Edgar Filing: Teekay Offshore Partners L.P.

20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

(Mark One)

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

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

For the fiscal year ended December 31, 2015

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

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

Date of event requiring this shell company report

For the transition period from to

Commission file number 1-33198

TEEKAY OFFSHORE PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

Not Applicable

(Translation of Registrant’s Name into English)

Republic of The Marshall Islands

(Jurisdiction of incorporation or organization)

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

Telephone: (441) 298-2530

(Address and telephone number of principal executive offices)

Edith Robinson

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

Telephone: (441) 298-2533

Fax: (441) 292-3931

(Contact information for company contact person)

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


Title of each class		Name of each exchange on which registered
Common Units		New York Stock Exchange
Series A Preferred Units		New York Stock Exchange
Series B Preferred Units		New York Stock Exchange
6.00% Notes due 2019		New York Stock Exchange

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

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

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

107,026,979 Common Units

6,000,000 Series A Preferred Units

5,000,000 Series B Preferred Units

10,438,413 Series C Preferred Units

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

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

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

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

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

Large Accelerated Filer x Accelerated Filer ¨ Non-Accelerated Filer ¨

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

U.S. GAAP x

International Financial Reporting Standards as issued

by the International Accounting Standards Board ¨

Other ¨

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

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

TEEKAY OFFSHORE PARTNERS L.P.

INDEX TO REPORT ON FORM 20-F


		Page
PART I.

Item 1.	Identity of Directors, Senior Management and Advisors		5
Item 2.	Offer Statistics and Expected Timetable		5
Item 3.	Key Information		5
	Selected Financial Data		5
	Risk Factors		10
	Tax Risks		24
Item 4.	Information on the Partnership		25
	A. Overview, History and Development		25
	Overview and History		25
	Potential Additional Shuttle Tanker, FSO, and FPSO Projects		25
	B. Business Overview		26
	Shuttle Tanker Segment		26
	FPSO Segment		27
	FSO Segment		28
	Conventional Tanker Segment		29
	Towage Segment		29
	UMS Segment		30
	Business Strategies		30
	Customers		31
	Safety, Management of Ship Operations and Administration		31
	Risk of Loss, Insurance and Risk Management		31
	Flag, Classification, Audits and Inspections		32
	Regulations		32
	C. Organizational Structure		37
	D. Properties		37
	E. Taxation of the Partnership		37
Item 4A.	Unresolved Staff Comments		38
Item 5.	Operating and Financial Review and Prospects		38
	Overview		39
	Significant Developments		39
	Potential Additional Shuttle Tanker, FSO and FPSO Projects		40
	Our Contracts and Charters		40
	Important Financial and Operational Terms and Concepts		41
	Items You Should Consider When Evaluating Our Results		41
	Results of Operations		42
	Liquidity and Capital Resources		57
	Cash Flows		58
	Contractual Obligations and Contingencies		60
	Off-Balance Sheet Arrangements		60
	Critical Accounting Estimates		60
Item 6.	Directors, Senior Management and Employees		63
	A. Directors and Senior Management		63
	Management of Teekay Offshore Partners L.P.		63
	Directors and Executive Officers of Teekay Offshore GP L.L.C.		64
	B. Compensation		65
	Executive Compensation		65
	Compensation of Directors		65
	2006 Long-Term Incentive Plan		65
	C. Board Practices		65
	D. Employees		66
	E. Unit Ownership		67
Item 7.	Major Unitholders and Related Party Transactions		67
	A. Major Unitholders		67
	B. Certain Relationships and Related Party Transactions		67


Item 8.	Financial Information	69
	Consolidated Financial Statements and Other Financial Information	69
	Consolidated Financial Statements and Notes	69
	Legal Proceedings	69
	Cash Distribution Policy	69
Item 9.	The Offer and Listing	70
Item 10.	Additional Information	72
	Memorandum and Articles of Association	72
	Material Contracts	72
	Exchange Controls and Other Limitations Affecting Unitholders	72
	Material U.S. Federal Income Tax Considerations	73
	Non-United States Tax Consequences	76
	Documents on Display	77
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	77
	Interest Rate Risk	77
	Foreign Currency Fluctuation Risk	77
	Commodity Price Risk	78
Item 12.	Description of Securities Other than Equity Securities	78

PART II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	78
Item 14.	Material Modifications to the Rights of Unitholders and Use of Proceeds	78
Item 15.	Controls and Procedures	78
	Management’s Report on Internal Control over Financial Reporting	79
Item 16A.	Audit Committee Financial Expert	79
Item 16B.	Code of Ethics	79
Item 16C.	Principal Accountant Fees and Services	79
Item 16D.	Exemptions from the Listing Standards for Audit Committees	80
Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers	80
Item 16F.	Change in Registrant’s Certifying Accountant	80
Item 16G.	Corporate Governance	80
Item 16H.	Mine Safety Disclosure	80

PART III.
Item 17.	Financial Statements	80
Item 18.	Financial Statements	80
Item 19.	Exhibits	81
Signature		83

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 units described herein, shall mean specifically Teekay Offshore Partners L.P. References in this Annual Report to “Teekay Corporation” refer to Teekay Corporation and/or any one or more of its subsidiaries.

In addition to historical information, this Annual Report contains forward-looking statements 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 or any increases in quarterly distributions, and the temporary nature of our current reduced distribution level;

•

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

•

our liquidity needs, including our funding gaps for 2016 and 2017, and anticipated funds for liquidity needs and the sufficiency of cash flows;

•

our ability to enter into new bank financings and to refinance existing indebtedness;

•

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;

•

the results of our charter contract negotiations related to the Piranema Spirit FPSO unit;

•

the results of our discussions with Sevan Marine ASA regarding our acquisition of Logitel Offshore Pte. Ltd.;

•

our ability to leverage to our advantage Teekay Corporation’s relationships and reputation in the shipping industry;

•

our continued ability to enter into fixed-rate time charters and FPSO contracts with customers;

•

results of operations and revenues and expenses;

•

expected decreases in vessel operating expenses, including crewing costs;

•

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 of our vessels;

•

the estimated sales price or scrap value of vessels;

•

our expectations as to any impairment of our vessels;

•

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

•

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 and our accepting such offers;

•

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

•

certainty of completion, estimated delivery, completion dates, intended financing and estimated costs for newbuildings, acquisitions and conversions, including the UMS, towage and shuttle tanker newbuildings, conversion of the Randgrid to an FSO unit to serve the Gina Krog oil and gas field, conversion of the Navion Norvegia to an FPSO unit to serve the Libra field and the upgrades of the Petrojarl I FPSO unit;

•

deferral of the delivery dates or cancellation of our UMS newbuildings;

•

expected employment and trading of older shuttle tankers;

•

payment of additional contingent consideration for our acquisitions of ALP and Logitel and the capabilities of the ALP vessels and UMS;

•

the expectations as to the chartering of unchartered vessels, including UMS and towage newbuildings and the HiLoad DP unit;

•

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;

•

the duration of dry dockings;

•

the future valuation of goodwill;

•

our compliance with covenants under our credit facilities;

•

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

•

our exposure to foreign currency fluctuations, particularly in Norwegian Kroner;

•

the adequacy of our insurance coverage;

•

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

•

the expected cost of, and our ability to comply with, governmental regulations and maritime self-regulatory organization standards applicable to our business, including the expected cost to install ballast water treatment systems on our vessels in compliance with IMO proposals;

•

anticipated taxation of our partnership and its subsidiaries and taxation of unitholders;

•

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

•

our general and administrative expenses as a public company and expenses under service agreements with other affiliates of 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 Advisors

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 the fiscal years 2011 through 2015, which have been derived from our audited 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 for each of the fiscal years ended December 31, 2013 through 2015.

Occasionally we purchase vessels from Teekay Corporation. In October 2011, we acquired from Teekay Corporation a newbuilding shuttle tanker, the Scott Spirit. In May 2013, we acquired from Teekay Corporation the Voyageur Spirit FPSO unit, along with its operations and charter contract. In July 2015, we acquired from Teekay Corporation the Petrojarl Knarr FPSO unit, along with its operations and charter contract.

These transactions were deemed to be business acquisitions between entities under common control. Accordingly, we have accounted for these transactions in a manner similar to the pooling of interest method. Under this method of accounting, our financial statements, prior to the date the interests in these vessels were actually acquired by us, are retroactively adjusted to include the results of these acquired vessels. The periods retroactively adjusted include all periods that we and the acquired vessels were both under common control of Teekay Corporation and had begun operations. As a result, our applicable consolidated financial statements and the selected financial data and other financial information herein reflect these vessels and the results of operations of the vessels, referred to herein as the Dropdown Predecessor and the Knarr Companies, as if we had acquired them when each respective vessel began operations under the ownership of Teekay Corporation. These vessels began operations on July 22, 2011 (Scott Spirit), April 13, 2013 (Voyageur Spirit) and March 9, 2015 (Petrojarl Knarr). Please read Item 18 – Financial Statements: Note 3 – Dropdown Predecessor.

We acquired the Peary Spirit on August 2, 2011. As this entity was considered a variable interest entity prior to its acquisition by us, our consolidated financial statements and selected financial information reflect the financial position, results of operations and cash flows of the Peary Spirit from October 1, 2010 to August 2, 2011. Subsequent to our acquisition of the entity which owns this vessel, this entity continues to be consolidated in our results as we hold voting control.

Our December 15, 2014, acquisition of the Petrojarl I FPSO unit from Teekay Corporation was deemed to be a transfer of net assets between entities under common control. Under this method, the carrying amount of net assets recognized in our balance sheets reflect the carrying values from the pre-acquisition balance sheet of Teekay Corporation, and no other assets or liabilities are recognized as a result of the transfer. The excess of the proceeds paid by us over Teekay Corporation’s historical cost is accounted for as an equity distribution to Teekay Corporation.

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


				Year Ended December 31,
	2011			2012			2013			2014			2015
	(in thousands of U.S. Dollars, except per unit, unit and fleet data)
Income Statement Data:
Revenues		840,982			901,227			930,739			1,019,539			1,229,413

Income from vessel operations⁽¹⁾		111,134			166,577			103,418			256,218			283,399
Interest expense		(35,929	)		(47,508	)		(62,855	)		(88,381	)		(122,838	)
Interest income		659			1,027			2,561			719			633
Realized and unrealized (loss) gain onderivative instruments		(159,744	)		(26,349	)		34,820			(143,703	)		(73,704	)
Equity income		—			—			6,731			10,341			7,672
Foreign currency exchange gain (loss) ⁽²⁾		1,500			(315	)		(5,278	)		(16,140	)		(17,467	)
Loss on bond repurchase		—			—			(1,759	)		—			—
Other income - net		3,683			1,538			1,144			781			1,091
Income tax (expense) recovery		(6,679	)		10,477			(2,225	)		(2,179	)		21,357

Net (loss) income from continuing operations		(85,376	)		105,447			76,557			17,656			100,143
Net (loss) income from discontinued operations		(11,495	)		17,568			(4,642	)		—			—

Net (loss) income		(96,871	)		123,015			71,915			17,656			100,143

Non-controlling and other interests in net (loss) incomefrom continuing operations		7,601			12,885			62			37,036			68,937
Non-controlling and other interests in net (loss) incomefrom discontinued operations		4,174			(1,772	)		(452	)		—			—
Limited partners’ interest:
Net (loss) income from continuing operations		(92,977	)		92,562			76,495			(19,380	)		31,206
Net (loss) income from continuing operations percommon unit (basic and diluted) ⁽³⁾		(1.49	)		1.26			0.93			(0.22	)		0.32
Net (loss) income from discontinued operations		(15,669	)		19,340			(4,190	)		—			—
Net (loss) income from discontinued operationsper common unit (basic and diluted) ⁽³⁾		(0.25	)		0.26			(0.05	)		—			—
Cash distributions declared per common unit		1.98			2.04			2.11			2.15			2.18

Balance Sheet Data (at end of year):
Cash and cash equivalents		179,934			206,339			219,126			252,138			258,473
Vessels and equipment ⁽⁴⁾		2,585,586			2,454,623			3,089,582			3,183,465			4,743,619
Total assets ⁽⁵⁾		3,132,506			3,042,625			3,786,700			3,917,837			5,744,166
Total debt ⁽⁵⁾		2,016,853			1,758,866			2,349,590			2,408,596			3,363,874
Total equity		484,733			705,229			821,341			802,853			967,848
Common units outstanding		70,626,554			80,105,108			85,452,079			92,386,383			107,026,979
Preferred units outstanding ⁽⁶⁾		—			—			6,000,000			6,000,000			21,438,413

Other Financial Data:
Net revenues ⁽⁷⁾		743,398			790,744			827,096			906,999			1,131,407
EBITDA ⁽⁸⁾		128,303			330,815			338,082			306,050			475,590
Adjusted EBITDA ⁽⁸⁾		390,967			405,243			397,445			467,868			631,190
Expenditures for vessels and equipment		148,480			87,408			455,578			172,169			664,667

Fleet data:
Average number of shuttle tankers ⁽⁹⁾		36.5			35.5			33.8			34.7			33.8
Average number of FPSO units ⁽⁹⁾		2.1			3.0			4.2			5.2			7.8
Average number of conventional tankers ⁽⁹⁾		10.6			6.0			5.2			4.0			3.9
Average number of FSO units ⁽⁹⁾		5.2			5.0			5.8			6.0			6.6
Average number of towing vessels⁽⁹⁾		—			—			—			—			4.3
Average number of units for maintenance and safety⁽⁹⁾		—			—			—			—			0.9

(1)	Income from vessel operations includes, among other things, the following:


	Year Ended December 31,
	2011			2012			2013			2014			2015
(Write down) and gain (loss) on sale of vessels		(37,039	)		(24,542	)		(76,782	)		(1,638	)		(69,998	)
Restructuring (charge) recovery		(3,924	)		(1,115	)		(2,607	)		225			(568	)

		(40,963	)		(25,657	)		(79,389	)		(1,413	)		(70,566	)

(2)

The majority of these foreign currency exchange gains and losses were unrealized and not settled in cash. Under GAAP, all foreign currency-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, accounts payable, advances from affiliates, deferred income taxes and long-term debt are revalued and reported based on the prevailing exchange rate at the end of the period. Foreign currency exchange gains and losses also include realized and unrealized gains and losses on our cross currency swaps.

(3)

Net (loss) income per common unit is determined by dividing net (loss) income, after deducting the amount of net (loss) income attributable to the Dropdown Predecessor, the non-controlling interests, our general partner’s interest and the distributions on our Series A, Series B and Series C preferred units, by the weighted-average number of common units outstanding during the period. We allocate the limited partners’ interest in net (loss) income, including both distributed and undistributed net (loss) income, between continuing operations and discontinued operations based on the proportion of net (loss) income from continuing and discontinuing operations to total net (loss) income.

(4)	Vessels and equipment consists of (a) vessels, at cost less accumulated depreciation and (b) advances on newbuilding contracts and conversion costs.

(5)

Prior to the adoption of Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs (or ASU 2015-03), all debt issuance costs were presented as other non-current assets in our consolidated balance sheets. With the adoption of ASU 2015-03 we present debt issuance costs related to a debt liability as a direct deduction from the carrying amount of that debt liability in our consolidated balance sheets. As a result of adopting ASU 2015-03, total assets and total debt decreased by $12.2 million (December 31, 2011), $10.8 million (December 31, 2012), $19.4 million (December 31, 2013), $27.4 million (December 31, 2014) and $61.5 million (December 31, 2015).

(6)	Preferred units outstanding includes the Series A preferred units in 2013, 2014 and 2015 and the Series B and Series C preferred units in 2015.

(7)

Consistent with general practice in the shipping industry, we use “net revenues” (defined as revenues less voyage expenses, which comprise all expenses relating to certain voyages, including bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions) as a measure of equating revenues generated from voyage charters to revenues generated from time charters, which assists us in making operating decisions about the deployment of vessels and their performance. Under time charters and bareboat charters, the charterer typically pays the voyage expenses, whereas under voyage charter contracts and contracts of affreightment the shipowner typically pays the voyage expenses. Some voyage expenses are fixed, and the remainder can be estimated. If we, as the shipowner, pay the voyage expenses, we typically pass the approximate amount of these expenses on to the customers by charging higher rates under the contract or billing the expenses to them. As a result, although revenues from different types of contracts may vary, the “net revenues” are comparable across the different types of contracts. We principally use net revenues, a non-GAAP financial measure, because it provides more meaningful information to us than revenues, the most directly comparable GAAP financial measure. Net revenues are also widely used by investors and analysts in the shipping industry for comparing financial performance between companies in the shipping industry to industry averages. The following table reconciles net revenues with revenues.


	Year Ended December 31,
	2011			2012			2013			2014			2015
Revenues		840,982			901,227			930,739			1,019,539			1,229,413
Voyage expenses		(97,584	)		(110,483	)		(103,643	)		(112,540	)		(98,006	)

Net revenues		743,398			790,744			827,096			906,999			1,131,407

(8)	EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, as discussed below.

•

Financial and operating performance. EBITDA and Adjusted EBITDA assist our management and investors by increasing the comparability of the fundamental performance of us from period to period and against the fundamental performance of other companies in our industry that provide EBITDA or Adjusted EBITDA-based information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest expense, taxes, depreciation or amortization, which items are affected by various and possibly changing financing methods, capital structure and historical cost basis and which items may significantly affect net (loss) income between periods. We believe that including EBITDA and Adjusted EBITDA as a financial and operating measures 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 common and preferred units.

•

Liquidity. EBITDA and Adjusted EBITDA allow us to assess the ability of assets to generate cash sufficient to service debt, make distributions and undertake capital expenditures. By eliminating the cash flow effect resulting from the existing capitalization of us and other items such as dry-docking expenditures, deferred mobilization revenue and expenditure, working capital changes and foreign currency exchange gains and losses (which may vary significantly from period to period), EBITDA and Adjusted EBITDA provide a consistent measure of our ability to generate cash over the long term. Management uses this information as a significant factor in determining (a) our proper capitalization (including assessing how much debt to incur and whether changes to the capitalization should be made) and (b) whether to undertake material capital expenditures and how to finance them, all in light of existing cash distribution commitments to common and preferred unitholders. Use of EBITDA and Adjusted EBITDA as liquidity measures also permits investors to assess our fundamental ability to generate cash sufficient to meet cash needs, including distributions on our common and preferred units.

Neither EBITDA nor Adjusted EBITDA, which are non-GAAP measures, should be considered as an alternative to net (loss) income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net (loss) 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 consolidated EBITDA and Adjusted EBITDA to net (loss) income, and our historical consolidated Adjusted EBITDA to net operating cash flow.


	Year Ended December 31,
	2011			2012			2013			2014			2015
	(in thousands of US dollars)
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net (loss) income”:
Net (loss) income from continuing operations		(85,376	)		105,447			76,557			17,656			100,143
Depreciation and amortization		171,730			189,364			199,006			198,553			274,599
Interest expense, net of interest income		35,270			46,481			60,294			87,662			122,205
Income tax expense (recovery)		6,679			(10,477	)		2,225			2,179			(21,357	)

EBITDA		128,303			330,815			338,082			306,050			475,590

Write down and loss (gain) of sale of vessels		37,039			24,542			76,782			1,638			69,998
Restructuring charge (recovery)		3,924			1,115			2,607			(225	)		568
Unrealized loss (gain) on derivative instruments		107,860			(39,538	)		(91,837	)		180,156			51,072
Realized loss on interest rate swaps		58,475			58,596			94,848			55,588			71,617
Foreign exchange (gain) loss⁽ⁱ⁾		(3,081	)		11,015			(33,318	)		(77,813	)		(44,267	)
Loss on bond repurchase		—			—			1,759			—			—
Amortization of in-process revenue contracts		(1,075	)		(12,634	)		(12,704	)		(12,744	)		(12,745	)
Adjustments relating to equity income⁽ⁱⁱ⁾		—			—			6,057			15,218			19,357
Adjustments relating to discontinued operations⁽ⁱⁱⁱ⁾		59,522			31,332			15,169			—			—

Adjusted EBITDA		390,967			405,243			397,445			467,868			631,190

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
Net operating cash flow		254,162			267,494			255,387			160,186			371,221
Expenditures for dry docking		26,407			19,122			19,332			36,221			13,060
Interest expense, net of interest income		35,270			46,481			60,294			87,662			122,205
Current income tax expense (recovery)		7,293			(1,669	)		75			1,290			1,650
Realized loss on interest rate swaps		58,475			58,596			94,848			55,588			71,617
Equity income, net of dividends received		—			—			6,731			(6,462	)		(171	)
Change in working capital		11,296			17,447			(51,999	)		111,484			(25,903	)
Restructuring charge (recovery)		3,924			1,115			2,607			(225	)		568
Loss on bond repurchase		—			—			1,759			—			—
Deferred mobilization revenue and costs		—			—			5,051			10,905			38,938
Realized (gain) loss on cross currency swaps		(2,882	)		(2,992	)		(8,363	)		1,992			10,140
Other, net		(3,946	)		(1,173	)		5,556			(5,991	)		8,508
Adjustments relating to equity income⁽ⁱⁱ⁾		—			—			6,057			15,218			19,357
Interest expense, net of interest income relatedto discontinued operations⁽ⁱⁱⁱ⁾		968			822			110			—			—

Adjusted EBITDA		390,967			405,243			397,445			467,868			631,190

(i)

Foreign exchange (gain) loss excludes the unrealized loss of $61.7 million in 2015 (2014 – loss of $94.0 million, 2013 – loss of $38.6 million, 2012 – gain of $10.7 million and 2011 – loss of $1.6 million) on cross currency swaps, which is incorporated in unrealized loss (gain) on derivative instruments in the table.

(ii)	Adjustments relating to equity income from our equity accounted joint ventures are as follows:


	Year Ended December 31,
	2011		2012		2013			2014			2015

Depreciation and amortization		—		—		4,239			8,085			8,356
Interest expense, net of interest income		—		—		2,715			3,837			4,234
Income tax (recovery) expense		—		—		(184	)		(33	)		161
Unrealized (gain) loss on derivative instruments		—		—		(2,302	)		410			4,137
Realized loss on interest rate swaps		—		—		1,589			2,919			2,469

Adjustments relating to equity income		—		—		6,057			15,218			19,357

(iii)

Adjustments relating to our discontinued operations are as follows:


	Year Ended December 31,
	2011			2012		2013			2014		2015

Net (loss) income from discontinued operations		(11,495	)		17,568		(4,642	)		—		—
Depreciation and amortization		15,980			5,267		1,236			—		—
Interest expense, net of interest income		968			822		110			—		—
Write down and loss on sale of vessels		54,069			7,675		18,465			—		—

Adjustments relating to discontinued operations		59,522			31,332		15,169			—		—

(9)

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 and those in discontinued operations. For 2015 and 2014 this includes two FPSO units, and for 2013 one FPSO unit, in equity accounted joint ventures 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 ownership of our 6.00% notes due 2019 (the Notes) and common and 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 interest, principal or distributions on, and the trading price of our Notes and common and 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 charters, voyages and contracts of affreightment (whereby our subsidiaries carry an agreed quantity of cargo for a customer over a specified trade route within a given period of time);

•

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;

•

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 rates, if any, and ability, at which our subsidiaries may be able to contract our newbuilding vessels, including our newbuilding units for maintenance and safety (or UMS) and towage vessels;

•

delays in the delivery of any newbuildings or vessels undergoing conversion or upgrades 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:

•

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 borrowings; and

•

the amount of any cash reserves, including reserves for future maintenance 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.

We may not have sufficient cash from operations to enable us to pay the current level of distribution on our units or to maintain or increase 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 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. In addition, while we would expect to increase or decrease distributions to our common unitholders if our subsidiaries increase or decrease distributions to us, the timing and amount of any such increased or decreased distributions will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by our subsidiaries to us.

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. We may not be able to pay distributions, and any distributions we do make may not be at or above our current level of quarterly 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.

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

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash (as defined in our partnership agreement) each quarter. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

In determining the amount of cash available for distribution, 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.

Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing for our capital expenditures and debt repayment obligations. As a result, effective for the quarterly distribution for the fourth quarter of 2015, we have temporarily reduced our quarterly cash distributions per common unit to $0.11 from $0.56, and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations with cash flows from operations rather than pursuing additional growth projects. It is uncertain when the energy and capital markets will normalize and when, if at all, the board of directors of our general partner may increase quarterly cash distributions on our common units.

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

We have relied primarily upon bank financing and debt and equity offerings to fund our growth. Current depressed market conditions generally in the energy sector and for master limited partnerships have significantly reduced our access to capital, particularly equity capital. Debt financing or refinancing may not be available on acceptable terms, if at all. Issuing additional common equity given current market conditions would be highly dilutive and costly. Lack of access to debt or equity capital at reasonable rates will adversely affect our growth prospects and our ability to refinance debt, make payments on our Notes 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 or 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, incur borrowings, raise capital through the sale of assets or ownership interests in certain assets or joint venture entities, debt or additional equity securities and/or seek to access other financing sources. Our access to draw on committed funding sources, 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:

•

seeking to restructure our debt;

•

seeking additional debt or equity capital;

•

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

•

further reducing cash distributions;

•

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 credit agreements may restrict our ability to implement some of these measures.

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 maintain our quarterly distributions to unitholders.

Our primary liquidity needs for 2016 and 2017 are to make payments for existing, committed capital expenditures and to make scheduled repayments of debt, in addition to paying debt service costs, quarterly distributions on our outstanding common and preferred units, operating expenses and dry docking expenditures and funding general working capital requirements. We anticipate that our primary sources of funds for 2016 and 2017 will be cash flows from operations, bank debt and proceeds from the sale of certain assets. However, we currently estimate cash flow gaps of approximately $250 million in 2016 and $90 million in 2017. These cash flow gaps represent the difference between (a) cash inflows from cash flow from vessel operations, dividends from our equity accounted joint ventures and borrowings under committed and anticipated debt financings and refinancings and (b) cash outflows for expected capital expenditures, equity investments in joint ventures, secured and unsecured debt repayments, interest expense and anticipated distributions on our common and preferred units. In addition, we are required to pay $172.3 million upon delivery of our second UMS newbuilding, which currently is scheduled for late-2016; however, we are seeking to further delay or cancel the delivery of this unit. The cash flow gaps do not take into account utilizing our liquidity balance of $282.7 million at December 31, 2015, which comprises of unrestricted cash and undrawn revolvers. For debt covenant purposes, we need to maintain a minimum liquidity balance of 5% of total consolidated debt, which was approximately $175 million as at December 31, 2015.There can be no assurance that we will be able to fill these cash flow gaps.

We have limited current liquidity.

As at December 31, 2015, we had total liquidity of $282.7 million, consisting of $258.5 million of cash and cash equivalents and $24.2 million of undrawn long-term borrowings under our revolving credit facilities, subject to limitations in the credit facilities. As at December 31, 2015, we had a working capital deficit of $490.0 million. Our limited availability under existing credit facilities and our current working capital deficit could limit our business, ability to meet our financial obligations and growth prospects. We expect to manage our working capital deficit primarily with net operating cash flow and other funding initiatives, including securing debt financing on our under-levered and unmortgaged assets, entering into sale-leaseback transactions, divesting assets, issuing hybrid or other equity securities, reducing our capital expenditures relating to existing projects, accessing the unsecured bond markets and seeking loans from our sponsor, Teekay Corporation. However, there can be no assurance that any such funding will be available to us on acceptable terms, if at all.

We must make substantial capital expenditures to maintain the operating capacity of our fleet, which reduces cash available for distribution. In addition, each quarter our general partner is required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

We must make substantial capital expenditures to maintain, over the long term, the operating capacity of our fleet. We intend to continue to expand our fleet, which would increase the level of our maintenance capital expenditures. 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 payments on our Notes and for distribution to our unitholders.

Our partnership agreement requires our general partner to deduct our estimated, rather than actual, maintenance capital expenditures from operating surplus each quarter in an effort to reduce fluctuations in operating surplus (as defined in our partnership agreement). The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the Conflicts Committee of our general partner at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders is lower than if actual maintenance capital expenditures were deducted from operating surplus. If our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates.

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 an Aframax or Suezmax-size shuttle tanker is approximately $90 to $125 million, the cost of an FSO unit is approximately $50 to $250 million and the cost of an FPSO unit is approximately $200 million to $3 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. The total cost of our newbuilding UMS is approximately $175 to $195 million per unit and the cost of our newbuilding towing and offshore installation vessel is approximately $55 to $60 million per vessel.

We and Teekay Corporation regularly evaluate and pursue opportunities to provide marine transportation services and offshore oil production and storage services for new or expanding offshore projects. Under an omnibus agreement that we have entered into in connection with our initial public offering, Teekay Corporation is required to offer to us, certain shuttle tankers, FSO units and FPSO units Teekay Corporation owns or may acquire in the future, provided the vessels are servicing contracts with remaining durations of greater than three years. We may also acquire other vessels that Teekay Corporation may offer us from time to time and pursue direct acquisitions from third parties and new offshore projects. Neither we nor Teekay Corporation may be awarded charters or contracts of affreightment relating to any of the projects we pursue or it pursues, and we may choose not to purchase the vessels Teekay Corporation is required to offer to us under the omnibus agreement. If we elect pursuant to the omnibus agreement to obtain Teekay Corporation’s interests in any projects Teekay Corporation may be awarded, or if we bid on and are awarded contracts relating to any offshore project, we will need to incur significant capital expenditures to buy Teekay Corporation’s interest in these offshore projects or to build the offshore units.

We typically must pay between 10% to 20% of the purchase price of a shuttle tanker upon signing the purchase contract, even though delivery of the completed vessel will not occur until much later (approximately two to three years from the time the order is placed). 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 will increase the aggregate amount of interest or cash required to maintain our current level of quarterly distributions to unitholders prior to generating cash from the operation of the newbuilding.

Our substantial capital expenditures may reduce our cash available for payments on our Notes and 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 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, results of operations and financial condition and on our ability to make payments on our Notes and cash distributions.

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

As at December 31, 2015, our total debt was approximately $3.4 billion and we had the ability to borrow an additional $24.2 million under our revolving credit facilities, subject to limitations in the credit facilities. We plan to increase our total debt relating to our towing, UMS and shuttle tanker newbuildings and FPSO/FSO conversion projects. 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;

•

we will need a substantial portion of our cash flow 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 or the economy generally; and

•

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

Our ability to service our debt depends upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as further reducing cash distributions, reducing, cancelling or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, seeking to restructure or refinance our debt, seeking additional debt or equity capital or seeking bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

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

The operating and financial restrictions and covenants in our financing arrangements and any future financing agreements for us 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 or guarantee indebtedness;

•

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

•

make dividends or distributions;

•

make certain negative pledges and grant certain liens;

•

sell, transfer, assign or convey assets;

•

make certain investments; and

•

enter into a new line of business.

Four of our revolving credit facilities are guaranteed by us and certain of our subsidiaries for all outstanding amounts and contain covenants that require us to maintain the greater of a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months of maturity) of at least $75.0 million and 5.0% of the our total consolidated debt. One revolving credit facility is guaranteed by Teekay Corporation and contain covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. The revolving credit facilities are collateralized by first-priority mortgages granted on 18 of our vessels, together with other related security. The ability of Teekay Corporation or us to comply with covenants and restrictions contained in debt instruments may be affected by events beyond their or 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. Neither Teekay Corporation nor we might have, or 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 one revolving credit facility and four term loans that require us to maintain vessel values to drawn principal balance ratio of a minimum range of 113% to 125%. As at December 31, 2015, these ratios ranged from 126% to 212%. The vessel values used in these ratios are the appraised values prepared by us based on second hand sale and purchase market data. Changes in the conventional or shuttle tanker, towing, UMS or FPSO markets could negatively affect our compliance with these ratios.

At December 31, 2015, we and Teekay Corporation were in compliance with all covenants in the credit facilities and long-term debt.

Restrictions in our debt 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.

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

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), Petroleo Brasileiro S.A. (or Petrobras), Statoil ASA (or Statoil) and E.ON Ruhrgas UK GP Limited (or E.ON) accounted for approximately 26%, 18%, 11% and 11%, respectively, of our consolidated revenues from continuing operations during 2015. Petrobras, Statoil, E.ON and Repsol S.A. accounted for approximately 22%, 19%, 12% and 11%, respectively, of our consolidated revenues from continuing operations during 2014. Petrobras, Statoil and Repsol S.A. accounted for approximately 25%, 20% and 13%, respectively, of our consolidated revenues from continuing operations during 2013. No other customer accounted for 10% or more of revenues from continuing operations during any of these periods. Please read “Item 18 – Financial Statements: Note 5 – Segment Reporting.”

