses and certificates with respect to our operations. Subject to the discussion below and to the fact that the kinds of permits, licenses and certificates required for the operations of the vessels we own will depend on a number of factors, we believe that we will be able to continue to obtain all permits, licenses and certificates material to the conduct of our operations.

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 oil tankers have been adopted by many of the jurisdictions in which our tanker 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, but not the United States, 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 by discharge of persistent oil (e.g. crude oil, fuel oil, heavy diesel oil or lubricating oil), subject to certain defenses. The right to limit liability to specified amounts that are periodically revised 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 dynamic positioning (or DP) systems, which would apply to shuttle tankers and DP-assisted FSO units 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. For example, 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 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 ships engaged in anchor handling operations and to ships 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.

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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 and the protection of the fuel supply for liquefied gas fuel tanks aimed at preventing explosions, 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 2020 sulphur limit and intend to utilize low or zero sulphur fuel where possible.

As of March 1, 2018, amendments to Annex VI impose 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.

The IMO has issued guidance regarding protecting against acts of piracy off the coast of Somalia. We comply with these guidelines.

The IMO's Ballast Water Management Convention (BWM Convention) entered into force on September 8, 2017 and stipulates two standards for discharged ballast water. The D-1 standard covers ballast water exchange while the D-2 standard covers ballast water treatment. The BWM Convention requires the implementation of either standard. There will be a transitional period from the entry into force to the International Oil Pollution Prevention (or IOPP) renewal survey in which ballast water exchange can be employed. The MEPC agreed to a compromise on the implementation dates for the D-2 discharge standard: ships constructed on or after September 8, 2017 must comply with the D-2 standard upon delivery. Existing ships should be D-2 compliant on the first IOPP renewal following entry into force if the survey is completed on or after September 8, 2019, or a renewal IOPP survey was completed on or after September 8, 2014 but prior to September 8, 2017. Ships should be D-2 compliant on the second IOPP renewal survey after September 8, 2017 if the first renewal survey after that date is completed prior to September 8, 2019 and if the previous two conditions are not met. Vessels will be required to meet the discharge standard D-2 by installing an approved Ballast Water Management System (or BWMS). Pursuant to the BWM Convention amendments that entered into force in October 2019, BWMSs installed on or after October 28, 2020 shall be approved in accordance with BWMS Code, while BWMSs installed before October 23, 2020 must be approved taking into account guidelines developed by the IMO or the BWMS Code. 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.

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

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

As per MSC. 338(91), requirements have been highlighted for audio and visual indicators for breathing apparatus' which will alert the user before the volume of the air in the cylinder has been reduced to no less than 200 liters. This applies to ships constructed on or after July 1, 2014. Ships constructed before July 1, 2014 must have complied no later than July 1, 2019.

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.

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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. Since January 1, 2014, the California Air Resources Board has also required vessels to burn fuel with 0.1% sulphur content or less within 24 nautical miles of California. China also has established emission control areas and continues to establish such areas, restricting the maximum sulphur content of the fuel to be used by vessels within those areas and which limits become progressively stricter over time.

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 (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 has been 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.

China

China has also established ECAs in the Pearl River Delta, the Yangtze River Delta and the Bohai Sea area with restrictions limiting sulphur content not to exceed 0.5% in such ECAs, with such limit decreasing over time.

All the key ports within the three China ECAs (i.e. Tianjin, Qinhuangdao, Tangshan, Huanghua, Shenzhen, Guangzhou, Zhuhai, Shanghai, Ningbo-Zhoushan, Suzhou and Nantong) have implemented the low sulphur bunker requirements.

Commencing January 1, 2018, ships berthing (excluding one hour after berthing and one hour before departure) at all ports within the China ECAs are required to use fuel with sulphur contents at or below 0.5%. These limitations apply to the entire period vessels are in port within China ECAs and became effective January 1, 2019.

On October 23, 2019, the China Maritime Safety Administration issued a notice regarding the implementation of the global sulphur limit. The notice provides in part that beginning January 1, 2020, ships are not permitted to discharge wash water from open loop scrubbers in ECAs. Effective January 1, 2022, the permissible sulphur content will decrease to 0.10%.

North Sea, Canada and Brazil

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

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

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

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

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

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

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

In addition to the regulations imposed by the IMO and EU, countries having jurisdiction over North Sea areas impose regulatory requirements in connection with operations in those areas, including the United Kingdom 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.

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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. Customers bear the cost to install and operate the VOC equipment on board the shuttle tankers.

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

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

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

United States

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

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

 

•	natural resources damages and the related assessment costs;

•	real and personal property damages;

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

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

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

•	loss of subsistence use of natural resources.

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OPA 90 limits the liability of responsible parties in an amount it periodically updates. The liability limits do not apply if the incident was proximately 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. The Coast Guard has announced it intends to propose similar regulations requiring certain vessels to prepare response plans for the release of hazardous substances.

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 incorporated Coast Guard requirements for ballast water exchange and includes specific technology-based requirements for vessels, and includes 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 effective to December 18, 2018. The Vessel Incidental Discharge Act (or VIDA) was signed into law on December 4, 2018, and establishes a new framework for the regulation of vessel incidental discharges under the CWA. VIDA requires the EPA to develop performance standards for incidental discharges, and requires the Coast Guard to develop regulations within two years of the EPA’s promulgation of standards. Under VIDA, all provisions of the Vessel General Permit remain in force and effect as currently written until the Coast Guard regulations are published.

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.

California Biofouling Management Plan requirements are as follows: developing and maintaining a Biofouling Management Plan, developing and maintaining a Biofouling Record Book, mandatory biofouling management of the vessel’s wetted surfaces, mandatory biofouling management for vessels that undergo an extended residency period (i.e. remain in the same location for 45 or more days). All vessel calling at California water were required to submit the "Annual Marine Invasive Reporting Form" by October 1, 2017 and should have CA-Biofouling management plan after a vessel’s first regularly scheduled out-of-water maintenance (i.e. dry dock) after January 1, 2018, or upon delivery on or after January 1, 2018.

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New Zealand

New Zealand's Craft Risk Management Standard (or CRMS) requirements are based on the IMO's guidelines for the control and management of ships' biofouling to minimize the transfer of invasive aquatic species.

Marine pests and diseases brought in on vessel hulls (biofouling) are a threat to New Zealand's marine resources. From May 15, 2018, all vessels arriving in New Zealand will need to have a clean hull. Vessels staying up to 20 days and only visiting designated ports (places of first arrival) will be allowed a slight amount of biofouling. Vessels staying longer and visiting other places will only be allowed a slime layer and goose barnacles.

Greenhouse Gas 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. Although shipping was ultimately not included in the Paris Agreement, it is expected that the adoption of the Paris Agreement may lead to regulatory changes in relation to curbing greenhouse gas emissions from shipping.

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

The EU also has indicated that it intends to propose an expansion of an existing EU emissions trading regime to include emissions of greenhouse gases from vessels, and individual countries in the EU may impose additional requirements. The EU has adopted regulations on the monitoring, reporting and verification (or MRV) of CO2 emissions from vessels (or the MRV Regulation), which entered into force on July 1, 2015. The MRV Regulation aims to quantify and reduce CO2 emissions from shipping and generally requires ship owners and operators to annually monitor, report and verify CO2 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 CO2 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. While the EU was considering a proposal for the inclusion of shipping in the EU Emissions Trading System as from 2021 (in the absence of a comparable system operating under the IMO), it appears that the decision to include shipping may be deferred until 2023.

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.

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.

Vessel Security

The ISPS was adopted by the IMO in December 2002 in the wake of heightened concern over worldwide terrorism and became effective on July 1, 2004. The objective of ISPS is to enhance maritime security by detecting security threats to ships and ports and by requiring the development of security plans and other measures designed to prevent such threats. Each of the existing vessels in our fleet currently complies with the requirements of ISPS and Maritime Transportation Security Act of 2002 (U.S. specific requirements). Procedures are in place to inform the relevant reporting regimes such as Maritime Security Council Horn of Africa (or MSCHOA), the Maritime Domain Awareness for Trade - Gulf of Guinea (or MDAT-GoG), the Information Fusion Center (or IFC) whenever our vessels are calling in the Indian Ocean Region, or West Coast of Africa (or WAC) or SE Asia high risk areas respectively. In order to mitigate the security risk, security arrangements are required for vessels which travel through these high risk areas.

C.	Organizational Structure

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

Please read Exhibit 8.1 to this Annual Report for a list of our subsidiaries as of December 31, 2019.

D.	Properties

Other than our vessels and VOC plants mentioned above, we do not have any material property.

E.	Taxation of the Partnership

United States Taxation

The following is a discussion of the expected material U.S. federal income tax considerations applicable to us. This discussion is based upon provisions of 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 2020, 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 2019. 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 we do not expect that we and our controlled affiliates will, conduct 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 13 – Income Taxes".

Item 4A.	Unresolved Staff Comments

Not applicable.

Item 5.	Operating and Financial Review and Prospects

The following discussion should be read in conjunction with the financial statements and notes thereto. Please read Item 18 - Financial Statements.

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

OVERVIEW

We are a leading international midstream services provider to the offshore oil 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 Republic of the Marshall Islands limited partnership in August 2006 by Teekay Corporation (NYSE: TK), a portfolio manager and project developer in the

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marine midstream market. In September 2017, affiliates of Brookfield Business Partners L.P. (NYSE: BBU) (TSX: BBU.UN) purchased from an affiliate of Teekay Corporation a 49% interest in our general partner and purchased additional common units, representing an approximately 60% interest in our total common units outstanding, 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. In October 2019, we announced that we entered into a merger agreement, pursuant to which Brookfield agreed to acquire all of the outstanding publicly held common units representing limited partner interests in us not already owned by Brookfield. 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 (please see "Significant Developments - Brookfield Merger" below).

We currently operate shuttle tankers, FPSO units, FSO units, a UMS and long-distance towage and offshore installation vessels. As at December 31, 2019, our fleet consisted of 34 shuttle tankers (including seven newbuildings which are scheduled for delivery through 2022, two chartered-in vessels and one HiLoad DP unit), eight FPSO units, five FSO units, ten long-distance towage and offshore installation vessels and one UMS. Our interests in non-chartered-in vessels range from 50% to 100%.

Our near-to-medium term business strategy is primarily to focus on extending contracts and redeploying existing assets on long-term charters, repaying or refinancing scheduled debt obligations and pursuing additional growth projects. Despite the weakness in the global energy and capital markets in recent years, our operating cash flows have increased, 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.

Although global crude oil and gas prices have experienced moderate recoveries since falling from the highs of mid-2014, prices have not returned to those same highs and remain volatile due to global and regional geopolitical, economic and strategic risks and changes. This has affected the energy and capital markets and may also result in our vessels being employed on customer contracts that are cancellable or the failure of customers to exercise charter extension options, potentially resulting in increased off-hire for affected vessels. Conversely, we expect that a continuation of lower oil prices will motivate charterers to use existing FPSO units on new projects, given their lower cost relative to a newbuilding unit. Our operational focus over the short-term is to focus on extending contracts and the redeployment of our assets that are scheduled to come off charter over the next few years.

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

SIGNIFICANT DEVELOPMENTS

Brookfield Merger

In May 2019, we received an unsolicited non-binding proposal from Brookfield to acquire all issued and outstanding publicly held common units representing limited partnership interests of us that Brookfield did not already own in exchange for $1.05 in cash per common unit. The Conflicts Committee of our general partner, consisting only of non-Brookfield affiliated directors, evaluated the proposed offer on behalf of the owners of the non-Brookfield owned limited partnership interests, and on October 1, 2019, we announced that we entered into a Merger Agreement. 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.

Under the terms of the Merger Agreement, a newly formed subsidiary of Brookfield merged with and into us, with us surviving as a wholly owned subsidiary of Brookfield and our general partner and 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 described below. As an alternative to receiving the cash consideration, 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 common units held by Brookfield following the Merger, but have limited voting rights and limited transferability.

As a result of the Merger, Brookfield owns 100% 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 as of the closing of the Merger, are held by the unaffiliated unitholders who elected to receive the equity consideration in respect of their common units. Pursuant to the terms of the Merger Agreement, our outstanding preferred units were unchanged and remain outstanding following the Merger.

Financing

In October 2019, a subsidiary of ours, Teekay Shuttle Tankers L.L.C., placed $125 million of senior unsecured green bonds due in October 2024. The green bonds bear interest at a rate of three-months LIBOR plus 6.50%. We expect to use the proceeds from the bonds to partially fund four LNG-fueled shuttle tanker newbuildings, two of which were delivered to us in early-2020, and the remaining of which are currently under construction with expected deliveries through 2021.

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In October 2019, we secured a $100 million bridge loan to provide pre- and post-delivery financing for a shuttle tanker newbuilding to operate on the East Coast of Canada (see "--Shuttle Tanker Newbuildings" below). The bridge loan matures in August 2022. The debt facility bears interest at a rate of LIBOR plus 2.50% until March 2020 and increases by 25 basis points per quarter thereafter. We intend to refinance the bridge loan into the existing East Coast Canada shuttle tanker financing secured by the three vessels in operation. The facility remains undrawn.

In September 2019, we entered into a sale and leaseback transaction with a third-party that will: provide pre-delivery financing for two shuttle

tanker newbuildings currently under construction; provide for the purchase of the vessels from us for an adjustable purchase price of $107 million per vessel upon their expected deliveries in late-2020 and early-2021, respectively; and provide for the charter of the vessels back to us for ten years, at which point the vessels will be sold back to us. The pre-delivery financing bears interest at a fixed rate of 5.5%, while the post-delivery sale and leaseback transaction is based on an interest rate of LIBOR plus 2.85%.

In September 2019, we completed a $120 million U.S. private placement of 7.107% senior bonds, to be used for general corporate purposes. The bonds reduce over time with semi-annual payments and are due in September 2027.

In September 2019, we amended an existing loan agreement secured by the Arendal Spirit UMS to remove a mandatory prepayment clause

under which the outstanding balance was due on September 30, 2019. The modified debt facility now matures in February 2023.

In September 2019, we extended the maturity date of an existing unsecured revolving credit facility provided by Brookfield, which provides for borrowings of up to $125 million. The amended revolving credit facility matures on October 1, 2020 and bears interest at a rate of LIBOR plus a margin of 7.0% on any drawn amount during the extended term.

In September 2019, Teekay Shuttle Tankers L.L.C. amended its $250 million fixed rate bond agreement to remove a change of control clause in the event of a delisting of our common units. The bonds will be repaid at 101% of par value, rather than 100%, when maturing in August 2022.

In August 2019, we completed a $26 million refinancing of an existing term loan secured by the Suksan Salamander FSO unit, which extended the maturity from August 2019 to August 2022. The new credit facility bears interest at LIBOR plus a margin of 2.90%.

In July 2019, the remaining $75 million principal amount of our outstanding five-year 6.0% senior unsecured bonds matured and was repaid by drawing $75 million under the existing unsecured revolving credit facility provided by Brookfield. At December 31, 2019, the credit facility provided by Brookfield had an undrawn balance of $105 million.

In May 2019, we secured a $450 million revolving credit facility secured by 16 shuttle tankers. The facility was used to refinance an existing revolving credit facility dated September 2017, which bore interest at LIBOR plus a margin of 3.00% and was scheduled to mature in 2022. The new revolving credit facility bears interest at LIBOR plus 2.50% and matures in 2024.

In April 2019, we secured a term loan facility totaling $414 million related to the first four of our seven shuttle tanker newbuildings. The term loan bears interest at LIBOR plus 2.25%, except for one tranche, which is fixed at 4.55%. The term loan reduces over time with semi-annual payments for each of the four shuttle tanker newbuildings and matures in 2032. Each of our subsidiaries that own the four shuttle tanker newbuildings has guaranteed a portion of the term loan relating to the applicable vessel. We drew on this facility in early-May 2019.

In April 2019, we completed a $100 million refinancing of a revolving credit facility related to the Piranema Spirit, Voyageur Spirit and Petrojarl

Varg FPSO units. The revolving credit facility reduces with quarterly repayments and provides for a final balloon payment of $45 million in 2022. The previous credit facility matured at the same time with a final balloon payment of $35 million. We drew on this facility in late-April 2019. The revolving credit facility bears interest at LIBOR plus 3.00%.

Rebranding as Altera Infrastructure

In January 2020, following the closure of the Merger, we announced that we intend to change our name in due course to Altera Infrastructure L.P. and, effective from March 24, 2020, to rebrand the consolidated group of companies under the new umbrella of Altera Infrastructure.

Board of Directors Changes

In January 2020, we announced that David L. Lemmon retired from his position as a member of the board of directors of our general partner, and as a member of the audit committee, compensation committee and conflicts committee. Mr Lemmon was replaced on the audit committee by Bill Utt, the Chairman of the board of directors of our general partner.

In January 2020, we announced that Kenneth Hvid will retire from his position as a member of the board of directors of our general partner on June 17, 2020.

In July 2019, Brookfield appointed Gregory Morrison as a member of the board of directors of our general partner, replacing Walter Weathers, who was appointed by Brookfield in September 2017.

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In March 2019, Teekay Corporation appointed Mr. William L. Transier as a member of the board of directors of our general partner, a member of the conflicts committee and Chairman of the audit committee of our general partner, replacing Mr. John J. Peacock, who was appointed in 2006 and resigned concurrently with Mr. Transier's appointment.

Shuttle Tanker Newbuildings

In January and February 2020, we took delivery of the first two of the six E-Shuttle tanker newbuildings, the Aurora Spirit and the Rainbow Spirit, respectively. The vessels were constructed based on our Shuttle Spirit design, which incorporates technologies intended to increase fuel efficiency and reduce emissions, including LNG fuel and recovered VOC as secondary fuel, as well as battery packs for flexible power distribution and blackout prevention. The vessels will commence operations under an existing master agreement with Equinor in the North Sea.

In August 2019, we entered into a shipbuilding contract with Samsung Heavy Industries Co. Ltd. to construct a shuttle tanker for an estimated

aggregate fully built-up cost of approximately $130 million. The shuttle tanker newbuilding, together with three existing vessels, is expected to operate under the existing contracts with a group of oil companies to provide shuttle tanker services for oil production on the East Coast of Canada. The vessel is expected to be delivered to us in early-2022.

Sale of Vessels

In January 2020, we delivered the 1999-built Navion Hispania shuttle tanker to its buyer for green recycling and received total proceeds of approximately $7 million, which was the approximate carrying value of the vessel.

In January 2020, we delivered the 1999-built Stena Sirita shuttle tanker to its buyer for green recycling and received total proceeds of approximately $6 million, which was the approximate carrying value of the vessel.

In April 2019, we delivered the 1998-built Alexita Spirit shuttle tanker to its buyer for green recycling and received total proceeds of approximately $9 million and recorded a gain on the sale of the vessel of approximately $1 million during the second quarter of 2019.

In April 2019, we delivered the 2001-built Nordic Spirit shuttle tanker to its buyer for green recycling and received total proceeds of approximately $9 million and recorded a gain on the sale of the vessel of approximately $1 million during the second quarter of 2019.

In April 2019, we delivered the Pattani Spirit FSO unit to its buyer for continued operations for total proceeds of approximately $16 million and recorded a gain on the sale of the vessel of approximately $11 million during the second quarter of 2019.

Termination of Cheviot Field Agreement

In June 2019, we announced that an agreement with Alpha Petroleum Resources Limited (or Alpha) relating to the use of the Petrojarl Varg

FPSO unit was terminated as a result of Alpha being unable to satisfy certain conditions precedent, including Alpha providing initial funding to cover life extension and upgrade costs, by the contractual deadline. We are currently pursuing alternative deployment opportunities for the Petrojarl Varg FPSO unit.

Dispute Resolutions

In September 2019, the arbitration hearing relating to claims brought against us by the charterer of the Petrojarl Knarr FPSO unit seeking a reduced purchase price option and certain liquidated damages, concluded. The claim relating to the charterers right to purchase the FPSO at a 20% purchase price discount was denied; however, liquidated damages were awarded to the charterer of the unit, partially offset by damages awarded to us in respect of counterclaims brought against the charterer for their actions. Interest was applied to the awarded amounts resulting in a payment obligation of approximately $25 million, which was settled by us in October 2019.

In September 2019, we resolved an existing dispute with a shipyard, relating to the completion of the conversion of the Randgrid FSO unit and in respect of amounts the shipyard claimed to be owed under disputed variation orders in the amount of approximately $100 million. We made a payment of approximately $22 million in October 2019 in full and final settlement of these claims.

Norwegian Investigation

In January 2020, Økokrim (the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime) and the local Stavanger police raided the premises of our subsidiary Teekay Shipping Norway AS in Stavanger, Norway, based on a search and seizure warrant issued pursuant to suspected violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018. Although we have not identified any such violations and deny the charges, we continue to evaluate any potential liabilities with our advisors.

Our Contracts and Charters

Our primary source of revenues is chartering our vessels and offshore units to our customers. We utilize five primary forms of contracts, consisting of FPSO contracts, CoAs, time-charter contracts, bareboat charter contracts and voyage charter contracts.

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FPSO contracts are generally long-term, fixed-rate contracts, which may also include variable consideration components in the form of expense adjustments or reimbursements, incentive compensation and penalties such as an allowance for us to be compensated for increases in our costs to operate the unit during the term of the contract 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. We 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 also be imposed.

CoAs are priced based on the pre-agreed terms in the agreement for whereby an agreed quantity of cargo is transported over a specified trade route within a given period of time. CoAs typically include the lease of the vessel to the charterer as well as the operation of the vessel, and are satisfied as services are rendered over the duration of the voyage, as measured using the time that has elapsed from commencement of the voyage. 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 (or, collectively, voyage expenses), are our responsibility.

Time charters, whereby vessels or FSO units that we operate and are responsible for crewing, are chartered to customers for a fixed period of time at rates that are generally fixed, but may contain a variable component based on expense adjustments due to changes in inflation indices, interest rates or current market rates or in the form of cost reimbursements for vessel operating expenditures or drydocking expenditures. Additionally, voyage expenses are the responsibility of the customer.

Bareboat charters, whereby customers charter vessels or FSO units for a fixed period of time at rates that are generally fixed, but the customers are responsible for the operation and maintenance of the vessels with their own crew as well as any expenses unique to a particular voyage, including all voyage expenses. 

Voyage charters, which are charters for a specific voyage and are generally for shorter intervals that are priced on a current, or “spot,” market rate. In addition, voyage expenses are our responsibility.

We also generate revenues from the operation of VOC systems on certain of our shuttle tankers, and the management of certain vessels on behalf of the owners or charterers of these assets.

The table below illustrates the primary distinctions among these types of charters and contracts:

	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.

Important Financial and Operational Terms and Concepts

We use a variety of financial and operational terms and concepts. These include the following:

Revenues. Revenues primarily include revenues from FPSO contracts, CoAs, time charters, bareboat charters, voyage charters and management fees. Revenues are affected by charter hire rates, the number of days a vessel operates and the daily production volume and the price of oil, as well as other monthly or annual operational performance measures, on FPSO units. Revenues are also affected by the mix of business between FPSO contracts, CoAs, time charters, bareboat charters and voyage charters. Hire rates for voyage charters are more volatile, as they are typically tied to prevailing market rates at the time of a voyage.

Voyage Expenses. 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. Voyage expenses are typically paid by the customer under time charters and bareboat charters and by the shipowner under CoAs and voyage charters. Voyage expenses are typically added to the hire rates at an approximate cost.

Net Revenues. Net revenues represent revenues less voyage expenses incurred by us. Because the amount of voyage expenses we incur for a particular charter depends upon the type of charter, we use net revenues to improve the comparability between periods of reported revenues that are generated by the different types of charters. We principally use net revenues, a non-GAAP financial measure, because it

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provides more meaningful information to us about the deployment of our vessels and their performance upon time charter equivalent (or TCE) rates, than revenues, the most directly comparable financial measure under U.S. generally accepted accounting principles (or GAAP).

Vessel Operating Expenses. Under all types of charters and contracts for our vessels, except for bareboat charters, we are responsible for vessel operating expenses, which include crewing, repairs and maintenance, ship management services, insurance, stores, lube oils and communication expenses. The two largest components of our vessel operating expenses are crew costs and repairs and maintenance. The strengthening or weakening of the U.S. Dollar relative to foreign currencies may result in significant decreases or increases, respectively, in our vessel operating expenses.

Time-Charter Hire Expenses. Time-charter hire expenses represent the cost to charter-in a vessel for a fixed period of time.

Operating Income. To assist us in evaluating operations by segment, we analyze the income we receive from each segment after deducting operating expenses, but prior to the deduction of interest expense, interest income, income taxes, realized and unrealized gain or loss on derivative instruments, equity income, foreign currency exchange gain or loss, losses on debt repurchases and other income (expenses) - net.

Dry docking. We must periodically dry dock our shuttle tankers and towage and offshore installation vessels for inspection, repairs and maintenance and any modifications to comply with industry certification or governmental requirements. UMS, FSO and FPSO units are generally not dry docked; however, we may dry dock FSO units if we desire to qualify them for shipping classification. Generally, we dry dock each of our shuttle tankers and towage and offshore installation vessels every two and a half to five years, depending upon the type of vessel and its age. We capitalize a substantial portion of the costs incurred during dry docking and amortize those costs on a straight-line basis from the completion of a dry docking over the estimated useful life of the 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. We expense 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, and for annual class survey costs on our FPSO units or our UMS. The number of dry dockings undertaken in a given period and the nature of the work performed determine the level of dry-docking expenditures.

Depreciation and Amortization. Depreciation and amortization expense typically consists of: charges related to the depreciation of the historical cost of our fleet (less an estimated residual value) over the estimated useful lives of the vessels or equipment; and charges related to the amortization of dry-docking expenditures over the estimated useful life of the dry docking.

Calendar-Ship-Days. Calendar-ship-days are the total number of calendar days that our vessels were in our possession during a period. We use calendar-ship-days primarily to highlight changes in vessel operating expenses, time-charter hire expense and depreciation and amortization. Calendar-ship days are based on our owned and chartered-in fleet, including vessels owned by our 50% and 89% owned subsidiaries, but excluding vessels owned by our 50% owned investments in equity-accounted joint ventures.

Items You Should Consider When Evaluating Our Results

You should consider the following factors when evaluating our historical financial performance and assessing our future prospects:

•

The size of and types of vessels in our fleet continues to change. Our results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries and vessel dispositions. Please read “Results of Operations” below for further details about vessel dispositions and deliveries. Due to the nature of our business, we expect our fleet to continue to fluctuate in size and composition.

•

The timing of completion of charter contracts and the redeployment of FPSO units. FPSO units are specialized vessels that have very limited alternative uses and require substantial capital investments prior to being redeployed to a new field and production service contract. Upon the completion of existing charter contracts, FPSO units may remain idle for a period of time until new redeployment opportunities arise, and, at which point, substantial capital upgrades may be required prior to the FPSO unit commencing a new charter contract. One of our FPSO production service contracts will expire in 2020 and, unless extended, a contract will expire in 2021 and a further two contracts will expire in 2022. Any idle time prior to the commencement of a new contract may have an adverse effect on our operating results.

•

Our financial results are affected by fluctuations in currency exchange rates. Under GAAP, all foreign currency-denominated monetary assets and liabilities (such as cash and cash equivalents, restricted cash, accounts receivable, accounts payable and deferred income taxes) are revalued and reported based on the prevailing exchange rate at the end of the period. Fluctuations in the value of the Norwegian Krone, British Pound, Euro, Australian Dollar, Canadian Dollar or Brazilian Real relative to the U.S. Dollar, may result in increased or decreased vessel operating and general and administrative expenses if the strength of the U.S. Dollar declines or increases, respectively, relative to the applicable currency. We periodically enter into foreign currency forward contracts to hedge portions of these forecasted expenditures.

•

Our operations are seasonal and our financial results vary as a consequence of dry dockings. Historically, the utilization of FPSO units and shuttle tankers in the North Sea is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our vessels, units and to offshore oil platforms. Downtime for repairs and maintenance generally reduces oil production and, thus, transportation requirements. In addition, we generally do not earn revenue when our vessels are in scheduled and unscheduled dry docking. Four shuttle tankers are scheduled for dry docking in 2020. From time to time, unscheduled dry dockings may cause additional fluctuations in our financial results.

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•

We do not control access to income generated by our investments in equity-accounted joint ventures. We do not have control over the operations of, nor do we have any legal claim to the revenue and expenses of our investments in, our equity-accounted joint ventures. Consequently, the income generated by our investments in equity-accounted joint ventures may not be available for use by us in the period that such income is generated

We manage our business and analyze and report our results of operations on the basis of our six business segments: the FPSO segment, the shuttle tanker segment, the FSO segment, the UMS segment, the towage and offshore installation vessels segment, and the conventional tanker segment, each of which are discussed below. Due to the redelivery of in-chartered conventional tankers in 2019, we no longer have a conventional tanker segment.

Consolidated Results of Operations

Year Ended December 31, 2019 versus Year Ended December 31, 2018

The following table presents certain of our consolidated operating results for the years ended December 31, 2019 and 2018:

(in thousands of U.S. Dollars, except percentages and per unit data)		Year Ended December 31,
		2019			2018			% Change
GAAP:
Revenues		1,268,000			1,416,424			(10.5	)
Operating (loss) income		(91,037	)		111,737			(181.5	)
Net loss		(350,895	)		(123,945	)		183.1
Limited partners' interest:
Net loss		(378,770	)		(147,141	)		157.4
Net loss per:
Common unit - basic		(0.92	)		(0.36	)		(155.6	)
Common unit - diluted		(0.92	)		(0.36	)		(155.6	)
Non-GAAP:
EBITDA(1)		206,909			466,799			(55.7	)
Adjusted EBITDA(1)		671,898			782,521			(14.1	)

(1)	EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please see "Non-GAAP Financial Measures" below for definitions of these measures and for reconciliations of them with net loss, the most directly comparable financial performance measure calculated and presented in accordance with GAAP.

Revenues. Revenues decreased by $148 million, or 10.5%, for 2019 compared to 2018, primarily due to a $91 million settlement agreement with Petróleo Brasileiro S.A. and certain of its subsidiaries (or Petrobras) in 2018, a $33 million decrease in 2019 due to reduced charter rates under the Piranema Spirit FPSO contract extension and a decrease in the amortization of an in-process revenue contract and a $30 million decrease due to the completion of the Ostras FPSO charter contract in March 2019.

Operating (loss) income. Operating loss increased by $203 million, or 181.5%, for 2019 compared to 2018, primarily due to the $91 million settlement agreement with Petrobras in 2018, a further $26 million decrease in earnings in our operating segments in 2019, primarily related to our FPSO segment (please see "Results by Segment" below) and a $109 million increase in the net write-down of vessels in 2019, partially offset by a $23 million decrease in depreciation and amortization due to the sale of vessels during 2018 and 2019.

Net loss. Net loss increased by $227 million, or 183.1%, for 2019 compared to 2018, primarily due to the $203 million increase in operating loss and a $98 million increase in realized and unrealized losses on derivative instruments, partially offset by the absence in 2019 of $55 million of losses on debt repurchases and a $15 million decrease in income tax expense.

Adjusted EBITDA. Adjusted EBITDA decreased by $111 million, or 14.1%, for 2019 compared to 2018, primarily due to the $91 million settlement with Petrobras in 2018 and a $54 million decrease in earnings in our FPSO segment in 2019, partially offset by a $35 million increase in earnings in our other operating segments in 2019, (please see "Results by Segment" below).

Results by Segment

Certain results of our six business segments are discussed below.

Effective for periods commencing on or after January 1, 2019, management and the chief operating decision maker has changed their primary measure for evaluating segment performance from income from vessel operations to Adjusted EBITDA, which measure is included in the segment discussions below. Adjusted EBITDA has also been presented for the year ended December 31, 2018 to maintain comparability of segment performance between the periods presented below. Please see “Item 18 - Financial Statements: Note 4 - Segment Reporting” for the definition of Adjusted EBITDA and for additional information.

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FPSO Segment

As at December 31, 2019, our FPSO fleet consisted of the Petrojarl Knarr, the Petrojarl Varg, the Rio das Ostras, the Piranema Spirit, the Voyageur Spirit, and the Petrojarl I FPSO units, all of which we own 100%, and the Itajai and the Libra FPSO units, of which we own 50% through our joint ventures with Ocyan S.A. (or Ocyan). The Petrojarl Varg and the Rio das Ostras FPSO units are currently in lay-up and as at December 31, 2019, the Rio das Ostras FPSO unit was classified as held for sale. We also provide management services for three FPSO units owned by certain subsidiaries of Teekay Corporation.

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 and Voyageur Spirit FPSO units operate, 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 Petrojarl I FPSO unit operates under a charter rate profile with a lower day rate during the first 18 months of production, which ended in November 2019. Since November 2019 and during the final three and a half years of the contract, the charter contract has increased to a higher day rate plus an oil price and production tariff. We have accounted for the fixed daily charter rate on a straight-line basis over the duration of the charter contract. 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 vessel operating expenses, since significant components of revenues are earned and vessel operating expenses are incurred in these currencies for our FPSO units.

The following table presents certain of the FPSO segment’s operating results for 2019 and 2018:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
Revenues		492,658			533,186			(7.6	)
Vessel operating expenses		(227,873	)		(214,623	)		6.2
General and administrative(1)		(40,846	)		(34,052	)		20.0
Restructuring charge		—			(1,520	)		(100.0	)
Adjusted EBITDA from equity-accounted joint ventures(2)		97,849			92,637			5.6
Adjusted EBITDA		321,788			375,628			(14.3	)
Depreciation and amortization		(145,935	)		(145,451	)		0.3
Write-down of vessels		(227,382	)		(180,200	)		26.2

(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). See the discussion under “Other Operating Results” below.

(2)	Adjusted EBITDA from equity-accounted vessels represents our proportionate share of Adjusted EBITDA from equity-accounted vessels. See the discussion under “Other Operating Results” below.

Revenues. Revenues decreased by $41 million for 2019 compared to 2018, primarily due to:

•	a decrease of $33 million due to the Piranema Spirit FPSO unit operating at a reduced charter rate under its charter contract extension and a decrease in the amortization of an in-process revenue contract;

•	a decrease of $30 million due to the completion of the charter contract of the Rio das Ostras FPSO unit in March 2019; and

•	a decrease of $14 million primarily due to the outcome of final arbitration during 2019 relating to a claim by the charterer of the Petrojarl Knarr FPSO unit;

partially offset by

•	an increase of $30 million due the commencement of the charter contract of the Petrojarl I FPSO unit in May 2018; and

•	an increase of $6 million due to the timing of recognition of revenues related to the Petrojarl Varg FPSO unit front end engineering design (or FEED) studies and the Cheviot field agreement.

Adjusted EBITDA. Adjusted EBITDA decreased by $54 million for 2019 compared to 2018, primarily due to:

•	a decrease in revenues of $41 million as described above;

•	an increase in vessel operating expenses of $10 million due to the commencement of the charter contract of the Petrojarl I FPSO unit in May 2018;

•	an increase in general and administrative expenses of $7 million (see the discussion under “Other Operating Results” below); and

•	an increase in vessel operating expenses of $6 million due to the timing of recognition of expenses related to the Petrojarl Varg FPSO unit FEED studies and the Cheviot field agreement;

partially offset by

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•	an increase in earnings of $5 million from equity-accounted joint ventures (see the discussion under “Other Operating Results” below).

Write-down of vessels. Write-down of vessels of $227 million for 2019 primarily includes the write-down of one FPSO unit, as a result of a reassessment of the future redeployment assumptions for the unit.

Write-down of vessels of $180 million for 2018 includes write-downs of the Piranema Spirit and Rio das Ostras FPSO units, as a result of a reassessment of the future redeployment assumptions for both units.