Petrobras, the Brazil state-controlled oil company, is alleged to have participated in a widespread corruption scandal involving improper payments to Brazilian politicians and political parties. It is uncertain at this time how this may affect Petrobras, its performance of existing contracts with us or the development of new projects offshore of Brazil. Any adverse effect on Petrobras’ ability to develop new offshore projects or to perform under existing contracts with us could harm us.

In addition, in October 2015, Sevan issued a press release indicating that certain individuals who have left Sevan may have made improper payments to Petrobras between 2005 and 2008 in order to obtain vessel contracts from Petrobras, including the existing contract for the Sevan Piranema FPSO unit, which unit and contract we acquired from Sevan in November 2011 and renamed Piranema Spirit. If it is determined that the Piranema Spirit FPSO contract was illegally obtained by Sevan, in addition to any penalties that could be assessed by the authorities, Petrobras may seek to terminate the contract or may seek damages relating to the arrangement, and any dispute with Petrobras may adversely affect our relationship with Petrobras. There is no assurance that we will be able to offset any losses through claims against Sevan.

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 revenues from them could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

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

We and our operating subsidiaries have entered into various services agreements with certain subsidiaries of Teekay Corporation pursuant to which those subsidiaries will provide to us all of our administrative services and to the operating subsidiaries substantially all of their managerial, operational and administrative services (including vessel maintenance, crewing, crew training, purchasing, shipyard supervision, insurance and financial services) and other technical and advisory services. Our operational success and ability to execute our growth strategy depends significantly upon the satisfactory performance of these services by the Teekay Corporation subsidiaries. Our business will be harmed if such subsidiaries fail to perform these services satisfactorily or if they stop providing these services to us or our operating subsidiaries.

In addition, 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, towing and offshore installation and storage projects and to enter into new charters or contracts of affreightment and expand our customer relationships depends largely on our ability to leverage our relationship with Teekay Corporation or our joint venture partners and their reputation and relationships in the shipping industry. If Teekay Corporation 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;

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successfully interact with shipyards during periods of shipyard construction constraints;

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obtain financing on commercially acceptable terms; or

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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, results of operations and financial condition and our ability to make cash distributions.

In January 2015, Teekay Offshore, through its 50/50 joint venture with Odebrecht Oil & Gas S.A. (or Odebrecht), finalized the contract with Petrobras to provide an FPSO unit for the Libra field located in the Santos Basin offshore Brazil. The contract will be serviced by a new FPSO unit being converted from Teekay Offshore’s 1995-built shuttle tanker, the Navion Norvegia. The converted unit is scheduled to commence operations in early-2017 under a 12-year firm period fixed-rate contract with Petrobras and its international partners. Senior Odebrecht S.A. personnel have been implicated in corruption charges related to improper payments to Brazilian politicians and political parties. Any adverse effect of these charges on Odebrecht may harm our growth prospects and results of operations and inhibit the near-term ability of our joint venture with Odebrecht to drawdown on its existing loan facility to fund the Libra FPSO conversion.

A continuation of the recent significant declines in oil prices may adversely affect our growth prospects and results of operations.

Global crude oil prices have significantly declined since mid-2014. A continuation of lower oil prices or a further decline in oil prices may adversely affect our business, results of operations and financial condition and our ability to make cash distributions, as a result of, among other things:

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

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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 components of our FPSO unit contracts or life-of-field contracts;

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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;

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

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

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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, processing and storage services, offshore accommodation, and towing and offshore installation services.

Our growth strategy focuses on expansion in the shuttle tanker, FSO, FPSO, UMS and towing sectors. 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:

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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;

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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;

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availability of new, alternative energy sources; and

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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 towing and offshore installation services would have a material adverse effect on our future growth and could harm our business, results of operations and financial condition.

Because payments under our contracts of affreightment are based on the volume of oil transported and a portion of the payments under our FPSO units operations contracts are based on the volume of oil produced, 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 operate under contracts of affreightment. Payments under these contracts of affreightment are based upon the volume of oil transported, which depends upon the level of oil production at the fields we service under the contracts. Payments made to us under FPSO operations 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. We have an annual adjustment (within a specified range) to the daily base hire rate under the Voyageur Spirit FPSO operations contract based on our operating performance. E.ON may terminate the Voyageur Spirit operations contract if the Huntington field does not yield sufficient revenues, although there is a significant termination fee. 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 many 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. If the oil field no longer produces oil or is abandoned or the contract term is not extended, we will no longer generate revenue under the related contract and will need to seek to redeploy affected vessels.

Many 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 for any reason, we no longer will generate revenue under the related contract. 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 and our ability to make payments on our Notes and cash distributions.

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 agreement. These factors increase the redeployment risk of FPSO units. Unless extended, five of our FPSO production service agreements will expire during the next five years. Our clients may also terminate certain of our FPSO production service agreements 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.

Future adverse economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.

Commencing in 2007 and 2008, the global economy experienced an economic downturn and crisis in the global financial markets that produced illiquidity in the capital markets, market volatility, and increased exposure to interest rate and credit risks and reduced access to capital markets. Additionally, more recently, global crude oil prices have significantly declined since mid-2014 and this has adversely affected energy and master limited partnership capital markets and available sources of financing. If there is continued economic instability in the future, we may continue to face restricted access to the capital markets or secured debt lenders, such as our revolving credit facilities. This decreased access to such resources could have a material adverse effect on our business, financial condition and results of operations.

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 results of operations.

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 results of operations.

The results of our shuttle tanker 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. Because the North Sea is one of our primary existing offshore oil markets, this seasonal repair and maintenance activity contributes to quarter-to-quarter volatility in our results of operations, as oil production typically is lower in the second and third quarters in this region compared with production in the first and fourth quarters. Because a portion of our North Sea shuttle tankers operate under contracts of affreightment, under which revenue is based on the volume of oil transported, the results of these shuttle tanker operations in the North Sea under these contracts generally reflect this seasonal production pattern. When we redeploy affected shuttle tankers as conventional oil tankers while platform maintenance and repairs are conducted, the overall financial results for the North Sea shuttle tanker operations may be negatively affected as the rates in the conventional oil tanker markets at times may be lower than contract of affreightment rates. In addition, we seek to coordinate some of the general dry-docking schedule of our fleet with this seasonality, which may 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, towing and offshore installation vessel and UMS contracts are awarded based upon a variety of factors relating to the vessel operator, including:

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industry relationships and reputation for customer service and safety;

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experience and quality of ship operations;

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quality, experience and technical capability of the crew;

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relationships with shipyards and the ability to get suitable berths;

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

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

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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, results of operations and financial condition and our ability to make payments on our Notes and cash distributions.

Delays in the operational start-up of FPSO units, deliveries of newbuilding vessels or of conversions or upgrades of existing 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 newbuildings or vessel conversions or upgrades 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 or converted vessel to 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:

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

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

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work stoppages or other labor disturbances at the shipyard;

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bankruptcy or other financial crisis of the shipbuilder;

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a backlog of orders at the shipyard;

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political or economic disturbances;

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

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requests for changes to the original vessel specifications;

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

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

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inability to obtain requisite permits or approvals.

If the operational start-up of an FPSO unit or the delivery of a vessel or of a conversion is materially delayed, it could adversely affect our results of operations and financial condition and our ability to make payments on our Notes and cash distributions.

Charter rates for towing and offshore installation vessels and conventional oil tankers may fluctuate substantially over time and may be lower when we are attempting to charter our towing and offshore installation vessels and charter our conventional oil tankers, 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 towing and offshore installation vessels will depend, among other things, the state of the towage market. Towage contracts are highly competitive and are based on the level of projects undertaken by the customer base. Our ability to charter our conventional oil tankers will depend upon, among other things, the state of the conventional tanker market. Conventional oil tanker trades are highly competitive and rates fluctuate significantly. 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.

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

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

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prevailing economic conditions in oil and energy markets;

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a substantial or extended decline in demand for oil;

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increases in the supply of vessel capacity;

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competition from more technologically advanced vessels;

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

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a decrease in oil reserves in the fields and other fields in which our FPSO units or other vessels might otherwise 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 results of operations 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.

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 lessen 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 financial and operational adverse impact on our business that we cannot predict with certainty at this time.

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 growth strategy includes selectively acquiring existing shuttle tankers, FSO and FPSO units, towing and offshore installation vessels and UMS, businesses that own or operate these types of vessels or businesses that provide services to the offshore oil and gas industry. Historically, there have been very few purchases of existing vessels and businesses in the FSO and FPSO segments. Factors that may contribute to a limited number of acquisition opportunities for FSO units and FPSO units in the near term include the relatively small number of independent FSO and FPSO fleet owners. In addition, competition from other companies, many of which have significantly greater financial resources than do we or Teekay Corporation, could reduce our acquisition opportunities or cause us to pay higher prices. We entered the long-haul ocean towage and offshore installation services business and the floating accommodation service business through our acquisitions of ALP Maritime Services B.V. (or ALP) and Logitel Offshore Holding AS (or Logitel) in 2014.

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:

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

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

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

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

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

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

Unlike newbuildings, 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.

We may not be successful in our entry into 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 these 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 HiLoad DP unit on contracts sufficient to recover our investment in the unit.

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, including Brazil, 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 South America. Conflicts in these regions have included attacks on ships and other efforts to disrupt shipping. 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, results of operations and financial condition and ability to make cash distributions. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in Southeast Asia or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could also harm our business and ability to make cash distributions. Finally, a government 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 financial results.

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:

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marine disasters;

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bad weather;

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mechanical failures;

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grounding, capsizing, fire, explosions and collisions;

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piracy;

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human error; and

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war and terrorism.

A portion of our shuttle tanker fleet and the Petrojarl Varg, Voyageur Spirit and Petrojarl Knarr FPSO units 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;

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delays in the delivery of cargo;

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loss of revenues from charters or contracts of affreightment;

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

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governmental fines, penalties or restrictions on conducting business;

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higher insurance rates; and

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damage to our reputation and customer relationships generally.

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

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

The operation of shuttle tankers, conventional oil tankers, FSO and FPSO units, towing 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 one of our vessels, the Petrojarl Knarr 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. 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 reduce revenue and increase costs.

Shuttle tankers, FSO and FPSO units, towing 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 results could harm our business, financial condition and operating results.

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

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

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, towing 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.

Acts of piracy have historically affected ocean-going vessels trading in regions of the world such as the South China Sea 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 and a resurgent piracy risk in the Straits of Malacca and surrounding waters. 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 may be incurred to the extent we employ on-board security guards, could increase in such circumstances. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition and results of operations.

The offshore shipping and storage industry is subject to substantial environmental and other regulations, which may significantly limit operations or increase expenses.

Our operations are affected by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, and the handling and disposal of hazardous substances and wastes. Many of these requirements are designed to reduce the risk of oil spills and other pollution. In addition, we believe that the heightened environmental, quality and security concerns of insurance underwriters, regulators and charterers will lead to additional regulatory requirements, including enhanced risk assessment and security requirements and greater inspection and safety requirements on vessels. We expect to incur substantial expenses in complying with these laws and 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, 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. Please see Item 4. Information on the Partnership – B. Business Overview – Regulations for important information on these regulations, including potential impacts on us.

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

We currently are paid partly in Norwegian Kroner under some of our time charters and FPSO contracts. In addition, we and our operating subsidiaries have entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which those subsidiaries provide to us administrative services and to our operating subsidiaries managerial, operational and administrative services. Under the services agreements, the applicable subsidiaries of Teekay Corporation are paid in U.S. Dollars for reasonable direct and indirect expenses incurred in providing the services. A substantial majority of those expenses are in Norwegian Kroner. Fluctuating exchange rates may result in increased payments by us under the services agreements if the strength of the U.S. Dollar declines relative to the Norwegian Kroner. We have entered into foreign currency forward contracts to economically hedge portions of our forecasted expenditures denominated in Norwegian Kroner. We also incur interest expense on our Norwegian Kroner-denominated bonds. We have entered into cross-currency swaps to economically hedge the foreign exchange risk on the principal and interest payments on our Norwegian Kroner bonds.

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 Teekay Corporation’s seafarers that crew certain of our vessels and Norwegian-based onshore operational staff that provide services to us are employed under collective bargaining agreements. Teekay Corporation may become subject to additional labor agreements in the future. Teekay Corporation 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, results of operations and financial condition.

Teekay Corporation 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 Teekay Corporation’s 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.

Teekay Corporation and its affiliates may engage in competition with us.

Teekay Corporation and its affiliates may engage in competition with us. Pursuant to an omnibus agreement we entered into in connection with our initial public offering, Teekay Corporation, Teekay LNG Partners L.P. (NYSE: TGP) and their respective controlled affiliates (other than us and our subsidiaries) generally have agreed not to engage in, acquire or invest in any business that owns, operates or charters (a) dynamically-positioned shuttle tankers (other than those operating in the conventional oil tanker trade under contracts with a remaining duration of less than three years, excluding extension options), (b) FSO units or (c) FPSO units (collectively “Offshore Vessels”) without the consent of our general partner. The omnibus agreement, however, allows Teekay Corporation, Teekay LNG Partners L.P. and any of such controlled affiliates to:

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own, operate and charter Offshore Vessels if the remaining duration of the time charter or contract of affreightment for the vessel, excluding any extension options, is less than three years;

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own, operate and charter Offshore Vessels and related time charters or contracts of affreightment acquired as part of a business or package of assets and operating or chartering those vessels if a majority of the value of the total assets or business acquired is not attributable to the Offshore Vessels and related contracts, as determined in good faith by Teekay Corporation’s Board of Directors or the conflicts committee of the Board of Directors of Teekay LNG Partners L.P.’s general partner, as applicable; however, if at any time Teekay Corporation or Teekay LNG Partners L.P. completes such an acquisition, it must, within 365 days of the closing of the transaction, offer to sell the Offshore Vessels and related contracts to us for their fair market value plus any additional tax or other similar costs to Teekay Corporation or Teekay LNG Partners L.P. that would be required to transfer the vessels and contracts to us separately from the acquired business or package of assets; or

•

own, operate and charter Offshore Vessels and related time charters and contracts of affreightment that relate to tenders, bids or awards for an offshore project that Teekay Corporation or any of its subsidiaries submits or receives; however, at least 365 days after the delivery date of any such Offshore Vessel, Teekay Corporation must offer to sell the vessel and related time charter or contract of affreightment to us, with the vessel valued (a) for newbuildings originally contracted by Teekay Corporation, at its “fully-built-up cost” (which represents the aggregate expenditures incurred (or to be incurred prior to delivery to us) by Teekay Corporation to acquire, construct and/or convert and bring such Offshore Vessel to the condition and location necessary for our intended use, plus project development costs for completed projects and projects that were not completed but, if completed, would have been subject to an offer to us) and (b) for any other vessels, Teekay Corporation’s cost to acquire a newbuilding from a third party or the fair market value of an existing vessel, as applicable, plus in each case any subsequent expenditures that would be included in the “fully-built-up cost” of converting the vessel prior to delivery to us.

If we decline the offer to purchase the Offshore Vessels and time charters described above, Teekay Corporation or Teekay LNG Partners L.P., as applicable, may own and operate the Offshore Vessels, but may not expand that portion of its business.

In addition, pursuant to the omnibus agreement, Teekay Corporation, Teekay LNG Partners L.P. and any of their respective controlled affiliates (other than us and our subsidiaries) may:

•

acquire, operate and charter Offshore Vessels and related time charters and contracts of affreightment if our general partner has previously advised Teekay Corporation or Teekay LNG Partners L.P. that our general partner’s Board of Directors has elected, with the approval of its Conflicts Committee, not to cause us or our controlled affiliates to acquire or operate the vessels and related time charters and contracts of affreightment;

•

acquire up to a 9.9% equity ownership, voting or profit participation interest in any publicly-traded company that engages in, acquires or invests in any business that owns or operates or charters Offshore Vessels and related time charters and contracts of affreightment; or

•

provide ship management services relating to owning, operating or chartering Offshore Vessels and related time charters and contracts of affreightment.

If there is a change of control of Teekay Corporation or of the general partner of Teekay LNG Partners L.P., the non-competition provisions of the omnibus agreement may terminate, which termination could have a material adverse effect on our business, results of operations and financial condition and our ability to make payments on our Notes and cash distributions.

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 at December 31, 2015, Teekay Corporation indirectly owns the 2.0% general partner interest and a 35.7% limited partner interest in us and controls our general partner, which controls us. 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 Teekay Corporation. Furthermore, certain directors and officers of our general partner are directors or officers of affiliates of our general partner. Conflicts of interest may arise between Teekay Corporation and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner 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 Teekay Corporation or its affiliates (other than our general partner) to pursue a business strategy that favors us or utilizes our assets, and Teekay Corporation’s officers and directors have a fiduciary duty to make decisions in the best interests of the stockholders of Teekay Corporation, which may be contrary to our interests;

•

the Chief Executive Officer, the Chief Financial Officer and director of our general partner, as well as another two directors of our general partner, also serve as officers, management or directors of Teekay Corporation and, for two of such individuals, the general partner of Teekay LNG Partners L.P. and one of such individuals is a director of Teekay Tankers Ltd.;

•

our general partner is allowed to take into account the interests of parties other than us, such as Teekay Corporation, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

•

our general partner has limited its liability and reduced its fiduciary duties under the laws 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 determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;

•

in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions (in each case to affiliates of Teekay Corporation);

•

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

•

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

•

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

•

our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80.0% of our common units;

•

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 the officers and directors of our general partner may conflict with those of the officers and directors of 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, the Chief Executive Officer, the Chief Financial Officer and all of the non-independent directors of our general partner also serve as officers, management or directors of Teekay Corporation and/or other affiliates of Teekay Corporation. Consequently, these officers and directors may encounter situations in which their fiduciary obligations to Teekay Corporation or its 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.

Tax Risks

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

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 (a) at least 75% of its gross income consists of “passive income,” or (b) 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 the current composition of our assets and operations (and those of our subsidiaries), 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 U.S. Federal Income Tax Considerations”) held units, such U.S. Holder would face adverse tax consequences. For a more comprehensive discussion regarding the tax consequences to U.S. Holders if we are treated as a PFIC, please read Item 10 – Additional Information: Material U.S. Federal Income Tax Considerations –- United States Federal Income Taxation of U.S. Holders – Consequences of Possible PFIC Classification.

We may be 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, further reducing the cash available for distribution. We have established reserves in our financial statements that we believe are adequate to cover our liability for any such additional taxes. We cannot assure you, however, that such reserves will be sufficient to cover any additional tax liability that may be imposed on our subsidiaries. In addition, changes in our operations or ownership could result in additional tax being imposed on us or on our subsidiaries in jurisdictions in which operations are conducted. For example, Teekay Corporation indirectly owns less than 50% of the value of our outstanding units and therefore we believe that we do not satisfy the requirements of the exemption from U.S. taxation under Section 883 of the Code and our U.S. source income is subject to taxation under Section 887 of the Code. The amount of such tax will depend upon the amount of income we earn from voyages into or out of the United States, which is not within our complete control.

Unitholders may be subject to income tax in one or more non-U.S. countries, including Canada, 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. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for distribution to unitholders.

We intend that our affairs and the business of each of our subsidiaries is conducted and operated in a manner that minimizes foreign income taxes which may be imposed upon unitholders as a result of owning our units. However, there is a risk that unitholders will be subject to tax in one or more countries, including Canada, 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. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for unitholders.

Item 4. Information on the Partnership

A. Overview, History and Development

Overview and History

Please see Item 5. Operating and Financial Review and Prospects – Management Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments for recent acquisitions and developments.

As of December 31, 2015, our fleet consisted of:

•

Shuttle Tankers. Our shuttle tanker fleet consisted of 31 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, three shuttle tanker newbuildings, and one shuttle tanker and one HiLoad Dynamic Positioning (or DP) unit in lay-up. Of these 36 shuttle tankers, six were owned through 50%-owned subsidiaries, one through a 67%-owned subsidiary and three were chartered-in. The remaining vessels are owned 100% by us. All of these shuttle tankers, with the exception of the HiLoad DP unit, provide transportation services to energy companies in the North Sea, Brazil and the East Coast of Canada. The average term of the contracts of affreightment, weighted based on vessel years, is 2.9 years. The time charters and bareboat charters have an average remaining contract term of approximately 4.1 years. As of December 31, 2015, our shuttle tanker fleet had a total cargo capacity of approximately 4.5 million deadweight tonnes (or dwt), representing approximately 36% of the total tonnage of the world shuttle tanker fleet.

•

FPSO Units. Our FPSO fleet consisted of six units, of which we have 100% ownership interests in, one of which is currently undergoing upgrades at the Damen Shipyard in the Netherlands, and two FPSO units, of which we have 50% ownership interests in, one of which is currently undergoing a conversion into an FPSO unit for operation in the Libra field in offshore Brazil. The remaining six units are operating under FPSO contracts with major energy companies in the North Sea and Brazil. We use the FPSO units to provide production, processing and storage services to oil companies operating offshore oil field installations. The FPSO contracts, including the contracts relating to the two FPSO units currently undergoing an upgrade and a conversion, have an average remaining term of approximately 4.6 years. As of December 31, 2015, our FPSO units had a total production capacity of approximately 0.4 million barrels of oil per day, including the expected capacity of the two units currently undergoing an upgrade and a conversion.

•

FSO Units. Our FSO fleet consisted of six units, of which we have 100% ownership interest in and includes one vessel which is currently undergoing conversion into an FSO unit, and one unit of which we have 89% ownership interests in. All of our FSO units operate under fixed-rate contracts, with an average remaining term of approximately 4.4 years. As of December 31, 2015, our FSO units had a total cargo capacity of approximately 0.8 million dwt, including the expected capacity of the unit currently undergoing conversion.

•

Conventional Tankers. We had two Aframax conventional crude oil tankers, of which, one vessel operated under a fixed-rate time charter with Teekay Corporation, and the other operated in the spot conventional tanker market. We had 100% ownership in both vessels. As of December 31, 2015, both vessels were classified as held for sale on our consolidated balance sheets due to the sale of these vessels in March 2016. As part of the sale, we chartered-in these vessels for a period of 3 years each, both with an additional one-year extension option One vessel is fixed on a two-year time-charter-out and the other vessel is trading in the spot conventional tanker market. As of December 31, 2015, our conventional tankers had a total cargo capacity of approximately 0.2 million dwt.

•

Towing and offshore installation vessels. Our long-distance towing and offshore installation fleet consisted of six on-the-water vessels and four ultra-long distance towing and offshore installation vessel newbuildings, which are scheduled to deliver during 2016. We have 100% ownership interests in all our towing and offshore installation vessels. All of our delivered towing and offshore installation vessels operate on voyage-charter towage contracts.

•

UMS: We have one operational UMS, the Arendal Spirit, and two newbuildings, which are currently scheduled to deliver in late-2016 and, subject to our exercise of a deferred delivery option, mid-2019, respectively. The Arendal Spirit operates on a fixed-rate time-charter contract with a remaining term of approximately 2.5 years. We are currently negotiating a three-year extension of the time-charter contract with the charterer of the Arendal Spirit in exchange for a reduction in the current charter rate. We may decide to cancel or further defer the delivery of the second UMS as well as conclude on the deferral of, or cancel, the third UMS. We have 100% ownership interests in all of these UMS.

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 4^th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530.

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 possible future vessel acquisitions.

B. Business Overview

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 from oil field installations, 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 for a specific offshore oil field or under contracts of affreightment for various fields. The number of voyages performed under these contracts of affreightment normally 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. Although the size of the world shuttle tanker fleet has been relatively unchanged in recent years, conventional tankers could be converted into shuttle tankers by adding specialized equipment to meet customer requirements. Shuttle tanker demand may also 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.

As of December 31, 2015, there were approximately 112 vessels in the world shuttle tanker fleet (including 24 newbuildings), the majority of which operate in the North Sea and Brazil. Shuttle tankers also operate off the East Coast of Canada and in the U.S. Gulf. As of December 31, 2015, we owned 33 shuttle tankers (including the HiLoad DP unit), in which our ownership interests ranged from 50% to 100%, and chartered-in an additional three shuttle tankers. Other shuttle tanker owners include Knutsen NYK Offshore Tankers AS, SCF Group, Viken Shipping and AET, which as of December 31, 2015 controlled fleets ranging from 5 to 26 shuttle tankers each. 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 our recent entry into the East Coast of Canada.

The following tables provide additional information about our shuttle tankers as of December 31, 2015:

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

Chevron, Hess, ENI, Draugen Transport, BP, ConocoPhillips, Total, Talisman, Nexen, Dana Petroleum, Shell, Statoil, OMV, Maersk Oil, Wintershall, Idemitsu, Rwe-Dea, E.ON Ruhrgas, Det Norske Oljeselslcap, Lundin, PGING, Itacha, Enquest, Premier, TAQA ⁽⁹⁾

Amundsen Spirit

109,300

2010

100%

DP2

North Sea

CoA

Stena Natalita

108,100

2001

50%⁽⁶⁾

DP2

North Sea

CoA

Navion Oslo

100,300

2001

100%

DP2

North Sea

CoA

Navion Oceania

126,400

1999

100%

DP2

North Sea

CoA

Navion Scandia

126,700

1998

100%

DP2

North Sea

CoA

Aberdeen

87,100

1996

In-chartered (until December 2016)

North Sea

CoA

Samba Spirit

154,100

2013

100%

DP2

Brazil

Time charter

Shell

June 2023

Lambada Spirit

154,000

2013

100%

DP2

Brazil

Time charter

Shell

August 2023

Bossa Nova Spirit

155,000

2013

100%

DP2

Brazil

Time charter

Shell

November 2023

Sertanejo Spirit

155,000

2013

100%

DP2

Brazil

Time charter

Shell

January 2024

Peary Spirit

109,300

2011

100%

DP2

North Sea

Time charter

Statoil ⁽¹⁰⁾

Nansen Spirit

109,300

2010

100%

DP2

North Sea

Time charter

Statoil ⁽¹⁰⁾

Stena Alexita

127,000

1998

50%⁽⁶⁾

DP2

North Sea

Time charter

Statoil ⁽¹⁰⁾

Heather Knutsen ⁽²⁾

148,600

2005

In-chartered (until December 2017)

DP2

Canada

Time charter

ExxonMobil, Canada Hibernia, Chevron, Husky, Mosbacher, Murphy, Nalcor, Statoil, Suncor ⁽⁹⁾

December 2017

Jasmine Knutsen ⁽²⁾

148,600

2005

In-chartered (until April 2018)

DP2

Canada

Time charter

April 2018

Navion Hispania ⁽²⁾

126,200

1999

100%

DP2

Canada

Time charter

April 2018

Stena Sirita

126,900

1999

50%⁽⁶⁾

DP2

North Sea

Time charter

Esso

September 2015

Navion Anglia

126,400

1999

100%

DP2

Brazil

Time charter

Petrobras

June 2016

Navion Britannia ⁽³⁾

124,200

1998

100%

DP2

North Sea

Time charter

Taqa Bratani Limited

December 2016

Navion Gothenburg

152,200

2006

50%⁽⁶⁾

DP2

Brazil

Bareboat

Petrobras ⁽¹¹⁾

July 2020

Nordic Brasilia

151,300

2004

100%

Brazil

Bareboat

Petrobras ⁽¹¹⁾

July 2017

Nordic Rio

151,300

2004

50%⁽⁶⁾

Brazil

Bareboat

Petrobras ⁽¹¹⁾

July 2017

Navion Stavanger

148,700

2003

100%

DP2

Brazil

Bareboat

Petrobras ⁽¹¹⁾

July 2019

Petroatlantic

93,000

2003

100%

DP2

North Sea

Bareboat

Teekay Corporation

March 2016

Petronordic

93,000

2002

100%

DP2

North Sea

Bareboat

Teekay Corporation

March 2016

Nordic Spirit

151,300

2001

100%

Brazil

Bareboat

Petrobras ⁽¹¹⁾

April 2018

Stena Spirit

151,300

2001

50%⁽⁶⁾

Brazil

Bareboat

Petrobras ⁽¹¹⁾

July 2018

Navion Bergen

105,600

2000

100%

DP2

Brazil

Bareboat

Petrobras ⁽¹¹⁾

April 2020

Navion Europa

130,300

1995

67%⁽⁷⁾

North Sea

Spot⁽⁸⁾

Navion Marita

103,900

1999

100%

Far-East

Spot

HiLoad DP Unit ⁽⁴⁾

n/a

2010

100%

Canary Islands

Lay-up

Navion Torinita ⁽⁵⁾

106,900

1992

100%

DP2

Lay-up

ECC 1 ⁽²⁾

155,000

2017

100%

DP2

Newbuilding

ECC 2 ⁽²⁾

155,000

2017

100%

DP2

Newbuilding

ECC 3 ⁽²⁾

155,000

2018

100%

DP2

Newbuilding

Total capacity

4,535,600

(1)	“CoA” refers to contracts of affreightment.

(2)

“ECC” refers to East Coast of Canada. These three newbuildings are expected to be delivered in the fourth quarter of 2017 through the first half of 2018. These newbuildings will replace the three existing vessels servicing the East Coast of Canada, including two third-party owned vessels chartered-in to us, and continue on the existing time-charter contracts until June 2030.

(3)	The vessel is capable of loading from a submerged turret loading buoy.

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

(5)	The Navion Torinita was sold in January 2016.

(6)	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.

(7)	The parties share in the profits and losses of the subsidiary in proportion to each party’s relative capital contributions.

(8)	The Navion Europa is operating on short-term projects.

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

(10)

Under the terms of a master agreement with Statoil, the vessels are chartered under individual fixed-rate annually renewable time-charter contracts. The number of vessels may be adjusted annually based on the requirements of the fields serviced. It is expected that between one and three vessels will be required by Statoil annually. Statoil will require three vessels during 2016. The vessels currently on time charter to Statoil may be replaced by vessels currently servicing contracts of affreightment or other time-charter contracts.

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

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 and Teekay Corporation have played an active role in establishing and participating in a unique co-operation among 29 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 or operate VOC systems on 13 of our shuttle tankers. 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 2015, approximately 41% of our consolidated net revenues from continuing operations were earned by the vessels in the shuttle tanker segment, compared to approximately 52% in 2014 and 55% in 2013. 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.

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 typically used as production facilities to develop marginal oil fields or 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 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, FPSOs 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 wellstream is brought to the surface via subsea equipment on the sea floor that is connected to the FPSO unit by flexible flow lines called risers. The risers carry 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. As of December 31, 2015, there were approximately 181 FPSO units operating and 25 FPSO units on order in the world fleet. At December 31, 2015, we owned six FPSO units, of which we have 100% ownership interests in, one of which is currently undergoing upgrades at the Damen Shipyard in the Netherlands, and two FPSO units, of which we have 50% ownership interests in, one of which is undergoing a conversion into an FPSO unit for operation in the Libra field in offshore Brazil. 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 and Bluewater.

The following table provides additional information about our FPSO units as of December 31, 2015:


Vessel	Production Capacity (bbl/day)		Built	Ownership			Field name and location	Charterer	Contract End Date
Petrojarl Knarr⁽¹⁾⁽²⁾		63,000	2014		100	%	Knarr, Norway	Shell	March 2025
Libra ⁽³⁾		50,000	2017		50	%	Libra, Brazil	Petrobras	March 2029
Cidade de Itajai ⁽¹⁾⁽⁴⁾		80,000	2012		50	%	Bauna and Piracaba, Brazil	Petrobras	February 2022
Voyageur Spirit ⁽¹⁾		30,000	2008		100	%	Huntington, U.K.	E.ON	April 2018
Petrojarl Cidade de Rio das Ostras ⁽⁵⁾		25,000	2008		100	%	Tartaruga Verde, Brazil	Petrobras	January 2018
Piranema Spirit ⁽¹⁾		30,000	2007		100	%	Piranema, Brazil	Petrobras	October 2018
Petrojarl Varg ⁽⁶⁾		57,000	1998		100	%	Varg, Norway	Repsol S.A.	August 2016
Petrojarl I ⁽⁷⁾		46,000	1986		100	%	Atlanta, Brazil	QGEP	March 2021

Total capacity		381,000

(1)	The charterer has options to extend the service contract.

(2)	The charterer has the annual right to terminate the contract after March 2021 subject to payment of certain termination fees.

(3)	The vessel is currently undergoing conversion into an FPSO unit for employment on the Libra field. The original hull was built in 1995. The unit is expected to commence its 12-year firm-period fixed-rate contract in early-2017.

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

(5)	The Petrojarl Cidade de Rio das Ostras was converted to an FPSO unit in 2008. The original hull was built in 1981.

(6)	The Petrojarl Varg is expected to be redelivered to us in August 2016.

(7)	The Petrojarl I is currently undergoing upgrades. The unit is scheduled to commence operations in the fourth quarter of 2016 under a five-year fixed-rate charter contract.