Shuttle Tanker Segment

As at December 31, 2019, our shuttle tanker fleet consisted of 26 vessels that operate under fixed-rate contracts of affreightment (or CoAs), time charters and bareboat charters, seven shuttle tanker newbuildings which are expected to deliver from early-2020 through early-2022, and the HiLoad DP unit, which is currently in lay-up. Of these 34 shuttle tankers, four are owned through 50%-owned subsidiaries and two were chartered-in. The remaining vessels are owned 100% by us. In early-2020, we sold two shuttle tankers which were previously in lay-up and we took delivery of two shuttle tanker newbuildings. All of our operating shuttle tankers, with the exception of two shuttle tankers that are currently trading as conventional tankers and the HiLoad DP unit, provide transportation services to energy companies 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 vessel operating expenses, as significant components of revenues are earned and vessel operating expenses 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 2019 and 2018, and compares its net revenues (which is a non-GAAP financial measure) for 2019 and 2018, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the shuttle tanker segment:

		Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)		2019			2018			% Change
Revenues		549,587			636,413			(13.6	)
Voyage expenses		(86,519	)		(109,796	)		(21.2	)
Net revenues		463,068			526,617			(12.1	)
Vessel operating expenses		(126,433	)		(149,226	)		(15.3	)
Time-charter hire expenses		(40,108	)		(36,421	)		10.1
General and administrative(1)		(20,788	)		(21,763	)		(4.5	)
Adjusted EBITDA attributable to non-controlling interests(2)		(10,864	)		(15,593	)		(30.3	)
Adjusted EBITDA		264,875			303,614			(12.8	)
Depreciation and amortization		(134,322	)		(155,932	)		(13.9	)
(Write-down) and gain on sale of vessels		(948	)		(43,155	)		(97.8	)
Calendar-Ship-Days
Owned Vessels		9,345			10,329			(9.5	)
Chartered-in Vessels		787			735			7.1
Total		10,132			11,064			(8.4	)

(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). See the discussion under “Other Operating Results” below.

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

Net revenues. Net revenues decreased by $64 million for 2019 compared to 2018, primarily due to:

•	a decrease of $55 million due to a settlement agreement with Petrobras in relation to the previously-terminated charter contract of the HiLoad DP unit recorded in 2018;

•	a decrease of $18 million relating to the re-deliveries to us of certain vessels during 2018 and 2019 and subsequent sales (offset in vessel operating expenses, as indicated below); and

•	a decrease of $9 million due to lower project revenue;

partially offset by

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•	an increase of $17 million due to the timing of dry-docking of vessels; and

•	an increase of $4 million due to higher CoA utilization and rates

Adjusted EBITDA. Adjusted EBITDA decreased by $39 million for 2019 compared to 2018, primarily due to the net decrease in revenue of $64 million, as described above, partially offset by a decrease in vessel operating expenses of $19 million relating to the re-deliveries to us of certain vessels during 2018 and 2019 and the subsequent sales, which includes non-recurring redelivery and lay-up expenses.

Depreciation and amortization. Depreciation and amortization expense decreased for 2019 compared to 2018, primarily due to the sale of three vessels during 2018 and two vessels during 2019.

(Write-down) and gain on sale of vessels. (Write-down) and gain on sale of vessels of ($43) million for 2018 includes a $19 million write-down of the HiLoad DP unit as a result of a change in the operating plans for the vessel, a $15 million write-down of the Nordic Spirit shuttle tanker and a $15 million write-down of the Stena Spirit shuttle tanker as a result of their charter contract expirations during 2018 and a change in the operating plans for these vessels, partially offset by a $3 million gain on the sale of the Navion Scandia shuttle tanker during 2018 and a $3 million gain on the sale of the Navion Britannia shuttle tanker during 2018.

The average size of our owned shuttle tanker fleet decreased for the year ended 2019 compared to 2018 primarily due to the sales of the Alexita Spirit and Nordic Spirit during 2019 and the Stena Spirit, Navion Scandia and Navion Britannia during 2018. Seven shuttle tanker newbuildings have been excluded from calendar-ship-days, as none of these vessels were yet delivered to us as at December 31, 2019.

FSO Segment

As at December 31, 2019, our FSO fleet consisted of five units that operate under fixed-rate time charters or fixed-rate bareboat charters, for which our ownership interests range from 89% to 100%.

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 vessel operating expenses 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 2019 and 2018:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
Revenues		140,117			136,557			2.6
Voyage expenses		(800	)		(769	)		4.0
Vessel operating expenses		(42,597	)		(42,913	)		(0.7	)
General and administrative(1)		(4,006	)		(2,174	)		84.3
Adjusted EBITDA attributable to non-controlling interests		(500	)		(677	)		(26.1	)
Adjusted EBITDA		92,214			90,024			2.4
Depreciation and amortization		(41,666)			(44,077)			(5.5	)
Gain on sale of vessel		11,206			—			100.0

(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). See the discussion under “Other Operating Results” below.

Revenues and Adjusted EBITDA. Revenues and Adjusted EBITDA increased by $4 million and $2 million, respectively, for 2019 compared to 2018, primarily due to the charter contract extension for the Falcon Spirit FSO unit in October 2018 being accounted for as an operating lease (previously classified as a direct financing lease). The increase in Adjusted EBITDA was primarily due to the increase in revenues, partially offset by a $2 million increase in general and administrative expenses in 2019.

Gain on sale of vessel. The gain on sale of vessel of $11 million for 2019 relates to the sale of the Pattani Spirit FSO unit for proceeds of $16 million upon the completion of its bareboat charter in April 2019.

UMS Segment

As at December 31, 2019, our UMS fleet consisted of one unit, the Arendal Spirit UMS, in which we own a 100% interest.

The UMS is used primarily for offshore accommodation, storage and support for maintenance and modification projects on existing offshore installations, or during the installation and decommissioning of large floating exploration, production and storage units, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs. The UMS is available for world-wide operations, excluding operations within

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the Norwegian Continental Shelf, and includes a DP3 keeping system that is capable of operating in deep water and harsh weather. The Arendal Spirit is currently in lay-up.

The following table presents certain of the UMS segment’s operating results for 2019 and 2018:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
Revenues		2,940			36,536			(92.0	)
Voyage expenses		(76	)		(47	)		61.7
Vessel operating expenses		(1,216	)		(3,679	)		(66.9	)
General and administrative(1)		(6,100	)		(3,547	)		72.0
Adjusted EBTIDA		(4,452	)		29,263			(115.2	)
Depreciation and amortization		(6,612	)		(6,611	)		—
Write-down of vessels		(115,000	)		—			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). See the discussion under “Other Operating Results” below.

Revenues and Adjusted EBITDA. Revenues and Adjusted EBITDA decreased by $34 million for 2019 compared to 2018, primarily due to $36.5 million of revenues recorded in 2018 related to a settlement agreement with Petrobras in relation to the previously-terminated charter contract of the Arendal Spirit UMS.

Write-down of vessels. Write-down of vessels of $115 million for 2019 relates to a write-down of the Arendal Spirit UMS, as a result of a reassessment of the future redeployment assumptions for the unit.

Towage Segment

As at December 31, 2019, our towage vessel fleet consisted of ten long-distance towage and offshore installation vessels. We own a 100% interest in each of the vessels in our towage fleet.

Long-distance towage 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 2019 and 2018, and compares its net revenues (which is a non-GAAP financial measure) for 2019 and 2018, to revenues, the most directly comparable GAAP financial measure, for the same years:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
Revenues		74,726			53,327			40.1
Voyage expenses		(37,530	)		(28,925	)		29.7
Net revenues		37,196			24,402			52.4
Vessel operating expenses		(28,832	)		(27,346	)		5.4
General and administrative(1)		(4,401	)		(3,531	)		24.6
Adjusted EBITDA		3,963			(6,475	)		161.2
Depreciation and amortization		(20,845	)		(20,323	)		2.6

(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). See the discussion under “Other Operating Results” below.

Net revenues and Adjusted EBITDA. Net revenues and Adjusted EBITDA increased by $13 million and $10 million, respectively, for 2019 compared to 2018. The increase in net revenues was primarily due to higher charter rates and higher utilization in the towage fleet as a result of increased demand in the offshore market. The increase in Adjusted EBITDA was primarily due to the increase in net revenues.

Conventional Tanker Segment

During the year ended December 31, 2019, our conventional tanker fleet consisted of two in-chartered conventional tankers, which we redelivered to their owners in March and April 2019, respectively.

The following table presents certain of the conventional tanker segment’s operating results for 2019 and 2018, and compares its net revenues (which is a non-GAAP financial measure) for 2019 and 2018, to revenues, the most directly comparable GAAP financial measure, for the same years:

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		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
Revenues		7,972			21,325			(62.6	)
Voyage expenses		(4,985	)		(12,453	)		(60.0	)
Net revenues		2,987			8,872			(66.3	)
Time-charter hire expenses		(4,319	)		(16,195	)		(73.3	)
General and administrative(1)		(104	)		(360	)		(71.1	)
Adjusted EBITDA		(1,436	)		(7,683	)		(81.3	)

(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). See the discussion under “Other Operating Results” below.

Net revenues. Net revenues decreased by $6 million for 2019 compared to 2018, primarily due to the redelivery of the two in-chartered vessels to their owners in March and April 2019, respectively.

Adjusted EBITDA. Adjusted EBITDA increased by $6 million for 2019 compared to 2018, primarily due to the redelivery of the two in-chartered vessels to their owners in March and April 2019 that were contributing negatively to Adjusted EBITDA.

Other Operating Results

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2019			2018			% Change
General and administrative		(76,245	)		(65,427	)		17.0
Interest expense		(205,709	)		(199,395	)		3.0
Interest income		5,111			3,598			42.0
Realized and unrealized (loss) gain on derivative instruments		(85,195	)		12,808			(765.0	)
Equity income		32,794			39,458			(17.0	)
Foreign currency exchange gain (loss)		2,193			(9,413	)		123.0
Losses on debt repurchases		—			(55,479	)		(100.0	)
Other expense - net		(1,225	)		(4,602	)		(73.0	)
Income tax expense		(7,827	)		(22,657	)		(65.0	)

General and administrative. General and administrative expenses increased to $76 million for 2019, compared to $65 million for 2018. General and administrative expenses increased primarily due to costs associated with the transition of corporate service functions, legal and advisory fees to support the Brookfield Merger (please see Item 5 - Significant Developments: Brookfield Merger) and increased legal fees to support certain claims (please see Item 18 - Financial Statements: Note 14 - Commitments and Contingencies).

Interest expense. Interest expense increased to $206 million for 2019, compared to $199 million for 2018, primarily due to:

•	an increase of $7 million due to the delivery of newbuilding vessels and upgrades in early-2018; and

•	an increase of $3 million due to the drawdown of the $125 million revolving credit facility provided by Brookfield and Teekay Corporation during the second quarter of 2018;

partially offset by

•	a decrease of $4 million due to lower average LIBOR rates during 2019 and repayments made on existing debt facilities.

Realized and unrealized (loss) gain on derivative instruments. Net realized and unrealized (loss) gain on non-designated derivative instruments was ($85) million for 2019 compared to $13 million for 2018. These totals are comprised of net losses on interest rate swaps of ($85) million in 2019 compared to net gains of $18 million in 2018 and net gains on foreign currency forward contracts of $nil in 2019 compared to net losses of ($6) million in 2018.

During 2019 and 2018, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.4 billion and $1.6 billion, respectively, and average fixed rates of approximately 3.6% and 3.5%, respectively. Short-term variable benchmark interest rates during 2019 and 2018 were generally 2.9% or less and as such, we incurred realized losses of $29 million (which includes a $14 million realized loss relating to the partial settlement of certain interest rate swaps) and $38 million (which includes a $16 million realized loss relating to the partial settlement of certain interest rate swaps) during 2019 and 2018, respectively, under the interest rate swap agreements. We also recognized a $113 million increase in unrealized losses on interest rate swaps due to a decrease in long-term LIBOR benchmark rates during the year ended December 31, 2019, compared to an increase during the year ended December 31, 2018.

During 2019 and 2018, we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures in NOK and Euro, which resulted in realized losses of $5 million and $1 million during 2019 and 2018, respectively. We also recognized a $10 million

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increase in the unrealized gain on foreign currency forward contracts mainly due to higher average forward spot rates on foreign currency forward contracts as at December 31, 2019 compared to December 31, 2018.

Please see Item 5 - Critical Accounting Estimates: Valuation of Derivative Instruments, which explains how our derivative instruments are valued, including the significant factors and uncertainties in determining the estimated fair value and why changes in these factors result in material variances in realized and unrealized gains and losses on derivative instruments.

Equity income. Equity income was $33 million for 2019 compared to $39 million for 2018. The decrease in equity income was primarily due to an increase in the unrealized losses on derivative instruments held by the Itajai and Libra FPSO equity-accounted joint ventures.

Foreign currency exchange gain (loss). Foreign currency exchange gain (loss) was $2 million for 2019, compared to ($9) million for 2018. 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 the net realized and unrealized gains (losses) 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 2018, NOK 914 million of our senior unsecured bonds were repurchased resulting in a realized foreign currency exchange gain and an unrealized foreign currency exchange loss of $35 million. In connection with the repurchase, we also settled a portion of our related cross currency swap resulting in a realized foreign currency exchange loss and an unrealized foreign currency exchange gain of $36 million. In January 2019, we repaid our remaining NOK-denominated bonds and settled the related cross currency swaps and, as a result, during 2019 we 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.

Losses on Debt Repurchases. Losses on debt repurchases of $55 million for 2018 relates to the prepayment of the $200 million Brookfield Promissory Note and the repurchases of $225 million of the $300 million five-year senior unsecured bonds that matured in July 2019, and NOK 914 million of the NOK 1,000 million senior unsecured bonds that matured in January 2019. The losses on debt repurchases are comprised of an acceleration of non-cash accretion expense of $32 million (resulting from the difference between the $200 million settlement amount of the Brookfield Promissory Note at its par value and its carrying value of $168 million) and an associated early termination fee of $12 million paid to Brookfield, as well as 2.0% - 2.5% premiums on the repurchase of the bonds and the write-off of capitalized loan costs. The carrying value of the Brookfield Promissory Note was lower than face value due to it being recorded at its relative fair value based on the allocation of net proceeds invested by Brookfield on September 25, 2017.

Income tax expense. Income tax expense was $8 million for 2019 compared to $23 million for 2018. The decrease in income tax expense was primarily due to a lower increase in our valuation allowances on certain Norwegian deferred tax assets associated with our shuttle tanker and FPSO fleet, due to changes in the assumptions for future taxable income.

Year Ended December 31, 2018 versus Year Ended December 31, 2017

The following table presents certain of our consolidated operating results for the years ended December 31, 2018 and 2017:

(in thousands of U.S. Dollars, except percentages and per unit data)		Year Ended December 31,
		2018			2017			% Change
GAAP:
Revenues		1,416,424			1,110,284			27.6
Operating income (loss)		111,737			(116,005	)		196.3
Net loss		(123,945	)		(299,442	)		(59.0	)
Limited partners' interest:
Net loss		(147,141	)		(339,501	)		(57.0	)
Net loss per:
Common unit - basic		(0.36	)		(1.45	)		(75.3	)
Common unit - diluted		(0.36	)		(1.46	)		(75.4	)
Non-GAAP:
EBITDA(1)		466,799			162,618			187.1
Adjusted EBITDA(1)		782,521			522,394			49.8

(1)	EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please see "Non-GAAP Financial Measures" below for definitions of these measures and for reconciliations of them with net loss, the most directly comparable financial measure calculated and presented in accordance with GAAP.

Revenues. Revenues increased by $306 million, or 27.6%, for 2018 compared to 2017, primarily due to a $91 million settlement with Petrobras in 2018, an increase of $71 million due to the gross-up of certain reimbursable operating expenses required by the adoption of Accounting Standards Codification 606, Revenue from Contracts with Customers, an increase of $70 million due to the Randgrid FSO unit commencing

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operations in October 2017, an increase of $48 million due to commencement of the charter contract of the Petrojarl I FPSO unit in May 2018, an increase of $30 million mainly due to the commencement of operations of the East Coast of Canada shuttle tankers, higher average rates in our CoA fleet and rate escalations on certain vessels in our time-charter fleet, an increase of $23 million due to accelerated amortization of an in-process revenue contract relating to the Piranema Spirit FPSO unit and an increase of $15 million due to higher charter rates and higher utilization in the towage fleet as a result of increased demand in the offshore market, partially offset by a decrease of $64 million due to the Voyageur Spirit and Rio das Ostras FPSO units operating at reduced charter rates related to charter contract extensions during 2018.

Operating income. Operating income increased by $228 million, or 196.3%, for 2018 compared to 2017, primarily due to a $195 million increase in earnings in five of our six operating segments in 2018 (please see "Results by Segment" below) and a $95 million decrease in the net write-down of vessels in 2018, partially offset by a $62 million increase in depreciation and amortization primarily due to the Randgrid FSO unit commencing operations in October 2017 and a change in an estimated useful life assumption for our shuttle tankers in 2018.

Net loss. Net loss decreased by $175 million, or 59.0%, for 2018 compared to 2017, primarily due a $228 million increase in operating income, a $56 million increase in realized and unrealized gains on derivative instruments and a $25 million increase in equity income, partially offset by a $52 million increase in losses on debt repurchases, a $45 million increase in interest expense, a $23 million increase in income tax expense and a $19 million increase in other expenses.

Adjusted EBITDA. Adjusted EBITDA increased by $260 million, or 49.8%, for 2018 compared to 2017, primarily due to an increase in earnings in our FPSO, Shuttle Tanker, FSO and UMS segments (please see "Results by Segment" below).

Results by Segment

Certain results of our six business segments are discussed below.

Effective for periods commencing on or after January 1, 2019, management and our chief operating decision maker has changed their primary measure for evaluating segment performance from income from vessel operations to Adjusted EBITDA, which measure is included in the segment discussions below. Adjusted EBITDA has also been presented for the years ended December 31, 2018 and 2017 below to maintain comparability of segment performance between all periods presented in this “Consolidated Results of Operations.” Please see “Item 18 - Financial Statements: Note 4 - Segment Reporting” for the definition of Adjusted EBITDA and for additional information.

FPSO Segment

As at December 31, 2018, our FPSO fleet consisted of the Petrojarl Knarr, the Petrojarl Varg, the Rio das Ostras, the Piranema Spirit, the Voyageur Spirit, and the Petrojarl I FPSO units, all of which we own 100%, and the Itajai and the Libra FPSO units, of which we own 50% through our joint ventures with Ocyan. The Petrojarl Varg was in lay-up as at December 31, 2018. We also provide management services for three FPSO units owned by certain subsidiaries of Teekay Corporation.

The following table presents certain of the FPSO segment’s operating results for 2018 and 2017:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
Revenues		533,186			458,388			16.3
Vessel operating expenses		(214,623	)		(149,153	)		43.9
General and administrative(1)		(34,052	)		(33,046	)		3.0
Restructuring charge		(1,520	)		(450	)		237.8
Adjusted EBITDA from equity-accounted joint ventures(2)		92,637			33,360			177.7
Adjusted EBITDA		375,628			309,099			21.5
Depreciation and amortization		(145,451	)		(143,559	)		1.3
Write-down of vessels		(180,200	)		(265,229	)		(32.1	)

(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). See the discussion under “Other Operating Results” below.

(2)	Adjusted EBITDA from equity-accounted vessels represents our proportionate share of Adjusted EBITDA from equity-accounted vessels. See the discussion under “Other Operating Results” below.

Revenues. Revenues increased by $75 million for 2018 compared to 2017, primarily due to:

•	an increase of $52 million due to the gross-up of certain reimbursable operating expenses required by the adoption of Accounting Standards Codification 606, Revenue From Contracts With Customers (this increase is mostly offset by a corresponding increase in vessel operating expenses);

•	an increase of $48 million due to commencement of the charter contract of the Petrojarl I FPSO unit in May 2018;

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•	an increase of $23 million due to the accelerated amortization of an in-process revenue contract relating to the Piranema Spirit FPSO unit;

•	an increase of $7 million due to revenue received for an offshore field study associated with the Petrojarl Varg FPSO unit that was substantially completed in the first quarter of 2018 (this revenue is offset by a corresponding increase in vessel operating expenses incurred); and

•	an increase of $5 million primarily due to project revenue earned on the Petrojarl Knarr FPSO unit;

partially offset by

•	a decrease of $43 million primarily due to the Voyageur Spirit FPSO unit operating at reduced charter rates related to a charter contract extension from April 2018; and

•	a decrease of $21 million primarily due to a rate reduction on the Rio das Ostras FPSO unit related to its charter extension from January 2018.

Adjusted EBITDA. Adjusted EBITDA increased by $67 million for 2018 compared to 2017, primarily due to:

•	an increase in revenues of $75 million, as described above; and

•	an increase in earnings of $59 million from equity-accounted joint ventures (see the discussion under “Other Operating Results” below);

partially offset by

•	an increase in vessel operating expenses of $50 million due to the gross-up of certain reimbursable operating expenses required by the adoption of Accounting Standards Codification 606, Revenue From Contracts With Customers (this increase is offset by a corresponding increase in revenues); and

•	an increase in vessel operating expenses of $15 million due to the commencement of the charter contract of the Petrojarl I FPSO unit in May 2018.

Write-down of vessels. Write-down of vessels of $180 million for 2018 includes the write-down of the Piranema Spirit FPSO unit and the Rio das Ostras FPSO unit as a result of a reassessment of the future redeployment assumptions for both units. Write-down of vessels of $265 million for 2017 includes the write-down of the Petrojarl I FPSO unit due to increased costs associated with additional upgrade work required and liquidated damages associated with the delay in the commencement of operations of the unit and the write-down of the Rio das Ostras FPSO unit due to a change in the future operating plans for the unit.

Shuttle Tanker Segment

As at December 31, 2018, our shuttle tanker fleet consisted of 26 vessels that operate under fixed-rate CoAs, time charters and bareboat charters, two vessels that were in lay-up, six shuttle tanker newbuildings and the HiLoad DP unit, which is currently in lay-up. Of these 35 shuttle tankers, four are owned through 50%-owned subsidiaries and two were chartered-in. The remaining vessels are owned 100% by us. All of our operating shuttle tankers, with the exception of two shuttle tankers trading as conventional tankers and the HiLoad DP unit, provide transportation services to energy companies in the North Sea, Brazil and the East Coast of Canada. Our shuttle tankers occasionally service the conventional spot tanker market.

The following table presents certain of the shuttle tanker segment’s operating results for 2018 and 2017, and compares its net revenues (which is a non-GAAP financial measure) to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the shuttle tanker segment:

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		Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)		2018			2017			% Change
Revenues		636,413			536,852			18.5
Voyage expenses		(109,796	)		(80,964	)		35.6
Net revenues		526,617			455,888			15.5
Vessel operating expenses		(149,226	)		(129,517	)		15.2
Time-charter hire expenses		(36,421	)		(62,899	)		(42.1	)
General and administrative(1)		(21,763	)		(17,425	)		24.9
Restructuring charge		—			(210	)		(100.0	)
Adjusted EBITDA attributable to non-controlling interests(2)		(15,593	)		(23,035	)		(32.3	)
Adjusted EBITDA		303,614			222,802			36.3
Depreciation and amortization		(155,932	)		(125,648	)		24.1
(Write-down) and gain on sale of vessels		(43,155	)		(51,741	)		(16.6	)
Calendar-Ship-Days
Owned Vessels		10,329			10,322			0.1
Chartered-in Vessels		735			1,248			(41.1	)
Total		11,064			11,570			(4.4	)

(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). See the discussion under “Other Operating Results” below.

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

Net revenues. Net revenues increased by $71 million for 2018 compared to 2017, primarily due to:

•	an increase of $55 million due to a settlement agreement with Petrobras in relation to the previously-terminated charter contract of the HiLoad DP unit recorded in 2018;

•	an increase of $16 million due to the gross-up of certain reimbursable operating expenses required by the adoption of Accounting Standards Codification 606, Revenue From Contracts With Customers (this increase is mostly offset by a corresponding increase in vessel operating expenses);

•	an increase of $14 million due to the commencement of operations of the Beothuk Spirit shuttle tanker newbuilding in late-2017 and the Norse Spirit and Dorset Spirit shuttle tanker newbuildings during 2018, servicing the East Coast of Canada charter contracts; and

•	an increase of $7 million due to higher average rates in our CoA fleet and rate escalations on certain vessels in our time-charter fleet;

partially offset by

•	a decrease of $13 million due to the timing of dry-docking of vessels; and

•	a decrease of $8 million due to the redelivery to us of the Nordic Spirit and Stena Spirit shuttle tanker during the second quarter of 2018 and subsequent sale of the Stena Spirit shuttle tanker in August 2018.

Adjusted EBITDA. Adjusted EBITDA increased by $81 million for 2018 compared to 2017, primarily due to:

•	an increase of $55 million due to a settlement agreement with Petrobras in relation to the previously-terminated charter contract of the HiLoad DP unit recorded in 2018;

•	a decrease in time-charter hire expenses of $26 million primarily due to the re-delivery to the owner of the Jasmine Knutsen in January 2018, which was replaced by the Beothuk Spirit shuttle tanker newbuilding in the East Coast of Canada;

•	a decrease in vessel operating expenses of $7 million primarily due to the timing of repairs and crew composition compared to the prior year; and

•	an increase of $7 million due to higher average rates in our CoA fleet and rate escalations on certain vessels in our time-charter fleet;

partially offset by

•	a decrease of $13 million due to the timing of dry-docking of vessels.

Depreciation and amortization. Depreciation and amortization expense increased by $30 million for 2018 compared to 2017, primarily due to:

•	an increase of $31 million due to a change in the estimated useful life of the tanker component for all shuttle tankers from 25 years to 20 years, effective January 1, 2018, and a decrease in the residual value of certain shuttle tankers;

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•	an increase of $12 million due to the commencement of operations of the Beothuk Spirit shuttle tanker newbuilding in late-2017 and the Norse Spirit and Dorset Spirit shuttle tanker newbuildings during 2018; and

•	an increase of $5 million due to the timing of dry-docking of vessels;

partially offset by

•	a decrease of $13 million mainly due to the write-down of three vessels and the sale of one vessel during 2017 and the write-down of three vessels and sale of three vessels during 2018.

(Write-down) and gain on sale of vessels. (Write-down) and gain on sale of vessels of ($43) million for 2018 includes a $19 million write-down of the HiLoad DP unit as a result of a change in the operating plans for the vessel, a $15 million write-down of the Nordic Spirit shuttle tanker and a $15 million write-down of the Stena Spirit shuttle tanker as a result of their charter contract expirations during 2018 and a change in the operating plans for these vessels, partially offset by a $3 million gain on the sale of the Navion Scandia shuttle tanker during 2018 and a $3 million gain on the sale of the Navion Britannia shuttle tanker during 2018.

(Write-down) and gain on sale of vessels of ($52) million for 2017 includes a $26 million write-down of the HiLoad DP unit as a result of a change in expectations for the future opportunities of the unit, an $11 million write-down of the Nordic Rio shuttle tanker and a $9 million write-down of the Nordic Brasilia shuttle tanker as a result of a change in the operating plans for these vessels due to the redelivery of these vessels from their charterer after completing their bareboat contracts in July 2017 and a $5 million write-down of the Navion Marita shuttle tanker as a result of the expected sale of the vessel in the third quarter of 2017.

The average size of our owned shuttle tanker fleet was consistent for 2018 compared to 2017. The delivery of three newbuilding shuttle tankers in late-2017 and early-2018 was offset by the sale of the Navion Marita, Navion Britannia, Stena Spirit and Navion Scandia shuttle tankers in November 2017, June 2018, August 2018 and November 2018, respectively. Six shuttle tanker newbuildings have been excluded from calendar-ship-days, as these vessels were not yet delivered to us as at December 31, 2018.

FSO Segment

As at December 31, 2018, our FSO fleet consisted of six units that operate under fixed-rate time charters or fixed-rate bareboat charters, for which our ownership interests range from 89% to 100%.

The following table presents certain of the FSO segment’s operating results for 2018 and 2017:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
Revenues		136,557			66,901			104.1
Voyage expenses		(769	)		(1,172	)		(34.4	)
Vessel operating expenses		(42,913	)		(25,241	)		70.0
General and administrative(1)		(2,174	)		(1,864	)		16.6
Adjusted EBITDA attributable to non-controlling interests		(677	)		(879	)		(23.0	)
Adjusted EBITDA		90,024			37,745			138.5
Depreciation and amortization		(44,077)			(19,406)			127.1
Write-down of vessel		—			(1,108	)		(100.0	)

(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). See the discussion under “Other Operating Results” below.

Revenues, Adjusted EBITDA and Depreciation and amortization. Revenues, Adjusted EBITDA and Depreciation and amortization increased by $70 million, $52 million and $25 million, respectively, for 2018 compared to 2017, primarily due to the Randgrid FSO unit commencing operations in October 2017.

UMS Segment

As at December 31, 2018, our UMS fleet consisted of one unit, the Arendal Spirit UMS, in which we own a 100% interest and which was in lay-up as at December 31, 2018.

The following table presents certain of the UMS segment’s operating results for 2018 and 2017:

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		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
Revenues		36,536			4,236			762.5
Voyage expenses		(47	)		(1,152	)		(95.9	)
Vessel operating expenses		(3,679	)		(33,656	)		(89.1	)
General and administrative(1)		(3,547	)		(5,068	)		(30.0	)
Restructuring charge		—			(2,004)			(100.0	)
Adjusted EBTIDA		29,263			(37,644	)		177.7
Depreciation and amortization		(6,611	)		(6,566	)		0.7

(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). See the discussion under “Other Operating Results” below.

Revenues. Revenues increased by $32 million for 2018, compared to 2017, primarily due to $37 million recorded in 2018 related to a settlement agreement with Petrobras in relation to the previously-terminated charter contract of the Arendal Spirit UMS.

Adjusted EBITDA. Adjusted EBITDA increased by $67 million for 2018 compared to 2017, primarily due to the increase in revenues, as described above, a decrease in vessel operating expenses due to the termination of the Arendal Spirit UMS charter contract in April 2017 and the subsequent lay-up of the unit in late-2017, and the remaining deferred mobilization costs of $14 million relating the charter contract recognized during 2017.

Towage Segment

As at December 31, 2018, our towage vessel fleet consisted of ten long-distance towage and offshore installation vessels. Two of the vessels were in lay-up as at December 31, 2018. We own a 100% interest in each of the vessels in our towage fleet. The average number of vessels in our towage fleet increased for 2018 compared to 2017, due to the delivery of three newbuilding vessels in June 2017, October 2017 and February 2018, respectively.

The following table presents certain of the towage segment’s operating results for 2018 and 2017, and compares its net revenues (which is a non-GAAP financial measure) for 2018 and 2017, to revenues, the most directly comparable GAAP financial measure, for the same years:

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
Revenues		53,327			38,771			37.5
Voyage expenses		(28,925	)		(17,727	)		63.2
Net revenues		24,402			21,044			16.0
Vessel operating expenses		(27,346	)		(21,074	)		29.8
Time-charter hire expenses		—			(925	)		(100.0	)
General and administrative(1)		(3,531	)		(4,486	)		(21.3	)
Adjusted EBITDA		(6,475	)		(5,441	)		(19.0	)
Depreciation and amortization		(20,323	)		(15,578	)		30.5

(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). See the discussion under “Other Operating Results” below.

Net revenues and Adjusted EBITDA. Net revenues and Adjusted EBITDA for 2018 were generally consistent compared to 2017.

Depreciation and Amortization. Depreciation and amortization expense increased for 2018 compared to 2017, mainly due to the timing of delivery of newbuilding vessels.

Conventional Tanker Segment

As at December 31, 2018, our conventional tanker fleet consisted of two in-chartered conventional tankers, both of which were trading in the spot conventional tanker market.

The following table presents certain of the conventional tanker segment’s operating results for 2018 and 2017, and compares its net revenues (which is a non-GAAP financial measure) for 2018 and 2017, to revenues, the most directly comparable GAAP financial measure, for the same years:

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		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
Revenues		21,325			14,022			52.1
Voyage expenses		(12,453	)		(359	)		3,368.8
Net revenues		8,872			13,663			(35.1	)
Vessel operating recoveries		—			10			(100.0	)
Time-charter hire expenses		(16,195	)		(16,491	)		(1.8	)
General and administrative(1)		(360	)		(360	)		—
Adjusted EBITDA		(7,683	)		(3,178	)		(141.8	)

(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). See the discussion under “Other Operating Results” below.

    

Net revenues and Adjusted EBITDA. Net revenues and Adjusted EBITDA decreased by $5 million for 2018 compared to 2017, primarily due to the termination of the time-charter contract of the Blue Power in late-2017 and the vessel operating in the spot conventional tanker market during 2018 at lower rates than those received under the time-charter contract.

Other Operating Results

		Year Ended December 31,
(in thousands of U.S. Dollars, except percentages)		2018			2017			% Change
General and administrative		(65,427	)		(62,249	)		5.1
Interest expense		(199,395	)		(154,890	)		28.7
Interest income		3,598			2,707			32.9
Realized and unrealized gain (loss) on derivative instruments		12,808			(42,853	)		129.9
Equity income		39,458			14,442			173.2
Foreign currency exchange loss		(9,413	)		(14,006	)		(32.8	)
Losses on debt repurchases		(55,479	)		(3,102	)		1,688.5
Other (expense) income - net		(4,602	)		14,167			(132.5	)
Income tax (expense) recovery		(22,657	)		98			(23,219.4	)

General and administrative. General and administrative expenses increased to $65 million for 2018, compared to $62 million for 2017. General and administrative expenses increased mainly due to the Randgrid FSO unit commencing operations in the fourth quarter of 2017, partially offset by a decrease in legal fees to support certain claims (please see Item 18 – Financial Statements: Note 14 – Commitments and Contingencies).

Interest expense. Interest expense increased to $199 million for 2018, compared to $155 million for 2017, primarily due to:

•	an increase of $27 million due to the delivery of vessel newbuildings, conversions and upgrades in late-2017 and early-2018;

•	an increase of $15 million due to an increase in the weighted-average interest rate on our existing and refinanced long-term debt, partially offset by a lower average existing and refinanced debt balance; and

•	an increase of $5 million due to the drawdown of the $125 million revolving credit facility provided by Brookfield and Teekay Corporation during the second quarter of 2018;

partially offset by

•	a decrease of $6 million due to non-cash guarantee fees to Teekay Corporation during 2017 associated with the long-term financing for the East Coast of Canada shuttle tanker newbuildings and certain of our interest rate swaps and cross currency swaps, which guarantees were terminated as part of the strategic partnership with Brookfield in September 2017.

Realized and unrealized gain (loss) on derivative instruments. Net realized and unrealized gain (loss) on non-designated derivative instruments were $13 million for 2018 compared to ($43) million for 2017. These totals are comprised of net gains on interest rate swaps of $18 million in 2018 compared to net losses of $45 million in 2017 and net losses on foreign currency forward contracts of $6 million in 2018 compared to net gains of $2 million in 2017.

During 2018 and 2017, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.6 billion and $1.8 billion, respectively, and average fixed rates of approximately 3.5% and 3.4%, respectively. Short-term variable benchmark interest rates during 2018 and 2017 were generally 2.9% or less and 1.8% or less, respectively, and as such, we incurred realized losses of $38 million and $78 million during 2018 and 2017, respectively, under the interest rate swap agreements. The decrease in realized loss was also due to lower settlement fees associated with early terminations of certain interest rate swaps that occurred during 2017. We also recognized

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a $23 million increase in unrealized gains on interest rate swaps due to a higher increase in long-term LIBOR benchmark rates during 2018 compared to those during 2017.

During 2018 and 2017, we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures in NOK and Euro, which resulted in a realized loss of $1 million and a realized gain of $1 million during 2018 and 2017, respectively. The realized amounts were partially offset by a $6 million increase in the unrealized loss on foreign currency forward contracts, mainly due to lower average forward spot rates on existing foreign currency forward contracts as at December 31, 2018 compared to December 31, 2017.

Please see Item 5 - Critical Accounting Estimates: Valuation of Derivative Instruments, which explains how our derivative instruments are valued, including the significant factors and uncertainties in determining the estimated fair value and why changes in these factors result in material variances in realized and unrealized gains and losses on derivative instruments.

Equity income. Equity income was $40 million for 2018 compared to $14 million for 2017. The increase in equity income was primarily due to the commencement of operations of the Libra FPSO unit in the fourth quarter of 2017.

Foreign currency exchange loss. Foreign currency exchange loss was $9 million for 2018, compared to $14 million for 2017. Our foreign currency exchange loss was due primarily to the relevant period-end revaluation of NOK-denominated monetary assets and liabilities for financial reporting purposes and the realized and unrealized gains and losses 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. There were additional realized and unrealized losses of $7 million for 2018 (2017 - losses of $10 million) on all other monetary assets and liabilities.

For 2018, foreign currency exchange loss includes a net foreign exchange loss of $1 million (2017 - gain of $8 million) on the cross currency swaps. The increase in net foreign exchange loss relating to the cross currency swaps is mainly due to unrealized gains recognized during 2017 due to the weakening of the U.S. Dollar against the NOK and lower notional cross currency swap balances in 2018. There was an additional net foreign exchange loss during 2018 of $1 million (2017 - loss of $12 million) on the revaluation and settlement of the NOK-denominated debt.

Losses on debt repurchases. Losses on debt repurchases of $55 million for 2018 relates to the prepayment of the $200 million Brookfield Promissory Note and the repurchases of $225 million of the existing $300 million five-year senior unsecured bonds that matured in July 2019, and NOK 914 million of the existing NOK 1,000 million senior unsecured bonds that matured in January 2019. The losses on debt repurchases are comprised of an acceleration of a non-cash accretion expense of $32 million resulting from the difference between the $200 million settlement amount of the Brookfield Promissory Note at its par value and its carrying value of $169 million, and an associated early termination fee of $12 million paid to Brookfield, as well as 2.0% - 2.5% premiums on the repurchase of the bonds and the write-off of capitalized loan costs. The carrying value of the Brookfield Promissory Note was lower than face value due to it being recorded at its relative fair value based on the allocation of net proceeds invested by Brookfield on September 25, 2017.

Other (expense) income - net. Other (expense) income - net of ($5) million for 2018 mainly relates to the settlement of a claim with Transocean Offshore International Ventures Limited in early-2018 relating to a grounding incident involving one of our towage and offshore installation vessels, the ALP Forward, in August 2016. Other income of $14 million for 2017 was mainly due to a partial reversal of a previously accrued contingent liability associated with the estimated damages from the cancellation of the UMS construction contracts, partially offset by a settlement entered into between CeFront Technology AS (or CeFront) and certain subsidiaries of ours to settle certain outstanding claims against us in September 2017.

Income tax (expense) recovery. Income tax (expense) recovery was ($23) million for 2018 compared to nil for 2017. The increase during 2018 was primarily due to increases in our valuation allowances on certain Norwegian deferred tax assets associated with our shuttle tanker and FPSO fleet, due to changes in the assumptions for future taxable income.

Non-GAAP Financial Measures

To supplement the consolidated financial statements prepared in accordance with GAAP, we have presented EBITDA and Adjusted EBITDA, which are non-GAAP financial measures. EBITDA and Adjusted EBITDA are intended to provide additional information and should not be considered substitutes for net loss or other measures of performance prepared in accordance with GAAP. In addition, these measures do not have standardized meanings, and may not be comparable to similar measures presented by other companies. These non-GAAP 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.

EBITDA represents net loss before interest expense (net), income tax expense and depreciation and amortization. Adjusted EBITDA represents 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 vessel write-downs, gains or losses on sale of vessels, unrealized gains or losses on derivative instruments, foreign exchange gains or losses, losses on debt repurchases, and certain other income or expenses. Adjusted EBITDA also excludes realized gains or losses on interest rate swaps as our management, in assessing performance, views these gains or losses as an element of interest expense, realized gains or losses on derivative instruments resulting from amendments or terminations of the underlying instruments and equity income. Adjusted EBITDA is further adjusted to include our proportionate share of Adjusted EBITDA from our equity-accounted joint ventures and to exclude the non-controlling interests' proportionate share of the Adjusted EBITDA from our consolidated joint ventures. We do not have control over the operations, nor do we have any legal claim to the revenue and expenses of our

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investments in equity-accounted joint ventures. Consequently, the income generated by our investments in equity-accounted joint ventures may not be available for use by us in the period that such income is generated.

The following table reconciles EBITDA and Adjusted EBITDA to net loss for the years ended December 31, 2019, 2018 and 2017:

(in thousands of U.S. Dollars)	Year Ended December 31,
	2019			2018			2017
Net loss	(350,895	)		(123,945	)		(299,442	)
Depreciation and amortization	349,379			372,290			309,975
Interest expense, net of interest income	200,598			195,797			152,183
Income tax expense (recovery)	7,827			22,657			(98	)
EBITDA	206,909			466,799			162,618
Write-down and (gain) on sale vessels	332,125			223,355			318,078
Realized and unrealized loss (gain) on derivative instruments	85,195			(12,808	)		42,853
Equity income	(32,794	)		(39,458	)		(14,442	)
Foreign currency exchange (gain) loss	(2,193	)		9,413			14,006
Losses on debt repurchases	—			55,479			3,102
Other expense (income) - net	1,225			4,602			(14,167	)
Realized (loss) gain on foreign currency forward contracts	(5,054	)		(1,228	)		900
Adjusted EBITDA from equity-accounted vessels(1)	97,849			92,637			33,360
Adjusted EBITDA attributable to non-controlling interests(2)	(11,364	)		(16,270	)		(23,914	)
Adjusted EBITDA	671,898			782,521			522,394

(1)

Adjusted EBITDA from equity-accounted vessels, which is a non-GAAP financial measure and should not be considered as an alternative to equity income or any other measure of financial performance presented in accordance with GAAP, represents our proportionate share of Adjusted EBITDA (as defined above) from equity-accounted vessels. 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 vessels is summarized in the table below:

	Year Ended December 31,
	2019			2018			2017
Equity income	32,794			39,458			14,442
Depreciation and amortization	32,534			30,947			10,719
Net interest expense	19,749			18,585			7,437
Income tax expense	250			442			103
EBITDA from equity-accounted vessels	85,327			89,432			32,701
Add (subtract) specific income statement items affecting EBITDA:
Realized and unrealized loss on derivative instruments	12,527			3,523			70
Foreign currency exchange (gain) loss	(5	)		(318	)		589
Adjusted EBITDA from equity-accounted vessels	97,849			92,637			33,360

(2)

Adjusted EBITDA attributable to non-controlling interests, which is a non-GAAP financial measure and should not be considered as an alternative to non-controlling interests in net loss or any other measure of financial performance presented in accordance with GAAP, 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,
	2019			2018			2017
Net loss attributable to non-controlling interests	(1,384	)		(7,161	)		3,764
Depreciation and amortization	10,525			14,617			13,324
Interest expense, net of interest income	1,470			2,064			1,549
EBITDA attributable to non-controlling interest	10,611			9,520			18,637
Add (subtract) specific income statement items affecting EBITDA:
Write-down of vessels	746			6,711			5,400
Foreign currency exchange loss (gain)	7			39			(123	)
Adjusted EBITDA attributable to non-controlling interests	11,364			16,270			23,914

Liquidity and Capital Resources

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Liquidity and Cash Needs

    

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

As at December 31, 2019, our total consolidated cash and cash equivalents were $199 million, compared to $225 million as at December 31, 2018. Our total liquidity, defined as cash, cash equivalents and undrawn revolving credit facilities, was $304 million as at December 31, 2019, compared to $225 million as at December 31, 2018.

As at December 31, 2019, we had a working capital deficit of $184 million, compared to a working capital deficit of $488 million as at December 31, 2018. Accounts payable and the amounts due to related parties decreased mainly due to the partial repayment of the revolving credit facility provided by Brookfield and the timing of vendor payments. The current portion of long-term debt decreased mainly due to the refinancing of five existing debt facilities and the repayment of certain five-year senior unsecured bonds upon maturity in July 2019, partially offset by the timing of debt repayments during 2019.

Our primary liquidity needs for 2020 are to pay existing, committed capital expenditures, to make scheduled repayments of debt, to pay debt service costs, to make quarterly distributions on outstanding preferred units, to pay operating expenses and dry-docking expenditures, to fund general working capital requirements, to settle claims and potential claims against us and to manage our working capital deficit. As at December 31, 2019, our total future contractual obligations for vessels and newbuildings were estimated to be $693 million, consisting of $519 million (2020), $101 million (2021) and $73 million (2022) related to seven shuttle tanker newbuildings. In April 2019, we secured a $414 million debt facility, which as at December 31, 2019, provided borrowings of $198 million for the newbuilding payments related to four vessels and was fully drawn. In September 2019, we secured $214 million of long-term financing under sale-leaseback transactions, which as at December 31, 2019, provided borrowings of $24 million for the newbuilding payments related to two vessels and was fully drawn. We expect to secure long-term financing related to the remaining vessel.

Primarily as a result of the working capital deficit and committed capital expenditures, over the one-year period following the issuance of our 2019 consolidated financial statements, we will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet our liquidity needs and our minimum liquidity requirements under financial covenants in our credit facilities. Additional potential sources of financing include refinancing or extension of debt facilities and extensions and redeployments of existing assets. We are actively pursuing the funding alternatives described above, which we consider probable of completion based on our history of being able to raise debt and refinance loan facilities for similar types of vessels. We are in various stages of completion on these matters.

Our revolving credit facilities and term loans are described in Item 18 – Financial Statements: Note 8 – Long-Term Debt. Certain of our revolving credit facilities, term loans and bonds contain covenants, debt-service coverage ratio (or DSCR) requirements and other restrictions typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from, among other things: incurring or guaranteeing indebtedness; changing ownership or structure, including mergers, consolidations, liquidations and dissolutions; paying dividends or distributions if we are in default or do not meet minimum DSCR requirements; making capital expenditures in excess of specified levels; making certain negative pledges and granting certain liens; selling, transferring, assigning or conveying assets; making certain loans and investments; or entering into a new line of business. Obligations under our credit facilities are secured by certain vessels, and if we are unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. Should we not meet these financial covenants or should we breach other covenants or DSCR requirements and not remedy the breach within an applicable cure period, if any, the lender may accelerate the repayment of the revolving credit facilities and term loans, thus having an impact on our short-term liquidity requirements and which may trigger cross-defaults or accelerations under other credit facilities. DSCR breaches can be remedied with cash cures by placing funds in escrow. We have two revolving credit facilities and seven term loans that require us to maintain vessel values to drawn principal balance ratios of a minimum range of 100% to 150%. Such requirement is assessed either on a semi-annual or annual basis, with reference to vessel valuations compiled by one or more agreed upon third parties. Should the ratio drop below the required amount, the lender may request us to either prepay a portion of the loan in the amount of the shortfall or provide additional collateral in the amount of the shortfall, at our option. As at December 31, 2019, these hull covenant ratios were estimated to range from 126% to 501% and we were in compliance with the minimum ratios required. The vessel values used in calculating these ratios are the appraised values provided by third parties where available, or prepared by us based on second-hand sale and purchase market data. Changes in the shuttle tanker, towage, UMS, FSO unit or FPSO unit markets could negatively affect these ratios. As at December 31, 2019, we were in compliance with all covenants relating to the credit facilities and consolidated long-term debt.

The passage of climate control legislation or other regulatory initiatives that restrict emissions of greenhouse gases could have a significant financial and operational impact on our business, which we cannot predict with certainty at this time. Such regulatory measures could increase our costs related to operating and maintaining our vessels and require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. In addition, increased regulation of greenhouse gases may, in the long term, lead to reduced demand for oil and reduced demand for our services.

Cash Flows

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

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		Year Ended December 31,
(in thousands of U.S. Dollars)		2019			2018			2017
Net cash flow from operating activities		319,909			280,643			305,200
Net cash flow (used for) from financing activities		(58,018	)		(121,338	)		142,947
Net cash flow used for investing activities		(189,215	)		(176,019	)		(540,140	)

Operating Cash Flows

Net cash flow from operating activities increased to $320 million for 2019, compared to $281 million for 2018, primarily due to changes in non-cash working capital items which contributed $12 million for the year ended December 31, 2019, compared to the use of $83 million for the year ended December 31, 2018. The increase in non-cash working capital items for the year ended December 31, 2019, compared to the same period last year is primarily due to the timing of payments made to vendors and settlements of balances with related parties, partially offset by the timing of payments received from customers.

Net cash flow from operating activities also increased for 2019 compared to 2018 due to:

•the commencement of the Petrojarl I FPSO unit charter contract in May 2018;

•higher utilization and rates of our shuttle tanker CoA fleet and differences in the timing of shuttle tanker dry-docking; and

•higher utilization of our towage fleet as a result of increased demand in the offshore market;

partially offset by

•	a settlement received in 2018 in relation to the previously-terminated charter contracts of the HiLoad DP unit and Arendal Spirit UMS; and

•	the completion of the charter contract of the Rio das Ostras FPSO unit in March 2019 and the Piranema Spirit FPSO unit operating at a reduced charter rate under its charter contract extension during 2019.

Net cash flow from operating activities decreased to $281 million for 2018, compared to $305 million for 2017, primarily due to changes in non-cash working capital items which used $83 million for the year ended December 31, 2018, compared to a contribution of $34 million for the year ended December 31, 2017. The decrease in non-cash working capital items for 2018 compared to 2017 is primarily due to settlements of balances with related parties and the timing of payments made to vendors, partially offset by the timing of payments received from customers.

Net cash flow from operating activities also decreased for 2018 compared to 2017 due to:

•	reduced charter rates earned on two of our FPSO units related to charter contract extensions; and

•	an increase in interest paid due to the refinancing of certain of our debt facilities in late-2017 and 2018 and the delivery of vessel newbuildings, upgrades and conversions in late-2017 and early-2018;

partially offset by

•	a settlement received in 2018 in relation to the previously-terminated charter contracts of the HiLoad DP unit and Arendal Spirit UMS;

•	the commencement of operations of the Randgrid FSO unit in late-2017;

•	the commencement of operations of the Petrojarl I FPSO unit in May 2018;

•	lower operating expenses due to the lay-up of the Arendal Spirit UMS since late-2017;

•	lower time charter hire expense on our shuttle tanker fleet mainly due to the redelivery of the Jasmine Knutsen to its owner in January 2018; and

•	lower repairs and maintenance expenses on our FPSO units and shuttle tanker fleet.

For a further discussion of changes in income statement items described above for our six reportable segments, please read “Results of Operations”.

Financing Cash Flows

We use our revolving credit facilities to finance capital expenditures and for general corporate purposes. Occasionally, we will do this until longer-term financing is obtained, at which time we typically use all or a portion of the proceeds from the longer-term financings to prepay outstanding amounts under the revolving credit facilities. Our proceeds from long-term debt, net of debt issuance costs and prepayments of long-term debt, were $469 million in 2019, $263 million in 2018 and $486 million in 2017.

Net proceeds from the issuance of long-term debt for the year ended December 31, 2019 related to the refinancing of three debt facilities, the drawdown of an existing debt facility, the issuance of $125 million senior unsecured green bonds and the drawdown of one new debt

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facility. These proceeds were used primarily to fund installment payments on the shuttle tanker newbuildings and to fund working capital requirements.

Net proceeds from the issuance of long-term debt for the year ended December 31, 2018, mainly related to the issuance of $700 million five-year 8.5% senior unsecured bonds, net of the repurchase of a portion of our existing bonds, the refinancing of two debt facilities and one revolving debt facility, the drawdown of two existing debt facilities and the drawdown of two new debt facilities. These proceeds were used primarily to fund installment payments on six shuttle tanker newbuildings, to fund the final installment payment on the Dorset Spirit shuttle tanker newbuilding constructed for the East Coast of Canada contract, the final installment payment on the ALP Keeper towage and offshore installation vessel, the Petrojarl I FPSO unit upgrades and to fund working capital requirements.

Net proceeds from the issuance of long-term debt for the year ended December 31, 2017, mainly related to the issuance of $250 million in senior unsecured bonds in the Norwegian bond market, the refinancing of eight debt facilities and the drawdown of three existing debt facilities.

We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments of long-term debt were $410 million in 2019, compared to $567 million in 2018 and $653 million in 2017. Repayments during 2019 included the maturity of our NOK-denominated bonds, certain five-year senior unsecured bonds and one debt facility. Repayments during 2018 included the maturity of one term loan and one revolving credit facility. Repayments during 2017 included the maturity of one revolving credit facility, the refinancing of four debt facilities, the repayment of eight existing debt facilities, four which were subsequently refinanced, and the repayment of a portion of an existing debt facility relating to the Randgrid FSO unit conversion upon delivery of the unit, which was reimbursed by the charterer of the unit.

In September 2019, we secured $214 million of long-term financing under sale-leaseback transactions for two of our shuttle tanker newbuildings, which as at December 31, 2019, provided pre-delivery borrowings of $24 million. During 2019, we drew down $24 million related to this financing.

In March 2018, we entered into a credit agreement for an unsecured revolving credit facility provided by Brookfield and Teekay Corporation, which provides for borrowings of up to $125 million ($25 million by Teekay Corporation and $100 million by Brookfield). During the year ended December 31, 2018, we drew down borrowings of $125 million related to this facility. These proceeds were used primarily to fund working capital requirements. On May 8, 2019, Brookfield acquired from Teekay Corporation its $25 million receivable under this revolving credit facility. During the year ended December 31, 2019, we prepaid $200 million and drew down $95 million related to this revolving credit facility.

In January 2018, we issued 5 million 8.875% Series E Preferred Units in a public offering for net proceeds of $116 million. We used the net proceeds from the public offering for general corporate purposes, which included funding installment payments on newbuildings and upgrade projects and debt repayments.

In 2017, as part of a transaction with Brookfield, we issued 244 million common units and 62 million common unit warrants to Brookfield for gross proceeds of $610 million. In addition, we issued 12 million common units and 3 million common unit warrants to Teekay Corporation for gross proceeds of $30 million. We used a portion of the proceeds to repurchase and subsequently cancel all outstanding Series C-1 and D Preferred Units and the remainder for general corporate purposes, mainly for the funding of newbuilding installments and capital conversion and upgrade projects.

Cash distributions paid to our common and preferred unitholders and our general partner totaled $32 million in 2019, $47 million in 2018 and $61 million in 2017. The decrease in cash distributions paid in 2019 from 2018 was due to a decrease in the quarterly distribution paid on our common units effective from the first quarter of 2019 to nil per common unit compared to $0.01 per common unit paid during 2018, partially offset by an increase in distributions due to the issuance of the Series E Preferred Units during the first quarter of 2018.

The decrease in cash distributions paid in 2018 from 2017 was mainly due to a decrease in the quarterly distribution paid on our common units effective from the third quarter of 2017 to $0.01 per common unit compared to $0.11 per common unit paid during the first and second quarters of 2017 and the repurchase and subsequent cancellation of all outstanding Series C-1 and Series D Preferred Units during the third quarter of 2017; partially offset by an increase in distributions due to the issuance of 256 million common units during the third quarter of 2017 and the issuance of the Series E Preferred Units during the first quarter of 2018.

Subsequent to December 31, 2019, aggregate cash distributions of $8 million for our Series A, Series B and Series E Preferred Units relating to the fourth quarter of 2019 were declared and were paid on February 18, 2020.

Investing Cash Flows

During 2019, net cash flow used for investing activities was $189 million, primarily relating to $215 million of installment payments on the shuttle tanker newbuildings and an $8 million investment in one of our equity-accounted joint ventures, partially offset by proceeds of $33 million from the sale of the Pattani Spirit FSO unit and Alexita Spirit and Nordic Spirit shuttle tankers.

During 2018, net cash flow used for investing activities was $176 million, primarily relating to $234 million of payments for vessels and equipment (including final upgrade costs on the Petrojarl I FPSO unit, final installment payments on the final newbuilding towage and offshore installation vessel, the final East Coast of Canada newbuilding shuttle tanker and installment payments on six shuttle tanker newbuildings) and a $3 million investment in one of our equity-accounted joint ventures, partially offset by $25 million of net cash balances acquired as part of the acquisition of management companies from Teekay Corporation, proceeds of $30 million from the sale of the Navion Scandia, Navion Britannia and Stena Spirit shuttle tankers and scheduled lease payments received of $5 million from leasing our direct financing lease assets.

During 2017, net cash flow used for investing activities was $540 million, primarily relating to $533 million of payments for vessels and equipment (including conversion costs on the Randgrid FSO unit conversion, upgrade costs on the Petrojarl I FPSO unit and installment

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payments on the newbuilding towage and offshore installation vessels, the East Coast of Canada newbuilding shuttle tankers and the two Suezmax DP2 shuttle tanker newbuildings) and $26 million of investments in our equity-accounted joint ventures, partially offset by proceeds of $13 million from the sale of the Navion Marita shuttle tanker and Navion Saga FSO unit and scheduled lease payments received of $6 million from leasing our direct financing lease assets.

Contractual Obligations and Contingencies

The following table summarizes our long-term contractual obligations as at December 31, 2019:

 

		Total			2020			2021			2022			2023			2024			Beyond 2024
		(in millions of U.S. Dollars)
Bond repayments(1)		1,075			—			—			250			700			125			—
Secured debt - scheduled repayments(1)		1,495			314			292			226			197			146			320
Secured debt - repayments on maturity(1)		659			40			24			101			217			182			95
Unsecured revolving credit facility - due to related parties(1)		20			20			—			—			—			—			—
Obligations related to finance leases (1)		24			1			1			1			1			1			19
Chartered-in vessels (operating leases)		78			19			20			20			18			1			—
Office leases		17			3			3			3			2			2			4
Newbuildings committed costs (2)		693			519			101			73			—			—			—
Total contractual obligations		4,061			916			441			674			1,135			457			438

(1)

Our interest-bearing obligations include bonds, commercial bank debt, an unsecured revolving credit facility provided by Brookfield and obligations related to finance leases. Please see Item 18 – Financial Statements: Note 8 – Long-Term Debt, Item 18 – Financial Statements: Note 11 – Related Party Transactions and Balances and Item 18 – Financial Statements: Note 14 – Commitments and Contingencies for the terms upon which future interest payments are determined as well as Item 18 – Financial Statements: Note 12 – Derivative Instruments and Hedging Activities for a summary of the terms of our derivative instruments which economically hedge certain of our floating rate interest-bearing obligations.

(2)	Consists of the estimated remaining payments for the acquisition of seven shuttle tanker newbuildings, one of which delivered in January 2020. Please see Item 18 – Financial Statements: Notes 14c – Commitments and Contingencies.

Off-Balance Sheet Arrangements

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

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with GAAP, which requires us to make estimates in the application of our accounting policies based on our best assumptions, judgments and opinions. 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 GAAP. 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. Accounting estimates and assumptions discussed in this section are those that we consider to be the most critical to an understanding of our financial statements, because they inherently involve significant judgments and uncertainties. For a further description of our material accounting policies, please read Item 18 - Financial Statements: Note 1 - Summary of Significant Accounting Policies.

Revenue Recognition

Description. Each vessel 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 direct financing lease, the lease component of charter hire receipts is allocated to the lease receivable and voyage 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 direct financing 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 FPSO and FSO 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.

Effect if Actual Results Differ from Assumptions. A different assessment of the lease term could result in an operating lease being classified as a direct financing lease or a direct financing 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

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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.

Vessel Lives and Impairment

Description. The carrying value of each of our vessels represents its original cost at the time of delivery or purchase less depreciation and impairment charges. We depreciate the original cost, less an estimated residual value, of our vessels on a straight-line basis over each vessel’s estimated useful life. We continually reassess the estimated useful life of our vessels. The carrying values of our vessels 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.

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 carrying value is greater than the future net undiscounted cash flows the asset is expected to generate over its remaining useful life. For a vessel under charter, the discounted cash flows from that vessel may exceed its market value, as market values may assume the vessel is not employed on an existing charter. If the estimated future net undiscounted cash flows of an asset exceed the asset’s carrying value, no impairment is recognized even though the fair value of the asset may be lower than its carrying value. If the estimated future net undiscounted cash flows of an asset are less than the asset’s carrying value and the fair value of the asset is less than its carrying value, an impairment loss is recognized and the asset is written down to its fair value. Fair value is calculated as the net present value of estimated future cash flows, which, in certain circumstances, will approximate the estimated market value of the vessel.

Our business model is to employ our vessels on fixed-rate contracts with oil companies, typically with terms between three and ten years. Consequently, while the market value of a vessel may decline below its carrying value, the carrying value of a vessel may still be recoverable based on the future net undiscounted cash flows the vessel is expected to obtain from servicing its existing and future contracts.

The following table presents by segment, the aggregate market values and carrying values of certain of our vessels that we have determined have a market value that is less than their carrying value as of December 31, 2019, except vessels operating on contracts where the remaining term is significant and the estimated future net undiscounted cash flows relating to such contracts are sufficiently greater than the carrying value of the vessels, such that we consider it unlikely impairment would be recognized in the following year. Additionally, the following table also includes certain vessels which, although their market value exceeds their carrying value as at December 31, 2019, we consider these vessels at a higher risk of future impairment. Consequently, the vessels included in the following table generally include those vessels employed on single-voyage, or spot charters, as well as those vessels nearing the end of existing charters or other operational contracts or are in lay-up. No impairment has been recognized on any of these vessels as the estimated future net undiscounted cash flows relating to such vessels are greater than their carrying values.

The table is disaggregated for vessels which have estimated future undiscounted cash flows that are marginally or significantly greater than their respective carrying values. Vessels with estimated future undiscounted cash flows significantly greater than their respective carrying values would not necessarily represent vessels that would likely be impaired in the following year. The recognition of impairment in the future for those vessels may primarily depend upon our decision to dispose of the vessel instead of continuing to operate it. In deciding whether to dispose of a vessel, we determine whether it is economically preferable to sell the vessel or to continue to operate it. This assessment includes an estimate of the net proceeds expected to be received if the vessel is sold in its existing condition compared to the present value of the vessel’s estimated future revenues, net of operating costs. Such estimates are based on the terms of the existing charter, charter market outlook and estimated operating costs, given a vessel’s type, condition and age. In addition, we typically do not dispose of a vessel that is servicing an existing customer contract. The recognition of impairment in the future may be more likely for vessels that have estimated future undiscounted cash flows marginally greater than their respective carrying value.

(in thousands of U.S. Dollars, except number of vessels) Reportable Segment		Number of Vessels		Market Values(1) $			Carrying Values $
FPSO Segment(2)		1		133,500			96,167
Towage Segment(2)		1		13,000			16,056
Shuttle Tanker Segment(3)		2		106,400			76,377
FPSO Segment(3)		1		142,000			217,313
Towage Segment(3)		3		46,750			64,070

(1)

Market values are determined using reference to second-hand market comparable values or using a depreciated replacement cost approach as at December 31, 2019. Since vessel values can be volatile, our estimates of market value may not be indicative of the current or future prices we could obtain if we sold any of the vessels. In addition, the determination of estimated market values for our shuttle tankers, FPSO units and towage and offshore installation vessels may involve considerable judgment, given the illiquidity of the second-hand markets for these types of vessels.

The estimated market values for shuttle tankers was based on second-hand market comparable values for conventional tankers of similar age and size, adjusted for shuttle tanker specific functionality. The estimated market value for the FPSO units was based on second-hand market comparable values for similar units. The estimated market values for the towage and offshore installation vessels were based on second-hand market comparable values for towage and offshore installation vessels of similar age and specifications.

(2)	Undiscounted cash flows for these vessels are significantly greater than their carrying values.

(3)	Undiscounted cash flows for these vessels are marginally greater than their carrying values.

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Judgments and Uncertainties. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life to an estimated residual value. FPSO units are depreciated using 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 specific equipment which is depreciated over the expected life of the oil field. The estimated useful life of our FPSO units is reassessed subsequent to a major upgrade being completed. 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 or the estimated useful life of the specific unit. 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 and offshore installation vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard.

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 loss. The estimated useful life of our vessels takes into account design life, commercial considerations and regulatory restrictions. Our estimates of future cash flows involve assumptions about future charter rates, vessel utilization, operating expenses, dry-docking expenditures, vessel residual values or estimated sale proceeds and the remaining estimated 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 operating expenses and dry-docking expenditures are based on historical operating and dry-docking costs and our expectations of future inflation and operating requirements. Vessel residual values are a product of a vessel’s lightweight tonnage and estimated recycling rates. 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 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. If we conclude that a vessel or equipment is impaired, we recognize an impairment loss in an amount equal to the excess of the carrying value of the asset over its fair value at the date of impairment. The written-down amount becomes the new lower cost basis and will result in a lower annual depreciation expense than for periods before the vessel impairment.

Dry docking

Description. We must periodically dry dock our shuttle tankers and towage and offshore installation vessels for inspection, repairs and maintenance and any modifications to comply with industry certification or governmental requirements. UMS, FSO and FPSO units are generally not dry docked; however, we may dry dock FSO units if we desire to qualify them for shipping classification. We capitalize a substantial portion of the costs incurred during dry docking and amortize those costs on a straight-line basis from the completion of a dry docking over the estimated useful life of the 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. We expense 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, and for annual class survey costs on our FPSO units or our UMS.

Judgments and Uncertainties. Amortization of capitalized dry-dock expenditures requires us to estimate the period of the next dry docking or estimated useful life of dry-dock expenditures. While we typically dry dock each shuttle tanker and towage vessel every two and a half to five years, we may dry dock the vessels at an earlier date.

Effect if Actual Results Differ from Assumptions. A change in our estimate of the useful life of a dry dock will have a direct effect on our annual amortization of dry-docking expenditures.

Goodwill

Description. We allocate the cost of acquired companies to the identifiable tangible and intangible assets and liabilities acquired, with the remaining amount being classified as goodwill. Our future operating performance will be affected by the potential impairment charges related to goodwill. Accordingly, the allocation of the purchase price to goodwill may significantly affect our future operating results. Goodwill is not amortized, but reviewed for impairment annually or more frequently if impairment indicators arise. The process of evaluating the potential impairment of goodwill is highly subjective and requires significant judgment at many points during the analysis.

Judgments and Uncertainties. The allocation of the purchase price of acquired companies to goodwill requires management to make significant estimates and assumptions, including estimates of future cash flows expected to be generated by the acquired assets and the appropriate discount rate to value these cash flows. In addition, the process of evaluating the potential impairment of goodwill and intangible assets is highly subjective and requires significant judgment at many points during the analysis. The fair value of our reporting units was estimated based on discounted expected future cash flows using a weighted-average cost of capital rate. The estimates and assumptions regarding expected cash flows and the appropriate discount rates require considerable judgment and are based upon existing contracts, historical experience, financial forecasts and industry trends and conditions.

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As of December 31, 2019, the shuttle tanker segment and the towage and offshore installation vessels segment had goodwill of $127.1 million and $2.0 million, respectively, (2018 - $127.1 million and $2.0 million, respectively) attributable to them. As of the date of this filing, we do not believe that there is a reasonable possibility that the goodwill attributable to these reporting units might be impaired within the next year. However, certain factors that impact this assessment are inherently difficult to forecast and as such we cannot provide any assurances that an impairment will or will not occur in the future. An assessment for impairment involves a number of assumptions and estimates that are based on factors that are beyond our control.

Effect if Actual Results Differ from Assumptions. A change in our assessment for the impairment of goodwill may result in the recognition of an impairment loss in an amount equal to the excess of the carrying value of the reporting unit over its fair value at the date of impairment.

Valuation of Derivative Instruments

Description. Our risk management policies permit the use of derivative financial instruments to manage interest rate and foreign exchange risks. Changes in fair value of derivative financial instruments that are not designated as cash flow hedges for accounting purposes are recognized in earnings.

Judgments and Uncertainties. A substantial majority of the fair value of our derivative instruments and the change in fair value of our derivative instruments from period to period result from our use of interest rate swap agreements. The fair value of our derivative instruments is the estimated amount that we would receive or pay to terminate the agreements in an arm’s length transaction under normal business conditions at the reporting date, taking into account current interest rates, foreign exchange rates and the current credit worthiness of ourselves and the swap counterparties. The estimated amount is the present value of estimated future cash flows, being equal to the difference between the benchmark interest rate and the fixed rate in the interest rate swap agreement, multiplied by the notional principal amount of the interest rate swap agreement at each interest reset date.

The fair value of our interest rate swap agreements at the end of each period is most significantly impacted by the interest rate implied by the benchmark interest rate yield curve, including its relative steepness. Interest rates have experienced significant volatility in recent years in both the short-term and long-term. While the fair value of our interest rate swap agreements is typically more sensitive to changes in short-term rates, significant changes in the long-term benchmark interest rate also materially impact our interest rate swap agreements.

The fair value of our interest rate swap agreements is also impacted by changes in our specific credit risk included in the discount factor. We discount our interest rate swap agreements with reference to the credit default swap spreads of similarly rated global industrial companies and by considering any underlying collateral. The process of determining credit worthiness requires significant judgment in determining which source of credit risk information most closely matches our risk profile.

The benchmark interest rate yield curve and our specific credit risk are expected to vary over the life of the interest rate swap agreements. The larger the notional amount of the interest rate swap agreements outstanding and the longer the remaining duration of the interest rate swap agreements, the larger the impact of any variability in these factors will be on the fair value of our interest rate swaps. We economically hedge the interest rate exposure on a significant amount of our variable rate long-term debt and for long durations. As such, we have historically experienced, and we expect to continue to experience, material variations in the period-to-period fair value of our derivative instruments.

Effect if Actual Results Differ from Assumptions. Although we measure the fair value of our derivative instruments using the inputs and assumptions described above, if we were to terminate the agreements at the reporting date, the amount we would pay or receive to terminate the derivative instruments may differ from our estimate of fair value. If the estimated fair value differs from the actual termination amount, an adjustment to the carrying amount of the applicable derivative asset or liability would be recognized in earnings for the current period. Such adjustments could be material. Please see Item 18 – Financial Statements: Note 12 – Derivative Instruments for the effects on the change in fair value of our derivative instruments on our consolidated statements of loss.

Taxes

Description. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.

Judgments and Uncertainties. The future realization of deferred tax assets depends on the existence of sufficient taxable income of the appropriate character in either the carryback or carryforward period. 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 we were able to realize a net deferred tax asset in the future, in excess of the net 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 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. As at December 31, 2019, we had a valuation allowance of $222.2 million (2018 - $224.6 million).

Item 6.	Directors, Senior Management and Employees

A.	Directors and Senior Management

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Management of Teekay Offshore Partners L.P.

Teekay Offshore GP L.L.C., our general partner, manages our operations and activities. Unitholders generally are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.

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 directors of our general partner oversee our operations. Our general partner has one officer, a Vice President and Company Secretary, but does not have any other officers. In February 2017, the Partnership and its wholly-owned subsidiary, Teekay Offshore Holdings L.L.C. (or Holdco), entered into a services agreement with Teekay Offshore Group Ltd. (or the Service Provider), a subsidiary of Holdco.

Pursuant to the service agreement, the Service Provider provides certain services to us. Please see Item 7- Major Unitholders and Related Party Transactions.

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

Directors of Teekay Offshore GP L.L.C.

The following table provides information about the directors of our general partner, Teekay Offshore GP L.L.C., as at the date of this Annual Report. The business address of each of our directors listed below is c/o 4th Floor, Belvedere Building, 69 Pitts Bay Road, Pembroke, HM 08, Bermuda. Ages of the directors and officers are as of December 31, 2019.

 

Name		Age		Position
Ian Craig		67		Director (1)
Kenneth Hvid		51		Director (2)
Craig Laurie		48		Director (3)
Gregory Morrison		62		Director (4)
Jim Reid		54		Director (5)
William L. Transier		65		Director (6)
Denis Turcotte		58		Director (7)
Bill Utt		62		Chairman of the board of directors (8)

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

(2)	Observer to Compensation Committee. On January 23, 2020, Mr. Hvid announced he will retire from his position on the board of directors effective June 17, 2020.

(3)	Member of Compensation Committee and Corporate Governance Committee.

(4)	Appointed on July 8, 2019, replacing Walter Weathers.