During 2015, approximately 47% of our consolidated net revenues from continuing operations were earned by our FPSO units, compared to approximately 39% in 2014 and 34% in 2013. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

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 a jacked-up fixed production system, floating production systems that do not have sufficient storage facilities or as supplemental storage for fixed platform systems, which generally have some on-board storage capacity. An FSO unit is usually of similar design to a conventional tanker, but has specialized loading and off-take systems required by field operators or regulators. 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. 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 conventional tanker lifespan of 25 years.

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

As of December 31, 2015, there were approximately 92 FSO units operating and seven FSO units on order in the world fleet, and we had seven FSO units in which our ownership interests ranged from 89% to 100%, including one vessel currently undergoing conversion into an FSO unit. 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, 2015:


Vessel	Capacity (dwt)		Built		Ownership			Field name and location	Contract Type	Charterer	Contract End Date
Suksan Salamander⁽¹⁾		78,200		1993		100	%	Bualuang, Thailand	Bareboat	Teekay Corporation	August 2024
Navion Saga ⁽¹⁾		149,000		1991		100	%	Volve, Norway	Time charter	Statoil	October 2016
Pattani Spirit ⁽¹⁾		113,800		1988		100	%	Platong, Thailand	Bareboat	Teekay Corporation	April 2019
Dampier Spirit ⁽¹⁾		106,700		1987		100	%	Stag, Australia	Time charter	Apache Energy	October 2024
Falcon Spirit ⁽¹⁾		124,500		1986		100	%	Al Rayyan, Qatar	Time charter	Occidental Qatar Energy	June 2017
Apollo Spirit ⁽²⁾		129,000		1978		89	%	Banff, U.K.	Bareboat	Teekay Corporation	December 2020
Gina Krog ⁽¹⁾⁽³⁾		124,500		1995		100	%	Gina Krog, Norway	Time charter	Statoil	March, 2020

		825,700

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

(2)	Charterer is required to charter the vessel for as long as Teekay Corporation’s Petrojarl Banff FPSO unit produces in the Banff field in the North Sea, which is expected to remain under contract until the end of 2020.

(3)	The vessel is currently undergoing conversion into an FSO unit. The FSO unit is expected to commence its three-year time-charter contract plus 12 one-year extension options in early-2017.

During 2015, approximately 5% of our consolidated net revenues from continuing operations were earned by the vessels in the FSO segment, compared to 6% in 2014 and 7% in 2013. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Conventional Tanker Segment

Conventional oil tankers are used primarily for transcontinental seaborne transportation of oil. As used in this discussion, “conventional” oil tankers exclude those vessels that can carry dry bulk and ore, tankers that currently are used for storage purposes and shuttle tankers.

In March 2016, we sold our two conventional tankers and subsequently chartered-in both vessels for three years each; both with an additional one-year extension option. One vessel is fixed on a two-year time-charter-out contract and the other vessel is trading in the spot conventional tanker market.

The following table provides information about our conventional tankers as of December 31, 2015:

Vessel

Capacity (dwt)

Built

Ownership

Contract Type⁽¹⁾

Charterer

Contract End Date

Kilimanjaro Spirit ⁽²⁾

115,000

2004

100

Time charter

Teekay Corporation

March 2016

Fuji Spirit ⁽²⁾

106,400

2003

100

Spot

Total capacity

221,400

(1)	“Spot” refers to spot conventional tanker market.

(2)

As of December 31, 2015, the Kilimanjaro Spirit operated under a fixed-rate time charter with Teekay Corporation and the Fuji Spirit operated in the spot conventional tanker market. Both of these vessels were classified as held for sale on our consolidated balance sheet as at December 31, 2015 due to the sale of these vessels in March 2016. As part of the sales of these vessels we are in-chartering these vessels for three years each, both with an additional one-year extension option. One vessel is fixed on a two-year time-charter-out contract and the other vessel is trading in the spot conventional tanker market.

During 2015, approximately 2% of our consolidated net revenues from continuing operations were earned by the vessels in the conventional tanker segment, compared to 3% in 2014 and 4% in 2013. All earnings from discontinued operations were from the conventional tanker segment. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Towage Segment

Long-distance towing and offshore installation vessels are used for the towage, station-keeping, installation and decommissioning of large floating objects such as exploration, production and storage units, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs. We operate with high-end vessels which can be defined as long-distance towing and offshore installation vessels with a bollard pull of greater than 180 tonnes and a fuel capacity of more than 2,000 metric tonnes. Our focus is on intercontinental towages requiring trans-ocean movements.

We are the sole provider of long-distance towing and offshore installation vessels with DP2 capability. Our vessels operate on voyage-charter towage contracts. Voyage-charter contract revenue is less volatile than revenue from spot market rates, as project budgets are prepared and maintained well in advance of the contract commencement.

As of December 31, 2015, there were approximately 33 long-distance towing and offshore installation vessels operating and four long-distance towing and offshore installation vessels on order in the world fleet. At December 31, 2015, our towage fleet includes ten long-distance towing and offshore installation vessels (including four ultra-long distance towing and offshore installation vessel newbuildings, which are all scheduled to deliver during 2016), all of which we have 100% ownership interest in.

The following table provides additional information about our towing and offshore installation vessels as of December 31, 2015:


Vessel	Bollard Pull (tonnes)		Built		Ownership			Contract Type
ALP Centre		298		2010		100	%	Voyage-charter
ALP Guard		298		2009		100	%	Voyage-charter
ALP Forward		218		2007		100	%	Voyage-charter
ALP Winger		219		2007		100	%	Voyage-charter
ALP Ace		192		2006		100	%	Voyage-charter
ALP Ippon		207		2006		100	%	Voyage-charter
ALP Striker ⁽¹⁾		306		2016		100	%
ALP Defender⁽¹⁾		306		2016		100	%
ALP Sweeper⁽¹⁾		306		2016		100	%
ALP Keeper⁽¹⁾		306		2016		100	%

		2,656

(1)	Newbuilding scheduled for delivery in 2016.

During 2015, approximately 2% of our consolidated net revenues from continuing operations were earned by the vessels in the towage segment compared to $nil in 2014 and 2013. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

UMS Segment

Units for Maintenance and Safety 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 exploration, production and storage units, including FPSO units, FLNG units and floating drill rigs. Our UMS fleet is available for world-wide operations, excluding operations within the Norwegian Continental Shelf, and include DP3 keeping systems that are capable of operating in deep water and harsh weather. As of December 31, 2015, there were approximately 38 DP UMS operating and 24 units on order in the world fleet.

The Arendal Spirit UMS, delivered to us in February 2015 and commenced its three-year time-charter contract in June 2015. We are currently negotiating a three-year contract extension with the charterer in exchange for a reduction in the current charter rate.

We have an additional two newbuildings (scheduled to deliver in late-2016 and, subject to the exercise of a deferred delivery option, mid-2019). These vessels are not yet chartered. We may decide to seek a further deferral of the delivery of the Stavanger Spirit UMS or cancel both newbuilding contracts.

The following table provides additional information about our UMS as of December 31, 2015:


Vessel	Berths		Built		Ownership			Location	Contract type	Charterer	Contract End Date
Arendal Spirit		500		2015		100	%	Brazil	Time charter	Petrobras	June 2018
Stavanger Spirit⁽¹⁾		500		2016		100	%
Nantong Spirit⁽²⁾		500		2019		100	%

Total capacity		1,500

(1)	Newbuilding expected to deliver in the fourth quarter of 2016; however, we may decide to further defer or cancel the delivery of this UMS.

(2)	Newbuilding expected to deliver in the second quarter of 2019, subject to the exercise of a deferred delivery option, however we may decide to cancel the delivery of this UMS.

During 2015, approximately 3% of our consolidated net revenues from continuing operations were earned by the UMS segment compared to $nil in 2014 and 2013. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Business Strategies

Our primary business objective is to increase distributable cash flow per common unit by executing the following strategies:

•

Project management and execution of our growth projects mostly secured on long-term contracts. We continue to focus on executing on our shuttle tanker, FPSO, FSO, towing and offshore installation and UMS growth projects delivering between now and 2019, ensuring these projects remain on time and on budget, to provide stable cash flows.

•

Extend contracts and redeploy existing assets on long-term contracts. Over the near-to-medium term, we intend to extend contracts and redeploy existing shuttle tankers and FPSO, FSO and UMS units on to long-term contracts, rather than ordering new vessels. We believe this approach reduces our financing requirements and provides our customers with a quick-to-market and lower cost offshore solution, which significantly lowers our customers’ break-even and lifting cost per barrel of oil production, compared to a new vessel. 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 and shipyard relationships.

•

Provide superior customer service by maintaining high reliability, safety, environmental and quality standards, while implementing various cost saving initiatives. Energy companies seek partners that have a reputation for high reliability, safety, environmental and quality standards. We intend 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 to reduce production costs and find efficiencies, while at the same time implementing our own cost saving initiatives.

Customers

We provide marine transportation, production and storage services to energy and oil service companies or their affiliates. Our largest customer measured by annual revenue is Shell, which is a global group of energy and petrochemical companies.

Shell, Petrobras, Statoil and E.ON accounted for approximately 26%, 18%, 11% and 11%, respectively, of our consolidated revenues from continuing operations during 2015. Petrobras, Statoil, E.ON and Repsol S.A. accounted for approximately 22%, 19%, 12% and 11%, respectively, of our consolidated revenues from continuing operations during 2014. Petrobras, Statoil and Repsol S.A. accounted for approximately 25%, 20%, and 13%, respectively, of our consolidated revenues from continuing operations during 2013. No other customer accounted for 10% or more of such consolidated revenues during 2015, 2014 or 2013.

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. In 2008, we introduced the Quality Assurance and Training Officers (or QATO) program to conduct rigorous internal audits of our processes and provide our seafarers with on-board training. In 2007, we introduced 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. In 2010, Teekay Corporation introduced the “Operational Leadership” campaign to reinforce commitment to personal and operational safety.

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.

We, through certain of our subsidiaries, assist our operating subsidiaries in managing their ship operations. All vessels are operated under our comprehensive and integrated Safety Management System that complies with the International Safety Management Code (or ISM Code), the International Standards Organization’s (or ISO) 9001 for Quality Assurance, ISO 14001 for Environment Management Systems, Occupational Health and Safety Assessment Series (or OHSAS) 18001 and the Maritime Labor Convention 2006 (or MLC 2006) that became effective in, 2013. The management system is certified by Det Norske Veritas (or DNV), the Norwegian classification society. 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 and applicable flag states.

We provide, through certain of our subsidiaries, expertise in various functions critical to the operations of our operating subsidiaries. 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.

Vessel management services are provided by subsidiaries of Teekay Corporation, located in various offices around the world. These include critical vessel management functions such as:

•

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, Teekay Corporation’s day-to-day focus on cost control is applied to our operations. In 2003, Teekay Corporation and two other shipping companies established a purchasing alliance, Teekay Bergesen Worldwide, which leverages the purchasing power of the combined fleets, mainly in such commodity areas as lube oils, paints and other chemicals. Through our arrangements with Teekay Corporation, we benefit from this purchasing alliance.

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.

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 to insure the vessel. We believe that 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 one of our vessels, the Petrojarl Knarr 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 to install and operate 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, 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. In order 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 the hull to facilitate underwater inspections by divers, their 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).

In addition to Class surveys, the vessels’ 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 International Management Code for the Safe Operation of Ships and for Pollution Prevention (or ISM Code). DNV 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 regular inspections which helps ensure 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.

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 scrapping 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 U.S. 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.

With regard to 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 (adopted by IMO Resolution MSC. 267(85) of December 4, 2008), which became mandatory on July 1, 2010, also applies mandatorily to offshore support vessels (with the exception of certain provisions thereof). The IMO has also developed non-mandatory codes and guidelines which apply to various types or aspects of offshore support vessels. These include, amongst others, the Code of Safe Practice for the Carriage of Cargoes and Persons by Offshore Supply Vessels (the OSV Code) (IMO Resolution A.863(20) of November 27, 1997) as subsequently amended, the Guidelines for the Design and Construction of Offshore Supply Vessels, 2006 (the OSV Guidelines)(IMO Resolution MSC.235(82) of December 1, 2006) as subsequently amended, the Guidelines for the Transport and Handling of Limited Amounts of Hazardous and Noxious Liquid Substances in Bulk on Offshore Support Vessels (the LHNS Guidelines)(IMO Resolution A.673(16)) of October 19, 1989, as subsequently amended, the Code of Safety for Special Purpose Ships, 2008 (Resolution MSC.266(84) of May 13, 2008 as subsequently amended, the Code of Safety for Dynamically Supported Craft (IMO Resolution A.373(X)) of November 17, 1977) as subsequently amended, the Guidelines for Vessels with Dynamic Positioning Systems (MSC/Circ.645 of June 6, 1994) and the Guidelines for Dynamic Positioning System (DP) Operator Training (MSC/Circ.738/Rev. 1 of July 7, 2006).

Annex VI to the IMO’s International Convention for the Prevention of Pollution from Ships (MARPOL) (or Annex VI) sets limits on sulfur oxide and nitrogen oxide emissions 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 sulfur content of fuel oil and allows for special areas to be established with more stringent controls on sulfur emissions.

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

In addition, the IMO has proposed (by the adoption in 2004 of the International Convention for the Control and Management of Ships’ Ballast Water and Sediments (or the Ballast Water Convention)) that all shuttle tankers of the size we operate that were built starting in 2012 contain ballast water treatment systems to comply with the ballast water performance standard specified in the Ballast Water Convention, and that all other similarly sized shuttle tankers install ballast water treatment systems in order to comply with the ballast water performance. This convention is not yet effective. We estimate that the installation of ballast water treatment systems on our tankers may cost between $2 million and $3 million per vessel.

The IMO has also developed and adopted an International Code for Ships Operating in Polar Waters (or Polar Code) which deals with matters regarding design, construction, equipment, operation, search and rescue and environmental protection in relation to ships operating in waters surrounding the two poles. The Polar Code includes both safety and environmental provisions and will be mandatory, with the safety provisions becoming part of SOLAS and the environmental provisions becoming part of MARPOL. In November 2014 the IMO’s MSC adopted the Polar Code and the related amendments to SOLAS in relation to safety, while in May 2015 the IMO’s Marine Environment Protection Committee (or MEPC) adopted the environmental provisions of the Polar Code and associated amendments to MARPOL. The Polar Code is to enter into force on January 1, 2017.

European Union (or EU)

Like the IMO, the EU has adopted regulations phasing out single-hull tankers. All of our tankers are double-hulled.

The EU has also adopted legislation (Directive 2009/16/EC on Port State Control as subsequently amended) 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 is also considering the adoption of criminal sanctions for certain pollution events, including improper cleaning of tanks (Directive 2009/15/EC as amended by Directive 2014/111/EU of December 17, 2014).

The EU has adopted a Directive requiring the use of low sulfur fuel. Since January 1, 2015, vessels have been required to burn fuel with sulfur 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 regulations requiring the use of low sulfur fuel. Since January 1, 2014, the California Air Resources Board has also required vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles of California. China also has established emission control areas in the Pearl River Delta, the Yangtze River Delta and the Bohai Bay rim area with restrictions, commencing on January 1, 2016, in the maximum sulfur content of the fuel to be used by vessels within those areas and which limits become progressively stricter over time.

IMO regulations require that as of January 1, 2015, all vessels operating within Emissions Control Areas (or ECAs) worldwide recognized under MARPOL Annex VI must comply with 0.1% sulfur requirements. Currently, the only grade of fuel meeting 0.1% sulfur content requirement is low sulfur marine gas oil (or LSMGO). Since January 1, 2015, the applicable sulfur content limits in the North Sea, the Baltic Sea and the English Channel sulfur control areas have been 0.1%. Other established ECAs under Annex VI to MARPOL are the North American ECA and the United States Caribbean Sea ECA. Certain modifications were necessary in order to optimize operation on LSMGO of equipment originally designed to operate on Heavy Fuel Oil (or HFO). In addition, LSMGO is more expensive than HFO and this will impact the costs of operations. However, for vessels employed on fixed term business, all fuel costs, including any increases, are borne by the charterer. 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 sulfur areas are able to comply with fuel requirements.

The EU has recently adopted Regulation (EU) No 1257/2013 which imposes rules regarding ship recycling and management of hazardous materials on vessels. The Regulation sets out requirements for the recycling of vessels in an environmentally sound manner at approved recycling facilities, so as to minimize the adverse effects of recycling on human health and the environment. The Regulation also contains rules to control and properly manage hazardous materials on vessels and prohibits or restricts the installation or use of certain hazardous materials on vessels. The Regulation aims at facilitating the ratification of the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships adopted by the IMO in 2009 (which has not entered into force). It applies to vessels flying the flag of a Member State. In addition, certain of its provisions also apply to vessels flying the flag of a third country calling at a port or anchorage of a Member State. For example, when calling at a port or anchorage of a Member State, the vessels flying the flag of a third country will be required, amongst other things, to have on board an inventory of hazardous materials which complies with the requirements of the Regulation and to be able to submit to the relevant authorities of that Member State a copy of a statement of compliance issued by the relevant authorities of the country of their flag and verifying the inventory. The Regulation is to apply not earlier than December 31, 2015 and not later than December 31, 2018, although certain of its provisions are applicable from December 31, 2014 and certain others are to apply from December 31, 2020.

North Sea and Brazil

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

There is no international regime in force which deals with compensation for oil pollution from offshore craft, such as FPSOs. The issue 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 to it (or the 1976 Limitation of Liability Convention), which deals with limitation of liability for maritime claims, apply to FPSOs is neither straightforward nor certain. The CLC and the Fund Convention were not drafted with FPSOs and offshore craft in mind and it is doubtful whether FPSOs and any claims for oil pollution caused by them fall within the ambit of the CLC and the Fund Convention. 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 FPSOs and oil pollution caused by them can come under the ambit of these conventions for the purposes of liability and compensation. However, the application of these conventions also depends on their implementation by the relevant domestic laws of the countries which are parties to them.

UK’s Merchant Shipping Act 1995, as amended (or the MSA), implements the CLC but uses a wider definition of a “ship” than the one used in the CLC and in its 1992 Protocol but still refers to the criteria used by the CLC. It is therefore doubtful that FPSOs fall within its wording. However, the MSA also includes separate provisions for liability for oil pollution otherwise than under the CLC (section 154 of Chapter III of Part VI of the MSA). 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 FPSOs. 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 FPSOs, 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 FPSOs 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 (or OPOL) 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 FPSOs, 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, FPSOs and FSUs. The IMO’s Marine Environment Protection Committee has issued guidelines for the application of MARPOL Annex I requirements (as revised from time to time) to FPSOs 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, regardless of fault or negligence. 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 has been implemented in the UK by the Environmental Damage (Prevention and Remediation) Regulations 2009.

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 UK 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 2009)) and the Offshore Installations (Offshore Safety Directive)(Safety Case etc.) Regulations 2015, both of which entered into force on 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.

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 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. 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 liability 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:

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natural resources damages and the related assessment costs;

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real and personal property damages;

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

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

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

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loss of subsistence use of natural resources.

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 vessel’s 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 United States Coast Guard (or 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 shipowner or operator 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:

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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”;

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describe crew training and drills; and

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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 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 current Vessel General Permit incorporates 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 drydocking after January 1, 2014 or January 1, 2016, depending on the vessel size. Vessels that are constructed after December 1, 2013 are subject to the ballast water numeric effluent limitations. 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.

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 195 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 deals with greenhouse gas emission reduction measures and targets from 2020 in order to limit the global temperature increases above pre-industrial levels to not more than 1.5 degrees Celsius. 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. Certain new IMO regulations for the reduction of greenhouse gas emissions became effective on January 1, 2013. The new technical and operational measures imposed by these new regulations include the “Energy Efficiency Design Index,” which is mandatory for newbuilding vessels, and the “Ship Energy Efficiency Management Plan,” which is mandatory for all vessels. In addition, the IMO is evaluating various mandatory measures to reduce greenhouse gas emissions from international shipping, which may include market-based instruments or a carbon tax. In October 2014, the IMO’s MEPC agreed in principle to develop a system of data collection regarding fuel consumption of ships. Work on the development of such a system continued during 2015. 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 recently adopted Regulation (EU) 2015/757 on the monitoring, reporting and verification of CO2 emissions from vessels (or MRV Regulation), which entered into force on July 1, 2015. The MRV Regulation is to generally apply to all vessels over 5,000 gross tonnage, irrespective of flag, in respect of CO2 emissions released during intra-EU voyages and EU incoming and outgoing voyages. The first reporting period will commence on January 1, 2018. The monitoring, reporting and verification system adopted by the MRV Regulation may be the precursor to a market-based mechanism to be adopted in the future. 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) and regularly exercise these plans to ensure efficient use and familiarity by all involved.

C. Organizational Structure

Our sole general partner is Teekay Offshore GP L.L.C., which is a wholly-owned indirect subsidiary of Teekay Corporation. Teekay Corporation also controls its other public subsidiaries Teekay LNG Partners L.P. (NYSE: TGP) and Teekay Tankers Ltd. (NYSE: TNK).

Please read Exhibit 8.1 to this Annual Report for a list of our significant subsidiaries as of December 31, 2015.

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 the provisions of the Internal Revenue Code of 1986, as amended (or the Code), legislative history, applicable U.S. Treasury Regulations (or Treasury Regulations), judicial authority and administrative interpretations, all as in effect on the date of this Annual Report, and which are subject to change, possibly with retroactive effect, or are subject to different interpretations. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

Election to be Taxed as a Corporation. We have elected to be taxed as a corporation for U.S. federal income tax purposes. As such, we are subject to U.S. federal income tax on our income to the extent it is from U.S. sources or otherwise is effectively connected with the conduct of a trade or business in the United States as discussed below.

Taxation of Operating Income. A significant portion of our gross income will be attributable to the transportation of crude oil and related products. For this purpose, gross income attributable to transportation (or Transportation Income) includes income derived from, or in connection with, the use (or hiring or leasing for use) of a vessel to transport cargo, or the performance of services directly related to the use of any vessel to transport cargo, and thus includes income from time charters, contracts of affreightment, bareboat charters, and voyage charters.

Fifty percent (50%) of Transportation Income attributable to transportation that either begins or ends, but that does not both begin and end, in the United States (or U.S. Source International Transportation Income) is considered to be derived from sources within the United States. Transportation Income attributable to transportation that both begins and ends in the United States (or U.S. Source Domestic Transportation Income) is considered to be 100% derived from sources within the United States. Transportation Income attributable to transportation exclusively between non-U.S. destinations is considered to be 100% derived from sources outside the United States. Transportation Income derived from sources outside the United States generally will not be subject to U.S. federal income tax.

Based on our current operations, a substantial portion of our Transportation Income is from sources outside the United States and not subject to U.S. federal income tax. In addition, we believe that we have not earned any U.S. Source Domestic Transportation Income, and we expect that we will not earn any such income in future years. However, certain of our activities give rise to U.S. Source International Transportation Income. Unless the exemption from U.S. taxation under Section 883 of the Code (or the Section 883 Exemption) applies, our U.S. Source International Transportation Income generally is subject to U.S. federal income taxation under either the net basis and branch profits taxes or the 4% gross basis tax, each of which is discussed below.

The Section 883 Exemption. In general, the Section 883 Exemption provides that if a non-U.S. corporation satisfies the requirements of Section 883 of the Code and the Treasury Regulations thereunder (or the Section 883 Regulations), it will not be subject to the net basis and branch profits taxes or the 4% gross basis tax described below on its U.S. Source International Transportation Income. The Section 883 Exemption does not apply to U.S. Source Domestic Transportation Income.

A non-U.S. corporation will qualify for the Section 883 Exemption if, among other things, it (i) is organized in a jurisdiction outside the United States that grants an exemption from tax to U.S. corporations on international Transportation Income (or an Equivalent Exemption), (ii) meets one of three ownership tests (or Ownership Tests) described in the Section 883 Regulations, and (iii) meets certain substantiation, reporting and other requirements (or the Substantiation Requirements).

We are organized under the laws of the Republic of The Marshall Islands. The U.S. Treasury Department has recognized the Republic of The Marshall Islands as a jurisdiction that grants an Equivalent Exemption. We also believe that we will be able to satisfy the Substantiation Requirements. However, we do not believe that we meet the Ownership Tests and therefore we will not qualify for the Section 883 Exemption and our U.S. Source International Transportation Income will not be exempt from U.S. federal income taxation.

The Net Basis and Branch Profits Taxes. If the Section 883 Exemption does not apply, our U.S. Source International Transportation Income may be treated as effectively connected with the conduct of a trade or business in the United States (or Effectively Connected Income) if we have a fixed place of business in the United States and substantially all of our U.S. Source International Transportation Income is attributable to regularly scheduled transportation or, in the case of income derived from bareboat charters, is attributable to a fixed place of business in the United States. Based on our current operations, none of our potential U.S. Source International Transportation Income is attributable to regularly scheduled transportation or is derived from bareboat charters attributable to a fixed place of business in the United States. As a result, we do not anticipate that any of our U.S. Source International Transportation Income will be treated as Effectively Connected Income. However, there is no assurance that we will not earn income pursuant to regularly scheduled transportation or bareboat charters attributable to a fixed place of business in the United States in the future, which would result in such income being treated as Effectively Connected Income. U.S. Source Domestic Transportation Income generally will be treated as Effectively Connected Income. However, we do not anticipate that any of our income has been or will be, U.S. Source Domestic Transportation Income.

Any income we earn that is treated as Effectively Connected Income would be subject to U.S. federal corporate income tax (the highest statutory rate currently is 35%) and a 30% branch profits tax imposed under Section 884 of the Code. In addition, a branch interest tax could be imposed on certain interest paid or deemed paid by us.

On the sale of a vessel that has produced Effectively Connected Income, we generally would be subject to the net basis and branch profits taxes with respect to our gain not in excess of certain prior deductions for depreciation that reduced Effectively Connected Income. Otherwise, we would not be subject to U.S. federal income tax with respect to gain realized on the sale of a vessel, provided the sale is considered to occur outside of the United States under U.S. federal income tax principles.

The 4% Gross Basis Tax. If the Section 883 Exemption does not apply and we are not subject to the net basis and branch profits taxes described above, we would be subject to a 4% U.S. federal income tax on our gross U.S. Source International Transportation Income, without benefit of deductions. For 2016, we estimate that the U.S. federal income tax on such U.S. Source International Transportation Income will be approximately $200,000 based on the amount of U.S. Source International Transportation Income we earned for 2015. 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.

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 or operations 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 Marshall Islands law. As a result, distributions by controlled affiliates to us are not subject to 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, but we do not expect any such tax to be material. However, we cannot assure this result as 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 appearing elsewhere in this report.

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

OVERVIEW

We are an international provider of marine transportation, oil production, storage, long-distance towing and offshore installation and maintenance and safety services to the offshore oil industry focusing on the deep-water offshore oil regions of the North Sea, Brazil and the East Coast of Canada. We operate shuttle tankers, floating production, storage and off-loading (or FPSO) units, floating storage and off-take (or FSO) units, units for maintenance and safety (or UMS), long-distance towing and offshore installation vessels and conventional crude oil tankers. As at December 31, 2015, our fleet consisted of 33 shuttle tankers (including three chartered-in vessels and one HiLoad Dynamic Positioning (or DP) unit), six FPSO units, seven FSO units, six long-distance towing and offshore installation vessels, one UMS and two conventional oil tankers, in which our interests range from 50% to 100%. We also have two FPSO upgrades or conversions scheduled for delivery in mid-2016 and early-2017, four long-haul towing and offshore installation vessel newbuildings scheduled for delivery in 2016, three newbuilding shuttle tankers scheduled for delivery in late-2017 to mid-2018 and two UMS newbuildings scheduled for delivery in late-2016 and mid-2019.

Our long-term growth strategy focuses on expanding our fleet of shuttle tankers and towing and offshore installation vessels, our FPSO and FSO units and our UMS under long-term, fixed-rate time charters and expanding into related offshore services. Over the long-term, we intend to continue our practice of primarily acquiring vessels as needed for approved projects only after the long-term charters for the projects have been awarded to us, rather than ordering vessels on a speculative basis. We seek to capitalize on opportunities in the offshore transportation, production and storage sectors by selectively targeting long-term, fixed-rate time charters. We have entered and may enter into joint ventures and partnerships with companies that may provide increased access to long-term, fixed-rate time charter opportunities or may engage in vessel or business acquisitions. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and its affiliates to pursue these growth opportunities in the offshore sectors and may consider other opportunities to which our competitive strengths are well suited. We have rights to participate in certain other FPSO, FSO and shuttle tanker opportunities provided by Teekay Corporation, Sevan Marine ASA (or Sevan) and Remora AS (or Remora). Our operating fleet primarily trades on medium to long-term, stable contracts and we are structured as a publicly-traded master limited partnership.

Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. We believe there is currently a dislocation in these markets relative to the stability of our businesses. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, 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, we have temporarily reduced our quarterly distributions on our common units and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and growing, supported by a large and well-diversified portfolio of fee-based contracts with high-quality counterparties.

In December 2015, we announced the temporary reduction in our quarterly cash distribution to $0.11 per common unit, commencing with the distribution for the fourth quarter of 2015, down from $0.56 per common unit for the third quarter of 2015.

In addition to its effect on the energy and capital markets, the decline in global crude oil prices may also result in our vessels being employed on customer contracts that are cancellable or 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 increase the efficiency of our business to ensure we are a cost-effective supplier in the offshore sector, as well as focusing on the redeployment of our assets that are scheduled to come off charter over the next few years.

SIGNIFICANT DEVELOPMENTS

Acquisition of Petrojarl Knarr FPSO

On July 1, 2015, we acquired from Teekay Corporation its 100% interest in Teekay Knarr AS and Knarr L.L.C. (the Knarr Companies), which own the Petrojarl Knarr FPSO unit, which operates on the Knarr Field in the North Sea under a six-year contract plus up to 14 one-year extension options with BG Norge Limited (or BG), which is now owned by Royal Dutch Shell Plc, for a purchase price of $529.4 million, consisting of a fully built-up cost of $1.26 billion and a working capital adjustment of $14.5 million, less assumed debt of $745.1 million. The purchase price was primarily financed with a $492.0 million convertible promissory note issued to Teekay, of which $300.0 million was converted into common units of Teekay Offshore on July 31, 2015 and $92.0 million was repaid during the third quarter of 2015. Of the remaining $37.4 million for the purchase price, $35.0 million was paid in cash by us to Teekay Corporation upon the acquisition of the Knarr Companies. Concurrently with the conversion of the promissory note, Teekay Corporation contributed $6.1 million to us to maintain its 2% general partner interest.

Delivery of UMS

In August 2014, we acquired Logitel Offshore Holding AS (Logitel), a Norway-based company focused on the high-end floating accommodation market and providing units for maintenance and safety. At the time of acquisition, Logitel was constructing three UMS newbuildings, based on the Sevan cylindrical hull design, at the COSCO (Nantong) Shipyard (COSCO) in China for a fully built-up cost of approximately $596 million, including $30.0 million from our assumption of Logitel’s obligations under a bond agreement from Sevan. We currently hold options to order up to an additional two units. Prior to the acquisition, Logitel secured a three-year fixed-rate charter contract with Petroleo Brasileiro S.A. (Petrobras) in Brazil for the first UMS, the Arendal Spirit, which commenced its three-year time-charter contract during the second quarter of 2015. We are currently negotiating a three-year contract extension with Petrobras in exchange for a reduction in the current charter rate. We financed the Arendal Spirit through long-term debt financing and our existing liquidity.

The two newbuildings are currently scheduled to deliver in late-2016 and, subject to our exercise of a deferred delivery option, mid-2019, respectively. We may decide to cancel or further defer the delivery of the second UMS as well as conclude on the deferral of, or cancel, the third UMS.

Commenced East Coast of Canada Contract

On June 1, 2015, we commenced 15-year contracts, plus extension options, with a group of oil companies to provide shuttle tanker services on the East Coast of Canada. These contracts were initially serviced by three third-party owned shuttle tankers already operating on the East Coast of Canada, which were in-chartered by us. We subsequently replaced one of these vessels with one of our existing shuttle tankers, the Navion Hispania, during the third quarter of 2015. In connection with these contracts, we have entered into shipbuilding contracts to construct three Suezmax-size, DP2 shuttle tanker newbuildings with a South Korean shipyard for a fully built-up cost of approximately $368 million. The three ordered vessels are scheduled to be delivered in the fourth quarter of 2017 through the first half of 2018.

Delivery of Towage Vessels

In late-October 2014, we, through our wholly-owned subsidiary ALP Maritime Services B.V. (or ALP), agreed to acquire six modern on-the-water long-distance towing and offshore installation vessels for approximately $222 million. The vessels were built between 2006 and 2010 and are all equipped with DP capabilities. We took delivery of all six vessels during 2015.