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

(6)	Appointed on March 11, 2019, replacing John Peacock. Member of the Audit Committee (Chair).

(7)	Member of the Corporate Governance Committee and Compensation Committee (Chair).

(8)	Chair of the Corporate Governance Committee and member of Project & Opportunity Review Committee. On January 23, 2020, Mr. Utt was appointed as a member of the Audit Committee.

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

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. He 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.

Kenneth Hvid was appointed President and Chief Executive Officer of Teekay Corporation in February 2017, has served as a director of our general partner since 2011, a director of Teekay Tankers Ltd since February 2017, and a director of Teekay Gas GP L.L.C. since September 2018. Mr. Hvid joined Teekay Corporation in 2000 and was responsible for leading its global procurement activities until he was promoted in

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2004 to Senior Vice President, Teekay Gas Services. During that time, Mr. Hvid was involved in leading Teekay Corporation through its entry and growth in the liquefied natural gas business. He held that position until the beginning of 2006, when he was appointed President of the Teekay Navion Shuttle Tankers and Offshore division. In that role, he was responsible for Teekay Corporation’s global shuttle tanker business as well as initiatives in the floating, storage and offtake business and related offshore activities. Mr. Hvid served as Teekay Corporation’s Chief Strategy Officer and Executive Vice President from 2011 to 2015, as a director of Teekay GP L.L.C. from 2011 to 2015 and as President and Chief Executive Officer of Teekay Offshore Group Ltd., from 2015 to 2016. Mr. Hvid has 30 years of global shipping experience, 12 of which were spent with A.P. Moller in Copenhagen, San Francisco and Hong Kong. In 2007, Mr. Hvid joined the board of Gard P. & I. (Bermuda) Ltd.

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 he has held a number of senior finance positions across the organization, including Chief Financial Officer of Brookfield Business Partners. Prior to joining Brookfield, Mr. Laurie worked in restructuring and advisory services at Deloitte. Mr. Laurie is a Chartered Professional Accountant and holds a Bachelor of Commerce from Queen’s University.

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

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

William L. Transier was appointed as a director of our general partner in March 2019. Mr. Transier is the Chief Executive Officer of Transier Advisors, LLC, an independent advisory firm, and has served as an independent director of Helix Energy Solutions Group since 2000 and as the Chairman of the board of directors since July 2017. Since October 2018, Mr. Transier has also served as a member of the board of directors of Sears Holding Corporation and as a member of its restructuring committee and restructuring subcommittee of the board. Mr. Transier served on the boards of directors of 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., a publicly traded company that was formerly a subsidiary of Helix, from 2006 to 2012, including as the lead director from 2009 to 2012. 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. from 1999 to 2003 and prior to that, he served in various positions of increasing responsibility with Seagull Energy Corporation (a predecessor company to Ocean Energy). Before his tenure with Seagull, 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, an MBA from Regis University, an MA in theological studies from Dallas Baptist University and is a Certified Public Accountant.

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

Bill Utt was appointed Chairman of the board and as a director of our general partner in June 2017. He served as a director of Teekay Corporation from 2015 to 2019 and was appointed as its Chairman of the board of directors from June 2017 until June 2019. Mr. Utt also served as a director of Teekay GP L.L.C., the general partner of Teekay LNG Partners L.P., from 2018 to 2019. From 2014 to 2018, he served as a director of Cobalt International Energy, Inc., including serving as Chairman of the board from 2016 to 2018. Mr. Utt brings over 34 years of engineering and energy industry experience to the board of our general partner. 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, part of the Clayton, Dubilier & Rice, LLC portfolio.

Our Management

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On February 1, 2017, Teekay Offshore Partners L.P. and its wholly-owned subsidiary, Holdco, entered into a service agreement with the Service Provider, a subsidiary of Holdco. 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, 2019:

Name		Age		Position
Ingvild Sæther		51		President and Chief Executive Officer, Teekay Offshore Group Ltd.
Jan Rune Steinsland		59		Chief Financial Officer, Teekay Offshore Group Ltd.
Duncan Donaldson		40		General Counsel, Teekay Offshore Group Ltd.

Ingvild Sæther was appointed President and Chief Executive Officer of Teekay Offshore Group Ltd., a service provider to us, in February 2017. Ms. Sæther joined Teekay Corporation in 2002, as a result of Teekay Corporation's acquisition of Navion AS from Statoil ASA. Since joining Teekay Corporation, Ms. Sæther has held management positions in Teekay Corporation's conventional tanker business until 2007, when she assumed the commercial responsibility for Teekay Corporation’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 Teekay Offshore Group Ltd., a service provider to us, in September 2018. Mr. Steinsland joined Teekay from drilling contractor Songa Offshore SE where he served as Chief Financial Officer from 2013 to 2018. Mr. Steinsland brings 30 years of energy and offshore industry experience. Previous assignments of Mr. Steinsland’s include serving as Chief Financial Officer at drilling contractor Ocean Rig and the financial group Acta Holding, as well as serving in several senior management positions at ExxonMobil. Mr. Steinsland has a Lic. Oec. degree from the University of St. Gallen, Switzerland and is a Certified European Financial Analyst (CEFA).

Duncan Donaldson was appointed General Counsel of Teekay Offshore Group Ltd., a service provider to us, 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, Texas, 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

During 2019, the aggregate amount incurred by the Service Provider for compensation expenses of the individuals identified, excluding any long-term incentive plan awards issued directly by us as described below, was $1.8 million. The amounts were paid primarily in Norwegian Kroner, but are reported here in U.S. Dollars using an average exchange rate of 8.79 Norwegian Kroner for each U.S. Dollar for 2019.

Compensation of Directors

Mr. Kenneth Hvid, the President and Chief Executive Officer of Teekay Corporation and who also serves as director of our general partner, does not receive additional compensation for his service as a director of our general partner. Each of our directors, other than Mr. Hvid, receives compensation for attending meetings of the board of directors, as well as committee meetings. During 2019, each director, other than the Chair and Mr. Hvid, received a director fee of $60,000 for the year and an award of common units with an aggregate maximum value of approximately $75,000 for the year. The Chair received a director fee of $60,000 and an additional annual fee of $47,500 for the year and an award of common units with a value of approximately $107,500 for the year. In addition, members of the audit, conflicts and corporate governance committees each received an additional committee fee of $7,500, $7,500 and $5,000, respectively, for the year, and the chairs of each committee received an additional fee of $17,000, $12,000 and $10,000, respectively, for the year for serving in that role. Each director was also 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 2019, the directors received, in the aggregate, $611,000 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. During the year ended December 31, 2019, a total of 561,420 common units, with an aggregate value of $0.7 million, were granted and issued to the directors of the general partner as part of their annual compensation for 2019.

2006 Long-Term Incentive Plan

Our general partner adopted the Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan for employees and directors of and consultants to our general partner and employees and directors of and consultants to its affiliates, who perform services for us. The plan provides for the award of restricted units, phantom units, unit options, unit appreciation rights and other unit or cash-based awards.

In March 2019, our general partner awarded 2,577,626 restricted units to certain of our employees and employees of Teekay Corporation's subsidiaries who provide services to our business with a grant date fair value of $3.0 million, based on our closing common unit price on the grant date. Prior to completion of the Merger each restricted unit was equal in value to one of our common units plus reinvested distributions

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from the grant date to the vesting date. Subsequent to the Merger each restricted unit that had not vested is expected to be settled as a cash-based award upon vesting.

C.	Board Practices

Teekay Offshore GP L.L.C., our general partner, manages our operations and activities. Unitholders generally are not entitled to elect directors of our general partner or directly or indirectly participate in our management or operation.

The Board currently consists of eight directors. Directors are appointed to serve until their successors are appointed or until they resign or are removed.

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

The Board has the following five committees: Audit Committee, Conflicts Committee, Corporate Governance Committee, Compensation Committee and Project & Opportunity Review Committee. The membership of these committees and the function of each of the committees are described below. The Audit Committee and Conflicts Committee are currently comprised solely of independent directors, and each of the committees operates under a written charter adopted by the Board. Mr. Kenneth Hvid, an officer and employee of Teekay Corporation, is an observer on the Compensation Committee; Mr. Jim Reid, an officer and employee of Brookfield, is an observer on the Audit Committee. The committee charters for the Audit Committee, the Conflicts Committee, the Corporate Governance Committee and the Compensation Committee are available under “Investors – Governance” from the home page of our web site at www.teekayoffshore.com. During 2019, the Board held 15 meetings. All directors attended all board meetings, except for seven meetings where one director did not attend and two meetings where three directors did not attend. All members of the Conflicts Committee attended all meetings, one member of the Corporate Governance Committee did not attend one meeting, one member of the Compensation Committee did not attend one meeting, one member of the Audit Committee did not attend one meeting, and the Project & Opportunity Review Committee did not hold any meetings.

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

The Audit Committee assists the Board 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), with a vacancy due to the retirement of David L. Lemmon on January 23, 2020. There is no observer to the committee. The members of the Conflicts Committee must not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the heightened NYSE and SEC director independence standards applicable to audit committee membership and certain other requirements.

The Conflicts Committee:

•	reviews specific matters that the Board 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 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 composed of directors Bill Utt (Chair), Denis Turcotte and Craig Laurie.

The Corporate Governance Committee:

•	oversees the operation and effectiveness of the Board and its corporate governance; and

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

Compensation Committee. The Compensation Committee of our general partner is composed of at least two directors. This committee is currently comprised of directors Denis Turcotte (Chair) and Craig Laurie. Mr. Hvid is an observer on the Compensation Committee.

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The Compensation Committee:

•	discharges the responsibilities of the Board relating to compensation of the executive officers, if any, of us, our general partner, our key subsidiaries and the Board; and

•	approves and evaluates compensation plans, policies and programs of us and our general partner.

Project & Opportunity Review Committee. The Project & Opportunity Review Committee of our general partner is composed of at least two directors. This committee is currently composed of directors Ian G. Craig (Chair), Jim Reid and Bill Utt. The Project & Opportunity Review Committee reviews in consultation with management, capital projects and other commercial opportunities proposed by management that require the Board’s approval.

D.	Employees

Crewing and Staff

As of December 31, 2019, approximately 1,900 seagoing staff served on our vessels, compared to approximately 2,000 seagoing staff as of December 31, 2018 and approximately 2,100 seagoing staff as of December 31, 2017. As of December 31, 2019, our subsidiaries employed approximately 450 staff who served on shore in technical, commercial and administrative roles in various countries compared to approximately 400 staff as of December 31, 2018 and approximately 53 staff as of December 31, 2017. Teekay Corporation subsidiaries also provided certain on-shore advisory and administrative support to our operating subsidiaries pursuant to service agreements, which are in the process of being transferred or have been transfered to us.

We regard attracting and retaining motivated seagoing personnel as a top priority, and offer seafarers what we believe are highly competitive employment packages and comprehensive benefits and opportunities for personal and career development, which relates to a philosophy of promoting internally.

Substantially all officers and seamen for the Norway-flagged vessels are covered by a collective bargaining agreement with Norwegian unions (Norwegian Maritime Officers’ Association, Norwegian Union of Marine Engineers and the Norwegian Seafarers’ Union). We have entered into a Collective Bargaining Agreement with Sindicato dos Trabalhadores Offshore do Brasil (or SINDITOB), which covers substantially all Brazilian resident offshore employees on board our FPSO units Rio das Ostras and Piranema Spirit. 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). The agreement covers substantially all of the offshore employees on board our FPSO units on the Norwegian Continental Shelf. 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 believe our relationships with these local labor unions are good, with long-term collective bargaining agreements which demonstrate commitment from both parties.

Our commitment to training is fundamental to the development of the highest caliber of seafarers for marine operations. Our cadet training approach is designed to balance academic learning with hands-on training at sea. Teekay Corporation has relationships with training institutions in the Philippines and we have relationships with training institutions in Canada, Norway, Brazil and the United Kingdom. After receiving formal instruction at one of these institutions, cadet training continues on board vessels. We also have a career development plan that was devised to ensure a continuous flow of qualified officers who are trained on our vessels and familiarized with our operational standards, systems and policies. We believe that high-quality crewing and training policies will play an increasingly important role in distinguishing larger independent shipping companies that have in-house or affiliate capabilities from smaller companies that must rely on outside ship managers and crewing agents on the basis of customer service and safety.

E.	Unit Ownership

The following table sets forth certain information regarding beneficial ownership, as of December 31, 2019, of our common units by all the current directors and the senior management of the Service Provider. The information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules, a person beneficially owns any common units that the person has the right to acquire as of February 29, 2020 (60 days after December 31, 2019) through the exercise of any common unit option or other right. Unless otherwise indicated, each person has sole voting and investment power (or shares such powers with his or her spouse) with respect to the common units set forth in the following table. Information for all persons listed below is based on information delivered to us.

Identity of Person or Group		Common Units Owned			Percentage of Common Units Owned(1)
All directors and senior management employees as a group __(11 persons)		312,141			0.08	%

(1)	Excludes the 0.76% general partner interest held by our general partner, a 100%-owned subsidiary of Brookfield.

Item 7.	Major Unitholders and Related Party Transactions

A.	Major Unitholders

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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. The number of common units beneficially owned by each person is determined under SEC rules and the information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules a person beneficially owns any common units as to which the person has or shares voting or investment power. In addition, a person beneficially owns any units that the person or entity has the right to acquire as of the date 60 days after the date of this Annual Report through the exercise of any common unit option or other right. 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%

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(1)	Excludes the 0.76% 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 held a 100% interest in our general partner.

B.	Certain Relationships and Related Party Transactions

Certain Relationships

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

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

Kenneth Hvid is a director of our general partner. Mr. Hvid is also the President and Chief Executive Officer of Teekay Corporation. Transactions and relationships between Teekay Corporation and us are described below.

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 2018.

Bill Utt is a director of our general partner and of BrandSafway, part of the Clayton, Dubilier & Rice, LLC portfolio. Brookfield Business Partners L.P. has agreed to purchase from Clayton, Dubilier & Rice, LLC a 45% interest in BrandSafway.

Transactions with Brookfield

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 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. For additional information about the Merger, please see Item 5--Operating and Financial Review and Prospects-- Management’s Discussion and Analysis of Financial Condition and Results of Operations--Significant Developments--Brookfield Merger.

2017 Brookfield Transactions

In September 2017, we entered into a strategic partnership (or the Brookfield Transaction) with Brookfield, which included the following transactions, among others:

a.Investment and Related Transactions

Brookfield and Teekay Corporation invested $610.0 million and $30.0 million, respectively, in us in exchange for 244.0 million and 12.0 million common units, respectively, at a price of $2.50 per common unit, and 62.4 million (or the Brookfield Purchased Warrants)

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and 3.1 million common unit warrants, respectively, with an exercise price of $0.01 per unit and which warrants were exercisable at any time until September 25, 2024 if our common unit volume-weighted average price was equal to or greater than $4.00 per unit (or the Threshold Price) for 10 consecutive trading days prior to that date.

Brookfield acquired from Teekay Corporation a 49.0% interest in our general partner in exchange for $4.0 million and an option (or the Option), which it exercised in July 2018, to purchase an additional 2.0% interest in our general partner from Teekay Corporation in exchange for 1.0 million of the Brookfield Purchased Warrants.

Brookfield acquired, from a subsidiary of Teekay Corporation, the $200 million promissory note originally issued by us to such subsidiary in July 2016 and which promissory note was amended and restated (or the Brookfield Promissory Note) in connection with the acquisition by Brookfield to, among other things, extend its maturity date from 2019 to 2022. Brookfield purchased the promissory note from Teekay Corporation for $140.0 million in cash and 11.4 million of the Brookfield Purchased Warrants. As described below, in July 2018 Brookfield exchanged the Brookfield Promissory Note for certain of our 8.5% senior unsecured bonds due 2023.

 

We repurchased and canceled all of our outstanding Series C-1 and Series D preferred units from existing unitholders, for an aggregate of approximately $250.0 million in cash, and at a price per Series C-1 Preferred Unit of $18.20 and per Series D Preferred Unit of $23.75 per unit, plus, in each case, any accrued and unpaid quarterly distributions. As part of such repurchases, we paid to Teekay Corporation an aggregate amount of $24.7 million as a holder of repurchased Series D Preferred Units. Concurrently, the per unit exercise price of our Series D tranche B warrants to purchase common units (which were issued in June 2016 as part of our Series D Preferred Unit financing, and a portion of which warrants were held by Teekay Corporation) was reduced from $6.05 to $4.55.

b.General Partner Agreement

The amended and restated limited liability company agreement of our general partner, as amended (or the GP LLC Agreement), which governs certain affairs of our general partner and certain rights and obligations among its owners.

Under the GP LLC Agreement, except as otherwise provided therein, directors of our general partner are elected (and removed and replaced, if applicable) by members holding a majority of the outstanding equity interests. Affiliates of Brookfield hold 100% of the outstanding equity interests of our general partner and are entitled to elect the directors of our general partner, provided that under the GP LLC Agreement, Teekay Corporation has the right to elect one director until the earlier of (x) May 8, 2020 or (y) the date of termination of the License Agreement (as defined below).

The GP LLC Agreement provides, among other things that, until the directors elected by Brookfield TOGP constitute a majority of the board of directors, our general partner and we will not engage in certain actions without Brookfield TOGP’s consent, which actions include, among others and in each case subject to specified exceptions, (i) authorizing, issuing, splitting, combining or reclassifying equity securities of our general partner or us, (ii) incurring indebtedness in excess of $50 million, (iii) amending the organizational documents or specified corporate policies of our general partner or us, (iv) entering into a transaction with any affiliate of ours in excess of $1 million, (v) entering into acquisition or divestment transactions, or making capital expenditures, in each case, in excess of $50 million, (vi) entering into, amending, waiving or terminating contracts in excess of $50 million or certain other contracts, (vii) commencing or settling litigation or dispute resolution proceedings in excess of $5 million, (viii) entering into any merger, business combination or spin-off transaction or taking any other action that requires the approval of the holders of our common units, (ix) increasing or decreasing the size of our general partner’s board of directors, (xi) making material changes to the employment of certain officers, (x) effecting any material change in the nature of our business or operations, (xi) approving a business plan or annual budget of ours involving an increase in expenditures in excess of 5% over the prior fiscal year, (xii) declaring or paying dividends or distributions on equity securities of our general partner or us, or (xiii) redeeming, purchasing or otherwise acquiring equity securities of our general partner or us.

c.Trademark License Agreement

We and Teekay Corporation entered into a trademark license agreement (or the License Agreement), pursuant to which Teekay Corporation granted to us a license to use certain intellectual property, including trademarks and service marks owned by Teekay Corporation and its subsidiaries, for no fee in connection with our business, subject to our compliance with Teekay Corporation’s quality control standards, applicable legal requirements and other conditions, including operation of our business consistent with certain key performance indicators applicable to Teekay Corporation public company subsidiaries. The License Agreement also contains covenants regarding the protection of Teekay Corporation’s intellectual property rights, indemnification obligations of us with respect to our use of the licensed marks, termination, and other customary provisions.

d.Services Agreements

Until December 31, 2017, Teekay Corporation and its wholly-owned subsidiaries directly and indirectly provided, pursuant to various services agreements, a majority of our operating subsidiaries’ commercial, technical, crew training, strategic, business development, securities law compliance and administrative service needs. In connection with the Brookfield Transaction, Teekay Corporation agreed to transfer to us the Teekay Corporation subsidiaries that are devoted exclusively or nearly exclusively to providing services to us and our subsidiaries pursuant to the services agreements. On January 1, 2018, we acquired a 100% ownership interest in seven subsidiaries of Teekay Corporation for cash consideration of $1.4 million, which subsidiaries provide ship management, commercial, technical, strategic, business development and administrative services, primarily related to our operating subsidiaries’ FPSO units, shuttle tankers and FSO units. Teekay Corporation continues to provide to us certain services, and since January 1, 2018, we provide to Teekay Corporation certain services, including those relating to its FPSO units.

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Because prior to January 1, 2018, certain people providing services to us and our subsidiaries previously were employees of various subsidiaries of Teekay Corporation, their compensation (other than any awards under our long-term incentive plan) prior to January 1, 2018 was set and paid by the Teekay Corporation subsidiary that employed them. These persons included Ingvild Sæther, the President and CEO of Teekay Offshore Group Ltd. and other executives of that entity. Pursuant to our services agreements with Teekay Corporation and its subsidiaries, we agreed to reimburse Teekay Corporation for time spent by such persons on providing services to us and our subsidiaries. These reimbursements are in addition to other fees paid under the various services agreements with Teekay Corporation. Please read Item 18. - Financial Statements: Note 11 - Related Party Transactions and Balances for further information.

e.Registration Rights Agreement

In connection with the Brookfield Transaction, we, Brookfield TOLP and Teekay Corporation entered into a registration rights agreement relating to the registration under the U.S. Securities Act of 1933, as amended, of certain common units and warrants. During the period the registration rights agreement is in effect, Brookfield and Teekay Corporation will suspend our general partner’s existing registration rights under our partnership agreement. The registration rights agreement provides each of Brookfield TOLP and Teekay Corporation with the right to include our common units held by them as of the closing of the Brookfield Transaction (including common units issuable upon the exercise of warrants issued to them in the Brookfield Transaction). In any registration statement filed by us in connection with a public offering of our common units or securities convertible into, or exchangeable for, common units, subject to customary exceptions and limitations. The registration rights agreement provides that registration expenses, including the reasonable fees and expenses of any counsel on behalf of the holders of the securities to be registered, will be borne by us.

f.Loan from Brookfield

Please read Item 18. - Financial Statements: Note 11(j) - Related Party Transactions and Balances for a description of a $125 million revolving credit agreement we entered into with Brookfield.

2018 Purchase of Senior Unsecured Bonds by Brookfield

Please read Item 18. - Financial Statements: Note 11(k) - Related Party Transactions and Balances for a description of Brookfield’s purchase from us in July 2018 of $500 million principal amount of our 8.50% senior unsecured bonds due 2023, and related transactions.

Omnibus Agreement

In connection with our initial public offering in 2006, we and our general partner entered into an omnibus agreement with Teekay Corporation, Teekay LNG Partners L.P. and related parties. The following discussion describes certain provisions of the omnibus agreement, as it has been amended.

Noncompetition. Under the omnibus agreement, Teekay Corporation and Teekay LNG Partners L.P. have agreed, and have caused their controlled affiliates (other than us) to agree, not to own, operate or charter certain “Offshore Assets” (including shuttle tankers, FSO units and FPSO units). This restriction does not prevent Teekay Corporation, Teekay LNG Partners L.P. or any of their other controlled affiliates from, among other things:

•	owning, operating or chartering Offshore Assets if the remaining duration of the time charter or contract of affreightment for the vessel, excluding any extension options, is less than three years; or

•	acquiring, operating or chartering Offshore Assets if our general partner has previously advised Teekay Corporation or Teekay LNG Partners L.P. that the board of directors of our general partner has elected, with the approval of its Conflicts Committee, not to cause us or our subsidiaries to acquire or operate the vessels.

In addition, under the omnibus agreement we have agreed not to own, operate or charter crude oil tankers or liquefied natural gas (or LNG) carriers. This restriction does not prevent us from, among other things, acquiring, operating or chartering oil tankers or LNG carriers if Teekay Corporation or Teekay LNG Partners L.P., respectively, has previously advised our general partner that it has elected not to acquire or operate those vessels.

Rights of First Offer on Conventional Tankers, LNG Carriers and Offshore Vessels. Under the omnibus agreement, we have granted to Teekay Corporation and Teekay LNG Partners L.P. a 30-day right of first offer on certain (a) sales, transfers or other dispositions of any Aframax tankers, in the case of Teekay Corporation, or certain LNG carriers in the case of Teekay LNG Partners L.P., or (b) re-charterings of any Aframax tankers or LNG carriers pursuant to a time charter or contract of affreightment with a term of at least three years if the existing charter expires or is terminated early. Likewise, each of Teekay Corporation and Teekay LNG Partners L.P. has granted a similar right of first offer to us for any Offshore Vessels it might own that, at the time of the proposed offer, is subject to a time charter or contract of affreightment with a remaining term, excluding extension options, of at least three years. These rights of first offer do not apply to certain transactions.

Termination. If Teekay Corporation or its affiliates no longer control our general partner or the general partner of Teekay LNG Partners L.P. or if there is a change of control of Teekay Corporation, our general partner, the general partner of Teekay LNG Partners L.P. or Teekay Corporation, as applicable, may terminate relevant non-competition and rights of first offer provisions of the omnibus agreement.

Other

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Please read Item 18. - Financial Statements: Note 11 - Related Party Transactions and Balances for additional information about these and various other related-party transactions.

Item 8.	Financial Information

Consolidated Financial Statements and Other Financial Information

Consolidated Financial Statements and Notes

Please see Item 18 below for additional information required to be disclosed under this Item.

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.

Please read Item 5 - Operating and Financial Review and Prospects - Management’s Discussion and Analysis of Financial Conditions and Results of Operations - Significant Developments - Dispute Resolutions for a description of the disposition of previously reported litigation or arbitration that occurred during 2019.

Please read Item 18. – Financial Statements: Note 14 – Commitments and Contingencies for a description of certain claims made against us.

In January 2020, Økokrim (the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime) and the local Stavanger police raided the premises of our subsidiary Teekay Shipping Norway AS, based on a search warrant issued pursuant to suspected violations of Norwegian pollution and export laws in connection with the export of the Navion Britannia shuttle tanker from the Norwegian Continental Shelf in March 2018 and the subsequent recycling of the vessel. We have not identified any such violations but continue to evaluate any potential liabilities with our advisors.

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

Our cash distribution policy requires us to distribute all of our available cash (as defined in our partnership agreement and after deducting expenses, including estimated future capital expenditures and reserves) rather than our 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. Accordingly, to the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may significantly impair our ability to meet our financial needs or to grow.

Although global crude oil and gas prices have experienced moderate recovery since falling from the highs of mid-2014, prices have not returned to those same highs and remain volatile due to global and regional geopolitical, economic and strategic risks and changes. This has affected the energy and capital markets and may also result in our vessels being employed on customer contracts that are cancellable or the failure of customers to exercise charter extension options, potentially resulting in increased off-hire for affected vessels. 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. Our operational focus over the short-term is on extending contracts and redeploying existing assets on long-term charters.

Limitations on Cash Distributions; Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us and our quarterly distributions on our common units are currently $nil. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

•	Our common unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to our general partner’s broad discretion to establish reserves and other limitations.

•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein but subject to rights of holders of our outstanding preferred units, may be amended with the approval of a majority of the outstanding common units.

•	Even if our cash distribution policy is not modified or revoked, the amount of distributions, if any, we pay under our cash distribution policy and the decision to make any distribution is determined by the board of directors of our general partner, taking into consideration the terms of our partnership agreement.

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•

Under Section 51 of the Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders to the extent that at the time of the distribution, after giving effect to the distribution, all of our liabilities, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specified property of ours, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of that property exceeds that liability.

•	We may lack sufficient cash to pay distributions to our unitholders due to decreases in net revenues or increases in operating expenses, principal and interest payments on outstanding debt, tax expenses, working capital requirements or anticipated cash needs.

•

Our distribution policy may be affected by restrictions on distributions under our credit facility agreements, which contain material financial tests and covenants that must be satisfied. Should we be unable to satisfy these restrictions included in the credit agreements or if we are otherwise in default under the credit agreements, we would be prohibited from making cash distributions, which would materially hinder our ability to make cash distributions to unitholders.

Incentive Distribution Rights

Prior to the Merger, our general partner was entitled to incentive distributions if the amount we distributed to common unitholders with respect to any quarter exceeded specified target levels. In connection with the Merger, the incentive distribution rights were canceled and ceased to exist.

During 2019, cash distributions on common units were below the minimum level to trigger for incentive distribution payments. Consequently, the increasing percentages were not used to calculate the general partner’s interest in net loss for the purposes of the net loss per common unit calculation for the year ended December 31, 2019.

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 our assets in liquidation in accordance with the partnership agreement.

Significant Changes

Not applicable.

Item 9.	The Offer and Listing

Prior to the Merger, our common units were traded on the NYSE under the symbol “TOO”; following the Merger neither our Class A common units or our Class B common units are listed on a national securities exchange. Our Series A Preferred Units are traded on the NYSE under the symbol “TOO-PRA”. Our Series B Preferred Units are traded on the NYSE under the symbol “TOO-PRB”. Our Series E Preferred Units are traded on the NYSE under the symbol “TOO-PRE”.

Item 10.	Additional Information

Memorandum and Articles of Association

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

Material Contracts

The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which we are or any of our subsidiaries is a party, for the two years immediately preceding the date of this Annual Report, each of which is included in the list of exhibits in Item 19:

a)	Amended and Restated Omnibus Agreement, dated December 19, 2006, among us, our general partner, Teekay Corporation, Teekay LNG and related parties. Please read Item 7 – Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for a summary of certain contract terms.

b)	Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. Please read Item 6 – Directors, Senior Management and Employees – 2006 Long-term Incentive Plan for a summary of certain plan terms.

c)	Agreement, dated September 8, 2017, for U.S. $600,000,000 Revolving Credit Facility, between Teekay Shuttle Tankers L.L.C. and Den Norske Bank Capital L.L.C. and various other banks.

d)	Indenture, dated as of July 2, 2018, for U.S. $700,000,000 aggregate principal amount of 8.50% Senior Notes due 2023, between Teekay Offshore Partners L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee.

e)	Second Supplemental Indenture, dated as of July 3, 2018, among Teekay Offshore Partners, L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee.

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f)	Investment Agreement, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P.

g)	Investment Agreement, dated as of July 26, 2017, between Teekay Offshore Partners L.P. and Teekay Holdings Limited.

h)	Purchase Agreement, dated as of July 26, 2017, between Teekay Holdings Limited and Brookfield TK TOGP L.P.

i)	Amended and Restated Subordinate Promissory Note, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P.

j)	Warrant Agreement, dated as of September 25, 2017, by and between Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P. (canceled in January 2020).

k)	Warrant Agreement, dated as of September 25, 2017, by and between Teekay Offshore Partners L.P. and Teekay Shipping Limited (canceled in January 2020).

l)	Registration Rights Agreement, dated September 25, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P.

m)	Master Services Agreement, dated September 25, 2017, by and between Teekay Corporation, Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P.

n)	Trademark License Agreement, dated September 25, 2017, by and between Teekay Corporation and Teekay Offshore Partners L.P.

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

Exchange Controls and Other Limitations Affecting Unitholders

We are not aware of any governmental laws, decrees or regulations, including foreign exchange controls, 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.

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 Teekay Offshore Partners L.P.

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

•	dealers in securities or currencies,

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

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

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

•	certain U.S. expatriates,

•	financial institutions,

•	insurance companies,

•	persons subject to the alternative minimum tax,

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

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

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

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

United States Federal Income Taxation of U.S. Holders

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

Distributions

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

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

Special rules may apply to any “extraordinary dividend” paid by us. Generally, an extraordinary dividend is a dividend with respect to a share of stock if the amount of the dividend is equal to or in excess of 10% of a common stockholder’s, or 5% of a preferred stockholder’s adjusted tax basis (or fair market value in certain circumstances) in such stock. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a stockholder’s adjusted tax basis (or fair market value in certain circumstances). If we pay an “extraordinary dividend” on our publicly traded preferred units that is treated as “qualified dividend income,” then any loss recognized by a Non-Corporate U.S. Holder from the sale or exchange of such units will be treated as long-term capital loss to the extent of the amount of such dividend.

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

Sale, Exchange or Other Disposition of Units

Subject to the discussion of PFICs below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of our units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s tax basis in such units. Subject to the discussion of extraordinary dividends above, such gain or loss generally will be treated as (i) long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition, or short-term capital gain or loss otherwise and (ii) U.S.-source gain or loss, as applicable, for foreign tax credit purposes. Non-Corporate U.S. Holders may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.

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

Consequences of Possible PFIC Classification

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either: (i) at least 75% of its gross income is “passive” income, or (ii) at least 50% of the average value of its assets is attributable to assets that produce, or are held for the production of, passive income.

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For purposes of these tests, “passive income” includes dividends, interest, gains from the sale or exchange of investment property and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. By contrast, income derived from the performance of services does not constitute “passive income.”

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

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder generally would be subject to different taxation rules depending on whether the U.S. Holder makes a timely and effective election to treat us as a “qualified electing fund” (or a QEF election). As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our units, as discussed below.

Taxation of U.S. Holders Making a Timely QEF Election. A U.S. Holder who makes a timely QEF election (or an Electing Holder), must report the Electing Holder’s pro rata share of our ordinary earnings and net capital gain, if any, for each taxable year for which we are a PFIC that ends with or within the Electing Holder’s taxable year, regardless of whether or not the Electing Holder received distributions from us in that year. Such income inclusions would not be eligible for the preferential tax rates applicable to qualified dividend income. The Electing Holder’s adjusted tax basis in our units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in our units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with the U.S. Holder’s timely filed U.S. federal income tax return (including extensions).

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

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

Taxation of U.S. Holders Making a “Mark-to-Market” Election. If we were to be treated as a PFIC for any taxable year and, as we anticipate, our units were treated as “marketable stock,” then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made for the first year a U.S. Holder holds or is deemed to hold our units and for which we are a PFIC, the U.S. Holder generally would include as ordinary income in each taxable year that we are a PFIC the excess, if any, of the fair market value of the U.S. Holder’s units at the end of the taxable year over the U.S. Holder’s adjusted tax basis in the units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the units over the fair market value thereof at the end of the taxable year that we are a PFIC, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder’s tax basis in our units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our units in taxable years that we are a PFIC would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of our units in taxable years that we are a PFIC would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were also determined to be PFICs.

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

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election. If we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year (or a Non-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (i) any excess distribution (i.e., the portion of any distribution received by the Non-Electing Holder on our units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years or, if shorter, the Non-Electing Holder’s holding period for our units), and (ii) any gain realized on the sale, exchange or other disposition of our units. Under these special rules:

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

•	the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income in the current taxable year;

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

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

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

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

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

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

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

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

Distributions

In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on distributions received from us with respect to our units unless the distributions are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment that the Non-U.S. Holder maintains in the United States). If a Non-U.S. Holder is engaged in a trade or business within the United States and the distributions are deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on those distributions in the same manner as if it were a U.S. Holder.

Sale, Exchange or Other Disposition of Units

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

Information Reporting and Backup Withholding

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

•	fails to timely provide an accurate taxpayer identification number;

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

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

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

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

Backup withholding is not an additional tax. Rather, a Non-Corporate U.S. Holder or Non-U.S. Holder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by accurately completing and timely filing a U.S. federal income tax return with the IRS.

Non-United States Tax Considerations

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

Documents on Display

Documents concerning us that are referred to herein may be accessed on our website under “Investors - Financials & Presentations” from the home page of our web site at www.teekayoffshore.com, or may be inspected at our principal executive offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Pembroke, HM 08, Bermuda. 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.

Item 11.	Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are exposed to the impact of interest rate changes, primarily through our floating-rate borrowings that require us to make interest payments based on LIBOR. Significant increases in interest rates could adversely affect operating margins, results of operations and our ability to service our debt. From time to time, we use interest rate swaps to reduce our exposure to market risk from changes in interest rates. The principal objective of these contracts is to minimize the risks and costs associated with our floating-rate debt.

We are 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.

The tables below provide information about financial instruments as at December 31, 2019, that are sensitive to changes in interest rates. For long-term debt, the table presents principal payments and related weighted-average interest rates by expected contractual maturity dates. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected contractual maturity dates.