Petrojarl Varg contract

On November 19, 2015, we received a termination notice for the Petrojarl Varg FPSO charter contract from Repsol S.A. (Repsol), formerly Talisman Energy, based on a termination right that is specific to the Petrojarl Varg FPSO contract. Following discussions with Repsol, we expect the Petrojarl Varg FPSO to be redelivered to us in August 2016. We are currently pursuing various redeployment opportunities for the Petrojarl Varg FPSO, a unit which meets the strict Norwegian petroleum industry (NORSOK) standards.

Equity Issuances

In April 2015, we issued 5.0 million of our 8.50% Series B Cumulative Redeemable Preferred Units (or Series B Preferred Units) in a public offering for net proceeds of $120.8 million. We used the net proceeds for general partnership purposes, including the funding of newbuilding installments, capital conversion projects and vessel acquisitions.

In July 2015, we issued 10.4 million of our 8.60% Series C Cumulative Convertible Perpetual Preferred Units (or Series C Preferred Units) in a private placement for net proceeds of $249.8 million. We used the proceeds from the private placement to partially finance the acquisition of the Petrojarl Knarr FPSO unit from Teekay Corporation and the initial installments for the three shuttle tanker newbuildings for the East Coast of Canada contract.

Potential Additional Shuttle Tanker, FSO and FPSO Projects

Pursuant to an omnibus agreement that we entered into in connection with our initial public offering in December 2006, Teekay Corporation is obligated to offer to us its interest in certain shuttle tankers, FSO units and FPSO units Teekay Corporation owns or may acquire in the future, provided the vessels are servicing contracts with remaining durations of greater than three years. We may also acquire other vessels that Teekay Corporation may offer us from time to time and we intend to pursue direct acquisitions from third parties and new offshore projects.

Pursuant to the omnibus agreement and subsequent agreements, Teekay Corporation is obligated to offer to sell to us the Petrojarl Foinaven FPSO unit, an existing unit owned by Teekay Corporation and operating under a long-term contract in the North Sea, subject to approvals required from the charterer. The purchase price for the Petrojarl Foinaven would be based on its fair market value. Teekay Corporation owns two additional FPSO units, the Hummingbird Spirit FPSO and the Petrojarl Banff FPSO, which may also be offered to us in the future pursuant to the omnibus agreement.

In May 2011, Teekay Corporation entered into a joint venture agreement with Odebrecht Oil & Gas S.A. (or Odebrecht) to jointly pursue FPSO projects in Brazil. Odebrecht is a Brazil-based company that operates in the engineering and construction, petrochemical, bioenergy, energy, oil and gas, real estate and environmental engineering sectors, with over 180,000 employees and a presence in over 20 countries. Through the joint venture agreement, Odebrecht is a 50 percent partner with us in the Cidade de Itajai (or Itajai) FPSO unit and the Libra FPSO project.

Our Contracts and Charters

We generate revenues by charging customers for the transportation and storage of their crude oil using our vessels. Historically, these services generally have been provided under the following basic types of contractual relationships:

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Contracts of affreightment, whereby we carry an agreed quantity of cargo for a customer over a specified trade route within a given period of time;

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Time charters, whereby vessels which 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 inflation, interest rates or current market rates;

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Bareboat charters, whereby customers charter vessels for a fixed period of time at rates that are generally fixed, but the customers operate the vessels with their own crews; and

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Voyage charters, which are charters for shorter intervals that are priced on a current, or “spot,” market rate.

We also generate revenues by charging customers for production, processing and storage services to oil companies operating offshore oil field installations. These services are typically provided under long-term, fixed-rate FPSO contracts, which may contain a variable component for incentive-based revenues dependent upon operating performance.

In addition, we generate revenues by charging customers 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, FLNG units and floating drill rigs. These services are typically provided under mid-term, fixed-rate time-charter contracts, which may contain a variable component for inflation.

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 contracts of affreightment, time charters, bareboat charters, voyage charters, FPSO contracts and UMS contracts. Revenues are affected by hire rates and the number of days a vessel operates and the daily production volume on FPSO units. Revenues are also affected by the mix of business between contracts of affreightment, time charters, bareboat charters, voyage charters, FPSO contracts and UMS contracts. 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 voyage charters and contracts of affreightment. When we pay voyage expenses, they typically are 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 provides more meaningful information to us about the deployment of our vessels and their performance 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. We are taking steps to maintain these expenses at a stable level, but expect an increase in line with inflation in respect of crew, material, and maintenance costs. 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.

Income from Vessel Operations. To assist us in evaluating operations by segment, we sometimes analyze the income we receive from each segment after deducting operating expenses, but prior to the deduction of interest expense, income taxes, realized and unrealized (losses) gains on non-designated derivative instruments, equity income, foreign currency exchange losses and other income.

Dry docking. We must periodically dry dock our shuttle tankers, conventional oil tankers and towage vessels for inspection, repairs and maintenance and any modifications to comply with industry certification or governmental requirements. We may dry dock FSO units if we desire to qualify them for shipping classification. Generally, we dry dock each of our 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. We expense costs related to routine repairs and maintenance performed during dry docking that do not improve or extend the useful lives of the assets, and for annual class survey costs on our FPSO units or 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:

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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;

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charges related to the amortization of dry-docking expenditures over the estimated useful life of the dry docking; and

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charges related to the amortization of the fair value of contracts of affreightment where amounts have been attributed to those items in acquisitions; these amounts are amortized over the period in which the asset is expected to contribute to future cash flows.

Revenue Days. Revenue days are the total number of calendar days our vessels were in our possession during a period, less the total number of off-hire days during the period associated with major repairs or dry dockings. Consequently, revenue days represent the total number of days available for the vessel to earn revenue. Idle days, which are days when the vessel is available to earn revenue, yet is not employed, are included in revenue days. We use revenue days in our explanations of net revenues between periods.

Calendar-Ship-Days. Calendar-ship-days are equal to 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%, 67% and 89% owned subsidiaries.

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:

•

Our financial results reflect the results of the interests in vessels acquired from Teekay Corporation for all periods the vessels were under common control. In May 2013, we acquired the Voyageur Spirit FPSO unit. In July 2015, we acquired the Petrojarl Knarr FPSO unit. These transactions were deemed to be business acquisitions between entities under common control. Accordingly, we have accounted for these transactions in a manner similar to the pooling of interests method. Under this method of accounting, our financial statements prior to the date the interests in these vessels were actually acquired by us are retroactively adjusted to include the results of these acquired vessels. The period retroactively adjusted includes all periods that we and the acquired vessels were both under common control of Teekay Corporation and had begun operations. As a result, our applicable consolidated financial statements reflect the vessels and their results of operations, referred to herein as the Dropdown Predecessor, as if we had acquired them when the vessels began operations under the ownership of Teekay Corporation on April 13, 2013 and March 9, 2015, respectively. Please read Item 18 – Financial Statements: Note 3 – Dropdown Predecessor.

•

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 , as well as our entry into new markets, such as our recent entries into the UMS and towage markets. 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.

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The decline in global crude oil prices is expected to result in a reduction in our operating expenses. With cost-saving initiatives implemented across the offshore industry, we expect to see a reduction in our operating expenses, in particular the cost of services and spares and crewing costs. There is a general understanding with our suppliers to focus on cost-saving initiatives to support the lower global crude oil prices and with labor unions that there will likely be minimal or no short-term salary increases in the near term.

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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, due to and from affiliates, long-term debt and deferred income taxes) are revalued and reported based on the prevailing exchange rate at the end of the period. We have entered into services agreements with subsidiaries of Teekay Corporation whereby the subsidiaries operate and crew the vessels. Payments under the service agreements are adjusted to reflect any change in Teekay Corporation’s cost of providing services based on fluctuations in the value of the Norwegian Kroner relative to the U.S. Dollar, which may result in increased or decreased payments under the services agreements if the strength of the U.S. Dollar declines or increases, respectively, relative to the Norwegian Kroner.

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Our financial results are affected by fluctuations in the fair value of our derivatives instruments. The change in fair value of our interest rate swaps, cross currency swaps and foreign currency forward contracts are included in our net income as the majority of our derivative instruments are not designated as hedges for accounting purposes. Although we believe that these non-designated derivative instruments are economic hedges, the changes in their fair value are included in our statements of income as unrealized gains or losses on derivatives for interest rate swaps and foreign currency forward contracts and as foreign exchange losses for the cross currency swaps. The unrealized gains or losses relating to changes in fair value of our derivative instruments do not affect our consolidated cash flows, liquidity or cash distributions to partners.

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Our operations are seasonal and our financial results vary as a consequence of dry dockings. Historically, the utilization of shuttle tankers in the North Sea is higher in the winter months, as favorable weather conditions in the warmer months provide opportunities for repairs and maintenance to our vessels 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. Six shuttle tankers are scheduled for dry docking in 2016. From time to time, unscheduled dry dockings may cause additional fluctuations in our financial results.

We manage our business and analyze and report our results of operations on the basis of our six business segments: the shuttle tanker segment, the FPSO segment, the FSO segment, the conventional tanker segment, the towage segment, and the UMS segment, each of which are discussed below.

Results of Operations

Year Ended December 31, 2015 versus Year Ended December 31, 2014

Shuttle Tanker Segment

As at December 31, 2015, our shuttle tanker fleet consisted of 31 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, three shuttle tanker newbuildings, and one shuttle tanker and the HiLoad DP unit in lay-up. Of these 36 shuttle tankers, six were owned through 50%-owned subsidiaries, one through a 67%-owned subsidiary and three were chartered-in. The remaining vessels are owned 100% by us. In January 2016, we sold a 1992-built shuttle tanker, the Navion Torinita, which was in lay-up and classified as held for sale on our consolidated balance sheet as of December 31, 2015. All of our operating shuttle tankers, with the exception of 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. We commenced the FSO conversion of the Randgrid shuttle tanker during the second quarter of 2015 and the vessel has been included in our FSO segment since June 9, 2015. We sold the Navion Norvegia to our 50/50 joint venture with Odebrecht in the fourth quarter of 2014 and the vessel is currently undergoing conversion into an FPSO unit for operation in the Libra oil field in Brazil. During the first quarter of 2015, we sold the Navion Svenita. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner, Euro and Brazilian Real may result in significant decreases or increases, respectively, in our vessel operating expenses.

The following table presents our shuttle tanker segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for our shuttle tanker segment:


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		541,792			577,064			(6.1	)
Voyage expenses		(82,777	)		(105,562	)		(21.6	)

Net revenues		459,015			471,502			(2.6	)
Vessel operating expenses		(128,156	)		(159,438	)		(19.6	)
Time-charter hire expense		(51,088	)		(31,090	)		64.3
Depreciation and amortization		(106,190	)		(110,686	)		(4.1	)
General and administrative⁽¹⁾		(22,884	)		(29,154	)		(21.5	)
(Write down) and gain on sale of vessels		(65,101	)		(1,638	)		3,874.4
Restructuring (charge) recovery		(568	)		225			(352.4	)

Income from vessel operations		85,028			139,721			(39.1	)


Calendar-Ship-Days
Owned Vessels		11,191			11,870			(5.7	)
Chartered-in Vessels		1,128			802			40.6

Total		12,319			12,672			(2.8	)

(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.

The average size of our owned shuttle tanker fleet decreased in 2015 compared to 2014, primarily due to the sale of the Navion Norvegia and the Navion Svenita in October 2014 and March 2015, respectively, and the commencement of the FSO conversion of the Randgrid in June 2015, partially offset by the delivery of the HiLoad DP unit in April 2014. Three shuttle tanker newbuildings have been excluded from calendar-ship-days until they are delivered to us.

The average size of our chartered-in shuttle tanker fleet increased in 2015 compared to 2014, primarily due to the in-chartering of three shuttle tankers, the Jasmine Knutsen, the Heather Knutsen, and the Mattea for the East Coast of Canada contract, which commenced in June 2015, partially offset by redeliveries to their owners of the Grena Knutsen in June 2015 and the Karen Knutsen in January 2014, decreased spot in-chartering of shuttle tankers, and the replacement of the Mattea by one of our owned shuttle tankers in September 2015.

Net Revenues. Net revenues decreased for 2015 from 2014, primarily due to:

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a decrease of $31.3 million relating to the expiration of a long-term contract at the Heidrun field serviced by our contracts of affreightment fleet;

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a decrease of $18.4 million due to the redelivery of two vessels to us in February 2014 and April 2015 as they completed their time-charter-out agreements; and

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a decrease of $14.1 million due to the sale of the Navion Svenita in March 2015;

partially offset by

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an increase of $35.3 million due to an increase in net revenues from the commencement of the East Coast of Canada contract in June 2015;

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an increase of $8.0 million in revenues from our contract of affreightment fleet due to higher average rates, an increase in rates as provided in certain contracts in our time-chartered-out fleet, and increase in revenues from the commencement of new contracts in mid-2015;

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an increase of $3.7 million due to higher average rates earned when trading excess shuttle tanker capacity in the conventional tanker spot market, offset by fewer conventional spot days;

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an increase of $2.9 million due to fewer repair off-hire days in our time-chartered-out fleet compared to 2014; and

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an increase of $1.7 million due to an increase in reimbursable bunker, crewing and dry-docking expenses.

Vessel Operating Expenses. Vessel operating expenses decreased for 2015 from 2014, primarily due to:

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a decrease of $14.3 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Euro and Brazilian Real;

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a decrease of $6.0 million due to the sales of the Navion Norvegia and the Navion Svenita in October 2014 and March 2015, respectively;

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a decrease of $4.9 million relating to the HiLoad DP unit mainly for mobilization expenses in 2014;

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a decrease of $3.7 million due to the commencement of the FSO conversion of the Randgrid in June 2015; and

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a decrease of $2.1 million due to a decrease in repairs and maintenance expenses compared to 2014, a decrease in crew costs compared to 2014 due to a change in crew composition, partially offset by an increase in crew training expenses compared to 2014.

Time-Charter Hire Expense. Time-charter hire expense increased for 2015 from 2014, primarily due to:

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an increase of $28.8 million due to the in-chartering of the three shuttle tankers for the East Coast of Canada contract, which commenced in June 2015 (one of these vessels was replaced by one of our owned vessels in September 2015); and

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an increase of $2.4 million primarily due to the drydocking and offhire of the Sallie Knutsen during the first and second quarters of 2014 and the drydocking of the Aberdeen during the second quarter of 2014;

partially offset by

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a decrease of $7.2 million due to the redelivery by us of the Karen Knutsen in January 2014 and the Grena Knutsen in June 2015;

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a decrease of $2.5 million due to decreased spot in-chartering of shuttle tankers; and

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a decrease of $1.3 million due to lower time-charter hire rates on the Aberdeen and an increase in off-hire during the third quarter of 2015.

Depreciation and Amortization. Depreciation and amortization expense decreased for 2015 from 2014, primarily due to:

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a decrease of $5.0 million due to the commencement of the FSO conversion of the Randgrid in the June 2015;

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a decrease of $2.1 million due to the Navion Europa being fully amortized during the second quarter of 2015;

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a decrease of $2.0 million due to the sale of the Navion Norvegia and the Navion Svenita in October 2014 and March 2015, respectively; and

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a decrease of $1.0 million due to lower vessel contract amortization expense;

partially offset by

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an increase of $3.0 million due to the dry docking of eight shuttle tankers from mid-2014 to late-2015; and

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an increase of $2.7 million due to the commencement of depreciation on the HiLoad DP unit in January 2015.

(Write-down) and gain on sale of vessels. (Write-down) and gain on sale of vessels was ($65.1) million for 2015 which consisted of a write-down of vessels of $66.7 million offset by a gain on sale of a vessel of $1.6 million. During 2015, the carrying values of seven of our 1990s-built shuttle tankers were written down to their estimated fair values using appraised values. Of the seven vessels, two of the vessels were written down during the first quarter of 2015 as a result of the expected sale of a vessel and a change in the operating plan of a vessel. In the fourth quarter of 2015, the write-down of five shuttle tankers, which have an average age of 17.5 years, was the result of changes in our expectations of their future opportunities, primarily due to their advanced age. While we expect four of the five vessels to continue to actively trade as shuttle tankers over the near-term and the fifth vessel to actively trade in the conventional tanker market, we anticipate fewer opportunities for alternative usage and increased age discrimination over time. In 2015, we sold a 1997-built shuttle tanker, the Navion Svenita, to a third party resulting in a gain on the sale of the vessel of $1.6 million.

(Write-down) and gain on sale of vessels was ($1.6) million for 2014 which consisted of a write-down of a vessel of $4.8 million and a gain on the sale of a vessel of $3.1 million. In the third quarter of 2014, the carrying value of one of our 1990s-built shuttle tanker was written down to its estimated fair value, using an appraised value. The write-down was the result of the vessel charter contract expiring in early-2015 and the expected sale of the vessel. In October 2014, a 1995-built shuttle tanker, the Navion Norvegia, was sold to our 50/50 joint venture with Odebrecht. The proceeds from the sale of the vessel were $13.4 million, which included $0.4 million for bunkers on-board at the time of sale. The net book value of the vessel at the time of sale was $6.8 million. As the vessel was sold to our 50/50 joint venture with Odebrecht, we deferred 50% of the gain on sale of the vessel. The vessel is undergoing conversion to a new FPSO unit for the Libra field.

Restructuring Recovery (Charge). Restructuring charge for 2015 was ($0.6) million relating to a reduction in fleet size.

Restructuring recovery for 2014 was $0.2 million relating to a $0.8 million reimbursement received relating to the reorganization of our shuttle tanker marine operations, partially offset by a $0.6 million charge relating to the reflagging of one shuttle tanker.

FPSO Segment

As at December 31, 2015, our FPSO fleet consisted of the Petrojarl Varg, the Cidade de Rio das Ostras (or Rio das Ostras), the Piranema Spirit, the Voyageur Spirit, the Petrojarl I, and the Petrojarl Knarr FPSO units, all of which we own 100%, and the Itajai and the Libra FPSO units, of which we own 50%. In October 2014, we sold a 1995-built shuttle tanker, the Navion Norvegia, to our 50/50 joint venture with Odebrecht and the vessel currently is undergoing conversion into an FPSO unit for the Libra field located in the Santos Basin offshore Brazil and is scheduled to commence operations in early-2017. We acquired the Petrojarl I FPSO unit from Teekay Corporation in December 2014. The unit is currently undergoing upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard in the Netherlands. We acquired the Petrojarl Knarr FPSO unit from Teekay Corporation in July 2015. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner, Brazilian Real, and British Pound may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

We use the FPSO units to provide production, processing and storage services to oil companies operating offshore oil field installations. These services are typically provided under long-term, fixed-rate FPSO contracts, some of which also include certain incentive compensation or penalties based on the level of oil production and other operational measures. Historically, the utilization of FPSO units and other vessels in the North Sea, where the Petrojarl Varg, Voyageur Spirit and Petrojarl Knarr operate, is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our vessels and the offshore oil platforms, which generally reduces oil production.

On April 13, 2013, the Voyageur Spirit FPSO unit began production and on May 2, 2013, we acquired the unit from Teekay Corporation. Upon commencing production, we had a specified time period to receive final acceptance from E.ON Ruhrgas UK GP (or E.ON), the charterer; however, due to a defect encountered in one of its two gas compressors, the FPSO unit was unable to achieve final acceptance within the allowable timeframe resulting in the FPSO unit being declared off-hire by the charterer retroactive to April 13, 2013.

On August 27, 2013, repairs to the defective gas compressor on the Voyageur Spirit FPSO unit were completed and the unit achieved full production capacity. We entered into an interim agreement with E.ON, whereby we were compensated for production beginning August 27, 2013 until final acceptance on February 22, 2014.

Until the Voyageur Spirit FPSO unit was declared on hire, Teekay Corporation indemnified us for certain production shortfalls and unreimbursed vessel operating expenses. For the period from April 13, 2013 to December 31, 2013, Teekay Corporation indemnified us for a total of $34.9 million for production shortfalls and unreimbursed repair costs. For the three months ended March 31, 2014, Teekay Corporation indemnified us for an additional $3.5 million for production shortfalls and unreimbursed repair costs. Amounts paid as indemnification from Teekay Corporation to us were treated as a reduction in the purchase price we paid for the FPSO unit.

The following table presents our FPSO segment’s operating results for 2015 and 2014, and also provides a summary of the calendar-ship-days for our FPSO segment. The table excludes the results of the Itajai and the Libra FPSO units, which are accounted for under the equity method.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		531,554			354,518			49.9
Vessel operating expenses		(189,900	)		(158,216	)		20.0
Depreciation and amortization		(137,914	)		(72,905	)		89.2
General and administrative⁽¹⁾		(38,588	)		(27,406	)		40.8

Income from vessel operations		165,152			95,991			72.0


Calendar-Ship-Days
Owned Vessels		2,009			1,476			36.1

(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. 2015 includes a business development fee of $9.7 million to Teekay Corporation related to the acquisition of the Petrojarl Knarr FPSO unit.

The average number of our FPSO units increased in 2015 compared to 2014, due to the acquisitions of the Petrojarl Knarr on July 1, 2015 and the Petrojarl I on December 15, 2014. No earnings are expected from the Petrojarl I until its upgrades are completed, which is scheduled for mid-2016. The unit is scheduled to commence operations in the second half of 2016 under a five-year fixed-rate charter contract with Queiroz Galvão Exploração e Produção SA (or QGEP) on the Atlanta field offshore from Brazil.

As a result of the inclusion of the Dropdown Predecessor, the financial results of the Petrojarl Knarr FPSO unit have been included in our financial results as if it was acquired when the unit commenced operations under the control of Teekay Corporation on March 9, 2015.

Revenues. Revenues increased for 2015 from 2014, primarily due to:

•

an increase of $182.0 million due to the acquisition of the Petrojarl Knarr FPSO unit in 2015;

•

an increase of $13.5 million on the Voyageur Spirit, primarily due to the charterer’s final acceptance of the charter contract on February 22, 2014, a production bonus earned in 2015 and a production penalty in 2014;

•

an increase of $3.7 million on the Petrojarl Varg, due to an increase in crew hours reimbursed by the charterer during 2015;

•

an increase of $3.6 million relating to revenue received for offshore field studies associated with the Petrojarl Varg (this revenue is offset by operating expenditures incurred – see below); and

•

an increase of $2.4 million due to the commencement of operations of a produced water treatment plant on the Piranema Spirit in the second quarter of 2014;

partially offset by

•

a decrease of $11.0 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Brazilian Real compared to the same periods last year on revenues related to the Petrojarl Varg and the Piranema Spirit, respectively (however, these decreases are offset by similar foreign-exchange related decreases in vessel operating expenses);

•

a decrease of $7.8 million due to unscheduled off-hire of the Piranema Spirit for repairs during the third and fourth quarters of 2015;

•

a decrease of $4.7 million due to the settlement of reimbursable expenses for the Voyageur Spirit FPSO unit during 2014;

•

a decrease of $2.9 million due to decreases in incentive compensation from the Petrojarl Varg during 2015; and

•

a decrease of $2.0 million primarily due to a decrease in the credit earned from the charterer of the unit for unused maintenance days under the service contract in 2015 from 2014 and a retroactive increase in rates on the Rio das Ostras in accordance with the annual contractual escalation adjustment recorded in the fourth quarter of 2014.

In connection with the sale and purchase agreement, Teekay Corporation indemnified us for lost revenue and unreimbursed repair costs from the Voyageur Spirit being off-hire since the unit began operations on April 13, 2013 until February 21, 2014. The indemnification amounts relating to lost revenue were $3.1 million and $31.3 million for 2014 and 2013, respectively. The indemnification amounts relating to unreimbursed repair costs were $0.4 million and $3.6 million for 2014 and 2013, respectively. These have been recorded in equity as an adjustment to the purchase price we paid for the FPSO unit.

Vessel Operating Expenses. Vessel operating expenses increased for 2015 from 2014, primarily due to:

•

an increase of $56.8 million due to the acquisition of the Petrojarl Knarr FPSO unit in 2015;

•

an increase of $7.7 million due to higher repair and maintenance costs on the Piranema Spirit due to unscheduled off-hires during the third and fourth quarters of 2015 and the timing of repair and maintenance costs; and

•

an increase of $4.0 million due to expenditures incurred on offshore field studies for the Petrojarl Varg during 2015;

partially offset by

•

a decrease of $27.2 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Brazilian Real and British Pound;

•

a decrease of $3.3 million due to the timing of costs related to repair and maintenance on the Voyageur Spirit, the Petrojarl Varg and the Rio das Ostras FPSO units;

•

a decrease of $3.0 million due to a reversal of an agency fee accrual relating to the Piranema Spirit during 2015, which we no longer consider payable;

•

a decrease of $2.2 million due to lower ship management costs related to operating the FPSO units; and

•

a decrease of $1.6 million due to external consulting fees incurred during the first quarter of 2014 to achieve final acceptance for the Voyageur Spirit FPSO unit.

Depreciation and Amortization Expense. Depreciation and amortization expense increased for 2015 from 2014, primarily due to the acquisitions of the Petrojarl Knarr on July 1, 2015 and the Petrojarl I on December 15, 2014.

FSO Segment

As at December 31, 2015, our FSO fleet consisted of six units that operate under fixed-rate time charters or fixed-rate bareboat charters, in which our ownership interests ranged from 89% to 100%, and one shuttle tanker, the Randgrid, currently undergoing conversion into an FSO unit, in which our ownership interest increased from 67% to 100% during the third quarter of 2015. We commenced the FSO conversion of the Randgrid during the second quarter of 2015 and the vessel has been included in our FSO segment since June 9, 2015. 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 Norwegian Kroner and Australian Dollars for certain vessels. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner or Australian Dollar may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

The following table presents our FSO segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days for our FSO segment:


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		57,391			53,868			6.5
Voyage expenses		(851	)		(1,500	)		(43.3	)

Net revenues		56,540			52,368			8.0
Vessel operating expenses		(26,394	)		(28,649	)		(7.9	)
Depreciation and amortization		(11,775	)		(8,282	)		42.2
General and administrative⁽¹⁾		(1,372	)		(3,870	)		(64.5	)

Income from vessel operations		16,999			11,567			47.0


Calendar-Ship-Days
Owned Vessels		2,395			2,190			9.4

(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.

The average number of our FSO units increased for 2015 compared to 2014, due to the commencement of the FSO conversion of the Randgrid on June 9, 2015. No earnings are expected from the Randgrid until its conversion is completed in early-2017, when the unit is scheduled to commence operations under a three-year time-charter contract with Statoil ASA (or Statoil), which includes 12 additional one-year extension options.

Net Revenues. Net revenues increased for 2015 from 2014, primarily due to:

•

an increase of $5.5 million due to the commencement of the Suksan Salamander FSO on its bareboat charter in the third quarter of 2014;

•

an increase of $2.4 million due to the drydocking of the Navion Saga during the third quarter of 2014; and

•

an increase of $2.0 million primarily due to the drydocking of the Dampier Spirit during the second quarter of 2014;

partially offset by

•

a decrease of $3.7 million primarily due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Australian Dollar;

•

a decrease of $1.3 million due to a contract extension in April 2014 for the Pattani Spirit at a lower charter rate for an additional five years; and

•

a decrease of $0.8 million due to reduced rates on the Falcon Spirit.

Vessel Operating Expenses. Vessel operating expenses decreased for 2015 from 2014, primarily due to:

•

a decrease of $3.6 million mainly from lower crew costs on the Navion Saga and the Dampier Spirit due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Australian Dollar;

partially offset by

•

an increase of $1.0 million due to the amortization of mobilization costs on the Suksan Salamander FSO commencing in the third quarter of 2014; and

•

an increase of $0.5 million due to lower crew costs for the Navion Saga in 2014 mainly relating to a pension adjustment recorded in the first quarter of 2014.

Depreciation and amortization. Depreciation and amortization expense increased for 2015 from 2014, primarily due the delivery of the Suksan Salamander FSO in August 2014 and an increase in drydock depreciation for the Navion Saga due its drydocking in the third quarter of 2014.

Conventional Tanker Segment

As at December 31, 2015, we owned 100% interests in two Aframax conventional crude oil tankers, the Kilimanajro Spirit, which operates under a fixed-rate time charter with Teekay Corporation, and the Fuji Spirit, which operates in the spot conventional tanker market. Both of these vessels were classified as held for sale as at December 31, 2015. As part of the sale of Fuji Spirit and Kilimanjaro Spirit in March 2016, we are in-chartering these vessels for three years each, both with an additional one-year extension option. One vessel is fixed on a two-year time-charter-out contract and the other vessel is trading in the spot conventional tanker market.

In December 2015, we terminated the time-charter contract of the Fuji Spirit with a subsidiary of Teekay Corporation and received an early termination fee of $4.7 million from Teekay Corporation.

In December 2015, we terminated the long-term bareboat contracts for the SPT Explorer and the Navigator Spirit conventional tankers with Teekay Corporation and paid early termination fees of $6.5 million to Teekay Corporation. Immediately following the contract terminations, we sold our 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd.

The following table presents our conventional tanker segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days by owned vessels for our conventional tanker segment.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		30,230			33,566			(9.9	)
Voyage expenses		(2,326	)		(5,373	)		(56.7	)

Net revenues		27,904			28,193			(1.0	)
Vessel operating expenses		(6,234	)		(5,906	)		5.6
Depreciation and amortization		(6,583	)		(6,680	)		(1.5	)
General and administrative⁽¹⁾		(1,062	)		(2,136	)		(50.3	)
Write down of vessels		(3,897	)		—			100.0

Income from vessel operations		10,128			13,471			(24.8	)


Calendar-Ship-Days
Owned Vessels		1,432			1,460			(1.9	)

(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.

The average number of our conventional tankers decreased in 2015 compared to 2014, due to the sales of the SPT Explorer and the Navigator Spirit conventional tankers in December 2015.

Net Revenues. Net revenues decreased for 2015 from 2014, primarily due to:

•

a decrease of $1.8 million due to net termination fees paid to Teekay Corporation in relation to the early terminations of bareboat and time-charter contracts with a subsidiary of Teekay Corporation for the SPT Explorer, Navigator Spirit and Fuji Spirit in December 2015; and

•

a decrease of $0.4 million due to the sales of the SPT Explorer and Navigator Spirit in December 2015;

partially offset by:

•

an increase of $1.0 million due to a higher amount of reimbursed bunkers in 2015 compared to 2014; and

•

an increase of $0.9 million due to the scheduled drydocking of the Kilimanjaro Spirit during the third quarter of 2014.

Write down of vessels. Write down of vessels was $3.9 million for 2015. During 2015, the carrying value of the Kilimanjaro Spirit and Fuji Spirit were written down to their estimated fair values using appraised values. The write-downs were the result of the expected sales of these two vessels and both vessels were classified as held for sale on the Partnership’s consolidated balance sheet as of December 31, 2015.

Towage Segment

As at December 31, 2015, our towage vessel fleet consisted of six long-distance towing and offshore installation vessels and four ultra-long distance towing and offshore installation vessel newbuildings, which are scheduled to deliver during 2016. We own a 100% interest in each of the vessels in our towage fleet.

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

The following table presents our towage segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for our towage segment. We did not operate any of these vessels during 2014 and our operating results for the segment in 2014 consisted mainly of general and administrative expenses of $4.3 million.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		40,112			523			7,569.6
Voyage expenses		(12,052	)		(105	)		11,378.1

Net revenues		28,060			418			6,612.9
Vessel operating expenses		(13,920	)		—			100.0
Time-charter hire expense		(662	)		—			100.0
Depreciation and amortization		(8,362	)		—			100.0
General and administrative⁽¹⁾		(4,598	)		(4,328	)		6.2

Income (loss) from vessel operations		518			(3,910	)		(113.2	)


Calendar-Ship-Days
Owned Vessels		1,587			—			100.0
Chartered-in Vessels		19			—			100.0

(1)

Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the towage segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.2 million to Teekay Corporation related to the acquisition of the six towing and offshore installation vessels. General and administrative expenses for the year ended December 31, 2014 includes business development fees of $2.6 million relating to the acquisition of ALP.

The average number of our towing and offshore installation vessels increased for 2015 compared to 2014, due to the delivery of the six towing and offshore installation vessels during 2015.

Income (loss) from vessel operations. Income from vessel operations increased for 2015 compared to 2014, primarily due to the delivery of the six towing and offshore installation vessels throughout the first seven months of 2015.

UMS Segment

As at December 31, 2015, our UMS fleet consisted of one operational unit, the Arendal Spirit, and two newbuildings. During the second quarter of 2015, we exercised our options to defer the delivery of our second UMS newbuilding by up to one year, and the delivery and all related construction work of our third UMS by 120 days, and may decide to defer the delivery of the third UMS by an additional two years. These two newbuildings are currently scheduled to deliver in late-2016 and, subject to our exercise of a deferred delivery option, mid-2019, respectively unless we decide to cancel the newbuilding contracts. We own a 100% interest in all three units.