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		Expected Maturity Date
		2020			2021			2022			2023			2024			There- after			Total			Fair Value Liability			Rate(1)
		(in millions of U.S. dollars, except percentages)
Long-Term Debt:
Variable Rate(2)		317			270			289			312			418			281			1,887			1,869			4.5	%
Variable Rate - Due to related parties(3)		20			—			—			—			—			—			20			20			8.8	%
Fixed Rate		37			46			288			802			35			134			1,342			1,337			7.3	%
Fixed Rate - Obligations related to finance leases(2)		1			1			1			1			1			19			24			24			5.5	%
Interest Rate Swaps:
Contract Amount(4)(5)		431			298			108			8			297			142			1,284			164			3.7	%
Average Fixed Pay Rate(2)		2.9	%		4.0	%		2.2	%		3.4	%		4.7	%		4.1	%		3.7	%

(1)

Rate relating to long-term debt refers to the weighted-average effective interest rate for our debt, including the margin paid on our floating-rate debt. Rate relating to interest rate swaps refers to the average fixed pay rate for interest rate swaps. The average fixed pay rate for interest rate swaps excludes the margin paid on the floating-rate debt, which as of December 31, 2019 ranged between 0.90% and 6.50% based on LIBOR.

(2)	Interest payments on U.S. Dollar-denominated debt and interest rate swaps are based on LIBOR.

(3)	Includes amounts related to the Brookfield unsecured revolving credit facility.

(4)	The average variable receive rate for interest rate swaps is set quarterly at the 3-month LIBOR or semi-annually at the 6-month LIBOR.

(5)	Includes three interest rate swaps, which as at December 31, 2019, had a total current notional amount of $438 million and a total fair value liability of $94 million. These interest rate swaps include early termination provisions, which if exercised, would terminate these interest rate swaps in 2021.

Foreign Currency Fluctuation Risk

Our functional currency is the U.S. Dollar because most of our revenues and operating expenses are in U.S. Dollars. We incur certain vessel operating expenses, general and administrative expenses and a portion of our capital upgrade projects in foreign currencies, the most significant of which is the Norwegian Krone and, to a lesser extent, the Australian Dollar, Brazilian Real, British Pound, Euro and Singapore Dollar. There is a risk that currency fluctuations will have a negative effect on the value of our cash flows.

We may continue to seek to hedge these currency fluctuation risks in the future. At December 31, 2019, we were committed to the following foreign currency forward contracts:

		Contract Amount in Foreign Currency (thousands)			Average Forward Rate(1)			Expected Maturity					Fair Value / Carrying Amount of Asset (Liability) (in thousands of U.S. Dollars)
								2020
								(in thousands of U.S. Dollars)
Norwegian Krone		457,205			8.87			51,567					518
Euro		5,000			0.90			5,563					57
								57,130					575

(1)	Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

Please read Item 18 – Financial Statements: Note 12 – Derivative Instruments.

Commodity Price Risk

We are exposed to changes in forecasted bunker fuel costs for certain vessels being time-chartered-out and for vessels servicing certain contracts of affreightment. We may use bunker fuel swap contracts as economic hedges to protect against changes in bunker fuel costs. As at December 31, 2019, we were not committed to any bunker fuel swap contracts.

Item 12.	Description of Securities Other than Equity Securities

Not applicable.

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PART II

Item 13.	Defaults, Dividend Arrearages and Delinquencies

Not Applicable.

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

Not applicable.

Item 15.	Controls and Procedures

We maintain 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)) that are designed to ensure that (i) information required to be disclosed in our reports that are filed or submitted under the Exchange Act, are recorded, processed, summarized, and reported within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms, and (ii) information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

We conducted an evaluation of our disclosure controls and procedures under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Service Provider. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer of the Service Provider concluded that our disclosure controls and procedures are effective as of December 31, 2019.

The Chief Executive Officer and Chief Financial Officer of the Service Provider do not expect that our disclosure controls or internal controls will prevent all errors and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within us have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining for us adequate internal control over financial reporting.

Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that: 1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; 2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and the directors; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or dispositions of our assets that could have a material effect on the 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, 2019.

Our independent auditors, Ernst & Young LLP, an independent registered public accounting firm, has audited the accompanying consolidated financial statements and our internal control over financial reporting. Their attestation report on the effectiveness of our internal control over financial reporting can be found on page F-2 of this Annual Report.

There were no changes in our internal controls that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rule 13a - 15 (f) under the Exchange Act) that occurred during the year ended December 31, 2019.

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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 and is independent under applicable NYSE and SEC standards.

Item 16B.	Code of Ethics

We have adopted a Standards of Business Conduct Policy that applies to all our employees and the directors of our general partner. This document is available under “Investors – Governance” from the home page of our web site (www.teekayoffshore.com). We intend to disclose, under “Investors – Governance” in the Investors section of our web site, any waivers to or amendments of the Code of Ethics for the benefit of any directors and executive officers of our general partner.

Item 16C.	Principal Accountant Fees and Services

Our principal accountant for 2019 was Ernst & Young LLP, Chartered Professional Accountants, and for 2018, was KPMG LLP, Chartered Professional Accountants. The following table shows the fees we incurred for services provided by our principal accountant for 2019 and 2018.

		2019				2018
		(in thousands of U.S. Dollars)
Audit Fees (1)		$	1,364			$	2,515
Audit-Related Fees (2)		3				30
Tax Fees (3)		510				24
Total		$	1,877			$	2,569

(1)

Audit fees represent fees for professional services provided in connection with the audits of our consolidated financial statements and effectiveness of internal control over financial reporting, review of our quarterly consolidated financial statements and audit services provided in connection with other statutory or regulatory filings, including professional services in connection with the review of our regulatory filings for our offering of preferred units in 2018.

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

(3)	For 2019, tax fees relate primarily to transfer pricing advisory and corporate tax compliance fees and for 2018, tax fees relate primarily to 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 2019.

Item 16D.	Exemptions from the Listing Standards for Audit Committees

Mr. Jim Reid, who serves on the Audit Committee of our board of directors as an observer, is a Managing Partner and the Chief Investment Officer in Brookfield’s Private Equity Group. Affiliates of Brookfield are the largest common unitholder of us and the owner of a 100% interest in our general partner. As an observer, Mr. Reid does not have voting rights on the Audit Committee. He is neither the chair of the Audit Committee nor an executive officer of us. Accordingly, we rely on the exemption provided in Rule 10A-3(b)(1)(iv)(D) of the U.S. Securities Exchange Act for Mr. Reid’s service on the Audit Committee. We do not believe that Mr. Reid’s affiliation with Brookfield materially adversely affects the ability of the Audit Committee to act independently or to satisfy the other requirements relating to audit committees contained in Rule 10A-3 under the Exchange Act.

Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers

Not applicable.

Item 16F.	Change in Registrant’s Certifying Accountant

KPMG LLP was previously the principal accountants for Teekay Offshore Partners L.P. In 2018, we conducted a competitive request for proposals from several independent accounting firms to provide audit and other principal accounting services. KPMG LLP elected not to stand for re-appointment as our independent registered public accounting firm for the audit and for the quarterly reviews of our financial statements for the year ending December 31, 2019. On January 16, 2019, we engaged Ernst & Young LLP 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 reports of KPMG LLP on our consolidated financial statements as of and for the fiscal years ended December 31, 2018 and 2017 did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles, except as follows:

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KPMG LLP’s report on our consolidated financial statements as of and for the years ended December 31, 2018 and 2017 contained a separate paragraph stating “As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its accounting policies for revenue recognition as of January 1, 2018 due to the adoption of ASU 2014-09 - Revenue from Contracts with Customers, and the classification of restricted cash and final settlements on cross currency swap agreements on the statement of cash flows for 2018 and comparative periods due to the adoption of ASU 2016-18 - Statement of Cash Flows: Restricted Cash and ASU 2016-15 - Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, respectively.”

During the fiscal years ended December 31, 2018 and 2017 and the subsequent interim period through January 16, 2019, there were no: (1) disagreements with KPMG LLP 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 KPMG LLP would have caused KPMG LLP to make reference thereto in their reports on our financial statements for such fiscal periods, and (2) no “reportable events” (as defined in SEC Regulation S-K Item 304(a)(1)(v)).

Item 16G.	Corporate Governance

As a foreign private issuer under SEC rules, we are not required to comply with certain corporate governance practices followed by U.S. publicly traded partnerships under the New York Stock Exchange (or NYSE) listing standards. The following is the significant way in which our corporate governance practices differ from those followed by U.S. limited partnerships listed on the NYSE, and which difference is permitted by NYSE rules for foreign private issuers:

•	The NYSE requires that U.S. issuers have an audit committee comprised entirely of independent directors. Our audit committee currently consists of three independent directors and one director (who does not meet the heightened independence standards for audit committee membership), who only has observer status and is a non-voting member of the committee.

Similar to other publicly traded partnerships and as a foreign private issuer, we are not required to obtain unitholder approval prior to the adoption of equity compensation plans or certain equity issuances, including, among others, issuing 20% or more of our outstanding common units or voting power in a transaction.

Item 16H.	Mine Safety Disclosure

Not applicable.

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PART III

Item 17.	Financial Statements

Not applicable.

Item 18.	Financial Statements

The following financial statements, together with the related reports of Ernst & Young LLP, Independent Registered Public Accounting Firm thereon, and KPMG LLP, Independent Registered Public Accounting Firm thereon, are filed as part of this Annual Report:

	Page
Reports of Independent Registered Public Accounting Firm	F- 1 , F-2, F-3
Consolidated Financial Statements
Consolidated Statements of Loss	F- 4
Consolidated Statements of Comprehensive Loss	F- 5
Consolidated Balance Sheets	F- 6
Consolidated Statements of Cash Flows	F- 7
Consolidated Statements of Changes in Total Equity	F- 8
Notes to the Consolidated Financial Statements	F- 9

All schedules for which provision is made in the applicable accounting regulations of the SEC are not required, are inapplicable or have been disclosed in the Notes to the Consolidated Financial Statements and therefore have been omitted.

Item 19.	Exhibits

The following exhibits are filed as part of this Annual Report:

1.1	Certificate of Limited Partnership of Teekay Offshore Partners L.P., dated August 30, 2016. (1)
1.2	Seventh Amended and Restated Agreement of Limited Partnership of Teekay Offshore Partners L.P. dated January 22, 2020.
1.3	Certificate of Formation of Teekay Offshore GP L.L.C., dated August 25, 2006. (1)
1.4	Second Amended and Restated Limited Liability Company Agreement of Teekay Offshore GP L.L.C., as amended.
1.5	Certificate of Limited Partnership of Teekay Offshore Operating L.P., dated September 22, 2006. (1)
1.6	Amended and Restated Agreement of Limited Partnership of Teekay Offshore Operating L.P. (1)
1.7	Certificate of Formation of Teekay Offshore Operating GP L.L.C., dated September 22, 2006. (1)
2.1	Equity Distribution Agreement, dated August 18, 2016, between Teekay Offshore Partners L.P. and Citigroup Global Markets Inc. to offer and sell common units having an aggregate offering price of up to $100,000,000 under the Continuous Offering Program. (2)
2.2	Agreement, dated September 8, 2017, for U.S. $600,000,000 Secured Revolving Credit Facility, between Teekay Shuttle Tankers L.L.C. and Den Norske Bank Capital L.L.C. and various other banks. (3)
2.3	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)
2.4	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)
2.5	Indenture, dated as of July 2, 2018, among Teekay Offshore Partners L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (6)
2.6	Second Supplemental Indenture, dated as of July 3, 2018, among Teekay Offshore Partners, L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (6)
2.7	Description of Securities Registered Under Section 12 of the Exchange Act.
4.1	Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. (1)
4.2	Form of Amended and Restated Omnibus Agreement. (1)
4.3	Registration Rights Agreement, dated June 29, 2016, by and among Teekay Offshore Partners L.P. and the Investors Named on Schedule A thereto. (7)
4.4	Registration Rights Agreement, dated June 29, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (7)
4.5	Common Unit Purchase Agreement, dated June 16, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers named on Schedule A thereto. (7)

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4.6	Series D Preferred Unit Purchase Agreement, dated June 22, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers named on Schedule A thereto. (7)
4.7	Investment Agreement, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P. (8)
4.8	Investment Agreement, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P. and Teekay Holdings Limited. (8)
4.9	Purchase Agreement, dated as of July 26, 2017, by and between Teekay Holdings Limited and Brookfield TK TOGP L.P. (8)
4.10	Amended and Restated Subordinate Promissory Note, dated as of July 26, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P. (8)
4.11	Registration Rights Agreement, dated September 25, 2017, by and between Teekay Offshore Partners L.P., Teekay Corporation and Brookfield TK TOLP L.P. (3)
4.12	Master Services Agreement, dated September 25, 2017, by and between Teekay Corporation, Teekay Offshore Partners L.P. and Brookfield TK TOLP L.P. (3)
4.13	Trademark License Agreement, dated September 25, 2017, by and between Teekay Corporation and Teekay Offshore Partners L.P. (3)
4.14	Agreement and Plan of Merger, dated as of September 30, 2019, by and among Teekay Offshore Partners L.P., Brookfield TK Acquisition Holdings LP, Brookfield TK Merger Sub LLC, Teekay Offshore GP L.L.C. and the other parties thereto. (9)
8.1	List of Subsidiaries of Teekay Offshore Partners L.P.
12.1	Rule 13a-14(a)/15d-14(a) Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd.
12.2	Rule 13a-14(a)/15d-14(a) Certification of Jan Rune Steinsland, Chief Financial Officer of Teekay Offshore Group Ltd.
13.1	Teekay Offshore Partners L.P. Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2	Teekay Offshore Partners L.P. Certification of Jan Rune Steinsland, Chief Financial Officer of Teekay Offshore Group Ltd. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Consent of Ernst & Young LLP, as independent registered public accounting firm.
15.2	Consent of KPMG LLP, as independent registered public accounting firm.
15.3	Consolidated Financial Statements of OOGTK Libra GmbH & Co KG and subsidiaries.
15.4	Letter of KPMG LLP, dated January 28, 2019, regarding change in independent registered public accounting firm. (10)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

(1)	Previously filed as exhibits 3.1, 3.3, 3.5, 3.6, 3.7, 10.2 and 10.3 to our Registration Statement on Form F-1 (File No. 333-139116), filed with the SEC on December 4, 2006, and hereby incorporated by reference to such Registration Statement.

(2)	Previously filed as exhibit 1.1 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 18, 2016, and hereby incorporated by reference to such Report.

(3)	Previously filed as exhibits 4.4, 10.5, 10.6 and 10.7 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 24, 2017, and hereby incorporated by reference to such Report.

(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 exhibits 4.1, 4.3, 10.1 and 10.2 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on June 30, 2016, and hereby incorporated by reference to such Report.

(8)	Previously filed as exhibits 10.1, 10.2, 10.3 and 10.4 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 1, 2017, and hereby incorporated by reference to such Report.

(9)	Previously filed as Annex A to Exhibit (a)(1) to Schedule 13e-3 (File No. 5-82284), filed with the SEC on December 12, 2019, and hereby incorporated by reference to such Schedule.

(10)	Previously filed as exhibit 16.1 to our Report on Form 6-K (File No. 1-33198), filed with the SEC on January 29, 2019, and hereby incorporated by reference to such Report.

87

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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.

 

				TEEKAY OFFSHORE PARTNERS L.P.
				By: Teekay Offshore GP L.L.C., its General Partner
Date: February 28, 2020				By:		/s/ Edith Robinson
				Edith Robinson Secretary

88

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and Board of Directors of Teekay Offshore Partners L.P.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Teekay Offshore Partners L.P. and subsidiaries (the “Partnership”) as of December 31, 2019, the related consolidated statements of loss, comprehensive loss, cash flows, and changes in total equity for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2020 expressed an unqualified opinion thereon.

Adoption of New Accounting Standard

As discussed in Note 2 to the consolidated financial statements, the Partnership changed its method for accounting for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s consolidated financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

 

/s/ Ernst & Young LLP

Chartered Professional Accountants

We have served as the Partnership’s auditor since 2019.

Vancouver, Canada

February 28, 2020

F- 1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders

Teekay Offshore Partners L.P.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Teekay Offshore Partners L.P. and subsidiaries (the Partnership) as of December 31, 2018, the related consolidated statements of loss, comprehensive loss, cash flows, and changes in total equity for each of the years in the two‑year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018, and the results of its operations and its cash flows for each of the years in the two‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Partnership has changed its accounting policy for revenue recognition as of January 1, 2018 due to the adoption of ASU 2014-09 - Revenue from Contracts with Customers.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

Chartered Professional Accountants

We served as the Partnership’s auditor from 2011 to 2019.

Vancouver, Canada

February 28, 2019

F- 2

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and Board of Directors of Teekay Offshore Partners L.P.

Opinion on Internal Control Over Financial Reporting

We have audited Teekay Offshore Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO” criteria). In our opinion, Teekay Offshore Partners L.P. and subsidiaries’ (the “Partnership”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Partnership as of December 31, 2019, the related consolidated statement of loss, comprehensive loss, cash flows, and changes in total equity for the year ended December 31, 2019, and the related notes, and our report dated February 28, 2020 expressed an unqualified opinion thereon.

Basis for Opinion 

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

/s/ Ernst & Young LLP

Chartered Professional Accountants

Vancouver, Canada

February 28, 2020

F- 3

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF LOSS

(in thousands of U.S. Dollars, except unit and per unit data)

		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
		2019			2018			2017
		$			$			$
Revenues (notes 5 and 11)		1,268,000			1,416,424			1,110,284
Voyage expenses		(129,910	)		(151,808	)		(99,444	)
Vessel operating expenses (note 11)		(426,951	)		(437,671	)		(353,564	)
Time-charter hire expenses		(44,427	)		(52,616	)		(80,315	)
Depreciation and amortization (note 1)		(349,379	)		(372,290	)		(309,975	)
General and administrative (notes 11 and 17)		(76,245	)		(65,427	)		(62,249	)
(Write-down) and gain on sale of vessels (notes 3 and 18)		(332,125	)		(223,355	)		(318,078	)
Restructuring charge (note 10)		—			(1,520	)		(2,664	)
Operating (loss) income		(91,037	)		111,737			(116,005	)
Interest expense (notes 8, 11 and 12)		(205,709	)		(199,395	)		(154,890	)
Interest income		5,111			3,598			2,707
Realized and unrealized (loss) gain on derivative instruments (note 12)		(85,195	)		12,808			(42,853	)
Equity income (note 19)		32,794			39,458			14,442
Foreign currency exchange gain (loss) (note 12)		2,193			(9,413	)		(14,006	)
Losses on debt repurchases (notes 8 and 11k)		—			(55,479	)		(3,102	)
Other (expense) income - net		(1,225	)		(4,602	)		14,167
Loss before income tax (expense) recovery		(343,068	)		(101,288	)		(299,540	)
Income tax (expense) recovery (note 13)		(7,827	)		(22,657	)		98
Net loss		(350,895	)		(123,945	)		(299,442	)
Non-controlling interests in net loss		(1,384	)		(7,161	)		3,764
Preferred unitholders' interest in net loss (note 16)		32,150			31,485			42,065
General Partner’s interest in net loss		(2,891	)		(1,128	)		(5,770	)
Limited partners' interest in net loss		(378,770	)		(147,141	)		(339,501	)
Limited partners' interest in net loss for basic net loss per common unit (note 16)		(378,770	)		(147,141	)		(320,749	)
Limited partners' interest in net loss per common unit
- basic (note 16)		(0.92	)		(0.36	)		(1.45	)
- diluted (note 16)		(0.92	)		(0.36	)		(1.46	)
Weighted-average number of common units outstanding:
- basic		410,727,035			410,261,239			220,755,937
- diluted		410,727,035			410,261,239			229,940,120
Related party transactions (note 11)
The accompanying notes are an integral part of the consolidated financial statements.

F- 4

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands of U.S. Dollars)

		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
		2019			2018			2017
		$			$			$
Net loss		(350,895	)		(123,945	)		(299,442	)
Other comprehensive (loss) income:
Other comprehensive (loss) income before reclassifications
Unrealized gain (loss) on qualifying cash flow hedging instruments (note 12)		—			6,017			(905	)
Pension adjustments, net of taxes		(1,662	)		1,096			—
Amounts reclassified from accumulated other comprehensive (loss) income
To interest expense:
Realized (gain) loss on qualifying cash flow hedging instruments (note 12)		(689	)		(102	)		1,186
To equity income:
Realized (gain) loss on qualifying cash flow hedging instruments		(600	)		873			—
Other comprehensive (loss) income		(2,951	)		7,884			281
Comprehensive loss		(353,846	)		(116,061	)		(299,161	)
Non-controlling interests in comprehensive loss		(1,384	)		(7,161	)		3,764
Preferred unitholders' interest in comprehensive loss		32,150			31,485			42,065
General and limited partners' interest in comprehensive loss		(384,612	)		(140,385	)		(344,990	)
The accompanying notes are an integral part of the consolidated financial statements.

F- 5

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands of U.S. Dollars)

		As at			As at
		December 31,			December 31,
		2019			2018
		$			$
ASSETS
Current
Cash and cash equivalents		199,388			225,040
Restricted cash (notes 3, 12 and 15)		17,798			8,540
Accounts receivable, including non-trade of $34,468 (December 31, 2018 - $8,183)		204,020			141,903
Vessels held for sale (notes 3 and 18)		15,374			12,528
Prepaid expenses		29,887			32,199
Due from related parties (note 11c)		—			58,885
Other current assets (notes 3b, 5 and 12)		7,467			11,879
Total current assets		473,934			490,974
Restricted cash - long-term (note 15)		89,070			—
Vessels and equipment
At cost, less accumulated depreciation of $1,666,582 (December 31, 2018 - $1,634,394)		3,511,758			4,196,909
Advances on newbuilding contracts (note 14c)		257,017			73,713
Investments in equity-accounted joint ventures (note 19)		234,627			212,202
Deferred tax asset (note 13)		7,000			9,168
Due from related parties (note 11c)		—			949
Other assets (notes 2, 3b, 5, 9 and 12)		220,716			198,992
Goodwill (note 6a)		129,145			129,145
Total assets		4,923,267			5,312,052
LIABILITIES AND EQUITY
Current
Accounts payable		56,699			16,423
Accrued liabilities (notes 7, 10, 12, and 17)		140,976			129,896
Deferred revenues (note 5)		53,728			55,750
Due to related parties (notes 11c and 11j)		20,000			183,795
Current portion of derivative instruments (note 12)		18,956			23,290
Current portion of long-term debt (note 8)		353,238			554,336
Other current liabilities (notes 2, 3 and 9)		14,793			15,062
Total current liabilities		658,390			978,552
Long-term debt (note 8)		2,825,712			2,543,406
Derivatives instruments (note 12)		143,222			94,354
Other long-term liabilities (notes 2, 3, 5, 9, 13 and 14)		223,877			236,616
Total liabilities		3,851,201			3,852,928
Commitments and contingencies (notes 8, 9, 12 and 14)
Equity
Limited partners - common units (411.1 million and 410.3 million units issued and outstanding at December 31, 2019 and December 31, 2018, respectively) (notes 16 and 17)		505,394			883,090
Limited partners - preferred units (15.8 million and 15.8 million units issued and outstanding at December 31, 2019 and December 31, 2018, respectively) (note 16)		384,274			384,274
General Partner		12,164			15,055
Warrants (note 16)		132,225			132,225
Accumulated other comprehensive income		4,410			7,361
Non-controlling interests		33,599			37,119
Total equity		1,072,066			1,459,124
Total liabilities and total equity		4,923,267			5,312,052
The accompanying notes are an integral part of the consolidated financial statements.

F- 6

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TEEKAY OFFSHORE PARTNERS 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,
		2019			2018			2017
		$			$			$
Cash, cash equivalents and restricted cash provided by (used for)
OPERATING ACTIVITIES
Net loss		(350,895	)		(123,945	)		(299,442	)
Adjustments to reconcile net loss to net operating cash flow:
Unrealized loss (gain) on derivative instruments (note 12)		50,956			(53,419	)		(59,702	)
Equity income, net of dividends received of $17,655 (2018 - $6,200, 2017 - $11,600) (note 19)		(15,139	)		(33,258	)		(2,842	)
Depreciation and amortization		349,379			372,290			309,975
Write-down and (gain) on sale and of vessels (note 18)		332,125			223,355			318,078
Deferred income tax expense (recovery) (note 13)		3,161			18,606			(1,870	)
Amortization of in-process revenue contract (note 6b)		(15,062	)		(35,219	)		(12,745	)
Expenditures for dry docking		(15,890	)		(21,411	)		(17,269	)
Other		(31,142	)		16,871			37,511
Change in non-cash working capital items related to operating activities (note 15b)		12,416			(83,227	)		33,506
Net operating cash flow		319,909			280,643			305,200
FINANCING ACTIVITIES
Proceeds from long-term debt (note 8)		492,517			734,698			1,205,477
Scheduled repayments of long-term debt and settlement of related swaps (notes 8 and 12)		(410,429	)		(567,298	)		(652,898	)
Prepayments of long-term debt and settlement of related swaps (notes 8 and 12)		—			(457,426	)		(702,115	)
Financing issuance costs		(23,755	)		(14,128	)		(17,268	)
Proceeds from financing related to sales and leaseback of vessels		23,800			—			—
Equity contribution from joint venture partners		—			—			6,000
Proceeds from issuance of common units and warrants (note 16)		—			—			640,595
Proceeds from issuance of preferred units (note 16)		—			120,000			—
Repurchase of preferred units (note 16)		—			—			(250,022	)
Expenses relating to equity offerings		—			(3,997	)		(12,155	)
Proceeds from credit facility due to related parties (note 11j)		95,000			125,000			—
Prepayments of credit facility due to related parties		(200,000	)		—			—
Cash distributions paid by the Partnership		(32,150	)		(46,675	)		(60,593	)
Cash distributions paid by subsidiaries to non-controlling interests		(3,636	)		(12,048	)		(9,891	)
Cash contribution paid from non-controlling interest to subsidiaries		1,500			1,500			—
Other		(865	)		(964	)		(4,183	)
Net financing cash flow		(58,018	)		(121,338	)		142,947
INVESTING ACTIVITIES
Net payments for vessels and equipment, including advances on newbuilding contracts and conversion costs		(214,670	)		(233,736	)		(533,260	)
Proceeds from sale of vessels and equipment (note 18)		33,341			30,049			13,100
Investments in equity accounted joint ventures		(7,886	)		(3,000	)		(25,824	)
Direct financing lease payments received		—			5,414			5,844
Acquisition of companies from Teekay Corporation (net of cash acquired of $26.6 million) (note 11l)		—			25,254			—
Net investing cash flow		(189,215	)		(176,019	)		(540,140	)
Increase (decrease) in cash, cash equivalents and restricted cash		72,676			(16,714	)		(91,993	)
Cash, cash equivalents and restricted cash, beginning of the year		233,580			250,294			342,287
Cash, cash equivalents and restricted cash, end of the year		306,256			233,580			250,294
Supplemental cash flow information (note 15)
The accompanying notes are an integral part of the consolidated financial statements.

F- 7

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 TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL EQUITY

(in thousands of U.S. Dollars and units)

		PARTNERS’ EQUITY
		Limited Partners
		Common Units #			Common Units and Additional Paid-in  Capital $			Preferred Units #			Preferred Units $			Warrants $			General Partner $			Accumulated Other Comprehensive (Loss) Income $			Non- controlling Interests $			Total Equity $			Convertible Preferred Units #			Convertible Preferred Units $			Redeemable Non- controlling Interest $
Balance as at December 31, 2016		147,514			784,056			11,000			266,925			13,797			20,658			(804	)		53,964			1,138,596			12,517			271,237			962
Net loss		—			(339,501	)		—			21,500			—			(5,770	)		—			3,711			(320,060	)		—			20,565			53
Other comprehensive income (note 12)		—			—			—			—			—			—			281			—			281			—			—			—
Distributions declared:
Common Units ($0.24 per unit)		—			(28,857	)		—			—			—			(31	)		—			—			(28,888	)		—			—			—
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 C-1 Convertible ($0.7496 per unit)		—			—			—			—			—			—			—			—			—			—			(6,384	)		—
Preferred Units - Series D Convertible ($0.9553 per unit)		—			—			—			—			—			—			—			—			—			—			(3,821	)		—
Payment-in-kind distributions (note 16)		6,391			19,687			—			—			—			(699	)		—			—			18,988			—			(14,022	)		—
Other distributions		—			—			—			—			—			—			—			(8,847	)		(8,847	)		—			—			(1,044	)
Contributions of capital from joint venture partner		—			—			—			—			—			—			—			6,000			6,000			—			—			—
Contribution of capital from Teekay Corporation (notes 11i and 16)		—			44,442			—			—			—			873			—			—			45,315			—			—			—
Proceeds from equity offerings, net of offering costs (note 16)		256,000			504,851			—			—			119,948			588			—			—			625,387			—			—			—
Repurchase of Convertible Preferred Units (note 16)		—			19,588			—			—			—			383			—			—			19,971			(12,517	)		(269,993	)		—
Equity based compensation and other (note 17)		140			(189	)		—			—			(1,520	)		(6	)		—			—			(1,715	)		—			2,418			—
Balance as at December 31, 2017		410,045			1,004,077			11,000			266,925			132,225			15,996			(523	)		54,828			1,473,528			—			—			(29	)
Net loss		—			(147,141	)		—			31,485			—			(1,128	)		—			(7,161	)		(123,945	)		—			—			—
Other comprehensive income (note 12)		—			—			—			—			—			—			7,884			—			7,884			—			—			—
Distributions declared:
Common Units ($0.04 per unit)		—			(16,410	)		—			—			—			(126	)		—			—			(16,536	)		—			—			—
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 ($1.7997 per unit)		—			—			—			(8,639	)		—			—			—			—			(8,639	)		—			—			—
Other distributions		—			—			—			—			—						—			(12,048	)		(12,048	)		—			—			—
Contribution from non-controlling interests		—			—			—			—			—			—			—			1,500			1,500			—			—			—
Proceeds from equity offerings, net of offering costs (note 16)		—			—			4,800			116,003			—			—			—			—			116,003			—			—			—
Change in accounting policy		—			41,381			—			—			—			316			—			—			41,697			—			—			—
Equity based compensation and other (note 17)		270			1,183			—			—			—			(3	)		—			—			1,180			—			—			29
Balance as at December 31, 2018		410,315			883,090			15,800			384,274			132,225			15,055			7,361			37,119			1,459,124			—			—			—
Net loss		—			(378,770	)		—			32,150			—			(2,891	)		—			(1,384	)		(350,895	)		—			—			—
Other comprehensive loss (note 12)		—			—			—			—			—			—			(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		—			—			—			—			—			—			—			1,500			1,500			—			—			—
Equity based compensation and other (note 17)		834			1,074			—			—			—			—			—			—			1,074			—			—			—
Balance as at December 31, 2019		411,149			505,394			15,800			384,274			132,225			12,164			4,410			33,599			1,072,066			—			—			—

F- 8

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

1.	Summary of Significant Accounting Policies

Basis of presentation

The consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (or GAAP). These financial statements include the accounts of Teekay Offshore Partners L.P., which is a limited partnership organized under the laws of the Republic of the Marshall Islands, and its wholly owned or controlled subsidiaries (collectively, the Partnership). Unless the context otherwise requires, the terms "we," "us," or "our," as used herein, refer to the Partnership.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.

Foreign currency

The consolidated financial statements are stated in U.S. Dollars and the functional currency of the Partnership is the U.S. Dollar. Transactions involving other currencies during the year are converted into U.S. Dollars using the exchange rates in effect at the time of the transactions. At the balance sheet dates, monetary assets and liabilities that are denominated in currencies other than the U.S. Dollar are translated to reflect the year-end exchange rates. Resulting gains or losses are reflected separately in the accompanying consolidated statements of loss.

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. Where the term of the contract is based on the duration of a single voyage, the Partnership uses a discharge-to-discharge basis in determining proportionate performance for all tanker spot voyages that contain a lease and a load-to-discharge basis in determining proportionate performance for all tanker spot voyages that do not contain a lease. 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. Reimbursements of vessel operating expenditures incurred to provide the contracted services to the charterer are recognized when the expenses entitling the Partnership to reimbursement are incurred. Revenue or penalties from performance-based metrics, such as production tariffs and other operational performance measures, are recognized as earned or incurred unless such performance-based revenue is based on a multi-period performance-based metric that is allocable to non-lease services provided. In such a case, the Partnership will estimate the amount of variable consideration, to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved and recognize such estimate of revenue over the performance period.

The consolidated balance sheets reflect, in other current assets, the accrued portion of revenues for those voyages that commence prior to balance sheet date and complete after the balance sheet date and reflect, in deferred revenues or other long-term liabilities, the deferred portion of revenues which will be earned in subsequent periods.

Prior to the adoption of the Financial Accounting Standards Board (or FASB) Accounting Standards Update 2014-09, Revenue from Contracts with Customers (or ASU 2014-09) on January 1, 2018:

•	Voyage revenues from towage and offshore installation vessels were recognized over the period of the tow and the mobilization and demobilization of the towage vessel, instead of the period where the tow is being performed. The cumulative-effect adjustment on January 1, 2018 was insignificant.

•

Revenue from time-charter contracts with fixed annual increases in the daily hire rate during the firm period of the charter to compensate for expected inflationary cost increases were recognized when due under the contract, instead of on a smoothed basis over the term of the time-charter. For time-charters with a termination fee owing if the contract is not extended past the contract term, the non-lease portion of such termination fee was recognized when the termination fee was incurred, instead of recognized over the contract term. The cumulative-effect adjustment on January 1, 2018 was an increase to equity of $7.7 million.

•	Costs incurred by the Partnership for its onshore staff and seafarers related to the management of FPSO units owned by Teekay Corporation and other vessels were presented on a net basis, instead of presented as vessel operating expenses and the reimbursement of such expenses presented as revenue. There was no cumulative impact to opening equity as at January 1, 2018.

•	Operating costs for the Partnership's Volatile Organic Compounds (or VOC) plants on certain shuttle tankers were presented on a net basis, instead of presented as vessel operating expenses and the reimbursement of such expenses presented as revenue. There was no cumulative impact to opening equity as at January 1, 2018.

•

The Partnership presented the net allocation for its vessels participating in revenue sharing arrangements as revenues, instead of the revenue from those voyages being presented in voyage revenues and the difference between this amount and the Partnership's net allocation from the revenue sharing arrangement being presented as voyage expenses. There was no cumulative impact to opening equity as at January 1, 2018.

F- 9

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Operating expenses

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. Vessel operating expenses include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses.

Voyage expenses and vessel operating expenses are recognized when incurred except when the Partnership incurs pre-operational costs related to the repositioning of a vessel or offshore unit 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 deferred and amortized over the duration of the customer contract. Prior to the adoption of ASU 2014-09 on January 1, 2018, the Partnership expensed such costs as incurred unless the costs were directly reimbursable by the contract or if they were related to the mobilization of offshore assets to an oil field. The cumulative-effect adjustment on January 1, 2018 was an increase to equity of $29.4 million.

The Partnership recognizes the expense from vessels time-chartered from other owners in time-charter hire expenses in the accompanying consolidated statements of loss. 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. 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 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.

Cash and cash equivalents

The Partnership classifies all highly-liquid investments with a maturity date of three months or less when purchased as cash and cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in existing accounts receivable. The Partnership determines the allowance based on historical write-off experience and customer economic data. The Partnership reviews the allowance for doubtful accounts regularly and past due balances are reviewed for collectability. Account balances are charged against the allowance when the Partnership believes that the receivable will not be recovered. There is no allowance for doubtful accounts recorded as at December 31, 2019 and 2018.

Investments in equity-accounted joint ventures

The Partnership’s investments in equity-accounted joint ventures are accounted for using the equity method of accounting. Under the equity method of accounting, the initial cost of the investment is adjusted for subsequent additional investments and the Partnership’s proportionate share of earnings or losses and distributions. The Partnership evaluates its investments in joint ventures for impairment when events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value below carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the Partnership’s consolidated statements of loss. No indicators of impairment existed at December 31, 2019 and 2018.

Vessels and equipment

All pre-delivery costs incurred during the construction of newbuildings and conversions, including interest, supervision and technical costs, are capitalized. The acquisition cost and all costs incurred to restore used vessels purchased by the Partnership to the standards required to properly service the Partnership’s customers are capitalized.

Vessel capital modifications include the addition of new equipment or can encompass various modifications to the vessel which are aimed at improving and/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.

Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life to an estimated residual value. Floating production storage and offloading (or FPSO) units are depreciated using an estimated useful life of 20 to 25 years commencing the date the unit is installed at the oil field and is in a condition that is ready to operate. Some of the Partnership’s FPSO units have oil field specific equipment, which is depreciated over the expected life of the oil field. Shuttle tankers are depreciated over an estimated useful life of 20 years commencing the date the vessel is delivered from the shipyard. Floating storage and off take (or FSO) units are depreciated over the estimated contract term or the estimated useful life of the specific unit. The unit for maintenance and safety (or UMS) is depreciated over an estimated useful life of 35 years commencing the date it arrived at the oil field and was in a condition that was ready to operate. Towage and offshore installation vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. Depreciation of vessels and equipment for the years ended December 31, 2019, 2018 and 2017, totaled $330.2 million, $348.4 million, and $286.1 million, respectively. Depreciation and amortization includes depreciation on all owned vessels.

F- 10

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Interest costs capitalized to vessels and equipment for the years ended December 31, 2019, 2018 and 2017 totaled $13.6 million, $11.1 million and $29.6 million, respectively.

Generally, the Partnership dry docks each shuttle tanker and towage and offshore installation vessel every two and a half to five years. UMS, FSO and FPSO units are generally not dry docked. 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. 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. 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.

Dry-docking activity for the three years ended December 31, 2019, 2018 and 2017 is summarized as follows:

		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
		2019			2018			2017
		$			$			$
Balance at beginning of the year		42,538			42,829			49,238
Cost incurred for dry-docking		13,546			23,602			17,183
Dry-docking amortization		(19,146	)		(23,893	)		(22,870	)
Write-down / sale of vessels with capitalized dry-dock costs		—			—			(722	)
Balance at end of the year		36,938			42,538			42,829

Vessels and equipment that are “held and used” are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. If the asset’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. The estimated fair value for the Partnership’s impaired vessels is determined using discounted cash flows or appraised values. 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 an impaired vessel. In cases where an active second hand sale and purchase market exists, an appraised value is used to estimate the fair value of an impaired vessel. 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. When an asset impairment occurs, the Partnership adjusts the carrying value of the asset to its new cost base and writes off the asset's accumulated depreciation.

Asset retirement obligation

The Partnership has an asset retirement obligation (or ARO) relating to the sub-sea mooring and riser system associated with the Randgrid FSO unit. This obligation involves the costs associated with the restoration of the environment surrounding the facility and removal of all equipment, which are subsequently to be reimbursed by the charterer. This obligation is expected to be settled at the end of the contract under which the FSO unit operates, which as at December 31, 2019, was estimated to be May 2024.

The Partnership records the fair value of an ARO as a liability in the period when the obligation arises. The fair value of the ARO is measured using expected future cash outflows discounted at the Partnership’s credit-adjusted risk-free interest rate. When the liability is recorded, and as the ARO will be covered by contractual payments to be received from the charterer, the Partnership records a separate receivable concurrently with the ARO being created. Each period, the liability is increased for the change in its present value. Changes in the amount or timing of the estimated ARO are recorded as an adjustment to the related liability and asset. As at December 31, 2019, the ARO and associated receivable, which are recorded in Other long-term liabilities and Other non-current assets, respectively, were both $26.4 million (2018 - $24.7 million).

Debt issuance costs

Debt issuance costs related to a recognized debt liability, including bank fees, commissions and legal expenses, are capitalized and amortized over the term of the relevant loan facility to interest expense using an effective interest rate method. Debt issuance costs are presented as a reduction from the carrying amount of that debt 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.

Fees paid to amend a non-revolving credit facility can be associated with the extinguishment of the old debt instrument and included in determining the debt extinguishment gain or loss to be recognized. Any unamortized debt issuance costs would be written off. If a debt amendment is considered not to be a substantial amendment, then the fees would be associated with the replacement or modified debt instrument and, along with any existing unamortized debt issuance costs and premium or discount, would be amortized as an adjustment of interest expense over the remaining term of the replacement or modified debt instrument using the effective interest method. Other related costs incurred with third parties directly related to the modification, other than the loan amendment fee, are expensed as incurred.

Fees paid to amend revolving credit facilities are deferred and amortized over the term of the modified credit facility. If the borrowing capacity is increased as a result of the amendment, unamortized loan costs of the original facility would be deferred and amortized over the term of

F- 11

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

the modified credit facility. If the borrowing capacity is decreased as a result of the amendment, a proportionate amount, based on the reduction in borrowing capacity, of the unamortized debt issuance costs of the original facility would be written off and the remaining amount would be deferred and amortized over the term of the modified credit facility.

Goodwill

Goodwill is not amortized, but reviewed for impairment at the reporting unit level on an annual basis or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. When goodwill is reviewed for impairment, the Partnership will measure the amount by which a reporting unit’s carrying value exceeds its fair value, with the maximum impairment not to exceed the carrying value of goodwill.

Derivative instruments

All derivative instruments are initially recorded at fair value as either assets or liabilities in the accompanying consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the derivative contract is designed to hedge a specific risk and also qualifies and is designated for hedge accounting. During the year ended December 31, 2018, certain of the Partnership's interest rate swaps were designated in qualifying hedging relationships and hedge accounting was applied in the consolidated financial statements or within the Partnership's equity-accounted joint ventures (see note 12).

When a derivative is designated in a cash flow hedge, the Partnership formally documents the relationship between the derivative and the hedged item. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge. Any hedge ineffectiveness is recognized immediately in earnings, as are any gains and losses on the derivative that are excluded from the assessment of hedge effectiveness. The Partnership does not apply hedge accounting if it is determined that the hedge was 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. As at December 31, 2018, the Partnership had de-designated all hedging relationships and during the year ended December 31, 2019, the Partnership did not apply hedge accounting to any of its derivative instruments.

For derivative financial instruments designated in qualifying cash flow hedges, changes in the fair value of the effective portion of the derivative financial instruments are initially recorded as a component of accumulated other comprehensive income in equity. In the periods when the hedged items affect earnings, the associated fair value changes on the hedging derivatives are transferred from equity to the corresponding earnings line item in the consolidated statements of loss. If a cash flow hedge is de-desiganted and the originally hedged item is still considered probable of occurring, the gains and losses initially recognized in equity remain there until the hedged item impacts earnings, at which point they are transferred to the corresponding earnings line item in the consolidated statements of loss. If the hedged item is no longer probable of occurring, amounts recognized in equity are immediately transferred to the relevant earnings line item in the consolidated statements of loss.

For derivative financial instruments that are not designated as accounting hedges, the changes in the fair value of the derivative financial instruments are recognized in earnings. Gains and losses from the Partnership’s non-designated foreign currency forward contracts and interest rate swaps are recorded in realized and unrealized loss on derivative instruments in the consolidated statements of loss. Gains and losses from the Partnership’s non-designated cross currency swaps are recorded in foreign currency exchange loss in the consolidated statements of loss.

Unit-based compensation

The Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of the Partnership and Teekay Corporation’s subsidiaries that provide services to the Partnership (see note 17). The Partnership measures the cost of such awards using an option pricing model to determine the grant date fair value of the award and recognizes that cost, net of estimated forfeitures, over the requisite service period. The requisite service period consists of the period from the grant date of the award to the earlier of the date of vesting or the date the recipient becomes eligible for retirement. For unit-based compensation awards subject to graded vesting, the Partnership calculates the value of the award as if it was one single award with one expected life and amortizes the calculated expense for the entire award on a straight-line basis over the requisite service period. Certain of these awards are cash settled. For cash settled awards, the fair value of such awards is remeasured at each reporting date, based on the fair market value of the Partnership's common units at that date, with the change in fair value recognized as compensation expense. Unit-based compensation expenses are recorded under general and administrative expenses in the Partnership’s consolidated statements of loss.

Income taxes

The Partnership is subject to income taxes relating to its subsidiaries in Norway, Australia, Brazil, the United Kingdom, Singapore, Qatar, Canada, Luxembourg and the Netherlands. The Partnership accounts for such taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Partnership’s assets and liabilities using the applicable jurisdictional tax rates. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

Recognition of uncertain tax positions is dependent upon whether it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax position meets the more-likely-than-not recognition threshold, it is measured to determine the amount of benefit

F- 12

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

to recognize in the consolidated financial statements based on guidance in the interpretation. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax (expense) recovery in the Partnership’s consolidated statements of loss.

Employee pension plans

On January 1, 2018, the Partnership acquired a 100% ownership interest in seven subsidiaries of Teekay Corporation. These subsidiaries provide ship management, commercial, technical, strategic, business development and administrative services to the Partnership, primarily related to the Partnership's FPSO units, shuttle tankers and FSO units (see note 11l). Employees of these companies are generally eligible to participate in 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. With the exception of certain of the Partnership’s employees in Norway, the Partnership’s employees are generally eligible to participate in defined contribution plans. These plans allow for the employees to contribute a certain percentage of their base salaries into the plans. The Partnership matches all or a portion of the employees’ contributions, depending on how much each employee contributes. During the year ended December 31, 2019, the amount of cost recognized for the Partnership’s defined contribution pension plans was $5.2 million (December 31, 2018 and 2017 - $4.5 million and nil, respectively).

The Partnership also has defined benefit pension plans covering 288 active and retired employees in Norway as at December 31, 2019 (December 31, 2018 and 2017 - 443 and nil, respectively). 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 balance sheets. The Partnership recognizes as a component of other comprehensive (loss) income, 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 surplus of $0.3 million as at December 31, 2019 (December 31, 2018 and 2017 - deficiency of $1.5 million and nil, respectively).

2.	Accounting Pronouncements

In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (or ASU 2016-02). ASU 2016-02 establishes a right-of-use model that requires a lessee to record a right-of-use asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. For lessees, leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 requires lessors to classify leases as a sales-type, direct financing, or operating lease. A lease is a sales-type lease if any one of five criteria are met, each of which indicate that the lease, in effect, transfers control of the underlying asset to the lessee. If none of those five criteria are met, but two additional criteria are both met, indicating that the lessor has transferred substantially all of the risks and benefits of the underlying asset to the lessee and a third party, the lease is a direct financing lease. All leases that are not sales-type leases or direct financing leases are operating leases. ASU 2016-02 was effective January 1, 2019, with early adoption permitted. In July 2018, FASB issued an additional Accounting Standards Update that made further amendments to accounting for leases, including allowing the use of a transition approach whereby a cumulative effect adjustment is made as of the effective date, with no retrospective effect. The Partnership elected to use this new optional transition approach. The Partnership adopted ASU 2016-02 on January 1, 2019. To determine the cumulative effect adjustment, the Partnership has not reassessed whether any expired or existing contracts are, or contain leases, has not reassessed lease classification, and has not reassessed initial direct costs for any existing leases. The adoption of ASU 2016-02 has resulted in a change in the accounting method for the lease portion of the daily charter hire for the Partnership's chartered-in vessels accounted for as operating leases with firm periods of greater than one year. As of January 1, 2019, the Partnership had four in-chartered vessels in its fleet, the accounting for three of which vessels was impacted by the adoption of ASU 2016-02, as well as a small number of office leases. Under ASU 2016-02, the Partnership has recognized a right-of-use asset and a lease liability on the balance sheet for these charters and office leases based on the present value of future minimum lease payments, whereas previously no right-of-use asset or lease liability was recognized. The right-of-use asset and lease liability recognized on January 1, 2019 was $19.4 million and as at December 31, 2019 it was $57.7 million. As at December 31, 2019, the right-of-use asset is included in Other assets, and the lease liability in Other current liabilities and Other long-term liabilities, on the Partnership's consolidated balance sheet. The pattern of expense recognition of chartered-in vessels is expected to remain substantially unchanged, unless the right-of-use asset becomes impaired. In addition, under ASU 2016-02, direct financing lease payments received have been presented as an operating cash inflow instead of an investing cash inflow in the statement of cash flows. Direct financing lease payments received during the year ended December 31, 2019 were $0.9 million. The Partnership’s FPSO contracts, contracts of affreightment (or CoAs), time charters, and voyage charters include both a lease component, consisting of the lease of the vessel, and a non-lease component, consisting of operation of the vessel for the customer. The Partnership has elected to not separate the non-lease component from the lease component for all such charters, where the lease component is classified as an operating lease, and account for the combined components as an operating lease.

In June 2016, the FASB issued Accounting Standards Update 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments (or ASU 2016-13). ASU 2016-13 replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This update became effective for the Partnership on January 1, 2020, with a modified-retrospective approach. The Partnership is currently evaluating the effect of adopting this new guidance. Based on the Partnership's preliminary assessment, adoption of ASU 2016-13 is not expected to have a material impact on the Partnership's consolidated financial statements.

F- 13

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

In December 2019, the FASB issued Accounting Standards Update 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (or ASU 2019-12), as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 eliminate certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences, among other changes. The guidance becomes effective for annual reporting periods beginning after December 15, 2020 and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period. The Partnership is currently evaluating the effect of adopting this new guidance.

3.	Fair Value Measurements and Financial Instruments

a)	Fair value measurements

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Cash and cash equivalents and restricted cash - The fair values of the Partnership’s cash and cash equivalents and restricted cash approximate their carrying amounts reported in the accompanying consolidated balance sheets.

Derivative instruments – The fair value of the Partnership’s derivative instruments is the estimated amount that the Partnership would receive or pay to terminate the agreements at the reporting date, taking into account current interest rates, foreign exchange rates and the current credit worthiness of both the Partnership and the derivative counterparties. The estimated amount is the present value of future cash flows. The Partnership transacts all of its derivative instruments through investment-grade rated financial institutions at the time of the transaction. The Partnership’s interest rate swap agreements and foreign currency forward contracts require no collateral from these institutions. As at December 31, 2018, the Partnership had $1.2 million (December 31, 2019 - $nil) on deposit with the relevant counterparties as security for cross currency swap liabilities under certain master agreements. The deposit is presented in restricted cash on the consolidated balance sheet as at December 31, 2018.

Long-term debt – 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.

Vessels held for sale - During 2019, the carrying values of the Navion Hispania and Stena Sirita shuttle tankers and the Petrojarl Cidade de Rio das Ostras (or Ostras) FPSO unit were written down to their estimated fair values, using appraised values, as a result of the expected sales of the vessels.

Vessels and equipment – During 2019, as a result of a reassessment of the future redeployment assumptions for one FPSO unit and the Arendal Spirit UMS, the Partnership determined that the units were impaired and wrote down the carrying value of the units to their estimated fair value based on a discounted cash flow approach.

The Partnership determined the discounted cash flows for the one FPSO unit using the current contract's time-charter rates and operating costs, projected future use on the existing field, projected future upgrade costs, projected future use on new fields, and estimated residual value, discounted at an estimated market participant rate of 10%. The projected future uses take into consideration the Partnership’s projected time-charter rates that could be contracted in future periods. In establishing these estimates, the Partnership considered the specific attributes of this FPSO unit, current discussions with existing and potential customers, available field expansions and historical experience redeploying FPSO units.

The Partnership determined the discounted cash flows for the Arendal Spirit UMS using the current lay-up costs, projected future redeployment opportunities, estimated residual value, and estimated sales price, discounted at an estimated market participant rate of 10%. The projected future redeployment opportunities take into consideration the Partnership’s projected time-charter rates that could be contracted in future periods. In establishing these estimates, the Partnership considered the specific attributes of this UMS, current discussions with potential customers, and available redeployment opportunities.

Obligations related to finance leases - The fair values of the Partnership's obligations related to finance leases are estimated using discounted cash flow analyses, based on rates currently available for debt with similar terms and remaining maturities. Obligations related to finance leases are classified as Other current liabilities and Other long-term liabilities on the Partnership's consolidated balance sheet.

The Partnership categorizes its fair value estimates using a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value as follows:

Level 1.Observable inputs such as quoted prices in active markets;

Level 2.Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

Level 3.Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

F- 14

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following table includes the estimated fair value and carrying value of those assets and liabilities that are measured at fair value on a recurring and non-recurring basis, as well as the estimated fair value of the Partnership’s financial instruments that are not accounted for at fair value on a recurring basis:

				December 31, 2019						December 31, 2018
		Fair Value Hierarchy Level		Carrying Amount Asset (Liability) $			Fair Value Asset (Liability) $			Carrying Amount Asset (Liability) $			Fair Value Asset (Liability) $
Recurring:
Cash and cash equivalents and restricted cash		Level 1		306,256			306,256			233,580			233,580
Derivatives instruments (note 12)
Interest rate swap agreements		Level 2		(163,972	)		(163,972	)		(107,074	)		(107,074	)
Cross currency swap agreement		Level 2		—			—			(4,538	)		(4,538	)
Foreign currency forward contracts		Level 2		575			575			(4,650	)		(4,650	)
Non-Recurring:
Vessels held for sale (note 18)		Level 2		15,374			15,374			—			—
Vessels and equipment (note 18)		Level 2		176,577			176,577			—			—
Other:
Long-term debt - public (note 8)		Level 1		(1,067,740	)		(1,069,204	)		(1,027,696	)		(977,917	)
Long-term debt - non-public (note 8)		Level 2		(2,111,210	)		(2,136,315	)		(2,070,046	)		(2,082,316	)
Due to related parties - current (notes 11c and 11j)		Level 2		(20,000	)		(19,781	)		(125,000	)		(123,025	)
Obligations related to finance leases (note 14c)		Level 2		(21,453	)		(23,800	)		—			—

b)	Financing receivables

The following table contains a summary of the Partnership’s financing receivables by type of borrower and the method by which the Partnership monitors the credit quality of its financing receivables on a quarterly basis:

		Credit Quality Indicator		Grade		Year Ended December 31, 2019 $			Year Ended December 31, 2018 $
Direct financing leases		Payment activity		Performing		3,875			4,793

4.	Segment Reporting

The Partnership is engaged in the international marine transportation of crude oil, the offshore processing and storage of crude oil, long-distance ocean towage and offshore installation services, and maintenance and safety services through the operation of its shuttle tankers, FSO units, FPSO units, towage and offshore installation vessels and UMS. The Partnership’s revenues are earned in international markets.

The Partnership has six reportable segments: its FPSO segment; its shuttle tanker segment; its FSO segment; its UMS segment; its towage and offshore installation vessels (or towage) segment; and its conventional tanker segment. The Partnership’s FPSO segment consists of its FPSO units to service its FPSO contracts. The Partnership’s shuttle tanker segment consists of shuttle tankers operating primarily on fixed-rate contracts of affreightment, time-charter contracts or bareboat charter contracts. The Partnership’s FSO segment consists of its FSO units subject to fixed-rate, time-charter contracts or bareboat charter contracts. The Partnership’s UMS segment consists of one unit currently in lay-up. The Partnership’s towage and offshore installation vessels segment consists of long-distance towage and offshore installation vessels which operate on time-charter or voyage charter contracts. During 2019, the Partnership redelivered its two in-chartered conventional tankers to their owners and ceased operations in this segment. The accounting policies applied to the reportable segments are the same as those used in the preparation of the Partnership’s consolidated financial statements.

F- 15

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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)		Year Ended December 31, 2019		Year Ended December 31, 2018		Year Ended December 31, 2017
Royal Dutch Shell Plc (1)		$311.3 or 25%		$327.6 or 23%		$338.2 or 31%
Equinor ASA (formerly Statoil ASA) (2)		$170.8 or 13%		$182.1 or 13%		$114.5 or 10%
Petroleo Brasileiro S.A.(1)		—  (3)		$254.8 or 18%		$190.7 or 17%
Premier Oil (4)		—  (3)		—  (3)		$113.5 or 10%

(1)	Shuttle tanker and FPSO segments.

(2)	Shuttle tanker and FSO segments.

(3)	Percentage of consolidated revenue was less than 10%.

(4)	FPSO segment.

Effective for periods commencing on or after January 1, 2019, management and the chief operating decision maker has changed their primary measure for evaluating segment performance from income from vessel operations to Adjusted EBITDA. Adjusted EBITDA has also been presented for the years ended December 31, 2018 and 2017 to maintain comparability of segment performance between the periods reported in these consolidated financial statements. Adjusted EBITDA is defined as net loss before interest expense (net), income tax expense, and depreciation and amortization as 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 vessel write-downs, gains or losses on the sale of vessels, unrealized gains or losses on derivative instruments, foreign exchange gains or losses, losses on debt repurchases, and certain other income or expenses. Adjusted EBITDA also excludes: realized gains or losses on interest rate swaps as management, in assessing the Partnership's performance, views these gains or losses as an element of interest expense; realized gains or losses on derivative instruments resulting from amendments or terminations of the underlying instruments; and equity income. Adjusted EBITDA also includes the Partnership's proportionate share of Adjusted EBITDA from its equity-accounted joint ventures and excludes the non-controlling interests' proportionate share of Adjusted EBITDA from the Partnership's consolidated joint ventures. The Partnership does not have control over the operations of, nor does it have any legal claim to the revenue and expenses of its investments in, its equity-accounted for joint ventures. Consequently, the cash flow generated by the Partnership’s investments in equity accounted joint ventures may not be available for use by the Partnership in the period that such cash flows are generated.

F- 16

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following tables include results for the Partnership’s FPSO unit segment; shuttle tanker segment; FSO unit segment; UMS segment; towage segment; and conventional tanker segment for the periods presented in these consolidated financial statements:

Year ended December 31, 2019		FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Corporate/Eliminations(2)			Total
Revenues		492,658			549,587			140,117			2,940			74,726			7,972			—			1,268,000
Voyage expenses		—			(86,519	)		(800	)		(76	)		(37,530	)		(4,985	)		—			(129,910	)
Vessel operating expenses		(227,873	)		(126,433	)		(42,597	)		(1,216	)		(28,832	)		—			—			(426,951	)
Time-charter hire expenses		—			(40,108	)		—			—			—			(4,319	)		—			(44,427	)
General and administrative(1)		(40,846	)		(20,788	)		(4,006	)		(6,100	)		(4,401	)		(104	)		—			(76,245	)
Realized loss on foreign currency forward contracts		—			—			—			—			—			—			(5,054	)		(5,054	)
Adjusted EBITDA from equity-accounted vessels		97,849			—			—			—			—			—			—			97,849
Adjusted EBITDA attributable to non-controlling interests		—			(10,864	)		(500	)		—			—			—			—			(11,364	)
Adjusted EBITDA		321,788			264,875			92,214			(4,452	)		3,963			(1,436	)		(5,054	)		671,898
Equity income		32,794			—			—			—			—			—			—			32,794
Investment in joint ventures		234,627			—			—			—			—			—			—			234,627
Expenditures for vessels and equipment, including advances on newbuilding contracts(3)		8,284			185,156			6,967			922			110			—			—			201,439
Expenditures for dry docking		—			11,902			—			—			1,644			—			—			13,546

Year ended December 31, 2018		FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Corporate/Eliminations(2)			Total
Revenues(4)		533,186			636,413			136,557			36,536			53,327			21,325			(920	)		1,416,424
Voyage expenses		—			(109,796	)		(769	)		(47	)		(28,925	)		(12,453	)		182			(151,808	)
Vessel operating expenses		(214,623	)		(149,226	)		(42,913	)		(3,679	)		(27,346	)		—			116			(437,671	)
Time-charter hire expenses		—			(36,421	)		—			—			—			(16,195	)		—			(52,616	)
General and administrative(1)		(34,052	)		(21,763	)		(2,174	)		(3,547	)		(3,531	)		(360	)		—			(65,427	)
Restructuring charge		(1,520	)		—			—			—			—			—			—			(1,520	)
Realized loss on foreign currency forward contracts		—			—			—			—			—			—			(1,228	)		(1,228	)
Adjusted EBITDA from equity-accounted vessels		92,637			—			—			—			—			—			—			92,637
Adjusted EBITDA attributable to non-controlling interests		—			(15,593	)		(677	)		—			—			—			—			(16,270	)
Adjusted EBITDA		375,628			303,614			90,024			29,263			(6,475	)		(7,683	)		(1,850	)		782,521
Equity income		39,458			—			—			—			—			—			—			39,458
Investment in joint ventures		212,202			—			—			—			—			—			—			212,202
Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs(3)		54,371			147,540			6,987			—			24,838			—			—			233,736
Expenditures for dry docking		—			22,135			—			—			1,467			—			—			23,602

F- 17

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Year ended December 31, 2017		FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Corporate/Eliminations(2)			Total
Revenues		458,388			536,852			66,901			4,236			38,771			14,022			(8,886	)		1,110,284
Voyage expenses		—			(80,964	)		(1,172	)		(1,152	)		(17,727	)		(359	)		1,930			(99,444	)
Vessel operating (expenses) recoveries		(149,153	)		(129,517	)		(25,241	)		(33,656	)		(21,074	)		10			5,067			(353,564	)
Time-charter hire expenses		—			(62,899	)		—			—			(925	)		(16,491	)		—			(80,315	)
General and administrative(1)		(33,046	)		(17,425	)		(1,864	)		(5,068	)		(4,486	)		(360	)		—			(62,249	)
Restructuring charge		(450	)		(210	)		—			(2,004	)		—			—			—			(2,664	)
Realized gain on foreign currency forward contracts		—			—			—			—			—			—			900			900
Adjusted EBITDA from equity-accounted vessels		33,360			—			—			—			—			—			—			33,360
Adjusted EBITDA attributable to non-controlling interests		—			(23,035	)		(879	)		—			—			—			—			(23,914	)
Adjusted EBITDA		309,099			222,802			37,745			(37,644	)		(5,441	)		(3,178	)		(989	)		522,394
Equity income		14,442			—			—			—			—			—			—			14,442
Investment in joint ventures		169,875			—			—			—			—			—			—			169,875
Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs(3)		193,817			216,157			88,039			3,931			31,316			—			—			533,260
Expenditures for dry docking		—			16,323			199			—			661			—			—			17,183

(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)	Includes revenues and expenses earned and incurred between segments of the Partnership, during the years ended December 31, 2018 and 2017.

(3)	Expenditures for vessels and equipment, including advances on newbuilding contracts for the year ended December 31, 2019 includes: Shuttle Tanker Segment - installment payments on the seven shuttle tanker newbuildings (see note 14c).

Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs for the year ended December 31, 2018 includes: FPSO Segment - upgrade costs on the Petrojarl I FPSO unit; Shuttle Tanker Segment - the final East Coast of Canada newbuilding installment payment and installment payments on six Shuttle Spirit shuttle tanker newbuildings (see note 14c); Towage Segment - the final installment payment on one newbuilding towage and offshore installation vessel.

Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs for the year ended December 31, 2017 includes: FPSO Segment - upgrade costs on the Petrojarl I FPSO unit; Shuttle Tanker Segment - installment payments on the three East Coast of Canada shuttle tanker newbuildings and two Shuttle Spirit shuttle tanker newbuildings (see note 14c); FSO Segment - conversion costs on the Randgrid FSO unit; Towage Segment - installment payments on three newbuilding towage and offshore installation vessels.

(4)	Includes revenues of $55.0 million and $36.5 million in the Shuttle Tanker and UMS segments, respectively, during the year ended December 31, 2018 related to a settlement agreement with Petrobras and Petroleo Netherlands B.V. - PNBV S.A. (or Petrobras) in relation to the previously-terminated charter contracts of the HiLoad DP unit and Arendal Spirit UMS (see note 5).

F- 18

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following table includes reconciliations of Adjusted EBITDA to net loss for the periods presented in these consolidated financial statements:

	Year ended December 31, 2019 $			Year ended December 31, 2018 $			Year ended December 31, 2017 $
Adjusted EBITDA	671,898			782,521			522,394
Depreciation and amortization(1)	(349,379	)		(372,290	)		(309,975	)
(Write-down) and gain on sale of vessels(2)	(332,125	)		(223,355	)		(318,078	)
Interest expense	(205,709	)		(199,395	)		(154,890	)
Interest income	5,111			3,598			2,707
Realized and unrealized (loss) gain on derivative instruments(3)	(80,141	)		14,036			(43,753	)
Foreign currency exchange gain (loss)	2,193			(9,413	)		(14,006	)
Losses on debt repurchases	—			(55,479	)		(3,102	)
Other (expense) income - net	(1,225	)		(4,602	)		14,167
Expenses and losses relating to equity accounted investments(4)	(65,055	)		(53,179	)		(18,918	)
Adjusted EBITDA attributable to non-controlling interests	11,364			16,270			23,914
Loss before income tax (expense) recovery	(343,068	)		(101,288	)		(299,540	)
Income tax (expense) recovery	(7,827	)		(22,657	)		98
Net loss	(350,895	)		(123,945	)		(299,442	)

(1)

Depreciation and amortization by segment for the year ended December 31, 2019 is as follows: FPSO $145.9 million, Shuttle Tanker $134.3 million, FSO $41.7 million, UMS $6.6 million and Towage $20.9 million. Depreciation and amortization by segment for the year ended December 31, 2018 is as follows: FPSO $145.5 million, Shuttle Tanker $155.9 million, FSO $44.1 million, UMS $6.6 million, Towage $20.3 million and eliminations of amounts incurred between segments of ($0.1) million. Depreciation and amortization by segment for the year ended December 31, 2017 is as follows: FPSO $143.6 million, Shuttle Tanker $125.6 million, FSO $19.4 million, UMS $6.6 million, Towage $15.6 million and eliminations of amounts incurred between segments of ($0.8) million.

(2)

(Write-down) and gain on sale of vessels by segment for the year ended December 31, 2019 is as follows: FPSO ($227.4) million, Shuttle Tanker ($0.9) million, FSO $11.2 million, UMS ($115.0) million. (Write-down) and gain on sale of vessels by segment for the year ended December 31, 2018 is as follows: FPSO ($180.2) million, Shuttle Tanker ($43.2) million. (Write-down) and gain on sale of vessels by segment for the year ended December 31, 2017 is as follows: FPSO ($265.2) million, Shuttle Tanker ($51.7) million, FSO ($1.1) million.

(3)	Excludes the realized gain (loss) on foreign currency forward contracts.

(4)

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 relating to equity accounted investments. The sum of (a) Adjusted EBITDA from equity-accounted vessels as presented in the tables above as part of the results for the Partnership’s reportable segments and (b) expenses and gains (losses) relating to equity accounted investments from this table equals the amount of equity income included on the Partnership's consolidated statements of loss.

A reconciliation of total segment assets to total assets presented in the accompanying consolidated balance sheets is as follows:

		December 31, 2019 $			December 31, 2018 $
FPSO segment		1,913,420			2,279,277
Shuttle tanker segment		1,778,073			1,684,887
FSO segment		425,694			463,647
Towage segment		390,895			419,000
UMS segment		101,009			220,509
Conventional tanker segment		—			4,259
Unallocated:
Cash and cash equivalents and restricted cash		306,256			233,580
Other assets		7,920			6,893
Consolidated total assets		4,923,267			5,312,052

5.	Revenue

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.

F- 19

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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, 2019, the Partnership also generated revenues from the operation of VOC systems on six of the Partnership’s shuttle tankers, and the management of three FPSO units and one FSO unit (December 31, 2018 - VOC systems on 13 of the Partnership's shuttle tankers, and the management of three FPSO units, one FSO unit and two shuttle tankers) on behalf of the disponent owners or charterers of these assets.

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 performance 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 such consideration is allocated to the distinct period in which such variable consideration was earned. The Partnership does not engage in any specific tactics 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.

Contracts of Affreightment

Voyages performed pursuant to a CoA for the Partnership’s shuttle tankers are priced based on the pre-agreed terms in the CoA. The performance obligations within a voyage performed pursuant to a CoA, which will typically include the lease of the vessel to the charterer as well as the operation of the vessel, are satisfied as services are rendered over the duration of the voyage, as measured using the time that has elapsed from commencement of performance. In addition, any expenses that are unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions, are the responsibility of the vessel owner. Consideration for such voyages consists of a fixed daily hire rate for the duration of the voyage, the reimbursement of costs incurred from fuel consumed during the voyage, as well as a fixed lump sum intended to compensate for time necessary for the vessel to return to the field following completion of the voyage. While such consideration is generally fixed, certain sources of variability exist, including variability in the duration of the voyage and the actual quantity of fuel consumed during the voyage. Payment for the voyage is not due until the voyage is completed. The duration of a single voyage will typically be less than two weeks. The Partnership does not engage in any specific tactics to minimize residual value risk due to the short-term nature of the contracts.

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 performance obligations within a time-charter contract, which will 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 such contract, 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 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. 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 half of the charter and such amount drawn down in the last half of the charter. Some time 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 drydocking 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 such consideration is allocated to the distinct period in which such variable consideration was earned. The Partnership does not engage in any specific tactics to minimize residual value risk.

The time charters for four shuttle tankers servicing the East Coast Canada project can be canceled upon two years' notice. The time charters for four shuttle tankers in Brazil can be extended by up to ten years, at the election of the charterer. The time charters for the vessels servicing the Equinor North Sea requirements under the terms of a master agreement are one year in length and may be renewed for subsequent one-year periods. The number of vessels required under the terms of the master agreement may be adjusted annually based on the requirements

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

of the fields serviced. The time charter contracts for three FSO units can be extended for periods between five and 12 years or terminated early.

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. However, 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. The performance obligations within a bareboat charter, which will include the lease of the vessel to the charterer, are satisfied as 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.

Voyage Charters

Voyage charters are charters for a specific voyage. Voyage charters for the Partnership’s shuttle tankers, conventional tankers and towage and offshore installation vessels are priced on a current or “spot” market rate. The performance obligations within a voyage charter contract, which 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, 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 and conventional tankers will normally contain a lease, whereas for towage and offshore installation vessels such contracts will not normally contain a lease. Such determination involves judgment about the decision-making rights the charterer has within 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. The Partnership does not engage in any specific tactics to minimize residual value risk due to the short-term nature of the contracts.

Management Fees and Other

During the year ended December 31, 2019, the Partnership also generated revenues from the operation of VOC systems on six of the Partnership’s shuttle tankers, and the management of three FPSO units and one FSO unit (December 31, 2018 - VOC systems on 13 of the Partnership's shuttle tankers, and the management of three FPSO units, one FSO unit and two shuttle tankers) 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 performance obligations within these contracts will typically consist of crewing, technical management, insurance and, potentially, commercial management. The performance obligations are satisfied concurrently and consecutively rendered over the duration of the management contract, as measured using the time that has elapsed from commencement of performance. Consideration for such contracts will generally consist 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 Table

The following tables contain the Partnership’s revenue for the years ended December 31, 2019, 2018 and 2017, by contract type and by segment:

Year ended December 31, 2019	FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Eliminations			Total
FPSO contracts	421,363			—			—			—			—			—			—			421,363
CoAs	—			188,277			—			—			—			—			—			188,277
Time charters	—			293,095			121,762			—			—			—			—			414,857
Bareboat charters	—			34,611			15,178			—			—			—			—			49,789
Voyage charters	—			24,315			—			—			74,726			7,972			—			107,013
Management fees and other	71,295			9,289			3,177			2,940			—			—			—			86,701
	492,658			549,587			140,117			2,940			74,726			7,972			—			1,268,000

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Year ended December 31, 2018	FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Eliminations(1)			Total
FPSO contracts	481,700			—			—			—			—			—			—			481,700
CoAs	—			198,448			—			—			—			—			—			198,448
Time charters	—			294,112			116,125			—			—			—			—			410,237
Bareboat charters	—			44,759			17,383			—			—			—			—			62,142
Voyage charters	—			28,027			—			—			53,327			21,325			(920	)		101,759
Management fees and other(2)	51,486			71,067			3,049			36,536			—			—			—			162,138
	533,186			636,413			136,557			36,536			53,327			21,325			(920	)		1,416,424

Year ended December 31, 2017	FPSO Segment			Shuttle Tanker Segment			FSO Segment			UMS Segment			Towage Segment			Conventional Tanker Segment			Eliminations(1)			Total
FPSO contracts	458,388			—			—			—			—			—			—			458,388
CoAs	—			170,703			—			—			—			—			—			170,703
Time charters	—			284,281			47,605			4,236			—			9,132			—			345,254
Bareboat charters	—			69,568			19,296			—			—			—			—			88,864
Voyage charters	—			12,300			—			—			38,771			4,890			(8,886	)		47,075
	458,388			536,852			66,901			4,236			38,771			14,022			(8,886	)		1,110,284

(1)	Includes revenues earned between segments of the Partnership, during the years ended December 31, 2018 and December 31, 2017.