The UMS fleet 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, FLNG units and floating drill rigs. Our UMS fleet is available for world-wide operations, excluding operations within the Norwegian Continental Shelf, and includes DP3 keeping systems that are capable of operating in deep water and harsh weather.

The following table presents our UMS segment’s operating results and calendar-ship-days for 2015 and 2014. We had no operations during 2014 and therefore no revenues or expenditures incurred for the segment for 2014, with the exception of acquisition costs presented as general and administrative expenses. The Arendal Spirit delivered to us on February 16, 2015 and began its three year charter contract on June 7, 2015. We are currently negotiating a three-year contract extension with the charterer in exchange for a reduction in the current charter rate.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2015			2014			% Change

Revenues		28,334			—			100.0
Vessel operating expenses		(13,876	)		—			100.0
Depreciation and amortization		(3,775	)		—			100.0
General and administrative⁽¹⁾		(4,109	)		(622	)		560.6
Write-down of vessel		(1,000	)		—			100.0

Income (loss) from vessel operations		5,574			(622	)		(996.1	)


Calendar-Ship-Days
Owned Vessels		318			—			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. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.0 million paid to Teekay Corporation related to the delivery of the Arendal Spirit UMS.

The average number of our operating units increased for 2015 compared to 2014, due to the delivery of the Arendal Spirit in February 2015.

Income from vessel operations. Income from vessel operations increased for 2015 compared to 2014, primarily due to the commencement of the charter contract of the Arendal Spirit in June 2015, partially offset by write-downs relating to two options to purchase two additional units, which expired during 2015.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased to $72.6 million for 2015, from $67.5 million for 2014. The increase was due to business development fees to Teekay Corporation of $9.7 million, $2.2 million and $2.0 million, respectively, in connection with the acquisition of the Petrojarl Knarr FPSO unit, six long-distance towing and offshore installation vessels, and the Arendal Spirit UMS recorded in the third quarter of 2015, an increase in general and administrative costs due to the acquisition of the Petrojarl Knarr FPSO unit in July 2015, the acquisition of Logitel during the third quarter of 2014, the commencement of the charter contract of the Arendal Spirit in June 2015, the commencement of the East Coast of Canada contract in June 2015 and an increase in services provided to us from Teekay Corporation as a result of our growth, partially offset by a decrease due to the strengthening of the U.S. Dollar compared to the same periods last year, a $2.1 million business development fee paid to Teekay Corporation in relation to the acquisition of the Petrojarl I FPSO unit during the fourth quarter of 2014, a $1.6 million business development fee paid to Teekay Corporation in relation to the acquisition of ALP during the second quarter of 2014, a $1.0 million acquisition fee to a third party relating to the acquisition of ALP during the first quarter of 2014, a decrease in management fees relating to our FPSO fleet primarily from our focus on obtaining final charter contract acceptance for the Voyageur Spirit in the first quarter of 2014 and a decrease in management fees relating to our shuttle tanker segment primarily from our cost saving initiatives.

Interest Expense. Interest expense increased to $122.8 million for 2015, from $88.4 million for 2014, primarily due to:

•

an increase of $26.7 million due to our assumption of debt related to the acquisition of the Petrojarl Knarr FPSO unit;

•

an increase of $17.0 million due to the borrowings and loan costs relating to the Suksan Salamander FSO unit (which commenced operations during the third quarter of 2014), the six towing vessels (which delivered throughout the first seven months of 2015), the Arendal Spirit UMS (which commenced operations during the second quarter of 2015) and the $300 million of senior unsecured bonds we issued in May 2014; and

•

an increase of $1.1 million due to the ineffective portion of unrealized losses incurred on interest rate swaps designated as cash flow hedges during 2015 for the towage newbuildings;

partially offset by

•

a decrease of $7.0 million relating to lower interest expense on our Norwegian Kroner (or NOK) bonds as a result of the depreciation of the NOK against the U.S. Dollar and a decrease in NIBOR; however, this decrease was offset by an increase in realized losses on cross currency swaps related to our NOK senior unsecured bonds, which losses are included in foreign currency exchange losses;

•

a decrease of $2.0 million due to an increase in capitalized interest on our newbuildings; and

•

a net decrease of $1.3 million due to lower debt balances, partially offset by higher interest rates on existing debt facilities compared to 2014.

Realized and Unrealized Losses on Derivative Instruments. Net realized and unrealized losses on non-designated derivative instruments were $73.7 million for 2015, compared to $143.7 million for 2014.

During 2015 and 2014, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $2.0 billion and $1.7 billion, respectively, and average fixed rates of approximately 3.2% and 3.6%, respectively. Short-term variable benchmark interest rates during these periods were generally 0.8% or less and, as such, we incurred realized losses of $60.7 million and $55.6 million during 2015 and 2014, respectively, under the interest rate swap agreements.

In addition, we incurred realized losses of $10.9 million during 2015 as a result of an early termination of an interest rate swap.

During 2015 and 2014, we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures in Norwegian Kroner. Additionally, during 2015 we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures denominated in Euro and Singapore Dollars.

The $70.0 million decrease in net realized and unrealized losses for 2015 was primarily due to higher current LIBOR interest rates compared to 2014, and a $87.8 million decrease in unrealized losses on interest rate swaps relating to a smaller decrease in long-term LIBOR benchmark interest rates as at December 31, 2015 relative to the beginning of 2015, compared to the decrease as at December 31, 2014 relative to the beginning of 2014, partially offset by a $10.9 million realized loss due to the early termination of an interest rate swap during 2015, a $5.2 million increase in realized losses on interest rate swaps due to a higher outstanding notional amount of interest rate swap agreements compared to last year and the transfer of previously recognized unrealized losses to realized losses on the interest rate swaps in 2015 related to actual cash settlements, and a $1.7 million net increase in realized and unrealized losses on foreign currency forward contracts due to a $11.9 million increase in realized losses on foreign currency forward contracts mainly due to the transfer of $10.2 million previously recognized unrealized losses to realized losses in 2015 related to actual cash settlements and from a stronger U.S. Dollar compared to last year.

Please see Item 5 - Operating and Financial Review and Prospects: 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 losses on derivative instruments.

Equity Income. Equity income was $7.7 million for 2015 compared to $10.3 million for 2014. The decrease in equity income compared to last year, was primarily due to an increase in unrealized losses on derivative instruments relating to our investment in the Libra FPSO unit, partially offset by a decrease in unrealized losses on derivative instruments relating to an investment in the Itajai FPSO unit and a decrease in vessel operating expenses in the Itajai FPSO joint venture mainly due to the strengthening of the U.S. Dollar against the Brazilian Real compared to last year, and a credit received during 2015 relating to unused maintenance days in the Itajai FPSO joint venture.

Foreign Currency Exchange Loss. Foreign currency exchange losses were $17.5 million for 2015, compared to $16.1 million for 2014. Our foreign currency exchange losses, are due primarily to the relevant period-end revaluation of Norwegian Kroner-denominated monetary assets and liabilities for financial reporting purposes and the realized and unrealized gains and losses on our cross currency swaps. Gains on Norwegian Kroner-denominated net monetary liabilities reflect a stronger U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on Norwegian Kroner-denominated net monetary liabilities reflect a weaker U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

For 2015, foreign currency exchange losses include realized losses of $10.1 million (2014 – loss of $2.0 million) and unrealized losses of $61.7 million (2014 – losses of $94.0 million) on the cross currency swaps, and unrealized gains of $61.2 million (2014 – gains of $86.0 million) on the revaluation of the Norwegian Kroner denominated debt. There were additional realized and unrealized foreign exchange losses of $6.8 million (2014 – losses of $6.2 million) on all other monetary assets and liabilities.

Income Tax Recovery (Expense). Income tax recovery (expense) was $21.4 million for 2015 and ($2.2) million for 2014. The increase in deferred income tax recovery of $23.9 million for 2015 compared to last year was primarily due to the acquisition of the Petrojarl Knarr FPSO unit and the commencement of the East Coast of Canada contract during 2015, and the expected commencement of the Gina Krog FSO unit contract in early-2017, from which we expect to utilize more of our Norwegian tax losses from the earnings anticipated from their contracts, as well as an expected increase in earnings from our existing fleet, which resulted in a decrease in our deferred tax asset valuation allowance and an increase in deferred income tax recovery.

Year Ended December 31, 2014 versus Year Ended December 31, 2013

Shuttle Tanker Segment

As at December 31, 2014, our shuttle tanker fleet consisted of 32 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, one shuttle tanker in lay-up as a conversion candidate, and one HiLoad DP unit. Of these 34 shuttle tankers, six were owned through 50%-owned subsidiaries, two through a 67%-owned subsidiary and two were chartered-in. The remaining vessels are owned 100% by us.

The following table presents our shuttle tanker segment’s operating results for 2014 and 2013, and compares its net revenues (which is a non-GAAP financial measure) for 2014 and 2013, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for our shuttle tanker segment:


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2014			2013			% Change

Revenues		577,064			552,019			4.5
Voyage expenses		(105,562	)		(99,543	)		6.0

Net revenues		471,502			452,476			4.2
Vessel operating expenses		(159,438	)		(152,986	)		4.2
Time-charter hire expense		(31,090	)		(56,682	)		(45.2	)
Depreciation and amortization		(110,686	)		(115,913	)		(4.5	)
General and administrative⁽¹⁾		(29,154	)		(21,821	)		33.6
(Write down) and gain (loss) on sale of vessels		(1,638	)		(76,782	)		(97.9	)
Restructuring recovery (charge)		225			(2,169	)		(110.4	)

Income from vessel operations		139,721			26,123			434.9


Calendar-Ship-Days
Owned Vessels		11,870			10,914			8.8
Chartered-in Vessels		802			1,456			(44.9	)

Total		12,672			12,370			2.4

(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).

The average size of our owned shuttle tanker fleet increased in 2014 compared to 2013, primarily due to the delivery to us, during 2013, of four newbuilding shuttle tankers (or the BG Shuttle Tankers) and the delivery of the HiLoad DP unit in April 2014, partially offset by the sale of the Navion Norvegia in October 2014, the commencement of the conversion of the Navion Clipper to the Suksan Salamander FSO unit in April 2013, and the sale of the Basker Spirit in January 2013.

The average size of our chartered-in shuttle tanker fleet decreased for 2014 compared to 2013, primarily due to the redelivery to their owners of the Karen Knutsten in January 2014 and the Grena Knutsen in November 2013.

Net Revenues. Net revenues increased for 2014 from 2013, primarily due to:

•

an increase of $60.0 million due to the commencement of the ten-year time-charter contracts of the four BG Shuttle Tankers during 2013 and early-2014;

•

an increase of $7.6 million due to more opportunities to trade excess shuttle tanker capacity in the conventional tanker spot market;

•

an increase of $3.8 million due to an increase in reimbursable bunker expenses; and

•

an increase of $0.8 million due to an increase in rates under certain bareboat charter contracts;

partially offset by

•

a decrease of $43.8 million due to fewer revenue days resulting from the redelivery of four vessels, to us, in July 2013, December 2013, January 2014 and February 2014, as they completed their time-charter-out agreements, a decrease in revenues in our contract of affreightment fleet due to lower fleet utilization and a decrease in rates as provided in certain contracts in our time-chartered-out fleet;

•

a decrease $5.0 million due to more repair off-hire days in our time-chartered-out fleet; and

•

a decrease of $4.6 million due to less opportunities to trade excess shuttle tanker capacity in short-term offshore projects.

Vessel Operating Expenses. Vessel operating expenses increased for 2014 from 2013, primarily due to:

•

an increase of $9.7 million due to the commencement of the time-charter-out agreements of the four BG Shuttle Tankers during 2013 and early-2014; and

•

an increase of $8.3 million relating to the HiLoad DP unit due to the commencement of operations of the unit in April 2014 and $4.7 million of mobilization costs;

partially offset by

•

a decrease of $4.4 million due to the lay-up of the Navion Norvegia in June 2014 and its subsequent sale to our 50/50 joint venture with Odebrecht in October 2014;

•

a decrease of $3.0 million primarily due to the timing of repairs and maintenance expenses, port expenses and project expenses;

•

a decrease of $2.5 million due to a decrease in ship management fees in our contract of affreightment and time-charter fleets resulting from the reorganization of our onshore marine operations in 2013;

•

a decrease of $0.8 million due to a change in crew composition relating to the reflagging of two vessels during late 2013 and early 2014, respectively, and the strengthening of the U.S. Dollar against the Norwegian Kroner; partially offset by an increase in crew and manning costs primarily due to higher crew levels; and

•

a decrease of $0.7 million relating to the lay-up of the Navion Clipper in February 2013 and the subsequent FSO conversion commencing April 2013.

Time-Charter Hire Expense. Time-charter hire expense decreased for 2014 from 2013, primarily due to:

•

a decrease of $26.1 million due to the redelivery, by us, of the Karen Knutsen in January 2014 and the Grena Knutsen in November 2013. The Grena Knutsen was subsequently re-chartered by us coinciding with the redelivery of the Sallie Knutsen, in September 2014;

•

a decrease of $1.7 million due to the off-hire and drydocking of the Sallie Knusten during 2014; and

•

a decrease of $1.3 million primarily relating to the drydocking and higher off-hire of the Aberdeen during 2014;

partially offset by

•

an increase of $3.6 million due to increased spot in-chartering of shuttle tankers.

Depreciation and Amortization. Depreciation and amortization expense decreased for 2014 from 2013, primarily due to the impact from the write-down of six shuttle tankers during 2013 and lower vessel contract amortization expense, partially offset by an increase due to the delivery of the four BG Shuttle Tankers during 2013, the dry docking of shuttle tankers in late-2013 and early-to-mid-2014, and a decrease in the depreciation period of a shuttle tanker, the Randgrid, due to its expected conversion to an FSO unit.

(Write-down) and gain (loss) on sale of vessels. (Write-down) and gain on sale of vessels was ($1.6) million for 2014 which consisted of a write-down of a vessel of $4.8 million and a gain on the sale of a vessel of $3.1 million. In the third quarter of 2014, the carrying value of one of our 1990s-built shuttle tankers was written down to its estimated fair value, using an appraised value. The write-down was the result of the vessel charter contract expiring in early-2015 and the expected sale of the vessel. In October 2014, a 1995-built shuttle tanker, the Navion Norvegia, was sold to our 50/50 joint venture with Odebrecht. The proceeds from the sale of the vessel were $13.4 million, which included $0.4 million for bunkers on-board at the time of sale. The net book value of the vessel at the time of sale was $6.8 million. As the vessel was sold to our 50/50 joint venture with Odebrecht, we have deferred 50% of the gain on sale of the vessel. The vessel is committed to a new FPSO conversion for the Libra field.

Write-down and loss on sale of vessels was $76.8 million for 2013, of which $37.2 million relates to two shuttle tankers which we own through a 50%-owned subsidiary and $19.3 million relates to two shuttle tankers which we own through a 67%-owned subsidiary. During 2013, the carrying value of six of our 1990s-built shuttle tankers were written down to their estimated fair values using appraised values. Of the six vessels, during the third quarter of 2013, four of the shuttle tankers were written down as the result of: the recontracting of one of the vessels, which we own through a 50%-owned subsidiary, at lower rates than expected; the cancellation of a short-term contract in September 2013; and a change in expectations for the contract renewal for two of the shuttle tankers, one operating in Brazil, and the other, which we own through a 50%-owned subsidiary, in the North Sea. In the fourth quarter of 2013, two shuttle tankers, which we own through a 67%-owned subsidiary, were written down to their estimated fair values due to a cancellation of a contract renewal and the expected sale of an aging vessel..

Restructuring Recovery (Charge). Restructuring recovery for 2014 was $0.2 million relating to a $0.8 million reimbursement received relating to the reorganization of our shuttle tanker marine operations, partially offset by a $0.6 million charge relating to the reflagging of one shuttle tanker.

Restructuring charge was $2.2 million for 2013 resulting from a $0.6 million charge from the reflagging of one shuttle tanker and a $1.6 million charge from the reorganization of our shuttle tanker marine operations.

FPSO Segment

As at December 31, 2014, our FPSO fleet consisted of the Petrojarl Varg, the Cidade de Rio das Ostras (or 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%. We acquired the Voyageur Spirit FPSO unit and our interest in the Itajai FPSO unit from Teekay Corporation in May 2013 and June 2013, respectively. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner, Brazilian Real, and British Pound may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

The following table presents our FPSO segment’s operating results for 2014 and 2013, and also provides a summary of the calendar-ship-days for our FPSO segment. The table excludes the results of the Itajai and the Libra FPSO units, which are accounted for under the equity method.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2014			2013			% Change

Revenues		354,518			284,932			24.4
Vessel operating expenses		(158,216	)		(152,616	)		3.7
Depreciation and amortization		(72,905	)		(66,404	)		9.8
General and administrative⁽¹⁾		(27,406	)		(17,742	)		54.5

Income from vessel operations		95,991			48,170			99.3


Calendar-Ship-Days
Owned Vessels		1,476			1,339			10.2

(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).

The average number of our FPSO units increased in 2014 compared to 2013, due to the acquisition of the Voyageur Spirit on May 2, 2013 and the Petrojarl I on December 15, 2014.

Revenues. Revenues increased for 2014 from 2013, primarily due to:

•

an increase of $60.9 million mainly relating to the commencement of the charter for the Voyageur Spirit FPSO unit in August 2013;

•

an increase of $4.5 million due to the settlement of reimbursable expenses for the Voyageur Spirit FPSO unit during the third and fourth quarters of 2014;

•

an increase of $4.5 million due the commencement of operations of a produced water treatment plant on the Piranema Spirit in the second quarter of 2014;

•

an increase of $4.1 million due to an increase in rates on the Rio das Ostras in accordance with the annual contractual escalation adjustment and a credit earned from the charterer of the unit for unused maintenance days under the service contract;

•

an increase of $2.0 million relating to the Piranema Spirit for a credit earned from the charterer for unused maintenance days under the service contract; and

•

an increase of $1.0 million relating to an increase in daily hire rates on the Voyageur Spirit, partially offset by a decrease in incentive compensation of the unit;

partially offset by

•

a decrease of $4.8 million due to a decrease in crew hours reimbursed by the charterer of the Petrojarl Varg; and

•

a decrease of $3.0 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner.

In connection with the Voyageur Spirit sale and purchase agreement, Teekay Corporation indemnified us for lost revenue and unreimbursed repair costs from the unit being off-hire since the unit began operations on April 13, 2013 until February 21, 2014. The indemnification amount relating to lost revenue was $3.1 million and $31.3 million for 2014 and 2013, respectively. The indemnification amount relating to unreimbursed repair costs was $0.4 million and $3.6 million for 2014 and 2013, respectively. These amounts have been recorded in equity as an adjustment to the purchase price we paid for the FPSO unit.

Vessel Operating Expenses. Vessel operating expenses increased for 2014 from 2013, primarily due to:

•

an increase of $23.2 million due to the acquisition of the Voyageur Spirit FPSO unit in May 2013 and the timing of costs related to repair and maintenance on the unit in 2014, partially offset by a decrease in external consulting fees for the unit;

partially offset by

•

a decrease of $8.5 million due to the timing of costs related to repair and maintenance on the Piranema Spirit, Petrojarl Varg and Rio das Ostras FPSO units;

•

a decrease of $7.6 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner;

•

a decrease of $1.3 million primarily due to lower ship management fees for the FPSO units; and

•

a decrease of $0.9 million due to a decrease in external agency fees for the Piranema Spirit FPSO unit.

Depreciation and Amortization Expense. Depreciation and amortization expense increased for 2014 from 2013, primarily due to the acquisition of the Voyageur Spirit FPSO unit during the second quarter of 2013.

FSO Segment

As at December 31, 2014, our FSO fleet consisted of six units that operate under fixed-rate time charters or fixed-rate bareboat charters, in which our ownership interests range from 89% to 100%. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner and Australian Dollar may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

The following table presents our FSO segment’s operating results for 2014 and 2013, and compares its net revenues (which is a non-GAAP financial measure) for 2014 and 2013, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days for our FSO segment:


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2014			2013			% Change

Revenues		53,868			59,016			(8.7	)
Voyage (expenses) recoveries		(1,500	)		432			(447.2	)

Net revenues		52,368			59,448			(11.9	)
Vessel operating expenses		(28,649	)		(32,713	)		(12.4	)
Depreciation and amortization		(8,282	)		(10,178	)		(18.6	)
General and administrative⁽¹⁾		(3,870	)		(2,553	)		51.6

Income from vessel operations		11,567			14,004			(17.4	)


Calendar-Ship-Days
Owned Vessels		2,190			2,100			4.3

(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).

The average number of our FSO units increased in 2014 compared to 2013, due to the conversion of the Navion Clipper shuttle tanker to an FSO unit, the Suksan Salamander, which commenced in April 2013 and was completed in July 2014. The Suksan Salamander commenced its charter contract in August 2014.

Net Revenues. Net revenues decreased for 2014 from 2013, primarily due to:

•

a decrease of $3.2 million due to a contract extension in April 2014 for the Pattani Spirit at a lower charter rate for an additional five years;

•

a decrease of $2.7 million due to the drydocking of the Navion Saga during the third quarter of 2014;

•

a decrease of $2.4 million due to the drydocking of the Dampier Spirit during the second quarter of 2014;

•

a decrease of $0.9 million due to a recovery of expenses in the first quarter of 2013 relating to the 2012 drydocking of the Navion Saga and the strengthening of the U.S. Dollar against the Norwegian Kroner;

•

a decrease of $0.9 million primarily due to the strengthening of the U.S. Dollar against the Australia Dollar; and

•

a decrease of $0.7 million due to an increase in bunker expenses.

partially offset by

•

an increase of $3.3 million due to the commencement of operations of the Suksan Salamander in the third quarter of 2014; and

•

an increase of $0.6 million primarily due to the timing of vessel operating expense reimbursements relating to the Dampier Spirit.

Vessel Operating Expenses. Vessel operating expenses decreased for 2014 from 2013, primarily due to:

•

a decrease of $1.7 million relating to expenditure on engineering studies completed to support our FSO tenders in 2013;

•

a decrease of $1.7 million for the Navion Saga FSO unit due to lower crew costs mainly relating to a pension expense incurred in the fourth quarter of 2013; and management transition costs incurred in the first quarter of 2013 relating to the transfer of the management of the unit from an external to internal managed unit; and

•

a decrease of $0.5 million due to the timing of services, spares and offshore expenses for the Navion Saga.

Depreciation and amortization. Depreciation and amortization expense decreased for 2014 from 2013, primarily due to an extension of the estimated useful lives of the Pattani Spirit and the Apollo Spirit, resulting from an extension of the charter periods for these units, and the completion of dry docking depreciation of the Dampier Spirit prior to its scheduled dry docking in the second quarter of 2014, partially offset by the delivery of the Suksan Salamander in August 2014.

Conventional Tanker Segment

As at December 31, 2014, we owned 100% interests in two Aframax conventional crude oil tankers (which operated under fixed-rate time charters with Teekay Corporation) and two vessels (that have additional equipment for lightering) which operated under fixed-rate bareboat charters with a 100% owned subsidiary of Teekay Corporation.

The table below excludes three additional conventional tankers as they were determined to be discontinued operations. During the first quarter of 2013, we sold a vessel and we terminated the long-term time-charter-out contract employed by one of our conventional tankers with a subsidiary of Teekay Corporation, which was subsequently sold in the second quarter of 2013. A third conventional tanker operating on a contract to Teekay Corporation was sold in the third quarter of 2013. We received early termination fees from Teekay Corporation of $6.8 million and $4.5 million in the first and second quarters of 2013, respectively, which are recorded in discontinued operations.

The following table presents our conventional tanker segment’s operating results for 2014 and 2013, and compares its net revenues (which is a non-GAAP financial measure) for 2014 and 2013, to revenues, the most directly comparable GAAP financial measure, for the same periods. The following table also provides a summary of the changes in calendar-ship-days by owned vessels for our conventional tanker segment.


	Year Ended December 31,
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)	2014			2013			% Change

Revenues		33,566			34,772			(3.5	)
Voyage expenses		(5,373	)		(4,532	)		18.6

Net revenues		28,193			30,240			(6.8	)
Vessel operating expenses		(5,906	)		(5,813	)		1.6
Depreciation and amortization		(6,680	)		(6,511	)		2.6
General and administrative⁽¹⁾		(2,136	)		(2,357	)		(9.4	)
Restructuring charge		—			(438	)		(100.0	)

Income from vessel operations		13,471			15,121			(10.9	)


Calendar-Ship-Days
Owned Vessels		1,460			1,460			—

(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).

Net Revenues. Net revenues decreased for 2014 from 2013, primarily due to a lower amount of reimbursed bunkers and off-hire days associated with the drydocking of one vessel in 2014.

Restructuring Charge. Restructuring charge was $0.4 million for 2013 related to the reorganization of the conventional tanker marine operations. The purpose of the restructuring was to create better alignment with marine operations resulting in a lower cost organization. The reorganization was completed by June 30, 2013.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased to $67.5 million for 2014, from $44.5 million for 2013, mainly due to: the acquisition of the Voyageur Spirit FPSO unit during the second quarter of 2013; the acquisition of ALP during the first quarter of 2014 (including a $1.6 million business development fee paid to Teekay Corporation in relation to the acquisition during the second quarter of 2014 and a $1.0 million fee to a third party relating to the acquisition during the first quarter of 2014); the delivery of the HiLoad DP unit during the second quarter of 2014; the acquisition of Logitel during the third quarter of 2014; the commencement of operations for the four BG Shuttle Tankers during 2013 and early-2014; the acquisition of the Petrojarl I FPSO during the fourth quarter of 2014 (including a $2.1 million business development fee paid to Teekay Corporation for assistance with securing the charter contract for the Petrojarl I); an increase in business development costs relating to FPSO tenders including the Libra FPSO project; an increase in equity based compensation relating to restricted unit awards; and an increase in the corporate service fees from Teekay Corporation to support our growth due to additional efforts required; partially offset by cost savings due to the reorganization of marine operations within our shuttle tanker business unit completed in 2013.

Interest Expense. Interest expense increased to $88.4 million for 2014, from $62.9 million for 2013, primarily due to:

•

an increase of $21.0 million due to $300 million senior unsecured bonds issued during the second quarter of 2014 and borrowings relating to the Voyageur Spirit FPSO, the four BG Shuttle Tankers (which commenced operations during 2013 and early-2014), and the Suksan Salamander (which commenced operations in the third quarter of 2014);

•

a net increase of $5.2 million primarily from the issuance of NOK 1,000 million senior unsecured bonds in January 2014, partially offset by the repurchase during the first quarter of 2013 of NOK 388.5 million of the NOK 600 million senior unsecured bonds and the remaining NOK 211.5 million bonds that matured in November 2013; and

•

an increase of $1.5 million from an increase in loan cost amortization relating to new debt facilities;

partially offset by

•

a decrease of $2.3 million mainly due to lower debt balances and partially due to lower interest rates on all other borrowings.

Interest Income. Interest income decreased to $0.7 million for 2014, from $2.6 million for 2013, primarily due to interest income received in 2013 on our partial prepayment to Teekay Corporation of $150 million in anticipation of the Voyageur Spirit FPSO unit acquisition. We received interest on this amount at a rate of LIBOR plus a margin of 4.25% until we acquired the FPSO unit on May 2, 2013.

Realized and Unrealized (Losses) Gains on Derivative Instruments. Net realized and unrealized (losses) gains on non-designated derivative instruments were ($143.7) million for 2014, compared to $34.8 million for 2013.

During 2014 and 2013, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.7 billion and $1.6 billion, respectively, and average fixed rates of approximately 3.6%. Short-term variable benchmark interest rates during these periods were generally 0.5% or less and, as such, we incurred realized losses of $55.6 million and $63.1 million during 2014 and 2013, respectively, under the interest rate swap agreements. Included in realized losses for 2013 is a $4.1 million loss due to the termination of an interest rate swap relating to the Voyageur Spirit, which is included in the results of the Dropdown Predecessor. Please see Item 18 – Financial Statements: Note 3.

In addition, we recorded a $31.8 million realized loss in 2013 related to the early termination of an interest rate swap.

During 2014 and 2013, we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures in Norwegian Kroner.

The $178.5 million increase in net realized and unrealized losses was primarily due to lower current LIBOR interest rates in 2014 compared to 2013, a $209.3 million increase in unrealized losses on interest rate swaps relating to a decrease in long-term LIBOR benchmark interest rates as at December 31, 2014 relative to the beginning of 2014, compared to an increase in long-term LIBOR benchmark interest rates as at December 31, 2013 relative to the beginning of 2013, and a $8.5 million increase in realized and unrealized losses on foreign currency forward contracts due to a stronger U.S. Dollar in 2014 compared to 2013, partially offset by a $31.8 million realized loss due to the early termination of an interest rate swap in 2013, and a $7.5 million decrease in realized losses on interest rate swaps due to the decrease in the transfer of previously recognized unrealized losses to realized losses related to actual cash settlements in 2014 compared to 2013.

Equity Income. Equity income was $10.3 million for 2014 compared to $6.7 million for 2013 relating to a full year of earnings on our investment in the Itajai FPSO unit, of which we acquired a 50% interest from Teekay Corporation in June 2013.

Foreign Currency Exchange Loss. Foreign currency exchange loss was $16.1 million for 2014, compared to $5.3 million for 2013. Our foreign currency exchange losses, substantially all of which are unrealized, are due primarily to the relevant period-end revaluation of Norwegian Kroner-denominated monetary assets and liabilities for financial reporting purposes and the realized and unrealized gains and losses on our cross currency swaps. Gains on Norwegian Kroner-denominated monetary liabilities reflect a stronger U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on Norwegian Kroner-denominated monetary liabilities reflect a weaker U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

For 2014, foreign currency exchange losses include realized losses of $2.0 million (2013 – gain of $1.6 million) and unrealized losses of $94.0 million (2013 – $38.6 million) on the cross currency swaps, and unrealized gains of $86.0 million (2013 - $38.0 million) on the revaluation of the Norwegian Kroner denominated debt. There were additional realized and unrealized foreign exchange losses of $6.2 million, (2013 - $6.5 million) on all other monetary assets and liabilities. During 2013, we repurchased NOK 388.5 million of the then outstanding NOK 600 million senior unsecured bonds that matured in November 2013. Associated with this, we recorded $6.6 million of realized losses on the repurchased bonds and recorded $6.8 million of realized gains on the termination of the associated cross currency swap.

Loss on Bond Repurchase. Loss on bond repurchase was $1.8 million for 2013. The loss represents a 2.5% premium paid for the repurchase of NOK 388.5 million of the then outstanding NOK 600 million senior unsecured bonds that matured in November 2013.

Other Income. Other income decreased to $0.8 million for 2014 from $1.1 million for 2013, mainly due to a decrease in leasing income from our VOC equipment. The leasing income decreased as a result of the completion of the VOC contracts during 2014.

Income Tax Expense. Income tax expense was $2.2 million for each of 2014 and 2013. Our 2014 deferred tax expense decreased, mainly due to a deferred tax recovery recognized in 2014 as a result of higher future projected income for our Norwegian tax group, while we incurred a deferred tax expense in 2013 due to lower projected income for our Norwegian tax group. The 2014 deferred tax recovery was offset by the recognition of deferred tax expense relating to the utilization of prior year losses carried forwards to offset an increase in 2014 earnings of the Dampier Spirit due to higher rates from a contract extension, and the utilization of prior year loss carry forward for the Voyageur Spirit. Our 2014 current tax expense increased, mainly due to income tax adjustments relating to the Rio das Ostras Brazilian entity during the first quarters of 2014 and 2013, and the settlement of a claim for prior taxes paid during 2013.

Net Loss from Discontinued Operations. Net loss from discontinued operations was $4.6 million for the year ended December 31, 2013. We sold the Leyte Spirit, the Poul Spirit and the Gotland Spirit during the first, second and third quarters of 2013, respectively.

If these vessels were not classified as discontinued operations, the results of the operations of these vessels would have been reported within the conventional tanker segment.

During the first and second quarters of 2013, we terminated the long-term time-charter-out contract employed by the Poul Spirit and the Gotland Spirit with a subsidiary of Teekay Corporation. We received early termination fees from Teekay Corporation of $11.3 million during 2013. In addition, we recorded write-downs and losses on sale of vessels of $18.5 million during 2013.

Liquidity and Capital Resources

Liquidity and Cash Needs

Our business model is to employ our vessels on fixed-rate contracts with major oil companies, typically with original terms between three to ten years. Prior to the fourth quarter of 2015, the operating cash flow our vessels generated each quarter, excluding a reserve for maintenance capital expenditures and distributions on our preferred units, was generally paid out to our common unitholders within approximately 45 days after the end of each quarter. Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. We believe there is currently a dislocation in these markets relative to the stability of our businesses. Based on upcoming equity capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with the uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, we believe that 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, effective for the quarterly distribution for the fourth quarter of 2015, we have temporarily reduced our quarterly cash distributions per common unit to $0.11 from $0.56, and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and growing, supported by a large and well-diversified portfolio of fee-based contracts with high quality counterparties.

Our primary liquidity needs for 2016 and 2017 are to pay existing, committed capital expenditures and to make scheduled repayments of debt, in addition to paying debt service costs, quarterly distributions on our outstanding common and preferred units, operating expenses and dry docking expenditures and funding general working capital requirements. We anticipate that our primary sources of funds for 2016 and 2017 will be cash flows from operations, bank debt and proceeds from the sale of certain assets. However, we currently have estimated cash flow gaps of approximately $250 million in 2016 and $90 million in 2017. These cash flow gaps represent the difference between (a) cash inflows from cash flow from vessel operations, dividends from our equity accounted joint ventures and borrowings under committed and anticipated debt financings and refinancings, and (b) cash outflows for expected capital expenditures, equity investments in joint ventures, secured and unsecured debt repayments, interest expense and our anticipated distributions on common and preferred units. In addition, we are required to pay $172.3 million upon delivery of our second UMS newbuilding, which currently is scheduled for the late-2016; however, we expect to enter into discussions with the shipyard to further delay or cancel the delivery of this unit. The cash flow gaps do not take into account utilizing the liquidity balance of $282.7 million at December 31, 2015, which comprises of unrestricted cash and undrawn revolvers. For debt covenant purposes, we need to maintain a minimum liquidity balance of 5% of total consolidated debt, which was approximately $175 million as at December 31, 2015. We are evaluating a number of potential sources to finance these cash flow gaps, including securing debt financing on our under-levered and unmortgaged assets, entering into sale-leaseback transactions, divesting of assets, issuing hybrid or other equity securities, reducing our capital expenditures relating to existing projects, accessing the unsecured bond market, utilizing existing liquidity and seeking loans from our sponsor, Teekay Corporation. We also expect to seek deferrals of certain shipyard deliveries and associated payments of our contractual obligations. There can be no assurance that any such financing will be available to us on acceptable terms, if at all.

Our liquidity needs beyond 2017 decline as a majority of our commitments for capital expenditures are in 2016 and 2017; however, this is partially offset by an increase in maturities of unsecured debt after 2017. Our ability to continue to expand the size of our fleet over the long-term is in part dependent upon our ability to continue to generate operating cash flow, particularly from our shuttle tanker and FPSO fleets, obtain long-term bank borrowings and other debt, as well as our ability to raise debt or equity financing through either public or private offerings.

As at December 31, 2015, our total future contractual obligation for vessels and newbuildings and committed conversions, including our 50% interest in the Libra FPSO conversion, was $1.5 billion, consisting of $982.8 million (2016), $237.3 million (2017), $84.2 million (2018) and $184.4 million (2019). Of this $1.5 billion of future contractual obligations, we have pre-arranged financing in place of $592.7 million and therefore a remaining funding requirement of $390.1 million (2016), $237.3 million (2017), $84.2 million (2018) and $174.1 million (2019). We expect to manage these funding requirements from the potential financing sources noted above and the deferral or cancellation of shipyard deliveries and associated payments of our contractual obligations.

Our revolving credit facilities and term loans are described in Item 18 – Financial Statements: Note 8 – Long-Term Debt. They contain covenants and other restrictions typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from incurring or guaranteeing indebtedness; changing ownership or structure, including mergers, consolidations, liquidations and dissolutions; making dividends or distributions if we are in default; 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. Certain of our revolving credit facilities and term loans include financial covenants. Should we not meet these financial covenants, the lender may accelerate the repayment of the revolving credit facilities and term loans, thus having an impact on our short-term liquidity requirements. We have one revolving credit facility and four term loans that require us to maintain vessel values to drawn principal balance ratios of a minimum range of 113% to 125%. As at December 31, 2015, these ratios ranged from 126% to 212%. The vessel values used in these ratios are appraised values provided by third parties where available, or are prepared by us based on second-hand sale and purchase market data. Changes in the conventional or shuttle tanker, towing, UMS or FPSO markets could negatively affect these ratios. As at December 31, 2015, we and our affiliates were in compliance with all covenants relating to the revolving credit facilities and term loans.

As at December 31, 2015, our total cash and cash equivalents were $258.5 million, compared to $252.1 million at December 31, 2014. Our total liquidity, including cash, cash equivalents and undrawn long-term borrowings, was $282.7 million as at December 31, 2015, compared to $351.7 million as at December 31, 2014. The decrease in liquidity was primarily due to: liquidity used to fund a portion of the Knarr FPSO acquisition from Teekay Corporation in July 2015; a portion of the final installment payment on the Arendal Spirit UMS in February 2015; payments for the delivery of six towing and offshore installation vessels in 2015; payments for committed newbuildings and conversions (please read Item 18 – Financial Statements: Note 14 – Commitments and Contingencies); a reduction in the amount available for borrowing under our revolving credit facilities; and the scheduled repayments or the prepayments of outstanding term loans or revolving credit facilities; partially offset by net proceeds of $249.8 million due to the issuance of Series C Preferred Units in July 2015, net proceeds of $120.8 million due to the issuance of Series B preferred units in April 2015 and the drawdown of six new debt facilities and one existing revolving credit facility in 2015.

As at December 31, 2015, we had a working capital deficit of $504.5 million, compared to a working capital deficit of $123.5 million at December 31, 2014. The current portion of long-term debt increased mainly due to the reclassification of NOK 500 million unsecured bonds maturing in January 2016 and two revolving credit facilities maturing in the second quarter of 2016 to current debt as at December 31, 2015, the assumption of one debt facility related to the acquisition of the Knarr FPSO unit from Teekay Corporation in July 2015 and the drawdown of four new debt facilities, the proceeds of which we used primarily to fund the final installment payment on the Arendal Spirit UMS, the delivery of six towing and offshore installation vessels during 2015 and installment payments on the four towing and offshore installation newbuildings. Net amounts due to affiliates increased mainly due to the acquisition of the Knarr FPSO unit from Teekay Corporation in July 2015. We expect to manage our working capital deficit primarily with net operating cash flow and other funding initiatives, including securing debt financing on our under-levered and unmortgaged assets, entering into sale-leaseback transactions, divesting assets, issuing hybrid or other equity securities, accessing the unsecured bond markets, and seeking loans from our sponsor, Teekay Corporation.

The passage of any 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:


	Year Ended December 31,
(in thousands of U.S. Dollars)	2015			2014			2013

Net cash flow from operating activities		371,221			160,186			255,387
Net cash flow from (used for) financing activities		273,138			42,404			231,865
Net cash flow used for investing activities		(638,024	)		(169,578	)		(474,465	)

Operating Cash Flows.

Net cash flow from operating activities increased to $371.2 million for 2015, from $160.2 million in 2014, primarily due to a $202.1 million increase in net revenues, a $137.4 million increase in changes in non-cash working capital and a $23.2 million decrease in dry-docking expenditures, partially offset by a $33.7 million increase in net deferred mobilization costs and long term accounts receivable, a $28.3 million increase in net interest expense, a $27.9 million increase in realized losses on derivatives, a $20.7 million increase in time-charter hire expense, a $17.1 million decrease in foreign exchange gains and other items, a $9.0 million increase in vessel operating expenses, a $9.0 million decrease in dividends received from our equity-accounted joint ventures, a $5.1 million increase in general and administrative expenses and a $0.8 million increase in restructuring costs.

The increase in non-cash working capital items for 2015 compared to 2014 is primarily due to the timing of settlements of intercompany balances with related parties and the timing of payments made to vendors, partially offset by the timing of payments received from customers.

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

Net cash flow from operating activities decreased to $160.2 million for 2014, from $255.4 million in 2013, primarily due to a $163.5 million decrease in changes in non-cash working capital, a $26.2 million increase in net interest expense, a $23.1 million increase in general and administrative expenses, a $16.9 million increase in dry-docking expenditures, a $15.1 million decrease in cash receipts from discontinued operations, a $6.6 million increase in vessel operating expenses, a $5.7 million decrease in foreign exchange gains and other items, and a $1.2 million increase in current income taxes, partially offset by a $77.9 million increase in net revenue, a $38.2 million decrease in realized losses on derivatives, a $25.6 million decrease in time-charter hire expense, a $16.8 million increase in dividends received from our equity-accounted joint venture, a $2.8 million decrease in restructuring costs and a $1.8 million decrease in loss on bond repurchase.

The increase in non-cash working capital items for 2014 compared to 2013 is primarily due to the timing of payments made to vendors and the timing of settlements with related parties, partially offset by the timing of payments received from customers.

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

Financing Cash Flows.

In order to partially finance new acquisitions, we have issued common or preferred units to the public and to institutional investors. We raised net proceeds (including our general partner’s 2% proportionate capital contribution) of $380.2 million in 2015, $186.1 million in 2014 and $263.8 million in 2013. We purchased the Knarr FPSO unit from Teekay Corporation during 2015, and for 2015 made cash payments of $112.7 million, net of $14.2 million of cash acquired, for this acquisition. We paid finance shipyard installments for the four BG shuttle tankers in 2013. We purchased the Voyageur Spirit FPSO unit during 2013.

We use our revolving credit facilities to finance capital expenditures and for general partnership 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 the issuance of long-term debt, net of debt issuance costs and prepayments of long-term debt were $639.4 million in 2015, $915.9 million in 2014 and $658.7 million in 2013. Net proceeds from the issuance of long-term debt decreased for 2015 from 2014, mainly due to proceeds from the issuance of NOK 1,000 million and $300.0 million unsecured bonds during 2014, which were used for general partnership purposes, and long-term debt issued to finance conversion costs for the Suksan Salamander in 2014, partially offset by the drawdown of six new debt facilities and one existing revolving credit facility during 2015, the proceeds of which we used primarily to fund the final installment payment on the Arendal Spirit UMS, the acquisition of six towing and offshore installation vessels during 2015, installment payments on the four towing and offshore installation newbuildings, upgrade payments on the Petrojarl I FPSO unit acquired from Teekay Corporation in December 2014 and conversion payments on the Gina Krog FSO unit conversion. Net proceeds from the issuance of long-term debt increased in 2014 from 2013, primarily due to the issuance of NOK 1,000 million and $300.0 million unsecured bonds in January 2014 and May 2014, respectively, and long-term debt issued to finance conversion costs for the Suksan Salamander in October 2014.

We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments of long-term debt decreased to $341.8 million in 2015, from $804.7 million in 2014 and $266.9 million in 2013.

Cash distributions paid by our subsidiaries to non-controlling interests totaled $23.6 million in 2015, $27.9 million in 2014 and $7.8 million in 2013. Cash distributions paid by us to our common and preferred unitholders and our general partner totaled $257.9 million in 2015, $214.7 million in 2014 and $192.1 million in 2013. The decrease in distributions paid by our subsidiaries to non-controlling interests in 2015 from 2014 was due to the timing of payments of cash distributions.

The increase in distributions to our common and preferred unitholders and our general partner in 2015 from 2014 was attributed to an increase of $0.0216 per unit in our cash distribution to common unitholders for our distributions relating to the third quarter of 2015, and an increase in the number of common units resulting from the 14.9 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2015, the 7.1 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2014 and an increase in the number of preferred units resulting from the issuance of 5.0 million Series B preferred units in April 2015 and the 10.4 million Series C convertible preferred units issued in July 2015. The increase in the 2015 cash distribution coincided with our acquisition of the Knarr FPSO unit.

The increase in distributions to our common and preferred unitholders and our general partner in 2014 from 2013 was attributed to two increases in our cash distribution to common unitholders, commencing with the cash distributions paid in the first quarter of 2014 and the second quarter of 2013 of $0.0131 per unit and $0.0128 per unit, respectively, or approximately 2.5% each; an increase in the number of common units resulting from the 7.1 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2014 and the 5.5 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2013; and the issuance of 6.0 million Series A preferred units in 2013. The increase in the 2014 cash distribution coincided with the completion of deliveries of the four BG Shuttle Tankers. The increase in the 2013 cash distribution coincided with our acquisition of the Voyageur Spirit FPSO unit.

The increases of $13.8 million and $46.8 million in restricted cash during 2015 and 2014, respectively, relates to an increase in collateral on cross currency swaps.

In April 2015, we completed a public offering of $125 million of our 8.5% Series B Preferred Units, raising net proceeds of approximately $120.8 million. The net proceeds from the issuance were used for general partnership purposes, including the funding of newbuilding installments, capital conversion projects and vessel acquisitions. In July 2015, we completed a private placement of $250 million of our 8.60% Series C Preferred Units for net proceeds of approximately $249.8 million. The net proceeds from the issuance were used to partially fund the acquisition of the Knarr FPSO unit from Teekay Corporation and to fund installments for the three shuttle tanker newbuildings being constructed for the East Coast of Canada contract.

Subsequent to December 31, 2015, cash distributions of $12.0 million on our outstanding common units and general partner interest related to the fourth quarter of 2015 were declared and were paid on February 12, 2016, which included a $0.45 per common unit decrease from the cash distribution related to the third quarter of 2015 and cessation of the incentive distribution rights to the general partner. Subsequent to December 31, 2015, cash distributions for Series A, Series B and Series C Preferred Units relating to the fourth quarter of 2015 were declared and were paid on February 12, 2016, and totaled $10.8 million.

Investing Cash Flows

During 2015, net cash flow used for investing activities was $638.0 million, primarily relating to expenditures for vessels and equipment (including $215.1 million on the six towing and offshore installation vessels delivered during 2015, the $167.0 million final installment on the Arendal Spirit UMS, $89.6 million for FSO conversion costs, $88.7 million of upgrade costs on the Petrojarl I FPSO unit, $34.3 million of costs on the three newbuilding shuttle tankers, $34.1 million on the four newbuilding towing and offshore installation vessels and $35.9 million on various other vessel additions and installments) and investments in the Libra and Itajai FPSO joint ventures of $22.9 million, partially offset by proceeds of $30.4 million from the sale of SPT Explorer L.L.C. and Navigator Spirit L.L.C., $8.9 million from the sale of the Navion Svenita shuttle tanker, $5.2 million for the repayment of advances from our joint venture and scheduled lease payments of $5.0 million received from leasing our direct financing lease assets.

During 2014, net cash flow used for investing activities was $169.6 million, primarily relating to the expenditures for vessels and equipment (including installments of $59.7 million on the four newbuilding ALP towage vessels, $53.4 million on FSO conversion costs, $11.5 million on installment payments on the UMS newbuildings and $47.6 million on various other vessel additions), investments in our equity accounted joint ventures of $12.4 million, $5.2 million of advances to our joint ventures and a $2.3 million acquisition cost for 100% of the shares of ALP, partially offset by aggregate sales proceeds of $13.4 million from the sale of the Navion Norvegia shuttle tanker, scheduled lease payments of $5.1 million received from the leasing of our VOC emissions equipment and direct financing lease assets and a net cash inflow of $4.1 million due to cash received of $8.1 million as part of the acquisition of 100% of the shares of Logitel, offset by $4.0 million cash consideration paid.

During 2013, net cash flow used for investing activities was $474.5 million, primarily relating to the expenditures for vessels and equipment (including installment and final payments of $336.8 million on the four newbuilding BG shuttle tankers, $54.3 million on the HiLoad DP unit and $64.5 million on various other vessel additions) and a $52.5 million acquisition from Teekay Corporation of its 50% interest in the Itajai FPSO joint venture, partially offset by aggregate sale proceeds of $28.0 million from the sale of the Basker Spirit shuttle tanker and the Leyte Spirit, the Poul Spirit and the Gotland Spirit conventional tankers and the scheduled lease payments of $5.6 million received from the leasing of our VOC emissions equipment and direct financing lease assets.

Contractual Obligations and Contingencies

The following table summarizes our long-term contractual obligations as at December 31, 2015:


	Total		2016		2017		2018		2019		2020		Beyond 2020
	(in millions of U.S. Dollars)

U.S. Dollar-Denominated Obligations
Bond repayments⁽¹⁾		320.0		—		10.0		—		310.0		—		—
Secured debt - scheduled repayments⁽¹⁾		2,050.0		316.1		374.4		345.8		280.3		181.9		551.5
Secured debt - repayments on maturity		728.7		113.6		184.7		144.1		25.0		40.0		221.3
Chartered-in vessels (operating leases)		125.5		63.3		41.4		16.7		4.1		—		—
Acquisition of vessels and newbuildings and committed conversion costs⁽²⁾		1,492.2		974.4		259.5		84.2		174.1		—		—
Share repurchase option⁽³⁾		40.2		40.2		—		—		—		—		—
Norwegian Kroner-Denominated Obligations
Bond repayments⁽⁴⁾		327.9		56.5		67.8		90.5		113.1		—		—

Total contractual obligations		5,084.5		1,586.3		925.6		681.3		896.6		221.9		772.8

(1)

Excludes expected interest for U.S. Dollar-Denominated debt of $85.5 million (2016), $72.6 million (2017), $58.8 million (2018), $40.7 million (2019), $23.2 million (2020) and $44.3 million (beyond 2020). Expected interest payments for secured debts are based on existing interest rates (fixed-rate loans) and LIBOR, plus margins which ranged between 0.30% and 3.25% (variable-rate loans) as at December 31, 2015. The expected interest payments do not reflect the effect of related interest rate swaps that we have used as an economic hedge of certain of our variable rate debt.

(2)

Consists of the acquisition of four towing and offshore installation newbuildings, two UMS newbuildings and three shuttle tanker newbuildings, our 50% interest in an FPSO conversion for the Libra field, upgrades of the Petrojarl I FPSO unit and the FSO conversion for the Randgrid shuttle tanker. Please read Item 18 – Financial Statements: Note 14 (b), (c), (d), (e), (f) and (g) – Commitments and Contingencies, and Note 18 (a) and (b) – Acquisitions. We have pre-arranged financing of approximately $592.7 million relating to our capital expenditure commitments for 2016. We are in the process of obtaining, or expect to obtain, additional debt financing for our remaining capital commitments relating to our newbuildings on order as at December 31, 2015.

(3)

Relates to a put and call option agreement we entered into in December 2015 with our 50/50 joint venture partner, Odebrecht, relating to the FPSO conversion for the Libra field. The agreement provides Odebrecht with a put option to sell 15%, 20% or 25% of the shares in the joint venture to the Partnership for consideration of $24.1 million, $32.1 million and $40.2 million, respectively. The exercise date for the put option is April 25, 2016 with a settlement date on May 25, 2016. Please read Item 18 – Financial Statements: Note 14 (h) – Commitments and Contingencies.

(4)

Norwegian Kroner-denominated bond repayments are based on the foreign exchange rate as at December 31, 2015 and exclude the impact of the cross-currency swaps. Excludes expected interest payments of $16.3 million (2016), $11.7 million (2017), $6.5 million (2018) and $0.5 million (2019). Expected interest payments are based on NIBOR, plus margins which ranged between 4.00% and 5.75% as at December 31, 2015. The expected interest payments do not reflect the effect of related interest rate swaps and cross currency swaps that we have used as an economic hedge of certain of our Norwegian Kroner-denominated obligations.

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. A portion of our revenues are generated from voyages servicing contracts of affreightment and to a lesser extent, spot voyages. Within the shipping industry, the two methods used to account for revenues and expenses are the proportionate performance and the completed voyage methods. Most shipping companies, including us, use the proportionate performance method. For each method, voyages may be calculated on either a load-to-load or discharge-to-discharge basis. In other words, revenues are recognized ratably either from the beginning of when product is loaded for one voyage to when it is loaded for another voyage, or from when product is discharged (unloaded) at the end of one voyage to when it is discharged after the next voyage. We recognize revenues from time charters and bareboat charters daily over the term of the charter as the applicable vessel operates under the charter. We recognize revenues from towage voyage charters ratably in proportion to the stage of completion of a project, which is determine based on upon an assessment of the work performed. Revenues from FPSO service contracts are recognized as service is performed. Revenues from UMS contracts are recognized as the service is performed. We generally do not recognize revenues during days that a vessel is off hire.

Judgments and Uncertainties. In applying the proportionate performance method, we believe that in most cases the discharge-to-discharge basis of calculating voyages more accurately reflects voyage results than the load-to-load basis. At the time of cargo discharge, we generally have information about the next load port and expected discharge port, whereas at the time of loading we are normally less certain what the next load port will be. We use this method of revenue recognition for all spot voyages. In the case of our shuttle tankers servicing contracts of affreightment, a voyage commences with tendering of notice of readiness at a field, within the agreed lifting range, and ends with tendering of notice of readiness at a field for the next lifting. In all cases we do not begin recognizing revenue for any of our vessels until a charter has been agreed to by the customer and us, even if the vessel has discharged its cargo and is sailing to the anticipated load port on its next voyage.

Effect if Actual Results Differ from Assumptions. If actual results are not consistent with our estimates in applying the proportionate performance method, our revenues could be overstated or understated for any given period by the amount of such difference.

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. 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 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 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 undiscounted cash flows of an asset is less than the asset’s carrying value and the fair value of the asset is less than its carrying value, 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 major oil companies. These contracts generally have original terms between three to ten years in length. 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 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, 2015. Specifically, the following table reflects all such vessels, except those operating on contracts, where the remaining term is significant and the estimated future 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. Consequently, the vessels included in the following table generally include those vessels employed on single-voyage, or spot charters, as well as those vessels near the end of existing charters or other operational contracts. While the market values of these vessels are below their carrying values, no impairment has been recognized on any of these vessels as the estimated future undiscounted cash flows relating to such vessels are greater than their carrying values.

We would consider the vessels reflected in the following table to be at a higher risk of future impairment. The table is disaggregated for vessels which have estimated future undiscounted cash flows that are only marginally or significantly greater than their respective carrying values. Vessels with estimated future cash flows significantly greater than their respective carrying values would not necessarily represent vessels that would likely be impaired in the next 12 months. 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 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 revenue, 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 flow only 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 $
Shuttle Tanker Segment		2	⁽²⁾		76,441		78,019
FSO Segment		1	⁽²⁾		6,000		10,286

(1)

Market values are determined using reference to second-hand market comparable values or using a depreciated replacement cost approach as at December 31, 2015. Since vessel values can be volatile, our estimates of market value may not be indicative of either 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 and FSO units may involve considerable judgment, given the illiquidity of the second-hand markets for these types of vessels.

The estimated market values for the shuttle tankers were 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 HiLoad DP unit in the table above was based on the present value of expected future cash flows given that there is no market comparable values for this unit. The estimated market value for the FSO unit in the table above was based on second-hand market comparable values for similar vessels. Given the advanced age of these vessels, the estimated market values substantially reflect the price of steel and amount of steel in the vessel.

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

Judgments and Uncertainties. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Shuttle and conventional tankers are depreciated using an estimated useful life of 20 to 25 years commencing the date the vessel is delivered from the shipyard, or a shorter period if regulations prevent us from operating the vessel for the estimated useful life. 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. FSO units are depreciated over the term of the contract. UMS’ are depreciated over an estimated useful life of 35 years commencing the date the unit arrives at the oil field and is in a condition that is ready to operate. Towage vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. However, the actual life of a vessel may be different than the estimated useful life, with a shorter actual useful life resulting in an increase in the quarterly depreciation and 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 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 historical scrap rates. 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, on-going 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, 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 a 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 dry dock each of our shuttle tankers, conventional oil tankers and towage vessels, periodically for inspection, repairs and maintenance and for any modifications to comply with industry certification or governmental requirements. We may dry dock FSO units if we desire to qualify them for shipping classification. We capitalize a substantial portion of the costs we incur during dry docking and amortize those costs on a straight-line basis over the estimated useful life of the dry dock. We immediately expense costs for routine repairs and maintenance performed during dry docking that do not improve or extend the useful lives of the assets.

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, conventional oil 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 and Intangible Assets

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. Certain intangible assets, such as time-charter contracts, are amortized over time. Our future operating performance will be affected by the amortization of intangible assets and potential impairment charges related to goodwill or intangible assets. Accordingly, the allocation of the purchase price to intangible assets and goodwill may significantly affect our future operating results. Goodwill and indefinite-lived assets are not amortized, but reviewed for impairment annually or more frequently if impairment indicators arise. 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.

Judgments and Uncertainties. The allocation of the purchase price of acquired companies to intangible assets and 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.

As of December 31, 2015, the shuttle segment and the towage segment had goodwill 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. These are discussed in more detail in the section entitled “Forward-Looking Statements.”

Aggregate amortization expense of intangible assets for 2015 and 2014 was $3.2 million and $4.0 million, respectively. If actual results are not consistent with our estimates used to value our intangible assets, we may be exposed to an impairment charge and a decrease in the annual amortization expense of our intangible assets. As at December 31, 2015 and 2014, the net book value of intangible assets was $3.2 million and $6.4 million, respectively.

Valuation of Derivative Instruments

Description. Our risk management policies permit the use of derivative financial instruments to manage interest rate and foreign exchange risk. 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 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 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 utilizing 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. 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 income.

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, 2015, we had a valuation allowance of $75.3 million (2014 - $128.4 million).

Item 6.

Directors, Senior Management and Employees

A. Directors and Senior Management

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. The day-to-day affairs of our business are managed by the officers of our general partner and key employees of certain of our controlled affiliates. Employees of certain subsidiaries of Teekay Corporation provide assistance to us pursuant to services agreements. Please see Item 7- Major Unitholders and Related Party transactions.

The Chief Executive Officer and Chief Financial Officer of our general partner, Peter Evensen, allocates his time between managing our business and affairs and the business and affairs of Teekay Corporation and its subsidiaries, including Teekay LNG Partners L.P. (NYSE: TGP) (or Teekay LNG ). Mr. Evensen is also the Chief Executive Officer and Chief Financial Officer of Teekay LNG’s general partner, Teekay GP L.L.C. The amount of time Mr. Evensen allocates among our business and the businesses of Teekay Corporation and Teekay LNG varies from time to time depending on various circumstances and needs of the businesses, such as the relative levels of strategic activities of the businesses. We believe Mr. Evensen devotes sufficient time to our business and affairs as is necessary for their proper conduct.

Officers of our general partner and those individuals providing services to us or our subsidiaries may face a conflict regarding the allocation of their time between our business and the other business interests of Teekay Corporation or its other affiliates. Our general partner intends to seek to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Directors and Executive Officers of Teekay Offshore GP L.L.C.

The following table provides information about the directors and executive officers of our general partner, Teekay Offshore GP L.L.C. Directors are elected for one-year terms. The business address of each of our directors and executive officers listed below is c/o 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Ages of the directors and officers are as of December 31, 2015.


Name	Age	Position
C. Sean Day	66	Chairman ⁽¹⁾
Peter Evensen	57	Chief Executive Officer, Chief Financial Officer and Director
Kenneth Hvid	47	Director
David L. Lemmon	73	Director ⁽¹⁾⁽²⁾
Carl Mikael L.L. von Mentzer	71	Director ⁽¹⁾⁽²⁾
John J. Peacock	72	Director ⁽¹⁾⁽²⁾

(1)	Member of Corporate Governance Committee.

(2)	Member of Audit Committee and Conflicts Committee.

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

C. Sean Day has served as Chairman of Teekay Offshore GP L.L.C. since it was formed in August 2006. Mr. Day has also served as Chairman of the Board of Teekay Corporation since September 1999. He served as Chairman of Teekay GP L.L.C. until 2015 and is currently a board member. He served as Chairman of Teekay Tankers from 2007 until 2013. From 1989 to 1999, Mr. Day was President and Chief Executive Officer of Navios Corporation, a large bulk shipping company based in Stamford, Connecticut. Prior to that, Mr. Day held a number of senior management positions in the shipping and finance industry. He is currently serving as a Director of Kirby Corporation and Chairman of Compass Diversified Holdings. Mr. Day is engaged as a consultant to Kattegat Limited, the parent company of Teekay Corporation’s largest shareholder, to oversee its investments, including that in the Teekay Corporation group of companies.

Peter Evensen has served as Chief Executive Officer, Chief Financial Officer and a Director of Teekay Offshore GP L.L.C. since August 2006. On April 1, 2011, Mr. Evensen became President and Chief Executive Officer of Teekay Corporation and also became a Director of Teekay Corporation. He also serves as Chief Executive Officer, Chief Financial Officer and a Director of Teekay GP L.L.C. He served as a Director of Teekay Tankers Ltd. from 2007 until 2013 and from June 2015 to present. He joined Teekay Corporation in 2003 as Senior Vice President, Treasurer and Chief Financial Officer and in 2006 was appointed Executive Vice President and Chief Strategy Officer. Mr. Evensen has over 30 years of experience in banking and shipping finance. Prior to joining Teekay Corporation, Mr. Evensen was Managing Director and Head of Global Shipping at J.P. Morgan Securities Inc., and worked in other senior positions for its predecessor firms. His international industry experience includes positions in New York, London and Oslo.

Kenneth Hvid has served as a Director of Teekay Offshore GP L.L.C. since April 2011. In May 2015 Mr. Hvid was appointed President and CEO of Teekay Offshore Group Ltd. He served as a Director of Teekay GP L.L.C. from 2011 until June 2015 and as Executive Vice President and Chief Strategy Officer of Teekay Corporation from April 2011 until December 2015. He joined Teekay Corporation in October 2000 and was responsible for leading its global procurement activities until he was promoted in 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 of Teekay Corporation. In that role, he was responsible for Teekay Corporation’s global shuttle tanker business as well as initiatives in the FSO business and related offshore activities. Mr. Hvid has 27 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.

David L. Lemmon has served as a Director of Teekay Offshore GP L.L.C since December 2006. Mr. Lemmon served on the board of directors of Kirby Corporation, a position he held from April 2006, until April 29, 2014. Mr. Lemmon also serves on the board of directors of Deltic Timber Corporation a position he has held since February of 2007. Mr. Lemmon was the President and Chief Executive Office of Colonial Pipeline Company from 1997 until his retirement in March of 2006. Prior to joining Colonial Pipeline Company, he served as President of Amoco Pipeline Company for seven years, as part of a career with Amoco Corporation that spanned 32 years. Mr. Lemmon has served as a member of the board of directors of the American Petroleum Institute, the National Council of Economic Education and the Battelle Energy Advisory Committee. He has served as a member of the Northwestern University Business Advisory Committee and as a guest faculty member at Northwestern University’s Kellogg Graduate School of Management.

Carl Mikael L.L. von Mentzer has served as a Director of Teekay Offshore GP L.L.C. since December 2006. Since 1998, Mr. von Mentzer has served as a non-executive director of Concordia Maritime AB in Gothenburg, Sweden and since 2002, has served as Deputy Chairman of its board of directors until May 2014. Prior to 1998 Mr. von Mentzer served in executive positions with various shipping and offshore service companies, including Gotaverken Arendal AB and Safe Partners AB in Gothenburg, Sweden and OAG Ltd. in Aberdeen, Scotland. He has also previously served as a non-executive director for Northern Offshore Ltd., in Oslo, Norway, and GVA Consultants in Gothenburg, Sweden.

John J. Peacock has served as a Director of Teekay Offshore GP L.L.C. since December 2006. Mr. Peacock retired in February 2007 from Fednav Limited, a Canadian ocean-going, dry-bulk shipowning and chartering group. Joining as Fednav’s Treasurer in 1979, he became Vice-President Finance in 1984 and joined the board of directors. In 1998, Mr. Peacock was appointed Executive Vice-President of Fednav and President and Chief Operating Officer of Fednav International Ltd., the Group’s principal operating subsidiary. Though retired, he continues to serve as a Director. Mr. Peacock has over 40 years accounting experience, and prior to joining Fednav was a partner with Clarkson Gordon (now Ernst & Young) in Montreal, Canada.

B. Compensation

Executive Compensation

Peter Evensen, the Chief Executive Officer and Chief Financial Officer of our general partner, and Kenneth Hvid, a director of our general partner, are each an employee of a subsidiary of Teekay Corporation. Each executive’s compensation (other than any awards under the long-term incentive plan described below) is set and paid by the Teekay Corporation subsidiary, and we reimburse the Teekay Corporation subsidiary for time they spend on our partnership matters.

During 2015, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the officers of the general partner incurred on our behalf excluding any long-term incentive plan awards issued directly by the Partnership as described below, was $2.2 million.