(2)

Includes revenues of $55.0 million and $36.5 million in the shuttle tanker and UMS segments, respectively, related to a settlement agreement with Petrobras in relation to the previously-terminated charter contracts of the HiLoad DP unit and Arendal Spirit UMS. As part of the settlement agreement, Petrobras has agreed to pay a total amount of $96.0 million to the Partnership, which includes $55.0 million that was paid November 2018, and amounts of $22.0 million payable in late-2020 and $19.0 million payable in late-2021, which are available to be reduced by 40% of the revenues paid prior to the end of 2021 by Petrobras under any new contracts entered into subsequent to October 25, 2018 relating specifically to the Arendal Spirit UMS and the Ostras and Piranema Spirit FPSO units.

The following table contains the Partnership’s revenue by lease and non-lease contracts for the years ended December 31, 2019, 2018 and 2017:

	Year ended December 31,
	2019			2018			2017
	$			$			$
Lease revenue
Lease revenue from lease payments of direct financing and sales type leases	858			1,720			2,396
Lease revenue from lease payments of operating leases	1,079,356			1,175,073			1,028,123
Variable lease payments - cost reimbursements(1)	11,314			19,316			33,159
Variable lease payments(2)	15,045			303			2,022
	1,106,573			1,196,412			1,065,700
Non-lease revenue
Non-lease revenue - related to sales type or direct financing leases	—			4,547			5,813
Voyage charters - towage	74,726			53,327			38,771
Management fees and other	86,701			162,138			—
	161,427			220,012			44,584
	1,268,000			1,416,424			1,110,284

(1)	Reimbursements for vessel operating expenditures received from the Partnership’s customers relating to such costs incurred by the Partnership to operate the vessel for the customer.

(2)	Compensation from 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.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

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 as deferred revenue 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 current 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 balance sheets associated with these long-term charter arrangements from contracts with customers:

	December 31, 2019			December 31, 2018
	$			$
Contract Assets
Current	3,816			7,926
Non-Current	74,830			62,295
	78,646			70,221
Contract Liabilities
Current	53,728			55,750
Non-Current	84,077			145,852
	137,805			201,602

During the year ended December 31, 2019 the Partnership recognized revenue of $53.1 million, that was included in the contract liability on December 31, 2018.

Contract Costs

In certain cases, the Partnership incurs pre-operational costs that relate directly to a specific customer contract, that generate or enhance resources of the Partnership that will be used in satisfying performance obligations in the future, whereby 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 vessel operating expenses over the duration of the customer contract. Amortization of such costs for the Partnership for the year ended December 31, 2019, 2018 and 2017 was $20.9 million, $19.7 million and $24.1 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 balance sheet, by main category, excluding balances in the Partnership’s equity accounted joint ventures, are as follows:

	Year ended December 31,
	2019			2018			2017
	$			$			$
Pre-operational costs	12,836			24,031			4,522
Offshore asset mobilization costs	35,632			51,302			57,818
Vessel repositioning costs	13,379			15,188			—
	61,847			90,521			62,340

6.	Goodwill and In-Process Revenue Contracts

a)	Goodwill

The carrying amount of goodwill for the shuttle tanker segment was $127.1 million as at December 31, 2019 and 2018. In 2019, 2018 and 2017, the Partnership conducted its annual goodwill impairment review of its shuttle tanker segment and concluded that no impairment had occurred.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The carrying amount of goodwill for the towage segment was $2.0 million as at December 31, 2019 and 2018. In 2019, 2018 and 2017, the Partnership conducted its annual goodwill impairment review of its towage segment and concluded that no impairment had occurred.

b)	In-Process Revenue Contracts

As part of the Partnership’s acquisition of the Piranema Spirit FPSO unit on November 30, 2011, the Partnership assumed an FPSO contract with terms that were less favorable than the then prevailing market terms and recorded a liability based on the estimated fair value of the contract. The Partnership amortized this liability over the term of the contract, which completed during 2019, on a weighted basis based on the revenue earned under the contract.

Amortization of in-process revenue contracts for the year ended December 31, 2019 was $15.1 million (2018 - $35.2 million, 2017 - $12.7 million), which is included in revenues on the consolidated statements of loss.

7.	Accrued Liabilities

		December 31, 2019 $			December 31, 2018 $
Interest including interest rate swaps		48,047			44,887
Payroll and benefits		36,807			34,828
Audit, legal, contingency and other general expenses		32,372			21,626
Voyage and vessel expenses		19,829			25,475
Income and other tax payable		3,921			3,080
		140,976			129,896

8.Long-Term Debt

	December 31, 2019 $			December 31, 2018 $
U.S. Dollar-denominated Revolving Credit Facilities due through 2024	513,200			523,125
U.S. Dollar-denominated Term Loans due through 2032	1,357,236			1,388,107
U.S. Dollar-denominated Term Loan due through 2021	42,073			55,018
U.S. Dollar Bonds due through 2024	1,075,000			1,024,816
U.S. Dollar Non-Public Bonds due through 2027	241,145			141,158
Norwegian Krone Bonds due through 2019	—			9,953
Total principal	3,228,654			3,142,177
Less debt issuance costs and other	(49,704	)		(44,435	)
Total debt	3,178,950			3,097,742
Less current portion	(353,238	)		(554,336	)
Long-term portion	2,825,712			2,543,406

As at December 31, 2019, the Partnership had two revolving credit facilities (December 31, 2018 - two), which, as at such date, provided for total borrowings of up to $513.2 million (December 31, 2018 - $523.1 million) and were fully drawn (December 31, 2018 - fully drawn). The total amount available under the revolving credit facilities reduces by $73.6 million (2020), $73.6 million (2021), $103.6 million (2022), $53.6 million (2023) and $208.8 million (2024). One revolving credit facility is guaranteed by the Partnership for all outstanding amounts and contains covenants that require the Partnership to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $75.0 million and 5.0% of the Partnership’s total consolidated debt. The other revolving credit facility is guaranteed by subsidiaries of the Partnership, and contains covenants that require Teekay Shuttle Tankers L.L.C. (a wholly-owned subsidiary of the Partnership which was formed during 2017 to hold the Partnership’s shuttle tanker fleet) to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $35.0 million and 5.0% of Teekay Shuttle Tankers L.L.C.'s total consolidated debt, and a net debt to total capitalization ratio no greater than 75.0%. The revolving credit facilities are collateralized by first-priority mortgages granted on 17 (December 31, 2018 - 19) of the Partnership’s vessels, together with other related security.

As at December 31, 2019, the Partnership had term loans outstanding secured by three shuttle tankers, two FSO units, two FPSO units, ten towage and offshore installation vessels, four shuttle tanker newbuildings, and the Arendal Spirit UMS, which totaled $1.4 billion in the aggregate. (December 31, 2018 - secured by three shuttle tankers, two FSO units, three FPSO units, ten towage and offshore installation vessels, four shuttle tanker newbuildings, and the Arendal Spirit UMS, which totaled $1.4 billion). The term loans reduce over time with quarterly or semi-annual payments and have varying maturities through 2032. As at December 31, 2019, the Partnership or a subsidiary of the Partnership had guaranteed all of these term loans.

As at December 31, 2019, two of the Partnership’s 50%-owned subsidiaries had one outstanding term loan (December 31, 2018 - one), which totaled $42.1 million (December 31, 2018 - $55.0 million). The term loan reduces over time with quarterly payments and matures in 2021. The term loan is collateralized by first-priority mortgages on the two shuttle tankers to which the loan relates, together with other related

F- 24

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

security. As at December 31, 2019, a subsidiary of the Partnership guaranteed $21.0 million of the term loan, which represents its 50% share of the outstanding term loan, and the other owner had guaranteed the remaining $21.0 million of the term loan.

Interest payments on the revolving credit facilities and the term loans are based on LIBOR plus margins, except for $71.6 million of one tranche of the term loan for the towage and offshore installation vessels, which is fixed at 2.93% and $79.2 million of one tranche of the term loan for the shuttle tanker newbuildings, which is fixed at 4.55%. At December 31, 2019, the margins for variable rate facilities and loans ranged between 0.90% and 4.30%, (December 31, 2018, 0.90% and 4.30%). The weighted-average interest rate on the Partnership’s variable rate facilities and loans as at December 31, 2019 was 4.3% (December 31, 2018 – 5.1%). This rate does not include the effect of the Partnership’s interest rate swaps (see note 12), fixed rate facilities or variable rate bonds.

In October 2019, the Partnership's wholly-owned subsidiary Teekay Shuttle Tankers L.L.C. issued $125.0 million in senior unsecured green bonds in the Norwegian bond market that mature in October 2024. These bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on LIBOR plus a margin of 6.50%. As at December 31, 2019, the carrying amount of the bonds was $125.0 million (December 31, 2018 - nil).

In July 2018, the Partnership issued, in a U.S. private placement, $700.0 million of five-year senior unsecured bonds that mature in July 2023. The interest payments on the bonds are fixed at a rate of 8.50%. The bonds contain certain incurrence-based covenants. As at December 31, 2019, the carrying amount of the bonds was $700.0 million. Brookfield Business Partners L.P. and its institutional investors (or Brookfield) purchased $500.0 million of these bonds and as at December 31, 2019 held $423.6 million of these bonds (December 31, 2018 - $475.0 million) (see note 11k).

In August 2017, the Partnership's wholly-owned subsidiary Teekay Shuttle Tankers L.L.C. issued $250.0 million in senior unsecured bonds in the Norwegian bond market that mature in August 2022. These bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are fixed at a rate of 7.125%. As at December 31, 2019, the carrying amount of the bonds was $250.0 million (December 31, 2018 - $250.0 million).

In September 2019, the Partnership issued $120.0 million in senior bonds in a U.S. private placement that mature in September 2027. The interest payments on the bonds are fixed at a rate of 7.107%. The bonds are collateralized by certain related security and are guaranteed by the Partnership. The Partnership makes semi-annual repayments on the bonds and as at December 31, 2019, the carrying amount of the bonds was $119.0 million (December 31, 2018 - nil).

In February 2015, the Partnership issued $30.0 million in senior bonds in a U.S. private placement that mature in July 2024. The interest payments on the bonds are fixed at a rate of 4.27%. The bonds are collateralized by a first-priority mortgage on the Dampier Spirit FSO unit, together with other related security, and are guaranteed by subsidiaries of the Partnership. The Partnership makes semi-annual repayments on the bonds and as at December 31, 2019, the carrying amount of the bonds was $13.6 million (December 31, 2018 - $17.2 million).

In September 2013 and November 2013, the Partnership issued, in a U.S. private placement, a total of $174.2 million of ten-year senior bonds that mature in January 2024, to finance the Bossa Nova Spirit and Sertanejo Spirit shuttle tankers. The bonds accrue interest at a fixed combined rate of 4.96%. The bonds are collateralized by first-priority mortgages on the two vessels to which the bonds relate, together with other related security, and are guaranteed by subsidiaries of the Partnership. The Partnership makes semi-annual repayments on the bonds and as at December 31, 2019, the carrying amount of the bonds was $108.6 million (December 31, 2018 - $123.9 million).

The aggregate annual long-term debt principal repayments required to be made subsequent to December 31, 2019, are $354.4 million (2020), $315.7 million (2021), $577.7 million (2022), $1,113.3 million (2023), $453.2 million (2024), and $414.4 million (thereafter).

Certain of the Partnership’s revolving credit facilities, term loans and bonds contain covenants, debt-service coverage ratio (or DSCR) requirements and other restrictions typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from, among other things: incurring or guaranteeing indebtedness; changing ownership or structure, including mergers, consolidations, liquidations and dissolutions; paying dividends or distributions if the Partnership is in default or does 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 the Partnership’s credit facilities are secured by certain vessels, and if the Partnership is unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. The Partnership has two revolving credit facilities and seven term loans that require the Partnership to maintain vessel values to drawn principal balance ratios of a minimum range of 100% to 150%. Such requirement is assessed either on a semi-annual or annual basis, with reference to vessel valuations compiled by one or more agreed upon third parties. Should the ratio drop below the required amount, the lender may request the Partnership to either prepay a portion of the loan in the amount of the shortfall or provide additional collateral in the amount of the shortfall, at the Partnership's option. As at December 31, 2019, these hull covenant ratios were estimated to range from 126% to 501% and the Partnership was in compliance with the minimum ratios required. The vessel values used in calculating these ratios are the appraised values provided by third parties where available, or prepared by the Partnership based on second-hand sale and purchase market data. Changes in the shuttle tanker, towage, UMS, FSO unit or FPSO unit markets could negatively affect these ratios.

As at December 31, 2019, the Partnership was in compliance with all covenants related to the credit facilities and consolidated long-term debt.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

9.	Leases

Charters-out

The cost, accumulated depreciation and carrying amount of the Partnership's vessels with charter-out contracts accounted for as operating leases at December 31, 2019 were $3.8 billion, $1.1 billion and $2.7 billion, respectively (2018 - $4.3 billion, $1.1 billion and $3.2 billion, respectively). As at December 31, 2019, minimum scheduled future rentals under these then-in-place time charters and bareboat charters to be received by the Partnership, were approximately $2.9 billion, comprised of $704.3 million (2020), $590.7 million (2021), $512.5 million (2022), $299.3 million (2023), $133.6 million (2024) and $622.2 million (thereafter).

The minimum scheduled future revenues should not be construed to reflect total charter hire revenues for any of the years. Minimum scheduled future revenues do not include revenue generated from new contracts entered into after December 31, 2019, revenue from unexercised option periods of contracts that existed on December 31, 2019, or variable or contingent revenues. The amounts may vary given unscheduled future events such as vessel maintenance. For a further description of the Partnership's charter-out contracts please see note 5.

Direct Financing Lease

Leasing of certain VOC equipment is accounted for as a direct financing lease. As at December 31, 2019, the minimum lease payments receivable under the direct financing lease approximated $4.6 million (2018 - $5.9 million), including unearned income of $0.7 million (2018 - $1.1 million). As at December 31, 2019, future scheduled payments under the direct financing leases to be received by the Partnership, were approximately $4.6 million, comprised of $1.3 million (2020), $1.3 million (2021), $1.3 million (2022) and $0.6 million (2023).

Charters-in

The Partnership charters in vessels from other vessel owners on time-charter contracts, whereby the vessel owner will provide use of the vessel to the Partnership, as well as operate 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. 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. 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 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.

With respect to time-charter-in contracts with an original term of more than one year, for the year ended December 31, 2019, the Partnership incurred $22.0 million of time-charter hire expense related to these time-charter-in contracts, of which $13.0 million was allocated to the lease component and $9.0 million was allocated to the non-lease component. The $13.0 million allocated to the lease component approximates the cash paid for the amounts included in lease liabilities and is reflected as a reduction in operating cash flows for the year ended December 31, 2019. As at December 31, 2019, the weighted-average remaining lease term and weighted-average discount rate for these time-charter-in contracts was 4.0 years and 5.29%, respectively.

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 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. For the year ended December 31, 2019, the Partnership incurred $22.4 million of time-charter hire expense related to time-charter contracts classified as short-term leases.

F- 26

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

A maturity analysis of the Partnership’s operating lease liabilities from time-charter-in contracts (excluding short-term leases) as at December 31, 2019 is as follows:

	Lease Commitment			Non-Lease Commitment			Total Commitment
As at December 31, 2019	$			$			$
Payments:
January to December 2020	11,694			7,552			19,246
January to December 2021	11,829			7,639			19,468
January to December 2022	11,995			7,746			19,741
January to December 2023	11,225			7,249			18,474
January to December 2024	641			414			1,055
Total payments	47,384			30,600			77,984
Less imputed interest	(4,840	)
Carrying value of operating lease liabilities	42,544

As at December 31, 2019, minimum commitments to be incurred by the Partnership under short-term time-charter contracts were approximately $16.0 million (2020) and $2.3 million (2021).

10.	Restructuring Charge

During the year ended December 31, 2018, the Partnership recognized a restructuring charge of $1.5 million, mainly relating to severance costs from crew reduction on the Petrojarl Varg FPSO unit, which is currently in lay-up. The Partnership incurred a total of $1.5 million of restructuring charges under this plan.

During the year ended December 31, 2017, the Partnership recognized a restructuring charge of $2.7 million, mainly relating to severance costs from the termination of the charter contract for the Arendal Spirit UMS and the resulting decommissioning of the unit. The Partnership incurred a total of $2.7 million of restructuring charges under this plan.

As of December 31, 2019 and December 31, 2018, restructuring liabilities of nil and $1.5 million, respectively, were recorded in accrued liabilities on the consolidated balance sheet.

11.	Related Party Transactions and Balances

a)

The Partnership provides to and receives from Teekay Corporation and its wholly-owned subsidiaries certain commercial, technical, crew training, strategic, business development and/or administrative services. In addition, the Partnership reimburses its general partner for expenses incurred by the general partner that are necessary or appropriate for the conduct of the Partnership’s business. On May 8, 2019, Brookfield acquired all of Teekay Corporation's remaining interests in the Partnership, including its 49% general partner interest (providing Brookfield with 100% of the general partner ownership interest), 13.8% interest in common units, 17.3 million common unit equivalent warrants and a $25 million loan receivable outstanding (see note 11j). Effective May 8, 2019, Teekay Corporation and its wholly-owned subsidiaries were no longer related parties of the Partnership; however, the Partnership continues to provide to and receive from Teekay Corporation the services described above. Certain administrative services historically provided to the Partnership by Teekay Corporation are in the process of being transferred or have been transferred to the Partnership. The Partnership's related party transactions recognized in the consolidated statements of loss were as follows for the periods indicated:

	Year Ended December 31,
	2019 $			2018 $			2017 $
Revenues(1)	42,628			117,764			49,509
Vessel operating expenses(2)	(2,535	)		(6,298	)		(32,346	)
General and administrative(3)	(8,811	)		(18,162	)		(31,340	)
Interest expense(4)(5)(6)(7)(8)	(46,744	)		(38,695	)		(25,882	)
Losses on debt repurchases(9)	—			(46,041	)		—

    

(1)	Includes revenue 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.

F- 27

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(3)	Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and 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 $8.3 million for the year ended December 31, 2019 (December 31, 2018 and 2017 - $5.0 million and nil, respectively), incurred on the unsecured revolving credit facility provided by Brookfield and by Teekay Corporation prior to May 8, 2019 (see note 11j).

(5)	Includes interest expense of $38.5 million for the year ended December 31, 2019 (December 31, 2018 and 2017 - $21.0 million and nil, respectively), incurred on a portion of five-year senior unsecured bonds held by Brookfield (see note 11k).

(6)	Includes interest expense of $10.0 million for the year ended December 31, 2018 (December 31, 2017 - $5.3 million), and accretion expense of $2.7 million for the year ended December 31, 2018 (December 31, 2017 - $2.2 million), incurred on the Brookfield Promissory Note (see note 11h).

(7)	Includes interest expense of $14.6 million for the year ended December 31, 2017, incurred on the 2016 Teekay Corporation Promissory Note (see note 11g).

(8)

Includes a guarantee fee to Teekay Corporation related to the final bullet payment of the Piranema Spirit FPSO unit debt facility, which was repaid in March 2017, and a guarantee fee to Teekay Corporation related to the Partnership's liabilities associated with the long-term debt financing relating to the East Coast of Canada shuttle tanker newbuildings and certain of the Partnership's interest rate swaps and cross currency swaps until September 25, 2017 (see notes 11i and 12).

(9)

Includes the loss on the Partnership's prepayment of the Brookfield Promissory Note, which includes the acceleration of non-cash accretion expense of $31.5 million resulting from the difference between the $200.0 million settlement amount at its par value and its carrying value of $168.5 million, an associated early termination fee of $12.0 million paid to Brookfield and the write-off of capitalized loan costs (see note 11k).

b)	During the year ended December 31, 2019, two shuttle tankers and three FSO units (December 31, 2018 - three shuttle tankers and three FSO units, December 31, 2017 - 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.

c)	At December 31, 2019, the carrying value of amounts due from related parties totaled nil (December 31, 2018 - $59.8 million) and the carrying value of amounts due to related parties totaled $20.0 million (December 31, 2018 - $183.8 million). As at December 31, 2019, the amounts due to related parties consisted only of the unsecured revolving credit facility provided by Brookfield (see note 11j).

d)

In December 2014, the Partnership entered into an agreement with a consortium led by Enauta Participações SA (or Enauta, formerly Queiroz Galvão Exploração e Produção SA) to provide an FPSO unit for the Atlanta field located in the Santos Basin offshore Brazil. In connection with the contract with Enauta, the Partnership acquired the Petrojarl I FPSO unit from Teekay Corporation for a purchase price of $57 million. The Partnership received project management and engineering services from certain subsidiaries of Teekay Corporation relating to this FPSO unit upgrade. The costs for these services have been capitalized and included as part of vessels and equipment. Cumulative project management and engineering costs paid to Teekay Corporation subsidiaries up to completion of the project in 2018 were $4.5 million.

e)

In June 2015, the Partnership entered into 15-year contracts, plus extension options, with a group of oil companies to provide shuttle tanker services for oil production on the East Coast of Canada. The Partnership entered into contracts to have three Suezmax Dynamic Positioning 2 (or DP2) shuttle tanker newbuildings constructed. These vessels replaced the existing vessels servicing the East Coast of Canada. The newbuildings delivered in late-2017 through early-2018. The Partnership received project management and engineering services from certain subsidiaries of Teekay Corporation relating to the construction of these shuttle tankers. The costs for these services have been capitalized and included as part of vessels and equipment. Project management and engineering costs paid to Teekay Corporation subsidiaries up to delivery of the final vessel in 2018 were $4.1 million.

f)

During 2017 and 2018, the Partnership entered into shipbuilding contracts with Samsung Heavy Industries Co., Ltd. to construct four Suezmax DP2 and two Aframax DP2 shuttle tanker newbuildings, which are expected to deliver through 2021 (see note 14c). The Partnership received project management and engineering services from certain subsidiaries of Teekay Corporation relating to the construction of these shuttle tankers. These costs are capitalized and included as part of advances on newbuilding construction contracts and are reclassified to vessels and equipment upon delivery of the vessels. Cumulative project management and engineering costs paid to Teekay Corporation subsidiaries were $1.8 million as at May 8, 2019 (December 31, 2018 - $1.1 million).

g)

Effective July 1, 2016, the Partnership issued a $200.0 million promissory note to a subsidiary of Teekay Corporation (or the 2016 Teekay Corporation Promissory Note) to re-finance existing promissory notes issued to Teekay Corporation. The 2016 Teekay Corporation Promissory Note bore interest at an annual rate of 10.00% on the outstanding principal balance, which was payable quarterly, and of which (a) 5.00% was payable in cash and (b) 5.00% was payable in common units of the Partnership, or in cash, at the election of Teekay Corporation. If the Partnership paid cash for the second 5.00% of interest, the Partnership was required to raise at least an equal amount of cash proceeds from the issuance of common units in advance of or within six months following the applicable interest payment date. The outstanding principal balance of the 2016 Teekay Corporation Promissory Note, together with accrued interest, was payable in full on January 1, 2019. On September 25, 2017, the Partnership, Brookfield and Teekay Corporation entered into an agreement to amend and restate this promissory note (see note 11h). During the year ended December 31, 2017, the Partnership incurred $14.6 million of interest expense on the 2016 Teekay Corporation Promissory Note, of which $9.6 million was paid in cash and the remainder was settled through the issuance of 1.7 million common units of the Partnership under the terms of the 2016 Teekay Corporation Promissory Note.

h)	Effective September 25, 2017, the Partnership, Brookfield and Teekay Corporation amended and restated the 2016 Teekay Corporation Promissory Note to create the Brookfield Promissory Note, concurrently with Brookfield’s acquisition of the 2016 Teekay Corporation

F- 28

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Promissory Note from a subsidiary of Teekay Corporation. The Brookfield Promissory Note of $200.0 million bore interest at an annual rate of 10.00% on the outstanding principal balance, which was payable quarterly. The outstanding principal balance of the Brookfield Promissory Note, together with accrued interest, was payable in full on January 1, 2022. The Brookfield Promissory Note was recorded at its relative fair value of $163.6 million based on the allocation of net proceeds invested by Brookfield, as at September 25, 2017 (see note 16). On July 2, 2018, the Partnership repurchased the Brookfield Promissory Note (see note 11k). During the year ended December 31, 2018, the Partnership incurred $10.0 million (December 31, 2017 - $5.3 million) of interest expense under the terms of the Brookfield Promissory Note.

i)

In June 2016, as part of various other financing initiatives, Teekay Corporation agreed to provide financial guarantees for the Partnership's liabilities associated with the long-term debt financing relating to the East Coast of Canada newbuilding shuttle tankers until their deliveries, and for certain of the Partnership's interest rate swaps and cross currency swaps until early-2019. The guarantees covered liabilities totaling up to a maximum amount of $495.0 million. Effective September 25, 2017, the Partnership secured the release, for fees to the applicable counterparties, of all of these financial guarantees provided by Teekay Corporation relating to the Partnership's interest rate swap, cross currency swap agreements and East Coast of Canada financing. During the year ended December 31, 2017, a guarantee fee of $5.8 million was recognized in interest expense on the Partnership's consolidated statements of loss, which represents the estimated fee a third party would charge to provide such financial guarantees. The guarantee fee was accounted for as an equity contribution by Teekay Corporation in the Partnership's consolidated statement of changes in total equity, as Teekay Corporation had provided such financial guarantees at no cost to the Partnership.

j)

On March 31, 2018, the Partnership entered into a credit agreement for an unsecured revolving credit facility provided by Brookfield and Teekay Corporation, which provides for borrowings of up to $125.0 million ($100.0 million by Brookfield and $25.0 million by Teekay Corporation). On May 8, 2019, Brookfield acquired from Teekay Corporation its $25.0 million receivable of the revolving credit facility. As at December 31, 2019, the credit facility had an undrawn balance of $105 million (December 31, 2018 - fully drawn). The interest payments on the revolving credit facility are based on LIBOR plus a margin of 5.00% per annum until March 31, 2019 and LIBOR plus a margin of 7.00% per annum for balances outstanding after March 31, 2019, with interest payable monthly. Any outstanding principal balances are due on the maturity date. During 2019, the maturity date of the revolving credit facility was extended to October 1, 2020. The revolving credit facility contains covenants that require the Partnership to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $75.0 million and 5.0% of the Partnership’s total consolidated debt. As at December 31, 2019, the Partnership was in compliance with these covenants.

k)

On July 2, 2018, the Partnership issued, in a U.S. private placement, a total of $700.0 million of five-year senior unsecured bonds that mature in July 2023. The interest payments on the bonds are fixed at a rate 8.50% (see note 8). Brookfield purchased $500.0 million of these bonds, which included an exchange of the Brookfield Promissory Note at its par value of $200.0 million and additionally, the Partnership paid an associated $12.0 million early termination fee to Brookfield. As at December 31, 2019, Brookfield held $423.6 million of these bonds (December 31, 2018 - $475.0 million), which is included in long-term debt on the Partnership's consolidated balance sheet. The loss on the exchange of the Brookfield Promissory Note is included in losses on debt repurchases on the Partnership's consolidated statements of loss.

l)

As part of Brookfield's acquisition of 60% of the common units of the Partnership in September 2017, on January 1, 2018, the Partnership acquired a 100% ownership interest in seven subsidiaries of Teekay Corporation for cash consideration of $1.4 million. These subsidiaries provide ship management, commercial, technical, strategic, business development and administrative services to the Partnership, primarily related to the Partnership's FPSO units, shuttle tankers and FSO units.

12.	Derivative Instruments

The Partnership uses derivative instruments to manage certain risks in accordance with its overall risk management policies.

Foreign Exchange Risk

The Partnership economically hedges portions of its forecasted expenditures denominated in foreign currencies with foreign currency forward contracts. The Partnership has not designated, for accounting purposes, any of the foreign currency forward contracts held during the years ended December 31, 2019 and 2018, as cash flow hedges.

As at December 31, 2019, the Partnership was committed to the following foreign currency forward contracts:

	Contract Amount in Foreign Currency (thousands)			Fair Value / Carrying Amount of Asset/(Liability) (in thousands of U.S. Dollars)			Average Forward Rate(1)			Expected Maturity
										2020
										(in thousands of U.S. Dollars)
Norwegian Krone	457,205			518			8.87			51,567
Euro	5,000			57			0.90			5,563
				575						57,130

(1)	Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

F- 29

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

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. During the years ended December 31, 2018 and 2017, certain of these interest rate swaps were designated in qualifying hedging relationships and hedge accounting was applied in the consolidated financial statements or within the Partnership's equity-accounted for investments. During 2018, the Partnership de-designated, for accounting purposes, certain interest rate swaps and since July 2, 2018, has not designated, for accounting purposes, any of its interest rate swaps as hedges of variable rate debt. Certain of the Partnership's interest rate swaps are secured by vessels.

As at December 31, 2019, the Partnership and its consolidated subsidiaries were committed to the following interest rate swap agreements:

						Fair Value /
						Carrying			Weighted-
						Amount of			Average		Fixed
	Interest		Notional			Assets			Remaining		Interest
	Rate		Amount			(Liability)			Term		Rate
	Index		$			$			(years)		(%)(1)
U.S. Dollar-denominated interest rate swaps (2)	LIBOR		680,648			(126,630	)		5.5		4.0	%
U.S. Dollar-denominated interest rate swaps (3)	LIBOR		603,071			(37,342	)		2.4		3.2	%
			1,283,719			(163,972	)

(1)	Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2019, ranged from 0.90% to 6.50%.

(2)	Notional amount remains constant over the term of the swap, unless the swap is partially terminated.

(3)	Principal amount reduces quarterly or semi-annually.

For the periods indicated, the following tables present the effective and ineffective portion of the gain (loss) on interest rate swap agreements designated and qualifying as cash flow hedges. The following tables exclude any interest rate swap agreements designated and qualifying as cash flow hedges in the Partnership’s equity accounted joint ventures.

Year Ended December 31, 2019											Year Ended December 31, 2018
Effective Portion Recognized in AOCI (1)			Effective Portion Reclassified from AOCI (2)			Ineffective Portion (3)					Effective Portion Recognized in AOCI (1)			Effective Portion Reclassified from AOCI (2)			Ineffective Portion (3)
—			689			—			Interest expense		(2,495	)		102			—		Interest expense
—			689			—					(2,495	)		102			—

Year Ended December 31, 2017
Effective Portion Recognized in AOCI (1)			Effective Portion Reclassified from AOCI (2)			Ineffective Portion (3)
(19	)		(1,186	)		(7	)		Interest expense
(19	)		(1,186	)		(7	)

(1)	Effective portion of designated and qualifying cash flow hedges recognized in accumulated other comprehensive income (or AOCI).

(2)	Effective portion of designated and qualifying cash flow hedges recorded in AOCI during the term of the hedging relationship and reclassified to earnings.

(3)	Ineffective portion of designated and qualifying cash flow hedges.

As at December 31, 2019, the Partnership had multiple interest rate swaps and foreign currency forward contracts governed by certain master agreements. Each of the master agreements provides for the net settlement of all derivatives subject to that master agreement through a single payment in the event of default or termination of any one derivative. The fair value of these derivatives is presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, 2019, these derivatives had an aggregate fair value asset amount of $1.1 million and an aggregate fair value liability amount of $118.2 million (December 31, 2018 - an aggregate fair value asset amount of nil and an aggregate fair value liability amount of $91.1 million). As at December 31, 2018, the Partnership had $1.2 million on deposit with the relevant counterparties as security for cross currency swap liabilities under certain master agreements. The deposit is presented in restricted cash on the consolidated balance sheet as at December 31, 2018.

F- 30

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Tabular disclosure

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the Partnership’s balance sheets.

	Other current assets $			Other assets $			Accrued liabilities $			Current portion of derivative liabilities $			Derivative liabilities $
As at December 31, 2019
Foreign currency contracts	1,123			—			—			(548	)		—
Interest rate swaps	—			—			(2,342	)		(18,408	)		(143,222	)
	1,123			—			(2,342	)		(18,956	)		(143,222	)
As at December 31, 2018
Foreign currency contracts	—			—			—			(4,225	)		(425	)
Cross currency swaps	—			—			(96	)		(4,442	)		—
Interest rate swaps	1,028			2,075			(1,625	)		(14,623	)		(93,929	)
	1,028			2,075			(1,721	)		(23,290	)		(94,354	)

Total realized and unrealized (loss) gain of interest rate swaps and foreign currency forward contracts that are not designated for accounting purposes as cash flow hedges are recognized in earnings and reported in realized and unrealized (loss) gain on derivative instruments in the consolidated statements of loss for the years ended December 31, 2019, 2018 and 2017 as follows:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Realized (loss) gain on derivative instruments
Interest rate swaps	(29,185	)		(38,011	)		(78,296	)
Foreign currency forward contracts	(5,054	)		(1,228	)		900
	(34,239	)		(39,239	)		(77,396	)
Unrealized (loss) gain on derivative instruments
Interest rate swaps	(56,182	)		56,420			33,114
Foreign currency forward contracts	5,226			(4,373	)		1,429
	(50,956	)		52,047			34,543
Total realized and unrealized (loss) gain on derivative instruments	(85,195	)		12,808			(42,853	)

In January 2019, the Partnership settled its outstanding cross currency swaps, in connection with the repayment of certain NOK-denominated bonds, and incurred a realized loss during the year ended December 31, 2019. Realized and unrealized gain (loss) on cross currency swaps are recognized in earnings and reported in foreign currency exchange gain (loss) in the consolidated statements of loss for the years ended December 31, 2019, 2018 and 2017 as follows:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Realized loss	(4,177	)		(39,647	)		(84,205	)
Unrealized gain	4,442			38,648			91,914
Total realized and unrealized gain (loss) on cross currency swaps	265			(999	)		7,709

The Partnership is exposed to credit loss in the event of non-performance by the counterparties, all of which are financial institutions, to the foreign currency forward contracts and the interest rate swap agreements. In order to minimize counterparty risk, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

F- 31

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

13.	Income Taxes

The significant components of the Partnership’s deferred tax assets and liabilities are as follows:

	December 31, 2019 $			December 31, 2018 $
Deferred tax assets:
Tax losses carried forward(1)	240,432			251,240
Other	9,348			2,887
Total deferred tax assets	249,780			254,127
Deferred tax liabilities:
Vessels and equipment	20,179			17,018
Other	3,566			5,531
Total deferred tax liabilities	23,745			22,549
Net deferred tax assets	226,035			231,578
Valuation allowance	(222,168	)		(224,593	)
Net deferred tax assets	3,867			6,985
Disclosed in:
Deferred tax asset	7,000			9,168
Other long-term liabilities	3,133			2,183
Net deferred tax assets	3,867			6,985

(1)

As at December 31, 2019, the income tax losses carried forward of $1,021.1 million (December 31, 2018 - $1,040.4 million) are available to offset future taxable income in the applicable jurisdictions, of which $632.7 million can be carried forward indefinitely, $0.9 million will expire in 2020, $0.4 million will expire in 2021, $0.5 million will expire in 2022, $2.2 million will expire in 2023, $0.3 million will expire in 2024, $0.6 million will expire in 2025, $0.1 million will expire in 2026, $377.8 million will expire in 2034 and $5.6 million will expire in 2035.