Compensation of Directors

Officers of our general partner or Teekay Corporation who also serve as directors of our general partner do not receive additional compensation for their service as directors. Each of our non-employee directors receives compensation for attending meetings of the Board of Directors, as well as committee meetings. During 2015, each non-employee director, other than the Chair, received a director fee of $50,000 for the year and an award of common units with an aggregate maximum value of approximately $70,000 for the year. The Chair received a director fee of $50,000 and an additional annual fee of $37,500 for the year and an award of common units with a value of approximately $87,500 for the year. In addition, members of the audit, conflicts and corporate governance committees each received an additional committee fee of $5,000 for the year, and the chairs of each committee received an additional fee of $12,000 for the year for serving in that role. In addition, each director was 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 Marshall Islands law.

During 2015, the four non-employee directors received, in the aggregate, $308,500 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. For the year ended December 31, 2015, an aggregate of 14,603 common units, with a grant date fair value of $0.3 million, based on our closing unit price on the grant date, were granted and issued to the non-employee directors of the general partner as part of their annual compensation for 2015.

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 2015, our general partner awarded 102,834 restricted units to certain employees of its affiliates who provide services to our business with a grant date fair value of $2.1 million, based on our closing unit price on the grant date. Each restricted unit is equal in value to one unit of our common units plus reinvested distributions from the grant date to the vesting date. The restricted units vest evenly over a three year period from the grant date. Any portion of a restricted unit award that is not vested on the date of a recipient’s termination of service is cancelled, unless their termination arises as a result of the recipient’s retirement and in this case the restricted unit award will continue to vest in accordance with the vesting schedule. Upon vesting, the value of the restricted units is paid to each grantee in the form of common units or cash.

C. Board Practices

Our general partner’s Board of Directors (or the Board) currently consists of six members. 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 three committees: Audit Committee, Conflicts Committee, and Corporate Governance Committee. The membership of these committees and the function of each of the committees are described below. Each of the committees is currently comprised solely of independent members, and operates under a written charter adopted by the Board, other than the Conflicts Committee. The committee charters for the Audit Committee, the Conflicts Committee and the Corporate Governance Committee are available under “Investors – Teekay Offshore Partners L.P. - Governance” from the home page of our web site at www.teekay.com. During 2015, the Board held six meetings. Each director attended all Board meetings. The members of the Audit Committee, the Conflicts Committee and the Corporate Governance Committee attended all 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 John J. Peacock (Chair), David L. Lemmon and Carl Mikael L.L. von Mentzer. All members of the committee are financially literate and the Board has determined that Mr. Peacock 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 composed of the same directors constituting the Audit Committee, being David L. Lemmon (Chair), John J. Peacock, and Carl Mikael L.L. von Mentzer. The members of the Conflicts Committee may 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 unit holders. 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 comprised of directors Carl Mikael L.L. von Mentzer (Chair), David L. Lemmon, John J. Peacock, and C. Sean Day.

The Corporate Governance Committee:

•

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

•

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; and

•

oversees director compensation and the long-term incentive plan described above.

D. Employees

Crewing and Staff

As of December 31, 2015, approximately 1,400 seagoing staff served on our vessels. Certain subsidiaries of Teekay Corporation employ the crews, who serve on the vessels pursuant to agreements with the subsidiaries. As of December 31, 2015, approximately 166 staff served on shore in technical, commercial and administrative roles in Norway, Brazil and Singapore, compared to approximately 149 staff in Norway, Brazil and Singapore as of December 31, 2014. Teekay Corporation subsidiaries also provide on-shore advisory, operational and administrative support to our operating subsidiaries pursuant to service agreements. Please see Item 7 – Major Unitholders and Related Party transactions – Certain Relationships and Related Party Transactions.

Teekay Corporation regards attracting and retaining motivated seagoing personnel as a top priority, and offers 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.

Teekay Corporation has entered into a Collective Bargaining Agreement with the Philippine Seafarers’ Union, an affiliate of the International Transport Workers’ Federation (or ITF), and a Special Agreement with ITF London, which covers substantially all of the officers and seamen that operate our Bahamian-flagged vessels. 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). Teekay Corporation has 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. Teekay Corporation has entered into a Collective Bargaining Agreement with Norwegian offshore unions (SAFE, Industry Energi and DSO), through our membership in Norwegian Shipowners Association (or NSA). The agreement covers substantially all of the offshore employees on board our FPSOs on the Norwegian Continental Shelf. Teekay Corporation has entered into a Collective Bargaining Agreement with the Fish, Food and Allied Workers Union of Newfoundland and Labrador 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 Teekay Corporation’s relationships with these local labor unions are good.

Our commitment to training is fundamental to the development of the highest caliber of seafarers for marine operations. Teekay Corporation’s cadet training approach is designed to balance academic learning with hands-on training at sea. Teekay Corporation has relationships with training institutions in Canada, Croatia, India, Norway, Philippines, Turkey and the United Kingdom. After receiving formal instruction at one of these institutions, cadet training continues on board vessels. Teekay Corporation also has a career development plan that was devised to ensure a continuous flow of qualified officers who are trained on its vessels and familiarized with its 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, 2015, of our units by all directors and officers of our general partner as a group. The information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules, a person beneficially owns any units that the person has the right to acquire as of February 29, 2016 (60 days after December 31, 2015) through the exercise of any 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 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⁽³⁾

All directors and officers as a group (6 persons) ^(1) (2)		406,784		0.38	%

(1)

Excludes units owned by Teekay Corporation, which controls us and on the board of which serve the directors of our general partner, C. Sean Day and Peter Evensen. Peter Evensen is also the Chief Executive Officer of Teekay Corporation and the Chief Executive Officer of Teekay Offshore GP L.L.C., and a Director of Teekay Offshore GP L.L.C. Kenneth Hvid is a Director of Teekay Offshore GP L.L.C. Please read Item 7: Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for more detail.

(2)	Each director, executive officer and key employee beneficially owns less than 1% of the outstanding units.

(3)	Excludes the 2% general partner interest held by our general partner, a wholly owned subsidiary of Teekay Corporation.

Item 7.

Major Unitholders and Related Party Transactions

A. Major Unitholders

The following table sets forth the beneficial ownership, as of December 31, 2015, of our units by each person we know to beneficially own more than 5% of the outstanding units. The number of 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 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 February 29, 2016 (60 days after December 31, 2015) through the exercise of any unit option or other right. Unless otherwise indicated, each unitholder listed below has sole voting and investment power with respect to the units set forth in the following table:


Identity of Person or Group	Common Units Owned		Percentage of Common Units Owned
Teekay Corporation⁽¹⁾		38,211,772		35.7	%
Advisory Research Inc. ⁽²⁾		6,551,542		6.1	%

(1)	Excludes the 2% general partner interest held by our general partner, a wholly owned subsidiary of Teekay Corporation.

(2)

Includes sole voting power of Advisory Research Inc. as to 6,470,122 units and sole dispositive power of Advisory Research as to 6,551,542 units, and shared voting power and shared dispositive power by Piper Jaffray Companies with respect to such same shares. This information is based on the Schedule 13G filed by this group with the SEC on February 16, 2016.

We are controlled by Teekay Corporation. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of us.

B. Certain Relationships and Related Party Transactions

C. Sean Day is the Chairman of our general partner, Teekay Offshore GP L.L.C. He also is the Chairman of Teekay Corporation, and board member of Teekay GP L.L.C., the general partner of Teekay LNG.

Peter Evensen is the President and Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and Chief Financial Officer of Teekay Offshore GP L.L.C and Teekay GP L.L.C., and a Director of Teekay Corporation, Teekay GP L.L.C., Teekay Offshore GP L.L.C. and Teekay Tankers Ltd.

Kenneth Hvid is a Director of Teekay Offshore GP L.L.C. Mr. Hvid was also Executive Vice President and Chief Strategy Officer of Teekay Corporation until December 2015.

Because Mr. Evensen and Mr. Hvid are employees of a subsidiary of Teekay Corporation, their compensation (other than any awards under the long-term incentive plan) is set and paid by the Teekay Corporation subsidiary. Pursuant to our partnership agreement, we have agreed to reimburse Teekay Corporation for time spent by Mr. Evensen and Mr. Hvid on our partnership matters.

We have entered into an amended and restated omnibus agreement with our general partner, Teekay Corporation, Teekay LNG and related parties. The following discussion describes certain provisions of the omnibus agreement.

Noncompetition. Under the omnibus agreement, Teekay Corporation and Teekay LNG have agreed, and have caused their controlled affiliates (other than us) to agree, not to own, operate or charter certain “Offshore Vessels”. This restriction does not prevent Teekay Corporation, Teekay LNG or any of their other controlled affiliates from, among other things:

•

owning, operating or chartering Offshore Vessels if the remaining duration of the time charter or contract of affreightment for the vessel, excluding any extension options, is less than three years;

•

acquiring Offshore Vessels and related time charters or contracts of affreightment as part of a business or package of assets and operating or chartering those vessels if a majority of the value of the total assets or business acquired is not attributable to the Offshore Vessels and related contracts, as determined in good faith by the board of directors of Teekay Corporation or the conflicts committee of the board of directors of Teekay LNG’s general partner; however, if Teekay Corporation or Teekay LNG completes such an acquisition, it must, within one year after completing the acquisition, offer to sell the Offshore Vessels and related contracts to us for their fair market value plus any additional tax or other similar costs to Teekay Corporation or Teekay LNG that would be required to transfer the Offshore Vessels and contracts to us separately from the acquired business or package of assets;

•

owning, operating or chartering Offshore Vessels and related time charters and contracts of affreightment that relate to tenders, bids or awards for an offshore project that Teekay Corporation or any of its subsidiaries submits or receives; however, at least one year after the delivery date of any such Offshore Vessel, Teekay Corporation must offer to sell the Offshore Vessel and related contract to us, with the vessel valued (i) for newbuildings originally contracted by Teekay Corporation, at its “fully-built-up cost” (which represents the aggregate expenditures incurred (or to be incurred prior to delivery to us) by Teekay Corporation to acquire, construct, and/or convert and bring such Offshore Vessel to the condition and location necessary for our intended use, plus project development costs for completed projects and projects that were not completed but, if completed, would have been subject to an offer to us pursuant to the omnibus agreement) and (ii) for any other vessels, Teekay Corporation’s cost to acquire a newbuilding from a third party or the fair market value of any existing vessel, as applicable, plus in each case any subsequent expenditures that would be included in the “fully-built-up cost” of converting the vessel prior to delivery to us; or

•

acquiring, operating or chartering Offshore Vessels if our general partner has previously advised Teekay Corporation or Teekay LNG 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 apply to any of the Aframax tankers in our current fleet, and the ownership, operation or chartering of any oil tankers that replace any of those oil tankers in connection with certain events. In addition, the restriction does not prevent us from, among other things:

•

acquiring oil tankers or LNG carriers and any related time charters as part of a business or package of assets and operating or chartering those vessels, if a majority of the value of the total assets or business acquired is not attributable to the oil tankers and LNG carriers and any related charters, as determined in good faith by the conflicts committee of our general partner’s board of directors; however, if at any time we complete such an acquisition, we are required to promptly offer to sell to Teekay Corporation the oil tankers and time charters or to Teekay LNG the LNG carriers and time charters for fair market value plus any additional tax or other similar costs to us that would be required to transfer the vessels and contracts to Teekay Corporation or Teekay LNG separately from the acquired business or package of assets; or

•

acquiring, operating or chartering oil tankers or LNG carriers if Teekay Corporation or Teekay LNG, 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 a 30-day right of first offer on certain (a) sales, transfers or other dispositions of any of our Aframax tankers, in the case of Teekay Corporation, or certain LNG carriers in the case of Teekay LNG, or (b) re-charterings of any of our 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 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.

The omnibus agreement and a subsequent agreement also obligated Teekay Corporation to offer to sell to us the Foinaven FPSO, an existing unit of a wholly-owned subsidiary of Teekay Corporation, subject to approvals required from the charterer. The purchase price for the Foinaven FPSO would be its fair market value.

Please read Item 18. – Financial Statements: Note 11 – Related Party Transactions for a description of our various 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. We are not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on us.

Please read Item 18. – Financial Statements: Note 14 – Commitments and Contingencies: Parts i) and j) for a description of the claims made against us.

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

Our general cash distribution policy reflects a basic judgment that our common unitholders are better served by our distributing our available cash (as defined in our partnership agreement and after deducting expenses, including estimated maintenance capital expenditures and reserves) rather than our retaining it. However, commencing with our distribution on common units relating to the fourth quarter of 2015, we have temporarily and significantly reduced the amount of our quarterly per common unit cash distributions. Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. We believe there is currently a dislocation in these markets relative to the stability of our businesses. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, the board of directors of our general partner believes 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, we have temporarily reduced our quarterly distributions on our common units. This reduction in the amount of common unit distributions to establish cash reserves for these purposes is consistent with our cash distribution policy, and the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance capital expenditures and reserves, including reserves for future capital expenditures and for anticipated future credit needs).

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

•

Our unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to 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, 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 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.

•

Under Section 51 of the Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

•

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, maintenance capital expenditures 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, notwithstanding our stated cash distribution policy.

•

If we make distributions out of capital surplus, as opposed to operating surplus (as such terms are defined in our partnership agreement), those distributions will constitute a return of capital and will result in a reduction in the minimum quarterly distribution and the target distribution levels under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus (as defined in our partnership agreement) after the minimum quarterly distribution to our common unitholders and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. Except for transfers of incentive distribution rights to an affiliate or another entity as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to such entity, the approval of a majority of our common units (excluding common units held by our general partner and its affiliates), voting separately as a class, generally is required for a transfer of the incentive distributions rights to a third party prior to December 31, 2016.

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the common unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the common unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the common unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests shown for our general partner include its 2.0% general partner interest and assume the general partner has contributed any capital necessary to maintain its 2.0% general partner interest and has not transferred the incentive distribution rights.


		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.35		98.0	%		2.0	%
First Target Distribution	Up to $0.4025		98.0	%		2.0	%
Second Target Distribution	Above $0.4025 up to $0.4375		85.0	%		15.0	%
Third Target Distribution	Above $0.4375 up to $0.525		75.0	%		25.0	%
Thereafter	Above $0.525		50.0	%		50.0	%

During 2015, cash distributions with respect to the first three quarters of 2015 exceeded $0.4025 per common unit, and were below $0.4025 per common unit with respect to the distribution for the fourth quarter of 2015. Consequently, the assumed distribution of net income resulted in the use of the increasing percentages to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation up to September 30, 2015 and increasing percentages were not used to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation from October 1, 2015 to December 31, 2015.

Item 9.

The Offer and Listing

Our common units are traded on the NYSE under the symbol “TOO”. The following table sets forth the high and low sales prices for our common units on the NYSE for each of the periods indicated:


Year Ended	Dec. 31,		Dec. 31,		Dec. 31,		Dec. 31,		Dec. 31,
	2015		2014		2013		2012		2011

High	$	26.73	$	37.46	$	36.09	$	30.14	$	31.50
Low	$	3.68	$	20.61	$	26.17	$	24.55	$	22.01

Quarter Ended	Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,		Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,		Mar. 31,
	2016		2015		2015		2015		2015		2014		2014		2014		2014

High	$	6.68	$	17.30	$	20.38	$	24.72	$	26.73	$	33.77	$	36.44	$	37.46	$	33.46
Low	$	2.30	$	3.68	$	13.74	$	19.21	$	18.91	$	20.61	$	32.66	$	32.41	$	30.87

Month Ended	Mar. 31,		Feb. 29,		Jan. 31,		Dec. 31,		Nov. 30,		Oct. 31,		Sep. 30,
	2016		2016		2016		2015		2015		2015		2015

High	$	6.68	$	4.62	$	6.50	$	13.44	$	16.72	$	17.30	$	17.75
Low	$	3.00	$	2.30	$	2.63	$	3.68	$	12.51	$	14.38	$	13.76

Our Series A Preferred Units are traded on the NYSE under the symbol “TOOPA”. The following table sets forth the high and low sales prices for our Series A Preferred Units on the NYSE for each of the periods indicated:


Year Ended	Dec. 31,		Dec. 31,		Dec. 31,
	2015		2014		2013⁽¹⁾

High	$	24.00	$	26.83	$	26.46
Low	$	11.70	$	21.85	$	24.01


Quarter Ended	Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,		Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,		Mar. 31,
	2016		2015		2015		2015		2015		2014		2014		2014		2014

High	$	16.84	$	20.15	$	21.44	$	23.41	$	24.00	$	26.03	$	26.83	$	26.60	$	25.80
Low	$	8.02	$	11.70	$	15.68	$	20.12	$	22.07	$	21.85	$	24.63	$	25.05	$	24.31

Month Ended	Mar. 31,		Feb. 29,		Jan. 31,		Dec. 31,		Nov. 30,		Oct. 31,		Sep. 30,
	2016		2016		2016		2015		2015		2015		2015

High	$	16.84	$	14.85	$	16.08	$	17.64	$	20.15	$	19.52	$	18.49
Low	$	14.04	$	8.73	$	8.02	$	11.70	$	15.90	$	16.00	$	15.78

(1)	Period from May 2, 2013 through December 31, 2013.

Our Series B Preferred Units are traded on the NYSE under the symbol “TOOPB”. The following table sets forth the high and low sales prices for our Series B Preferred Units on the NYSE for each of the periods indicated:


Year Ended	Dec. 31,
	2015⁽¹⁾

High	$	25.05
Low	$	12.31

Quarter Ended	Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,
	2016		2015		2015		2015⁽²⁾

High	$	18.20	$	21.83	$	24.32	$	25.05
Low	$	9.08	$	12.31	$	17.02	$	22.82

Month Ended	Mar. 31,		Feb. 29,		Jan. 31,		Dec. 31,		Nov. 30,		Oct. 31,		Sep. 30,
	2016		2016		2016		2015		2015		2015		2015

High	$	18.20	$	17.25	$	18.12	$	18.99	$	21.83	$	21.37	$	20.04
Low	$	15.85	$	10.18	$	9.08	$	12.31	$	15.62	$	17.00	$	17.02

(1)	Period from April 14, 2015 through December 31, 2015.

(2)	Period from April 14, 2015 through June 30, 2015.

Our 6.00% Notes due 2019 are traded on the NYSE under the trading number “EK289435”. The following table sets forth the high and low sales prices for our 6.00% Notes due 2019 on the NYSE for each of the periods indicated:


Year Ended	Dec. 31,		Dec. 31,
	2015		2014⁽¹⁾

High	$	94.50	$	103.47
Low	$	50.50	$	88.75

Quarter Ended	Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,		Mar. 31,		Dec. 31,		Sep. 30,		Jun. 30,
	2016		2015		2015		2015		2015		2014		2014		2014⁽²⁾

High	$	69.85	$	87.14	$	93.00	$	93.99	$	94.50	$	100.00	$	103.47	$	103.47
Low	$	39.60	$	50.50	$	68.90	$	86.50	$	87.20	$	88.75	$	97.81	$	100.00

Month Ended	Mar. 31,		Feb. 29,		Jan. 31,		Dec. 31,		Nov. 30,		Oct. 31,		Sep. 30,
	2016		2016		2016		2015		2015		2015		2015
	$	69.85	$	60.08	$	69.00	$	78.75	$	83.75	$	87.14	$	87.63
High	$	52.02	$	49.92	$	39.60	$	50.50	$	71.50	$	74.00	$	68.90
Low

(1)	Period from May 23, 2014 through December 31, 2014.

(2)	Period from May 23, 2014 through June 30, 2014.

Item 10.

Additional Information

Memorandum and Articles of Association

The information required to be disclosed under Item 10B is incorporated by reference to our Registration Statement on Form 8-A/A filed with the SEC on May 8, 2008.

Material Contracts

The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which we or any of our subsidiaries is a party, for the two years immediately preceding the date of this Annual Report, each of which is included in the list of exhibits in Item 19:

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.

We and certain of our operating subsidiaries have entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which the Teekay Corporation subsidiaries provide us, and our operating subsidiaries with administrative, advisory, technical, strategic consulting services, business development and ship management services for a reasonable fee that includes reimbursement of their direct and indirect expenses incurred in providing these services. Please read Item 7 – Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for a summary of certain contract terms.

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.

Agreement, dated January 25, 2013, for NOK 500,000,000 Senior Unsecured Bonds due January 2016, among us and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.00% per annum.

Agreement, dated January 25, 2013, for NOK 800,000,000 Senior Unsecured Bonds due January 2018, among us and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.75% per annum.

Agreement, dated February 27, 2013, for a commercial facility of U.S. $260,000,000 and a GIEK facility of $70,000,000 between Voyageur L.L.C. and ING Capital L.L.C. The total amount of the debt facility is U.S. $330,000,000. The commercial facility bears interest at LIBOR plus a margin of 3.25%. The amount available under the commercial facility reduces quarterly, with a bullet reduction of $78.8 million on maturity in April, 2018. The GIEK facility bears interest at LIBOR plus a margin of 2.92%. The amount available under the GIEK facility reduces quarterly, with a bullet reduction of $1.7 million on maturity in July 2020.

Agreement, dated September 10, 2013, for U.S. $174,150,000 senior secured bonds due December 2013 between Teekay Shuttle Tanker Finance L.L.C. and Wells Fargo.

Agreement, dated January 30, 2014, for NOK 1,000,000,000 Senior Unsecured Bonds due January 2019, between us and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.25% per annum.

Agreement, dated February 24, 2014, for a U.S. $815,000,000 Secure Term Loan Facility, among Knarr L.L.C., Citibank, N.A. and others, of which $614,944,162 is due through 2026, $120,000,000 is due through 2024 and $80,055,838 is due through 2020. The KEXIM and commercial facilities bear interest at LIBOR plus a margin of 2.75%, the K-Sure facility bears interest at LIBOR plus a margin of 2.10%, the KEXIM guarantee facility bears interest at LIBOR plus a margin of 1.90% and the GIEK facility bears interest at LIBOR plus a margin of 1.20%. The amounts available under all facilities reduce semi-annually, with no bullet reduction on the KEXIM, KEXIM guarantee and K-Sure facilities on maturity in June 2026, no bullet reduction on the GIEK facility with maturity in June 2024 and a bullet reduction of $40.0 million on the commercial facility on maturity in June 2020.

Indenture, dated May 30 2014, for U.S. $300,000,000 Senior Unsecured Bonds due July 2019 in the U.S. bond market, between us and The Bank of New York Mellon. The interest payments on the bonds are fixed at a rate of 6.0%.

Agreement, dated October 14, 2014, for a U.S. $330,000,000 Revolving Credit Facility between us, Den Norske Bank Capital LLC and various other banks. This facility bears interest at LIBOR plus a margin of 2.25%. The purpose of this facility is to refinance the OPCO U.S. $940,000,000 revolving credit facility and the Norsk Teekay Holdings U.S. $455,000,000 revolving credit facility. The amount available under the facility reduces quarterly. As at December 31, 2015, our obligations under the facility are secured by first-priority mortgages granted on 12 of our shuttle tankers and two of our conventional tankers, together with other related security.

Purchase Agreement, dated April 6, 2015, for the purchase of Knarr L.L.C. and Teekay Knarr AS, between us and Teekay Corporation.

Agreement, dated July 31, 2015, for a U.S. $803,711,787 term loan due 2027, among OOGTK Libra GmbH & Co KG, ABN AMRO Bank N.V. and various other banks.

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 dividends, interest or other payments to holders of our securities that are non-resident and not citizens.

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 U.S. 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 the 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; 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 own tax advisors to determine the appropriate tax treatment of the partnership’s ownership of our units.

This discussion does not address any U.S. estate tax considerations or tax considerations arising under the laws of any state, local or non-U.S. jurisdiction. Each unitholder is urged to consult its own 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 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 units by a U.S. Holder who is an individual, trust or estate (or a Non-Corporate U.S. Holder) will be treated as “qualified dividend income” that is taxable to such Non-Corporate U.S. Holder at preferential capital gain tax rates provided that we are not classified as a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (we intend to take the position that we are not now and have never been classified as a PFIC, as discussed below) Any dividends received with respect to our units not eligible for these preferential rates will be taxed as ordinary income to a Non-Corporate U.S. Holder.

Special rules may apply to any “extraordinary dividend” paid by us. Generally, an extraordinary dividend is a dividend with respect to a share of stock if the amount of the dividend is equal to or in excess of 10% of a common stockholder’s, or 5% of a preferred stockholder’s adjusted tax basis (or fair market value in certain circumstances) in such stock. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a shareholder’s adjusted tax basis (or fair market value in certain circumstances). If we pay an “extraordinary dividend” on our 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 (a) 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 (b) U.S.-source gain or loss, as applicable, for foreign tax credit purposes. Non-Corporate U.S. Holders may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.

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

Consequences of Possible PFIC Classification

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either: (i) at least 75% of its gross income is “passive” income; or (ii) at least 50% of the average value of its assets is attributable to assets that produce, or are held for the production of, passive income.

For purposes of these tests, “passive income” includes dividends, interest, gains from the sale or exchange of investment property and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. By contrast, income derived from the performance of services does not constitute “passive income.”

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

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder generally would be subject to different taxation rules depending on whether the U.S. Holder makes a timely and effective election to treat us as a “Qualified Electing Fund” (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. If a U.S. Holder makes a timely QEF election (an Electing Holder), the Electing Holder must report each taxable year for U.S. federal income tax purposes 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 the units in taxable years that we are a PFIC would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were also determined to be PFICs.

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

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election. If we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year (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 owns units, we are a PFIC, and the total value of all PFIC units that such U.S. Holder directly or indirectly 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 own 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 Elections 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 Form 8938. U.S. Individual Holders are encouraged to consult with their own tax advisor regarding the possible application of this disclosure requirement.

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 U.S. trade or business 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 (a) such gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in 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 (b) 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 U.S. trade or business and the disposition of our units is deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on the resulting gain in the same manner as if it were a U.S. Holder.

Information Reporting and Backup Withholding

In general, payments of distributions with respect to, or the proceeds of a disposition of units to a Non-Corporate U.S. Holder will be subject to information reporting requirements. These payments to a Non-Corporate U.S. Holder also may be subject to backup withholding if the Non-Corporate U.S. Holder:

•

fails to 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.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding on payments made to them within the United States, or through a U.S. payor, by certifying their status on IRS Form W-8BEN, W-8BEN-E, W-8ECI or W-8IMY, as applicable.

Backup withholding is not an additional tax. Rather, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by accurately completing and timely filing a U.S. federal income tax return with the IRS.

Non-United States Tax Consequences

Marshall Islands Tax Consequences. Because we and our subsidiaries do not, and we do not expect that we and our subsidiaries will, conduct business or operations in the Republic of The Marshall Islands, and because all documentation related to our initial public offering and follow-on offerings was executed outside of the Republic of The Marshall Islands, under current Marshall Islands law, no taxes or withholdings will be imposed by the Republic of the Marshall Islands on distributions, including upon a return of capital, made to unitholders, so long as such persons are not citizens of and do not reside in, maintain offices in, nor engage in business in the Republic of The Marshall Islands. Furthermore, no stamp, capital gains or other taxes will be imposed by the Republic of The Marshall Islands on the purchase, ownership or disposition by such persons of our common units.

Canadian Federal Income Tax Considerations. The following discussion is a summary of the material Canadian federal income tax considerations under the Income Tax Act (Canada) (or the Canada Tax Act) that we believe are relevant to holders of units who, for the purposes of the Canada Tax Act and the Canada-United States Tax Convention 1980 (or the Canada-U.S. Treaty), are at all relevant times resident in the United States and entitled to all of the benefits of the Canada-U.S. Treaty and who deal at arm’s length with us and Teekay Corporation (or U.S. Resident Holders). This discussion takes into account all proposed amendments to the Canada Tax Act and the regulations thereunder that have been publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof and assumes that such proposed amendments will be enacted substantially as proposed. However, no assurance can be given that such proposed amendments will be enacted in the form proposed or at all.

We are considered to be a partnership under Canadian federal income tax law and therefore not a taxable entity for Canadian income tax purposes. A U.S. Resident Holder will not be liable to tax under the Canada Tax Act on any income or gains allocated by us to the U.S. Resident Holder in respect of such U.S. Resident Holder’s units, provided that (a) we do not carry on business in Canada for purposes of the Canada Tax Act and (b) such U.S. Resident Holder does not hold such units in connection with a business carried on by such U.S. Resident Holder through a permanent establishment in Canada for purposes of the Canada-U.S. Treaty.

A U.S. Resident Holder will not be liable to tax under the Canada Tax Act on any income or gain from the sale, redemption or other disposition of such U.S. Resident Holder’s units, provided that, for purposes of the Canada-U.S. Treaty, such units do not, and did not at any time in the twelve-month period preceding the date of disposition, form part of the business property of a permanent establishment in Canada of such U.S. Resident Holder.

We believe that our activities and affairs are conducted in such a manner that we are not carrying on business in Canada and that U.S. Resident Holders should not be considered to be carrying on business in Canada for purposes of the Canada Tax Act or the Canada-U.S. Treaty solely by reason of the acquisition, holding, disposition or redemption of our units. We intend that this is and continues to be the case, notwithstanding that Teekay Shipping Limited (a subsidiary of Teekay Corporation that is resident and based in Bermuda) provides certain services to Teekay Offshore Partners L.P. and obtains some or all such services under subcontracts with Canadian service providers. If the arrangements we have entered into result in our being considered to carry on business in Canada for purposes of the Canada Tax Act, U.S. Resident Holders would be considered to be carrying on business in Canada and may be required to file Canadian tax returns and, subject to any relief provided under the Canada-U.S. Treaty, would be subject to taxation in Canada on any income that is considered to be attributable to the business carried on by us in Canada. The Canada-U.S. Treaty contains a treaty benefit denial rule which may have the effect of denying relief thereunder from Canadian taxation to U.S. Resident Holders in respect of any income attributable to a business carried on by us in Canada.

Although we do not intend to do so, there can be no assurance that the manner in which we carry on our activities will not change from time to time as circumstances dictate or warrant in a manner that may cause U.S. Resident Holders to be carrying on business in Canada for purposes of the Canada Tax Act. Further, the relevant Canadian federal income tax law may change by legislation or judicial interpretation and the Canadian taxing authorities may take a different view than we have of the current law.

Documents on Display

Documents concerning us that are referred to herein may be inspected at our principal executive offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, 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, or from the SEC’s Public Reference Section at 100 F Street, NE, Washington, D.C. 20549, at prescribed rates. Further information on the operation of the SEC public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330.

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 or NIBOR. 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, we only enter into derivative transactions with counterparties that are rated A- or better by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, 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, 2015 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.


	Expected Maturity Date
																There-						Fair Value
	2016			2017			2018			2019			2020			after			Total			Liability		Rate ⁽¹⁾
	(in millions of U.S. dollars, except percentages)
Long-Term Debt:
Variable Rate ($U.S.)⁽²⁾		411.1			542.8			470.0			284.3			202.3			665.1			2,575.6			2,560.9		2.5	%
Variable Rate (NOK)⁽³⁾		56.5			67.8			90.5			113.1			—			—			327.9			282.4		5.8	%
Fixed Rate Debt ($U.S.)		18.6			26.3			19.9			331.0			19.6			107.7			523.1			414.0		5.1	%
Interest Rate Swaps:
Contract Amount ⁽⁴⁾⁽⁵⁾		443.4			220.3			229.0			106.0			459.9			759.8			2,218.4			236.0		3.2	%
Average Fixed Pay Rate⁽²⁾		2.9	%		1.8	%		1.8	%		2.7	%		2.9	%		4.4	%		3.2	%

(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, 2015 ranged between 0.30% and 3.25% based on LIBOR and between 4.00% and 5.75% based on NIBOR.

(2)	Interest payments on U.S. Dollar-denominated debt and interest rate swaps are based on LIBOR.

(3)

Interest payments on NOK-denominated debt and interest rate swaps are based on NIBOR. Our NOK-denominated debt has been economically hedged with cross currency swaps, to swap all interest and principal payments at maturity into U.S. Dollars. Please see the table in the Foreign Currency Fluctuation Risk section below and read Item 18 – Financial Statements: Note 12 – Derivative Instruments.

(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 six interest rate swaps, which as at December 31, 2015, had a total notional amount of $763.5 million and a total fair value liability of $196.1 million. These interest rate swaps include early termination provisions, which if exercised, would terminate these interest rate swaps in the second half of 2016 and the second half of 2017.

Foreign Currency Fluctuation Risk

Our functional currency is the U.S. Dollars because virtually all of our revenues and most of our operating costs are in U.S. Dollars. We incur certain vessel operating expenses, general and administrative expenses and a portion of our capital conversion and upgrade projects in foreign currencies, the most significant of which is the Norwegian Kroner and, to a lesser extent, Australian Dollar, Brazilian Real, British Pound, Euro and Singapore Dollar. For the years ended December 31, 2015 and 2014, approximately 37.8% and 44.6%, respectively, of vessel operating costs and general and administrative expenses were denominated in Norwegian Kroner. There is a risk that currency fluctuations will have a negative effect on the value of cash flows.