The components of the provision for income taxes are as follows:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Current	(4,666	)		(4,051	)		(1,772	)
Deferred	(3,161	)		(18,606	)		1,870
Income tax (expense) recovery	(7,827	)		(22,657	)		98

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. Reconciliations of the tax charge related to the current year at the applicable statutory income tax rates and the actual tax charge related to the current year are as follows:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Net loss before taxes	(343,068	)		(101,288	)		(299,540	)
Net loss not subject to taxes	(418,027	)		(253,605	)		(244,045	)
Net income (loss) subject to taxes	74,959			152,317			(55,495	)
At applicable statutory tax rates	11,741			28,437			(15,784	)
Permanent differences	(3,846	)		(23,179	)		2,424
Adjustments related to currency differences	(360	)		(338	)		5,847
Valuation allowance and other	292			17,737			7,415
Tax expense (recovery) related to current year	7,827			22,657			(98	)

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

The following is a tabular reconciliation of the Partnership’s total amount of unrecognized tax benefits at the beginning and end of 2019, 2018 and 2017:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Balance of unrecognized tax benefits as at beginning of the year	1,596			1,410			2,174
Decreases for positions related to prior years	—			(189	)		(930	)
Increases for positions related to the current year	—			375			166
Balance of unrecognized tax benefits as at end of the year	1,596			1,596			1,410

The Partnership does not presently anticipate such uncertain tax positions will significantly increase or decrease in the next 12 months; however, actual developments could differ from those currently expected. The tax years 2010 through 2019 remain open to examination by some of the taxing jurisdictions in which the Partnership is subject to tax.

The interest and penalties on unrecognized tax benefits included in the tabular reconciliation above are not material.

14.	Commitments and Contingencies

a)

In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS (or Logitel), a Norway-based company focused on high-end UMS. At the time of the transaction, affiliates of Logitel were parties to construction contracts for three UMS newbuildings ordered from the COSCO (Nantong) Shipyard (or COSCO) in China. The Partnership took delivery of one of the UMS newbuildings, the Arendal Spirit UMS, in February 2015.

In June 2016, the Partnership canceled the UMS construction contracts for the two remaining UMS newbuildings, the Stavanger Spirit and the Nantong Spirit. As a result of this cancellation, during 2016, the Partnership wrote-off $43.7 million of assets related to these newbuildings and reversed contingent liabilities of $14.5 million associated with the delivery of these assets. An estimate of the potential damages for the cancellation of the Stavanger Spirit newbuilding contract is based on the amount due for the final yard installment of approximately $170 million less the estimated fair value of the Stavanger Spirit. Given the unique design of the vessel as well as the lack of recent sale and purchase transactions for this type of asset, the value of this vessel, and thus ultimately the amount of potential damages that may result from the cancellation, is uncertain. During December 2017, Logitel Offshore Rig II Pte Ltd., the single-purpose subsidiary relating to the Stavanger Spirit, received a notice of arbitration from COSCO to arbitrate all disputes arising from the cancellation of the construction contract of the Stavanger Spirit UMS and during March 2018, COSCO commenced arbitration against Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd. claiming $186.2 million plus interest, damages and costs. Pursuant to the Stavanger Spirit newbuilding contract and related agreements, COSCO only has recourse to the single-purpose subsidiary that was a party to the Stavanger Spirit newbuilding contract and its immediate parent company, Logitel Offshore Pte. Ltd., for damages incurred. Logitel Offshore Rig II Pte Ltd. and Logitel Offshore Pte. Ltd. are disputing this claim.

The Partnership's estimate of potential damages for the cancellation of the Nantong Spirit newbuilding contract is based upon estimates of a number of factors, including accumulated costs incurred by COSCO, sub-supplier contract cancellation costs, as well as how such costs are treated under the termination provisions in the contract. The Partnership estimates that the amount of potential damages faced by it in relation to the cancellation of the Nantong Spirit contract could range between $10 million and $40 million. Pursuant to the Nantong Spirit newbuilding contract, COSCO only has recourse to the single-purpose subsidiary that was a party to the Nantong Spirit newbuilding contract. During June 2017, Logitel Offshore Rig III LLC, the single-purpose subsidiary relating to the Nantong Spirit, received a claim from COSCO for $51.9 million for the unpaid balance for work completed, cancellation costs and damages, and during the third quarter of 2017, COSCO commenced arbitration against Logitel Offshore Rig III LLC. Logitel Offshore Rig III LLC is disputing this claim.

As at December 31, 2019, the Partnership's subsidiaries have accrued $43.3 million in the aggregate related to the above claims related to Logitel from COSCO.

b)

In December 2014, the Partnership acquired the Petrojarl I FPSO unit from Teekay Corporation for $57.0 million. The Petrojarl I FPSO unit underwent upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard (or Damen) in the Netherlands prior to being moved to the Aibel AS shipyard (or Aibel) in Norway where its upgrades were completed. The FPSO unit commenced operations in May 2018 under a five-year charter contract with Atlanta Field B.V. and a service agreement with Enauta.

During 2017, Damen commenced a formal arbitration with Petrojarl I L.L.C. (a wholly-owned subsidiary of the Partnership) as to the settlement of shipyard costs. During May 2018, the Partnership received a statement of case from Damen claiming $145.4 million for additional costs allegedly incurred by Damen in respect of the work and interest thereon. The Partnership served its defense to these claims on October 31, 2018 disputing the claims brought by Damen and bringing counterclaims against Damen (including a claim for abatement of the contract price) in excess of $110 million. In December 2019, arbitration hearings commenced. As of December 31, 2019, the Partnership had not accrued for any potential liability relating to these claims as the Partnership's best estimate is that the arbitration will not result in a net award, which would require an amount to be paid to Damen in excess of amounts already paid as at December 31, 2019.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

c)

In 2017, the Partnership entered into shipbuilding contracts with Samsung Heavy Industries Co., Ltd. to construct four Suezmax DP2 shuttle tanker newbuildings, for an estimated aggregate fully built-up cost of $588.7 million, excluding approximately $16 million of subsidies expected to be received by the Partnership. These newbuilding vessels are being constructed based on the Partnership's new Shuttle Spirit design which incorporates technologies intended to increase fuel efficiency and reduce emissions, including liquefied natural gas (or LNG) propulsion technology. Upon expected delivery in 2020, these vessels are to provide shuttle tanker services in the North Sea, with two to operate under the Partnership’s existing master agreement with Equinor, and two to operate directly within the North Sea CoA fleet. As at December 31, 2019, gross payments made towards these commitments were $221.1 million and the remaining gross payments required to be made are estimated to be $367.6 million (2020). In April 2019, the Partnership secured a $413.8 million debt facility, which as at December 31, 2019, provided borrowings of $198.1 million for the newbuilding payments and was fully drawn (see note 8).

In July 2018, the Partnership entered into shipbuilding contracts with Samsung Heavy Industries Co. Ltd., to construct two Aframax DP2 shuttle tanker newbuildings, for an estimated aggregate fully built-up cost of $257.1 million, excluding approximately $2 million of subsidies expected to be received by the Partnership. These newbuilding vessels are also being constructed based on the Partnership's new Shuttle Spirit design. Upon delivery in late-2020 through early-2021, these vessels will join the Partnership's CoA portfolio in the North Sea. As at December 31, 2019, gross payments made towards these commitments were $53.2 million and the remaining gross payments required to be made are estimated to be $129.5 million (2020) and $74.4 million (2021). In September 2019, the Partnership secured $214.2 million of long-term financing under sale-leaseback transactions, which as at December 31, 2019, provided pre-delivery borrowings of $23.8 million for the newbuilding payments and was fully drawn. The financing is classified as Other current liabilities and Other long-term liabilities on the Partnership's consolidated balance sheet and accrues interest at a fixed rate of 5.5% until the related vessels deliver.

In August 2019, the Partnership entered into a shipbuilding contract with Samsung Heavy Industries Co. Ltd., to construct one Suezmax DP2 shuttle tanker newbuilding, for an estimated aggregate fully built-up cost of $128.2 million. Upon delivery in early-2022, the vessel will operate under existing contracts with a group of oil companies on the East Coast of Canada. As at December 31, 2019, gross payments made towards this commitment were $7.2 million and the remaining gross payments required to be made are estimated to be $21.2 million (2020), $26.7 million (2021) and $73.1 million (2022). The Partnership expects to secure long-term financing related to this shuttle tanker newbuilding.

d)

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 16). On January 28, 2020 the same plaintiffs filed an Amended Consolidated Class Action 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 a breach of the Partnership’s limited partnership agreement and, in the alternative, a breach 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.

e)

Despite generating $319.9 million of cash flows from operating activities during 2019, the Partnership had a working capital deficit of $184.5 million as at December 31, 2019. This working capital deficit primarily relates to the scheduled maturities and repayments of $353.2 million of outstanding debt during the 12 months ending December 31, 2020, which amount was classified as current as at December 31, 2019. The Partnership also anticipates making payments related to commitments to fund vessels under construction during 2020 through 2022 of $693 million.

Based on these factors, during the one-year period following the issuance of these consolidated financial statements, the Partnership will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet its obligations and commitments and minimum liquidity requirements under its financial covenants. Additional potential sources of financing include refinancing or extension of debt facilities and extensions and redeployments of existing assets.

The Partnership is actively pursuing the funding alternatives described above, which it considers probable of completion based on the Partnership’s history of being able to raise debt and refinance loan facilities for similar types of vessels. The Partnership is in various stages of completion on these matters.

Based on the Partnership’s liquidity at the date these consolidated financial statements were issued, 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 following the issuance of these consolidated financial statements.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

15.	Supplemental Cash Flow Information

a)	The following is a tabular reconciliation of the Partnership's cash, cash equivalents and restricted cash balances for the periods presented in these consolidated financial statements:

	As at December 31,			As at December 31,			As at December 31,
	2019			2018			2017
	$			$			$
Cash and cash equivalents	199,388			225,040			221,934
Restricted cash(1)	17,798			8,540			28,360
Restricted cash - long-term(1)	89,070			—			—
	306,256			233,580			250,294

(1)	Restricted cash as at December 31, 2019 includes funds held as a guarantee for certain operating expenses, funds for scheduled loan facility repayments, withholding taxes and office lease prepayments. Restricted cash - long-term as at December 31, 2019 includes amounts held in escrow for a shuttle tanker newbuilding yard installment payment.

Restricted cash as at December 31, 2018 includes amounts held in escrow as collateral on the Partnership's cross currency swaps, funds for a scheduled loan facility repayment, withholding taxes and office lease prepayments.

Restricted cash as at December 31, 2017 includes amounts held in escrow as collateral on the Partnership’s cross currency swaps and funds for certain vessel upgrade costs.

b)	The changes in non-cash working capital items related to operating activities for the years ended December 31, 2019, 2018 and 2017 are as follows:

	Year Ended December 31, 2019 $			Year Ended December 31, 2018 $			Year Ended December 31, 2017 $
Accounts receivable	(57,957	)		22,320			(54,830	)
Prepaid expenses and other assets	1,115			(2,104	)		(6,618	)
Accounts payable and accrued liabilities	68,219			(32,800	)		43,113
Due from (to) related parties	1,039			(70,643	)		51,841
	12,416			(83,227	)		33,506

c)	Cash interest paid (including realized losses on interest rate swaps) during the years ended December 31, 2019, 2018 and 2017 totaled $217.8 million, $204.5 million and $205.0 million, respectively.

d)	Income taxes paid during the years ended December 31, 2019, 2018 and 2017 totaled $4.9 million, $2.1 million and $2.2 million, respectively.

16.	Total Capital and Net Loss Per Common Unit

At December 31, 2019, a total of 26.9% of the Partnership’s common units outstanding were held by the public. Brookfield held the remaining 73.1% of the common units of the Partnership and 100% of the general partner interest. At December 31, 2019, all of the Partnership’s outstanding Series A Cumulative Redeemable Preferred Units (or the Series A Preferred Units), Series B Cumulative Redeemable Preferred Units (or the Series B Preferred Units) and Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (or the Series E Preferred Units) were held by entities other than Brookfield and its affiliates.

On October 1, 2019, the Partnership announced that it entered into an agreement and plan of merger (or the Merger Agreement) with Brookfield, and 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 the Merger Agreement among the Partnership, the general partner and certain members of Brookfield. Under the terms of the Merger Agreement, 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 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 elected to receive the equity consideration (as defined below). As an alternative to receiving the cash consideration, each unaffiliated unitholder had the option to elect to forego the cash consideration and instead receive one of the Partnership's newly designated unlisted Class A Common Unit per common unit (or the equity consideration). The Class A Common Units are economically equivalent to the common units held by Brookfield following the Merger, but have limited voting rights and limited transferability.

As a result of the Merger, Brookfield owns 100% of the Class B Common Units, representing approximately 98.7% of the Partnership's 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 in respect of their common units.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Pursuant to the terms of the Merger Agreement, the Partnership's outstanding preferred units were unchanged and remain outstanding following the Merger.

Limited Partners’ Rights

Significant rights of the limited partners include the following:

•	Right of common unitholders to receive distributions of Available Cash (after deducting expenses, including estimated maintenance capital expenditures and reserves, including reserves for future capital expenditures and for anticipated future credit needs of the Partnership) within approximately 45 days after the end of each quarter.

•	No limited partner shall have any management power over the Partnership’s business and affairs; the general partner shall conduct, direct and manage our activities.

•	The general partner may be removed if such removal is approved by common unitholders holding at least 66.66% of the outstanding units voting as a single class, including units held by the general partner and its affiliates.

Incentive Distribution Rights

Prior to the Merger, when the Partnership’s incentive distribution rights were canceled and ceased to exist, the general partner was entitled to certain incentive distributions if the amount the Partnership distributed to common unitholders with respect to any quarter exceeded specified target levels shown below:

Quarterly Distribution Target Amount (per unit)	Unitholders			General Partner
Minimum quarterly distribution of $0.35	99.24	%		0.76	%
Up to $0.4025	99.24	%		0.76	%
Above $0.4025 up to $0.4375	86.24	%		13.76	%
Above $0.4375 up to $0.525	76.24	%		23.76	%
Above $0.525	51.24	%		48.76	%

During 2019, 2018 and 2017 cash distributions were below $0.35 per common unit. Consequently, the increasing percentages were not used to calculate the general partner’s interest in net loss for the purposes of the net loss per common unit calculation for the years ended December 31, 2019, 2018 and 2017.

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.

Series A, B and E Preferred Units

In April 2013, the Partnership issued 6.0 million 7.25% Series A Preferred Units in a public offering with an aggregate redemption amount of $150.0 million, for net proceeds of $144.8 million. Pursuant to the partnership agreement, distributions on the Series A Preferred Units to preferred unitholders are cumulative from the date of original issue and are payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. At any time on or after April 30, 2018, the Series A Preferred Units may be redeemed by the Partnership at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to the date of redemption. These units are listed on the New York Stock Exchange.

In April 2015, the Partnership issued 5.0 million 8.50% Series B Preferred Units in a public offering with an aggregate redemption amount of $125.0 million, for net proceeds of $120.8 million. Pursuant to the partnership agreement, distributions on the Series B Preferred Units to preferred unitholders are cumulative from the date of original issue and are payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. At any time on or after April 20, 2020, the Series B Preferred Units may be redeemed by the Partnership at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to the date of redemption. These units are listed on the New York Stock Exchange.

In January 2018, the Partnership issued 4.8 million 8.875% Series E Preferred Units in a public offering for net proceeds of $116.0 million. Pursuant to the partnership agreement, distributions on the Series E Preferred Units to preferred unitholders are cumulative from the date of original issue, payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. Distributions are payable on the Series E Preferred Units (i) from and including the original issue date to, but excluding, February 15, 2025 at a fixed rate equal to 8.875% per annum of the stated liquidation preference of $25.00 per unit and (ii) from and including February 15, 2025, at a floating rate equal to three-month LIBOR plus 6.407%. These units are listed on the New York Stock Exchange.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Series C-1 and Series D Preferred Units

In September 2017, the Partnership entered into a strategic partnership (or the Brookfield Transaction) with Brookfield. As part of this transaction, the Partnership repurchased and subsequently canceled all of its outstanding Series C-1 Cumulative Convertible Perpetual Preferred Units (or the Series C-1 Preferred Units) and Series D Cumulative Convertible Perpetual Preferred (or the Series D Preferred Units) from existing unitholders. The Series C-1 and Series D Preferred Units, similar to the Partnership’s previously outstanding Series C Preferred Units, were convertible into common units in accordance with their terms. The Series C-1 Preferred Units were repurchased for $18.20 per unit and Series D Preferred Units for $23.75 per unit, for a total cash payment of $260.2 million, which included $10.2 million of accrued and unpaid quarterly distributions, and resulted in a net accounting gain on repurchase of approximately $20.0 million, which was reflected as an equity contribution. Consideration for the repurchase of the Series D Preferred Units also included a reduction in the exercise price, from $6.05 to $4.55 per unit, of 2,250,000 of one of two tranches of warrants issued in conjunction with the Series D Preferred Units in June 2016. As at December 31, 2019, 2018 and 2017, 6,750,000 warrants originally issued in connection with the Series D Preferred Units with an exercise price of $4.55 remained outstanding.

Series D Detachable Warrants and Brookfield Transaction Warrants

Series D Detachable Warrants

In June 2016, the Partnership issued a total of 4.0 million of its 10.5% Series D Preferred Units to a group of investors and subsidiaries of Teekay Corporation. These investors and Teekay Corporation also received an aggregate of 4,500,000 warrants with an exercise price of $4.55 per unit (the $4.55 Warrants) and an aggregate of 2,250,000 warrants with an exercise price of $6.05 per unit (the $6.05 Warrants) (collectively, the Warrants).

In September 2017, the exercise price of the $6.05 warrants was reduced to $4.55 per unit, as described above. 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 recorded as permanent equity in the Partnership's consolidated balance sheets with 6,750,000 Warrants outstanding at December 31, 2019 (December 31, 2018 and 2017 - 6,750,000).

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. 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.

Brookfield Transaction Warrants and Common Units Issued

In September 2017, as part of the Brookfield Transaction, Brookfield and Teekay Corporation invested $610.0 million and $30.0 million, respectively, in the Partnership in exchange for 244.0 million and 12.0 million common units, respectively, at a price of $2.50 per common unit, and the Partnership issued to Brookfield and Teekay Corporation 62.4 million and 3.1 million warrants, respectively (the Brookfield Transaction Warrants), with each warrant exercisable for one common unit. As part of the amended and restated Brookfield Promissory Note transaction (see note 11h), Brookfield concurrently transferred 11.4 million Brookfield Transaction Warrants and $140.0 million to Teekay Corporation to acquire a $200 million subordinated promissory note owed by the Partnership. The $637.0 million net investment in the Partnership by Brookfield and Teekay Corporation was allocated on a relative fair value basis between the 256 million common units issued to Brookfield and Teekay Corporation ($512.6 million), the Brookfield Transaction Warrants ($121.3 million), the effective extinguishment of the $200 million 2016 Teekay Corporation Promissory Note (($160.5) million) and the concurrent issuance to Brookfield of the $200 million Brookfield Promissory Note ($163.6 million) (see note 11h)). The $39.5 million gain on the effective extinguishment of the subordinated promissory note was accounted for as a contribution of capital from Teekay Corporation. On July 2, 2018, the Partnership repurchased the Brookfield Promissory Note (see note 11j).

The Brookfield Transaction Warrants entitled the holders to acquire one common unit for each Brookfield Transaction 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 Transaction Warrants. In May 2019, Brookfield acquired all of Teekay Corporation's remaining interests in the Partnership, including its 49% general partner interest (providing Brookfield with 100% of the general partner ownership interest), 13.8% interest in common units, 17.3 million common unit equivalent warrants and a $25.0 million loan receivable outstanding. As at December 31, 2019, Brookfield and Teekay Corporation held 65.5 million and nil Brookfield Transaction Warrants, respectively (2018 - 50.0 million and 15.5 million, 2017 - 51.0 million and 14.5 million).

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. As a result of this transaction, and the fact that the exercise price of each of the outstanding Brookfield Transaction Warrants exceeded the cash consideration of $1.55 per common unit, each of the Brookfield Transaction Warrants was automatically canceled and ceased to exist. No consideration was delivered in respect thereof.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Net Loss Per Common Unit

	Year Ended
	December 31, 2019 $			December 31, 2018 $			December 31, 2017 $
Limited partners' interest in net loss	(378,770	)		(147,141	)		(339,501	)
Preferred units - periodic accretion	—			—			(2,380	)
Net gain on repurchase of Series C-1 and Series D Preferred Units	—			—			19,637
Gain on modification of warrants	—			—			1,495
Limited partners' interest in net loss for basic net loss per common unit	(378,770	)		(147,141	)		(320,749	)
Series C-1 Preferred Units - cash distributions	—			—			12,650
Gain on repurchase of Series C-1 Preferred Units	—			—			(26,994	)
Limited partners' interest in diluted net loss	(378,770	)		(147,141	)		(335,093	)
Weighted average number of common units	410,727,035			410,261,239			220,755,937
Dilutive effect of Series C-1 Preferred Units and unit based compensation	—			—			9,184,183
Common units and common unit equivalents	410,727,035			410,261,239			229,940,120
Limited partner's interest in net loss per common unit
- basic	(0.92	)		(0.36	)		(1.45	)
- diluted	(0.92	)		(0.36	)		(1.46	)

Limited partners’ interest in net loss per common unit – basic is determined by dividing net loss, after deducting the amount of net loss attributable to the non-controlling interests, the general partner’s interest, the distributions on the Series A, B, and E Preferred Units and for periods prior to their exchange or repurchase, the Series C-1 and D Preferred Units, the periodic accretion prior to the repurchase of the Series D Preferred Units, the net gain on the repurchase of the Series C-1 and D Preferred Units and gain on the modification of warrants, by the weighted-average number of common units outstanding during the period. The distributions payable or paid on the preferred units for the year ended December 31, 2019 were $32.2 million (2018 - $31.5 million, 2017 - $42.1 million).

The computation of limited partners’ interest in net income per common unit - diluted assumes the issuance of common units for all potential dilutive securities, consisting of restricted units (see note 17), warrants and, and for periods prior to their exchange or repurchase, Series C-1 and D Preferred Units. Consequently, for periods prior to their repurchase, the net income attributable to limited partners’ interest is exclusive of any distributions on the Series C-1 and D Preferred Units, the prior periodic accretion of the Series D Preferred Units, the net gain on the repurchase of preferred units, and the gain on the modification of warrants. In addition, the weighted average number of common units outstanding has been increased assuming conversion of the restricted units and exercise of the warrants using the treasury stock method and, for periods prior to the exchange or repurchase, the Series C-1 and D Preferred Units having been converted to common units using the if-converted method. The computation of limited partners’ interest in net income per common unit - diluted does not assume the issuance of common units pursuant to the restricted units, warrants and, for periods prior to their exchange or repurchase, Series C-1 and D Preferred Units if the effect would be anti-dilutive. In periods where a loss is attributable to common unitholders all restricted units, warrants, the Series C-1 and D Preferred Units (for applicable periods) could have been anti-dilutive. In periods where income is allocated to common unitholders, the Series C-1 and D Preferred Units could have been anti-dilutive for periods prior to their exchange or repurchase.

For the year ended December 31, 2019, a total common unit equivalent of 72.3 million warrants and 0.5 million restricted units were excluded from the computation of limited partners' interest in net loss per common unit - diluted, as their effect was anti-dilutive. For the year ended December 31, 2018, a total common unit equivalent of 72.3 million warrants and 0.1 million restricted units were excluded from the computation of limited partners’ interest in net loss per common unit - diluted, as their effect was anti-dilutive. For the year ended December 31, 2017, 31.9 million common unit equivalent Series D Preferred Units, 72.3 million common unit equivalent warrants and 0.4 million restricted units were excluded from the computation of limited partners’ interest in net loss per common unit - diluted, as their effect was anti-dilutive.

The general partner’s and common unitholders’ interests in net loss are calculated as if all net loss was distributed according to the terms of the Partnership’s partnership agreement, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net loss; rather, it provides for the distribution of 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 reserves for maintenance and replacement capital expenditure, anticipated capital requirements and any accumulated distributions on, or redemptions of, the Series A, Series B and Series E Preferred Units, and for periods prior to their exchange or repurchase, the Series C-1 and D Preferred Units. Unlike available cash, net 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 or loss.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Pursuant to the partnership agreement, allocations to partners are made on a quarterly basis.

Public and Private Offerings of Common Units

The following table summarizes the issuances of common units over the three years ending December 31, 2019:

Date

Offering Type

Number of Common Units Issued

Offering Price

Gross Proceeds (i)

Net Proceeds

Use of Proceeds

(in millions of U.S. Dollars)

During 2017

Payment-in-kind

6,391,087

(ii)

29.8

29.8

(ii)

September 2017

Private

256,000,000

(iii)

640.0

628.1

To strengthen the Partnership's capital structure and to fund the Partnership's existing growth projects.

(i)	Including the General Partner’s proportionate capital contribution, where applicable.

(ii)	Common units issued as a payment-in-kind for the distributions on the Partnership's Series C-1 and D Preferred Units and on the Partnership's common units and general partner interest held by subsidiaries of Teekay Corporation and payment-in-kind for interest on the 2016 Teekay Corporation Promissory Note (see note 11g).

(iii)

In September 2017, as part of the Brookfield Transaction, the Partnership issued to Brookfield 244.0 million common units and the Brookfield Transaction Warrants to purchase 62.4 million common units, for gross proceeds of $610.0 million. In addition, the Partnership issued to Teekay Corporation 12.0 million common units and the Brookfield Transaction Warrants to purchase 3.1 million common units, for gross proceeds of $30.0 million. The net proceeds are exclusive of expenses allocated to the Brookfield Transaction Warrants of $1.4 million.

17.	Unit Based Compensation

During the year ended December 31, 2019, a total of 561,420 common units, with an aggregate value of $0.7 million, were granted to the non-management directors of the general partner as part of their annual compensation for 2019.

The Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of the Partnership and Teekay Corporation’s subsidiaries that provide services to the Partnership. During the years ended December 31, 2019, 2018 and 2017, the Partnership granted restricted unit-based compensation awards with respect to 2,577,626, 1,424,058 and 321,318 units, respectively, with aggregate grant date fair values of $3.0 million, $3.7 million and $1.6 million, respectively for 2019, 2018 and 2017, based on the Partnership’s closing unit price on the grant dates. Each restricted unit is equal in value to one of the Partnership’s common units. Each award represents the specified number of the Partnership’s common units plus reinvested distributions from the grant date to the vesting date. The awards vest equally over three years from the grant date. Any portion of an award that is not vested on the date of a recipient’s termination of service is canceled, unless the termination arises as a result of the recipient’s retirement and, in this case, the award will continue to vest in accordance with the vesting schedule. Upon vesting, the awards are paid to each grantee in the form of common units or cash. As at December 31, 2019, 2018 and 2017, the Partnership had 3,764,261, 1,456,999 and 480,301 non-vested restricted units outstanding, respectively.

During the year ended December 31, 2019, restricted unit-based awards with respect to a total of 460,689 common units with a fair value of $1.6 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 116,282 common units and by paying $0.3 million in cash.

During the year ended December 31, 2018, restricted unit-based awards with respect to a total of 342,560 common units with a fair value of $2.0 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 111,336 common units and by paying $0.4 million in cash.

During the year ended December 31, 2017, restricted unit-based awards with respect to a total of 255,370 common units with a fair value of $2.2 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 83,060 common units and by paying $0.6 million in cash.

The Partnership recorded unit-based compensation expense of $2.6 million, $1.4 million and $0.9 million, during the years ended December 31, 2019, 2018 and 2017, respectively, in general and administrative expenses in the Partnership’s consolidated statements of loss.

As of December 31, 2019 and December 31, 2018, liabilities relating to cash settled restricted unit-based compensation awards of $2.4 million and $0.7 million, respectively, were recorded in accrued liabilities on the Partnership’s consolidated balance sheets. As at December 31, 2019, the Partnership had $3.2 million of non-vested awards not yet recognized, which the Partnership expects to recognize over a weighted average period of 1.1 years.

18.	(Write-down) and Gain on Sale of Vessels

In 2019, the carrying value of one FPSO unit and the Arendal Spirit UMS were written down to their estimated fair value, using a discounted cash flow valuation, as a result of a reassessment of the future redeployment assumptions for both units. The Partnership's consolidated

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

statement of loss for the year ended December 31, 2019 includes a $338.0 million write-down related to these units. The write-downs of the one FPSO unit and Arendal Spirit UMS are included in the Partnership's FPSO and UMS segments, respectively.

In 2019, the carrying value of the Ostras FPSO unit was written down to its estimated fair value, using an appraised value, due to the expected sale of the unit. The Ostras FPSO unit was classified as held for sale on the Partnership's consolidated balance sheet as at December 31, 2019. The Partnership's consolidated statement of loss for the year ended December 31, 2019 includes a $4.4 million write-down related to this vessel. The write-down is included in the Partnership's FPSO segment.

In 2019, the carrying value of the Navion Hispania and Stena Sirita shuttle tankers were written down to their estimated fair values, using appraised values, as a result of the expected sales of the vessels. These vessels were classified as held for sale on the Partnership's consolidated balance sheet as at December 31, 2019. The Partnership's consolidated statement of loss for year ended December 31, 2019 includes a $2.3 million write-down related to these vessels. The write-down is included in the Partnership's shuttle tanker segment.

In 2019, the Partnership sold a 1988-built FSO unit, the Pattani Spirit, for net proceeds of $15.7 million. The Pattani Spirit was classified as held for sale on the Partnership's consolidated balance sheet as at December 31, 2018. The Partnership's consolidated statement of loss for the year ended December 31, 2019 includes a $11.2 million gain related to the sale of this vessel. The gain on sale is included in the Partnership's FSO segment.

In 2019, the Partnership sold a 2001-built shuttle tanker, the Nordic Spirit, and a 1998-built shuttle tanker, the Alexita Spirit, for net proceeds of $8.9 million and $8.7 million, respectively. The Nordic Spirit was classified as held for sale on the Partnership's consolidated balance sheet as at December 31, 2018. The Partnership's consolidated statement of loss for the year ended December 31, 2019 includes a $1.3 million gain related to the sale of these vessels. The gain on sale is included in the Partnership's shuttle tanker segment.

In 2018, the carrying value of the Ostras and Piranema Spirit FPSO units were written down to their estimated fair values, using a discounted cash flow valuation, as a result of a reassessment of the future redeployment assumptions for both units. The Partnership's consolidated statement of loss for the year ended December 31, 2018 includes a $180.2 million write-down related to these vessels. The write-down is included in the Partnership's FPSO segment.

In 2018, the carrying value of the HiLoad DP unit was written down to nil using a discounted cash flow valuation. The unit was written down as a result of a settlement received from Petrobras (see note 5) and a change in the operating plan for the unit. The Partnership's consolidated statement of loss for the year ended December 31, 2018 includes a $19.2 million write-down related to this unit. The HiLoad DP unit had previously been written down to its estimated fair value using a discounted cash flow valuation in 2017, as a result of a change in expectations for the future employment opportunities for the unit and the unit proceeding into lay-up. The Partnership's consolidated statement of loss for the year ended December 31, 2017 includes a $26.3 million write-down related to this unit. The write-downs are included in the Partnership's shuttle tanker segment.

In 2018, the carrying value of the Nordic Spirit and Stena Spirit shuttle tankers were written down to their estimated fair values, using appraised values, due to the redelivery of these vessels from their charterer after completing their bareboat charter contracts in May 2018 and the resulting change in the expectations for the future opportunities for the vessels. The Partnership's consolidated statement of loss for the year ended December 31, 2018 includes a $29.7 million write-down related to these vessels, of which $14.8 million is included in a 50%-owned subsidiary of the Partnership. The write-down is included in the Partnership's shuttle tanker segment.

In 2018, the Partnership sold the 1998-built shuttle tankers, the Navion Scandia and Navion Britannia, for net proceeds of $10.8 million and $10.4 million, respectively. The Partnership's consolidated statement of loss for the year ended December 31, 2018 includes a $5.3 million gain related to the sale of these vessels. The gain on sale is included in the Partnership's shuttle tanker segment.

In 2017, the carrying value of two FPSO units were written down to their estimated fair value, using a discounted cash flow valuation. The Petrojarl I FPSO unit was written down to its estimated fair value, as a result of increasing costs associated with additional upgrade work required and estimated liquidated damages to the charterer associated with the delay in the commencement of the unit's operations. During 2017, the Petrojarl I FPSO unit was moved from the Damen Shipyard in the Netherlands to complete upgrades at the Aibel AS shipyard in Norway. Upon arrival at the Aibel AS shipyard, it was determined that additional upgrade work was required, resulting in a further increase in costs and a further delay of the commencement of the FPSO unit's operations until the second quarter of 2018. In addition, during 2017, the Ostras FPSO unit was written down to its estimated fair value, using a discounted cash flow valuation, as a result of an expected change in the operating plans for the unit resulting from receiving confirmation from the charterer that it planned to redeliver the unit upon completion of the firm charter contract in January 2018. The Partnership's consolidated statement of loss for the year ended December 31, 2017 includes an aggregate $265.2 million write-down related to these units. The write-downs are included in the Partnership's FPSO segment.

In 2017, the Nordic Brasilia and Nordic Rio shuttle tankers were written down to their estimated fair values, using appraised values, due to the redelivery of these vessels from their charterer after completing their bareboat charter contracts in 2017 and a resulting change in expectations for the future opportunities and operating plans for the vessels. The Partnership's consolidated statement of loss for the year ended December 31, 2017 includes a $25.2 million write-down related to these vessels, of which $10.8 million is included in a 50%-owned subsidiary of the Partnership. The write-downs are included in the Partnership's shuttle tanker segment.

In 2017, the Partnership sold a 1999-built shuttle tanker, the Navion Marita, for gross proceeds of $5.7 million, which was the approximate carrying value of the vessel at the time of sale. The shuttle tanker had previously been written down to its estimated fair value as a result of the expected sale of the vessel, and the Partnership’s consolidated statement of loss for the year ended December 31, 2017, includes a $5.1 million write-down related to the vessel. The write-down is included in the Partnership’s shuttle tanker segment.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

19.	Investment in Equity Accounted Joint Ventures

In October 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to OOG-TK Libra GmbH & Co KG (or Libra Joint Venture), a 50/50 joint venture of the Partnership and Ocyan S.A. (or Ocyan) which vessel was converted to a new 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, 2019 had an outstanding balance of $586.5 million (December 31, 2018 - $654.2 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 $536.1 million as at December 31, 2019 (December 31, 2018 - $588.8 million), which amortize quarterly over the term of the interest rate swap 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 in qualifying cash flow hedging relationships for accounting purposes.

In June 2013, the Partnership acquired Teekay Corporation’s 50% interest in OOG TKP FPSO GmbH & Co KG, a joint venture with Ocyan, which owns the Itajai FPSO unit. Included in the joint venture is an eight-year loan facility, which as at December 31, 2019 had an outstanding balance of $105.9 million (December 31, 2018 - $138.2 million). The interest payments of the loan facility are based on LIBOR, plus a margin of 2.45%. The final payment under the loan facility is due October 2021. In addition, the joint venture entered into ten-year and nine-year interest rate swap agreements with an aggregate notional amount of $105.9 million as at December 31, 2019 (December 31, 2018 - $123.4 million), which amortize semi-annually over the term of the interest rate swap agreements. These interest rate swap agreements exchange the receipt of LIBOR-based interest for the payment of a weighted average fixed rate of 2.50%. These interest rate swap agreements are not designated in qualifying cash flow hedging relationships for accounting purposes.

As at December 31, 2019 and 2018, the Partnership had total investments of $234.6 million and $212.2 million, respectively, in equity accounted joint ventures. No indicators of impairment existed as at December 31, 2019 and 2018.

The following table presents aggregated summarized financial information assuming a 100% ownership interest in the Partnership’s equity accounted joint ventures. The results included are for the Itajai FPSO joint venture and the Libra Joint Venture.

	As at December 31,
	2019 $			2018 $
Current assets	159,045			148,208
Non-current assets	1,122,079			1,189,463
Current liabilities	127,110			139,777
Long-term liabilities	686,371			780,685

	Year ended December 31,
	2019 $			2018 $			2017 $
Revenues	264,266			264,215			90,662
Operating income	134,321			119,774			43,422
Net income	72,022			78,916			28,884

The Partnership does not control its equity-accounted vessels and as a result, the Partnership does not have the unilateral ability to determine whether the cash generated by its equity-accounted vessels is retained within the entities in which the Partnership holds the equity-accounted investments or distributed to the Partnership and other owners. In addition, the Partnership does not control the timing of such distributions to the Partnership and other owners.

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