We may continue to seek to hedge these currency fluctuation risks in the future. At December 31, 2015, we were committed to the following foreign currency forward contracts:


									Fair Value / Carrying
	Contract Amount		Average		Expected Maturity				Amount of Asset (Liability)
	in Foreign Currency		Forward		2016		2017		(in thousands of U.S. Dollars)
	(thousands)		Rate⁽¹⁾		(in thousands of U.S. Dollars)				Non-hedge
Norwegian Kroner		590,000		7.62		54,577		22,896		(10,688	)
Euro		11,103		0.91		12,153		—		(45	)
Singapore Dollar		22,442		1.36		16,537		—		(776	)

										(11,509	)

(1)	Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

We incur interest expense on our Norwegian Kroner-denominated bonds. We have entered into cross currency swaps to economically hedge the foreign exchange risk on the principal and interest for these bonds. Please read Item 18 – Financial Statements: Note 12 – Derivative Instruments.

As at December 31, 2015, we were committed to the following cross currency swaps:


Principal		Principal									Fair Value /
Amount		Amount		Floating Rate Receivable							Carrying Amount of
NOK		USD		Reference				Fixed Rate			Asset (Liability)			Remaining
(Thousands)				Rate	Margin			Payable			(Thousands of U.S. Dollars)			Term (years)
	600,000		101,351	NIBOR		5.75	%		7.49	%		(36,504	)		1.1
	500,000		89,710	NIBOR		4.00	%		4.94	%		(33,714	)		0.1
	800,000		143,536	NIBOR		4.75	%		6.07	%		(56,985	)		2.1
	1,000,000		162,200	NIBOR		4.25	%		6.42	%		(56,124	)		3.1

												(183,327	)

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, 2015, we were not committed to any bunker fuel swap contracts.

Item 12.

Description of Securities Other than Equity Securities

Not applicable.

PART II

Item 13.

Defaults, Dividend Arrearages and Delinquencies

Not Applicable.

Item 14.

Material Modifications to the Rights of 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. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2015.

The Chief Executive Officer and Chief Financial Officer 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 controls 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 controls over financial reporting include 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 in accordance with authorizations of management and the directors; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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 controls 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 controls over financial reporting were effective as of December 31, 2015.

Our independent auditors, KPMG 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, 2015.

Item 16A.

Audit Committee Financial Expert

The board of directors of our general partner has determined that director John J. Peacock 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 that applies to all our employees and the employees and directors of our general partner. This document is available under “Investors – Teekay Offshore Partners L.P. – Governance” from the home page of our web site (www.teekay.com). We intend to disclose, under “Investors – Teekay Offshore Partners L.P. – 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 2015 and 2014 was KPMG LLP, Chartered Professional Accountants. The following table shows the fees we paid or accrued for audit services provided by KPMG LLP for 2015 and 2014.


	2015		2014
	(in thousands of U.S. Dollars)
Audit Fees ⁽¹⁾	$	1,033	$	841
Audit-related Fees ⁽²⁾		—		24
Tax Fees ⁽³⁾		23		34

Total	$	1,056	$	899

(1)

Audit fees represent fees for professional services provided in connection with the audit of our consolidated financial statements, 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 follow-on offering of common units and offerings of preferred units.

(2)	For 2014, audit-related fees relate primarily to assistance with general accounting issues.

(3)	For 2015 and 2014, 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 2015.

Item 16D.

Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E.

Purchases of Units by the Issuer and Affiliated Purchasers

Not applicable.

Item 16F.

Change in Registrant’s Certifying Accountant

Not applicable

Item 16G.

Corporate Governance

There are no significant ways in which our corporate governance practices differ from those followed by domestic companies under the listing requirements of the New York Stock Exchange.

Item 16H.

Mine Safety Disclosure

Not applicable.

PART III

Item 17.

Financial Statements

Not applicable.

Item 18.

Financial Statements

The following financial statements, together with the related reports of 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

Consolidated Financial Statements

Consolidated Statements of Income		F - 3

Consolidated Statements of Comprehensive Income		F - 4

Consolidated Balance Sheets		F - 5

Consolidated Statements of Cash Flows		F - 6

Consolidated Statements of Changes in Total Equity		F - 7

Notes to the Consolidated Financial Statements		F - 8

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. (1)

1.2		Fourth Amended and Restated Agreement of Limited Partnership of Teekay Offshore Partners L.P. (2)

1.3		Certificate of Formation of Teekay Offshore GP L.L.C. (1)

1.4		Amended and Restated Limited Liability Company Agreement of Teekay Offshore GP L.L.C. (1)

1.5		Certificate of Limited Partnership of Teekay Offshore Operating L.P. (1)

1.6		Amended and Restated Agreement of Limited Partnership of Teekay Offshore Operating Partners L.P. (1)

1.7		Certificate of Formation of Teekay Offshore Operating GP L.L.C. (1)

1.8		Amended and Restated Limited Liability Company Agreement of Teekay Offshore Operating GP L.L.C. (1)

2.1		Agreement, dated January 25, 2012, among Teekay Offshore Partners L.P. and Norsk Tillitsman ASA for NOK 600,000,000 Senior Unsecured Bonds due 2017. (6)

2.2		Agreement, dated January 25, 2013, among Teekay Offshore Partners L.P. and Norsk Tillitsman ASA for NOK 500,000,000 Senior Unsecured Bonds due 2016. (6)

2.3		Agreement, dated January 25, 2013, among Teekay Offshore Partners L.P. and Norsk Tillitsman ASA for NOK 800,000,000 Senior Unsecured Bonds due 2018. (6)

2.4		Agreement, dated May 29, 2013, between Teekay Offshore Partners L.P. and J.P. Morgan Securities L.L.C. to offer and sell common units having an aggregate offering price of up to $100,000,000 under the Continuous Offering Program. (7)

2.5		Agreement, dated September 10, 2013, between Teekay Shuttle Tanker Finance L.L.C. and Wells Fargo for senior secured bonds $174,150,000 due 2023. (8)

2.6		Agreement, dated January 30, 2014, for NOK 1,000,000,000 Senior Unsecured Bonds due January 2019, between Teekay Offshore Partners L.P. and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.25% per annum. (11)

2.7		Indentures, dated May 30 2014, for U.S. $300,000,000 Senior Unsecured Bonds due July 2019 in the U.S. bond market, between Teekay Offshore Partners L.P. and The Bank of New York Mellon. (9)

2.8		First Supplemental Indenture, dated as of May 30, 2014, among Teekay Offshore Partners L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (9)

2.9		Agreement, dated October 14, 2014, for a U.S. $330,000,000 Revolving Credit Facility between Teekay Offshore Partners L.P., Den Norske Bank Capital LLC and various other banks. (11)

2.10		Purchase Agreement, dated April 6, 2015 for Knarr L.L.C. and Teekay Knarr AS, between Teekay Corporation and Teekay Offshore Partners L.P. (12)

2.11		Agreement, dated February 2, 2015, among Logitel Offshore Rig I Pte.Ltd. and Citibank N.A., London Branch for a U.S. $150,000,000 term loan, of which U.S. $117,000,000 is due 2025 and U.S. $33,000,000 is due 2021. (14)

2.12		Agreement, dated February 6, 2015, among ALP Forward B.V., ALP Ace B.V., ALP Centre B.V., ALP Guard B.V., ALP Winger B.V. and ALP Ippon B.V. and Credit Suisse AG, for a U.S. $150,000,000 term loan due 2023. (14)

2.13		Agreement, dated June 29, 2015, among Petrojarl I L.L.C. and ABN AMRO CAPITAL USA LLC for a U.S. $180,000,000 term loan due 2021. (14)

2.14		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. (14)

2.15		Agreement, dated February 24, 2014 among Knarr L.L.C., Citibank, N.A. and others, for a U.S. $815,000,000 Secure Term Loan Facility Agreement, of which $614,944,162 is due through 2026, $120,000,000 is due through 2024 and $80,055,838 is due through 2020. (15)

4.1		Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. (1)

4.2		Amended and Restated Omnibus Agreement. (1)

4.3		Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Limited. (3)

4.4		Advisory, Technical and Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Limited. (3)

4.5		Administrative Services Agreement between Teekay Offshore Partners L.P. and Teekay Limited. (3)

4.6		Agreement, dated March 8, 2011, between Teekay Holdings Limited and Teekay Offshore Partners L.P., relating to the purchase of limited partner interests of Teekay Offshore Operating L.P. (4)

4.7		Agreement, dated February 23, 2012, among Piranema L.L.C. and Den Norske Bank ASA for a U.S. $130,000,000 debt facility maturing in 2017. (6)

4.8		Business Development Services Agreement between Teekay Offshore Holdings L.L.C. and Teekay Shipping Limited. (6)

4.9		Agreement, dated September 11, 2012, between Teekay Corporation and Teekay Offshore Partners L.P., relating to the purchase of the Voyageur Spirit. (5)

4.10		Agreement, dated February 27, 2013, between Voyageur L.L.C. and ING Capital L.L.C. for U.S. $330,000,000 debt facility due 2020. (8)

8.1		List of Subsidiaries of Teekay Offshore Partners L.P.

10.1		Common Unit Purchase Agreement, dated November 24, 2014, by and among Teekay Offshore Partners L.P. and the purchasers named therein. (10)

10.2		Series C Preferred Unit Purchase Agreement, dated June 30, 2015, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (13)

10.3		Registration Rights Agreement, dated July 1, 2015, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (13)

10.4		Amendment No. 1 to Knarr Purchase Agreement, dated June 29, 2015, by and among Teekay Offshore Partners L.P. and Teekay Corporation. (13)

10.5		Convertible Promissory Note, dated July 1, 2015, made by Teekay Offshore Partners L.P. for the benefit of Teekay Corporation. (13)

12.1		Rule 13a-14(a)/15d-14(a) Certification of Teekay Offshore Partners L.P.’s Chief Executive Officer.

12.2		Rule 13a-14(a)/15d-14(a) Certification of Teekay Offshore Partners L.P.’s Chief Financial Officer.

13.1		Teekay Offshore Partners L.P. Certification of Peter Evensen, Chief Executive Officer and Chief Financial Officer, 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 KPMG LLP, as independent registered public accounting firm.

15.2		Consolidated Financial Statements of OOG TKP FPSO GmbH & Co KG and subsidiaries.

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 an exhibit 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 4.1 to our Report on Form 6-K filed on July 6, 2015 (File No. 1-33198), and hereby incorporated by reference to such Report.

(3)	Previously filed as an exhibit to our Amendment No. 1 to Registration Statement on Form F-1 (File No. 333-139116), filed with the SEC on December 8, 2006, and hereby incorporated by reference to such Registration Statement.

(4)	Previously filed as an exhibit to our Annual Report on Form 20-F (File No.1-33198), filed with the SEC on April 11, 2011, and hereby incorporated by reference to such Report.

(5)	Previously filed as an exhibit to our Report on Form 6-K (File No.1-33198), filed with the SEC on September 11, 2012, and hereby incorporated by reference to such Report.

(6)	Previously filed as an exhibit to our Annual Report on Form 20-F (File No. 33198), filed with the SEC on April 11, 2013, and hereby incorporated by reference to such Report.

(7)	Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on May 29, 2013, and hereby incorporated by reference to such Report.

(8)	Previously filed as an exhibit to our Report on Form 20-F (File No.1-33198), filed with the SEC on April 29, 2014, and hereby incorporated by reference to such Report.

(9)	Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on May 30, 2014, and hereby incorporated by reference to such Report.

(10)	Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 29, 2014, and hereby incorporated by reference to such Report.

(11)	Previously filed as an exhibit to our Report on Form 20-F (File No. 1-33198), filed with the SEC on April 2, 2015, and hereby incorporated by reference to such Report.

(12)	Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on May 28, 2015, and hereby incorporated by reference to such Report.

(13)	Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on July 6, 2015, and hereby incorporated by reference to such Report.

(14)	Previously filed as an exhibit 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.

(15)	Previously filed as an exhibit 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.

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: April 18, 2016	By:	/s/ Peter Evensen
	Peter Evensen Chief Executive Officer and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders of

Teekay Offshore Partners L.P.

We have audited the accompanying consolidated balance sheets of Teekay Offshore Partners L.P. and subsidiaries (the “Partnership”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2015. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, 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), the Partnership’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated April 18, 2016 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

As discussed in Note 2 to the consolidated financial statements, the Partnership has retrospectively changed its method of accounting for debt issuance costs effective December 31, 2015 due to the adoption of Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs.


Vancouver, Canada				/s/ KPMG LLP
April 18, 2016				Chartered Professional Accountants

F - 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Teekay Offshore Partners L.P.

We have audited Teekay Offshore Partners L.P. and subsidiaries (the “Partnership”) internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 Management’s Report on Internal Control over Financial Reporting in the accompanying Form 20-F. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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 U.S. 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.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Partnership as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2015, and our report dated April 18, 2016, expressed an unqualified opinion on those consolidated financial statements.


Vancouver, Canada				/s/ KPMG LLP
April 18, 2016				Chartered Professional Accountants

F - 2

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)

CONSOLIDATED STATEMENTS OF INCOME

(in thousands of U.S. Dollars, except unit and per unit data)


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2015			2014			2013
	$			$			$

Revenues (note 11)		1,229,413			1,019,539			930,739

Voyage expenses		(98,006	)		(112,540	)		(103,643	)
Vessel operating expenses (notes 11 and 12)		(378,480	)		(352,209	)		(344,128	)
Time-charter hire expense		(51,750	)		(31,090	)		(56,682	)
Depreciation and amortization		(274,599	)		(198,553	)		(199,006	)
General and administrative (notes 11, 12 and 17)		(72,613	)		(67,516	)		(44,473	)
(Write down) and gain on sale of vessels (note 19)		(69,998	)		(1,638	)		(76,782	)
Restructuring (charge) recovery (note 10)		(568	)		225			(2,607	)

Income from vessel operations		283,399			256,218			103,418

Interest expense (notes 8, 11 and 12)		(122,838	)		(88,381	)		(62,855	)
Interest income (note 11)		633			719			2,561
Realized and unrealized (losses) gains on derivative instruments (note 12)		(73,704	)		(143,703	)		34,820
Equity income		7,672			10,341			6,731
Foreign currency exchange loss (note 12)		(17,467	)		(16,140	)		(5,278	)
Loss on bond repurchase		—			—			(1,759	)
Other income – net		1,091			781			1,144

Income from continuing operations before income tax recovery (expense)		78,786			19,835			78,782
Income tax recovery (expense) (note 13)		21,357			(2,179	)		(2,225	)

Net income from continuing operations		100,143			17,656			76,557
Net loss from discontinued operations (notes 11 and 19)		—			—			(4,642	)

Net income		100,143			17,656			71,915


Non-controlling interests in net income		13,911			10,503			(19,089	)
Dropdown Predecessor’s interest in net income (note 3)		10,100			—			(2,225	)
Preferred unitholders’ interest in net income (note 16)		28,609			10,875			7,250
General Partner’s interest in net income from continuing operations		16,317			15,658			14,126
General Partner’s interest in net loss from discontinued operations		—			—			(452	)
General Partner’s interest in net income		16,317			15,658			13,674
Limited partners’ interest in net income from continuing operations		31,206			(19,380	)		76,495
Limited partners’ interest in net income from continuing operations per common unit:
- basic (note 16)		0.32			(0.22	)		0.93
- diluted (note 16)		0.32			(0.22	)		0.93
Limited partners’ interest in net loss from discontinued operations		—			—			(4,190	)
Limited partners’ interest in net loss from discontinued operations per common unit:
- basic (note 16)		—			—			(0.05	)
- diluted (note 16)		—			—			(0.05	)
Limited partners’ interest in net income		31,206			(19,380	)		72,305
Limited partners’ interest in net income per common unit:
- basic (note 16)		0.32			(0.22	)		0.88
- diluted (note 16)		0.32			(0.22	)		0.88
Weighted-average number of common units outstanding:
- basic		98,507,732			86,212,290			82,634,000
- diluted		98,602,412			86,212,290			82,659,179

Cash distributions declared per unit		2.1752			2.1536			2.1143

Related party transactions (note 11)

The accompanying notes are an integral part of the consolidated financial statements

F - 3

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands of U.S. Dollars)


	Year Ended		Year Ended			Year Ended
	December 31,		December 31,			December 31,
	2015		2014			2013
	$		$			$
Net income		100,143		17,656			71,915


Other comprehensive income:
Unrealized net gain on qualifying cash flow hedging instruments (note 12)		696		—			6
Realized net loss on qualifying cash flow hedging instruments (note 12)		—		—			52

Other comprehensive income		696		—			58

Comprehensive income		100,839		17,656			71,973

Non-controlling interest in comprehensive income		13,911		10,503			(19,089	)
Preferred unitholders’ interest in comprehensive income		28,609		10,875			7,250
Dropdown Predecessor’s interest in comprehensive income (note 3)		10,100		—			(2,225	)
General and limited partners’ interest in comprehensive income		48,219		(3,722	)		86,037

The accompanying notes are an integral part of the consolidated financial statements.

F - 4

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)

CONSOLIDATED BALANCE SHEETS

(in thousands of U.S. Dollars)


	As at		As at
	December 31,		December 31,
	2015		2014
	$		$
ASSETS
Current
Cash and cash equivalents		258,473		252,138
Restricted cash (note 12)		51,431		4,704
Accounts receivable, including non-trade of $4,140 (December 31, 2014 - $6,825)		153,662		103,665
Vessels held for sale (notes 4a and 19)		55,450		—
Net investments in direct financing lease - current (notes 4b and 9)		5,936		4,987
Prepaid expenses		34,027		30,211
Due from affiliates (note 11k)		81,271		44,225
Advances to joint venture (note 20)		—		5,225
Other current assets (note 12)		20,490		4,626


Total current assets		660,740		449,781


Restricted cash - long-term (note 12)		9,089		42,056

Vessels and equipment
At cost, less accumulated depreciation of $1,230,868 (December 31, 2014 - $1,202,663)		4,348,535		3,010,689
Advances on newbuilding contracts and conversion costs (notes 14b, 14c, 14d, 14f, 14g, 18a and 18b)		395,084		172,776
Net investments in direct financing lease (notes 4b and 9)		11,535		17,471
Investment in equity accounted joint ventures (notes 14e and 20)		77,647		54,955
Deferred tax asset (note 13)		30,050		5,959
Other assets (note 12)		82,341		35,005
Goodwill (note 6a)		129,145		129,145


Total assets		5,744,166		3,917,837

LIABILITIES AND EQUITY
Current
Accounts payable		15,899		15,064
Accrued liabilities (notes 7, 12 and 17)		91,065		68,013
Deferred revenues		54,378		25,669
Due to affiliates (note 11k)		304,583		108,941
Current portion of derivative instruments (note 12)		201,456		85,318
Current portion of long-term debt (note 8)		485,069		257,501
Current portion of in-process revenue contracts (note 6b)		12,779		12,744


Total current liabilities		1,165,229		573,250

Long-term debt (note 8)		2,878,805		2,151,095
Derivative instruments (note 12)		221,329		257,754
In-process revenue contracts (note 6b)		63,026		75,805
Other long-term liabilities		192,258		44,238


Total liabilities		4,520,647		3,102,142

Commitments and contingencies (notes 8, 9, 12 and 14)

Redeemable non-controlling interest (note 14a)		3,173		12,842

Convertible Preferred Units (10.4 million and nil units issued and outstanding at December 31, 2015 and December 31, 2014, respectively) (note 16)		252,498		—

Equity
Limited partners - common units (107.0 million and 92.4 million units issued and outstanding at December 31, 2015 and December 31, 2014, respectively) (note 16)		629,264		589,165
Limited partners - preferred units (11.0 million and 6.0 million units issued and outstanding at December 31, 2015 and December 31, 2014, respectively) (note 16)		266,925		144,800
General Partner		17,608		21,038
Accumulated other comprehensive income		696		—
Non-controlling interests		53,355		47,850


Total equity		967,848		802,853


Total liabilities and equity		5,744,166		3,917,837

Subsequent events (note 21)

The accompanying notes are an integral part of the consolidated financial statements.

F - 5

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of U.S. Dollars)


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2015			2014			2013
	$			$			$
Cash and cash equivalents provided by (used for)
OPERATING ACTIVITIES
Net income		100,143			17,656			71,915
Non-cash items:
Unrealized loss (gain) on derivative instruments (note 12)		51,072			180,156			(91,837	)
Equity income, net of dividends received of $7,843 (2014 - $16,803, 2013 - $nil)		171			6,462			(6,731	)
Depreciation and amortization		274,599			198,553			200,242
Write down and (gain) on sale of vessels (note 19)		69,998			1,638			95,247
Deferred income tax (recovery) expense (note 13)		(23,007	)		889			2,150
Amortization of in-process revenue contracts		(12,745	)		(12,744	)		(12,744	)
Unrealized foreign currency exchange gain and other		(101,853	)		(84,719	)		(35,522	)
Change in non-cash working capital items related to operating activities (note 15a)		25,903			(111,484	)		51,999
Expenditures for dry docking (note 1)		(13,060	)		(36,221	)		(19,332	)

Net operating cash flow		371,221			160,186			255,387


FINANCING ACTIVITIES
Proceeds from long-term debt (note 8)		785,577			1,350,096			1,140,237
Scheduled repayments of long-term debt (note 8)		(341,837	)		(804,704	)		(266,874	)
Prepayments of long-term debt (note 8)		(123,606	)		(418,625	)		(466,781	)
Debt issuance costs		(22,587	)		(15,555	)		(14,797	)
Equity contribution from joint venture partners		5,500			27,267			4,750
Proceeds from issuance of common units (notes 3 and 16)		9,674			186,353			119,588
Proceeds from issuance of preferred units (note 16)		375,000			—			150,000
Expenses relating to equity offerings		(4,459	)		(228	)		(5,837	)
Increase in restricted cash (notes 4 and 12)		(13,760	)		(46,760	)		—
Cash distributions paid by the Partnership		(257,900	)		(214,656	)		(192,142	)
Cash distributions paid by subsidiaries to non-controlling interests		(23,575	)		(27,939	)		(7,750	)
Settlement of contingent consideration liability (note 4a)		(3,303	)		—			—
Purchase of Voyageur LLC from Teekay Corporation (net of $nil indemnification by Teekay Corporation (2014 - $6.2 million, 2013 - $34.9 million) and cash acquired of $nil (2014 - $nil, 2013 - $0.9 million)) (notes 11d and 15e)		—			6,181			(234,125	)
Purchase of Teekay Knarr AS and Knarr L.L.C. from Teekay Corporation (net of cash acquired of $14.2 million) (notes 3 and 15e)		(112,710	)		—			—
Equity contribution from Teekay Corporation to Dropdown Predecessor (note 15f)		—			—			5,596
Other		1,124			974			—

Net financing cash flow		273,138			42,404			231,865


INVESTING ACTIVITIES
Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs		(664,667	)		(172,169	)		(455,578	)
Purchase of equity investment in Itajai FPSO joint venture (net of cash acquired of $1.3 million) (notes 11e and 15e)		—			—			(52,520	)
Proceeds from sale of vessels and equipment		8,918			13,364			27,986
Investments in equity accounted joint ventures		(22,855	)		(12,413	)		—
Repayments (advances) from (to) joint venture partners and equity accounted joint ventures (note 20)		5,225			(5,225	)		—
Direct financing lease payments received		4,987			5,097			5,647
Acquisition of ALP Maritime Services B.V. (net of cash acquired of $0.3 million) (note 18a)		—			(2,322	)		—
Acquisition of Logitel Offshore Holding AS (net of cash acquired of $8.1 million) (note 18b)		—			4,090			—
Proceeds from sale of SPT Explorer L.L.C. and Navigator Spirit L.L.C. (notes 11f and 19)		30,368			—			—

Net investing cash flow		(638,024	)		(169,578	)		(474,465	)


Increase in cash and cash equivalents		6,335			33,012			12,787
Cash and cash equivalents, beginning of the year		252,138			219,126			206,339

Cash and cash equivalents, end of the year		258,473			252,138			219,126

Supplemental cash flow disclosure (note 15)

The accompanying notes are an integral part of the consolidated financial statements.

F - 6

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)

CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL EQUITY

(in thousands of U.S. Dollars and units)


	PARTNERS’ EQUITY
				Limited Partners
						Common											Accumulated
						Units and											Other														Redeemable
	Dropdown					Additional											Comprehensive			Non-						Convertible		Convertible			Non-
	Predecessor			Common		Paid-in			Preferred		Preferred			General			Income			controlling			Total			Preferred		Preferred			controlling
	Equity			Units		Capital			Units		Units			Partner			(Note 12)			Interests			Equity			Units		Units			Interest
	$			#		$			#		$			$			$			$			$			#		$			$
Balance as at December 31, 2012		—			80,106		640,990			—		—			20,162			(58	)		44,135			705,229			—		—			28,815

Net income		(2,225	)		—		72,305			—		7,250			13,674			—			(12,698	)		78,306			—		—			(6,391	)
Other comprehensive income		—			—		—			—		—			—			58			—			58			—		—			—
Cash distributions		—			—		(172,150	)		—		(5,891	)		(14,101	)		—			—			(192,142	)		—		—			—
Distribution to non-controlling interests		—			—		—			—		—			—			—			(1,890	)		(1,890	)		—		—			(5,860	)
Contribution of capital by joint venture partner		—			—		—			—		—			—			—			4,750			4,750			—		—			—
Equity based compensation		—			9		946			—		—			—			—			—			946			—		—			—
Proceeds from equity offering, net of offering costs (note 16)		—			3,891		115,762			6,000		144,800			3,189			—			—			263,751			—		—			—
Purchase of Voyageur LLC from Teekay Corporation (note 11d)		(201,752	)		—		(76,019	)		—		—			(1,551	)		—			—			(279,322	)		—		—			—
Net proceeds from equity offering to Teekay Corporation for purchase of Voyageur LLC (note 11d)		—			1,447		44,268			—		—			—			—			—			44,268			—		—			—
Net change in Teekay Corporation’s equity in Dropdown Predecessor (note 11d)		203,977			—		—			—		—			—			—			—			203,977			—		—			—
Distribution of capital to Teekay Corporation related to acquisition of equity investment in Itajai FPSO joint venture		—			—		(6,459	)		—		—			(131	)		—			—			(6,590	)		—		—			—
Other		—			—		1,359			—		(1,359	)		—			—			—			—			—		—			—

Balance as at December 31, 2013		—			85,453		621,002			6,000		144,800			21,242			—			34,297			821,341			—		—			16,564

Net income		—			—		(19,380	)		—		10,875			15,658			—			2,726			9,879			—		—			7,777
Cash distributions		—			—		(184,286	)		—		(10,875	)		(19,495	)		—			—			(214,656	)		—		—			—
Distribution to non-controlling interests		—			—		—			—		—			—			—			(16,440	)		(16,440	)		—		—			(11,499	)
Contribution of capital from joint venture partner		—			—		—			—		—			—			—			27,267			27,267			—		—			—
Indemnification payment on Voyageur LLC from Teekay Corporation (note 11d)		—			—		6,057			—		—			124			—			—			6,181			—		—			—
Proceeds from equity offering, net of offering costs (note 16)		—			6,918		182,398			—		—			3,727			—			—			186,125			—		—			—
Distribution of capital to Teekay Corporation related to the equity investment in Itajai FPSO joint venture (note 11e)		—			—		(6,082	)		—		—			—			—			—			(6,082	)		—		—			—
Distribution of capital to Teekay Corporation related to the purchase of Petrojarl I FPSO unit (note 11g)		—			—		(12,166	)		—		—			(248	)		—			—			(12,414	)		—		—			—
Equity based compensation and other (note 11f and 17)		—			15		1,622			—		—			30			—			—			1,652			—		—			—

Balance as at December 31, 2014		—			92,386		589,165			6,000		144,800			21,038			—			47,850			802,853			—		—			12,842

Net income		10,100			—		31,206			—		18,260			16,317			—			10,980			86,863			—		10,349			2,931
Other comprehensive income (note 12)		—			—		—			—		—			—			696			—			696			—		—			—
Cash distributions		—			—		(209,177	)		—		(16,925	)		(24,197	)		—			—			(250,299	)		—		(7,601	)		—
Distribution to non-controlling interests		—			—		—			—		—			—			—			(10,975	)		(10,975	)		—		—			(12,600	)
Contribution of capital from joint venture partner		—			—		—			—		—			—			—			5,500			5,500			—		—			—
Proceeds from equity offerings, net of offering costs (note 16)		—			211		3,485			5,000		120,790			71			—			—			124,346			10,438		249,750			—
Net proceeds from equity offering to Teekay Corporation for purchase of Knarr LLC and Teekay Knarr AS (notes 3 and 11h)		—			14,402		300,000			—		—			6,122			—			—			306,122			—		—			—
Purchase of Knarr LLC and Teekay Knarr AS from Teekay Corporation (notes 3 and 11h)		(426,116	)		—		(101,254	)		—		—			(2,066	)		—			—			(529,437	)		—		—			—
Net change in Teekay Corporation’s equity in Dropdown Predecessor (notes 3 and 11h)		416,016			—		—			—		—			—			—			—			416,016			—		—			—
Contribution of capital from sale of SPT Explorer L.L.C. and Navigator Spirit L.L.C. (notes11f and 19)		—			—		14,011			—		—			286			—			—			14,297			—		—			—
Equity based compensation and other (notes 11f and 17)		—			28		1,828			—		—			38			—			—			1,866			—		—			—

Balance as at December 31, 2015		—			107,027		629,264			11,000		266,925			17,608			696			53,355			967,848			10,438		252,498			3,173

The accompanying notes are an integral part of the consolidated financial statements.

F - 7

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, its wholly owned or controlled subsidiaries and the Dropdown Predecessor (see note 3) (collectively, 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.

The Partnership presents non-controlling ownership interests in subsidiaries in the consolidated financial statements within the equity section, but separate from the Partners’ equity. However, the holder of the non-controlling interest of one of the Partnership’s subsidiaries holds a put option which, if exercised, would obligate the Partnership to purchase the non-controlling interest (see note 14a). As a result, the non-controlling interest that is subject to this redemption feature is not included on the Partnership’s consolidated balance sheet as part of the total equity and is presented as redeemable non-controlling interest above the equity section but below the liabilities section.

The Partnership presents its Series C Cumulative Convertible Perpetual Preferred Units (the Series C Preferred Units) in the consolidated financial statements within the equity section, but separate from the Partner’s equity. At any time after the 18-month anniversary of the closing date, at the election of each holder, the Series C Convertible Preferred Units may be converted on a one-for-one basis into common units of the Partnership. The Series C Convertible Preferred Units may be redeemed in cash if a change of control occurs in the Partnership. As a result, the Series C Convertible Preferred Units are not included on the Partnership’s consolidated balance sheet as part of the total equity and are presented as temporary equity above the equity section but below the liabilities section (see note 16).

In the current period, the Partnership has presented debt issuance costs associated with a specific debt instrument as a direct deduction from the carrying amount of that debt liability in the Partnership’s statements of financial position as part of the adoption of Accounting Standards Update 2015-03 (see note 2). Prior to the adoption of ASU 2015-03, all debt issuance costs were presented as other non-current assets in the Partnership’s statements of financial position. All such similar debt issuance costs recorded in comparative periods have been reclassified from non-current assets to current portion of long-term debt and long-term debt, as appropriate, in the Partnership’s statements of financial position.

Foreign currency

The consolidated financial statements are stated in U.S. Dollars and the functional currency of the Partnership and its subsidiaries 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 income.

Operating revenues and expenses

Contracts of Affreightment and Voyage Charters

Revenues from contracts of affreightment and voyage charters are recognized on a proportionate performance method. Shuttle tanker voyages servicing contracts of affreightment with offshore oil fields commence with tendering of notice of readiness at a field, within the agreed lifting range, and ends with tendering of notice of readiness at a field for the next lifting. The Partnership uses a discharge-to-discharge basis in determining proportionate performance for all voyage charters, whereby it recognizes revenue ratably from when product is discharged (unloaded) at the end of one voyage to when it is discharged after the next voyage. The Partnership does not begin recognizing revenue until a charter has been agreed to by the customer and the Partnership, even if the vessel has discharged its cargo and is sailing to the anticipated load port on its next voyage. Towing and offshore installation voyage charter revenue is recognized ratably in proportion to the stage of completion of a project, which is determine based on upon an assessment of the work performed.

Time Charters, Bareboat Charters, FPSO Contracts and UMS Contracts

Operating Leases - The Partnership recognizes revenues from time charters, bareboat charters, floating, production, storage and offloading (or FPSO) contracts and Units for Maintenance and Safety (or UMS) contracts accounted for as operating leases on a straight-line basis daily over the term of the charter as the applicable vessel operates under the charter. Receipt of incentive-based revenue from the Partnership’s FPSO units is dependent upon its operating performance and such revenue is recognized when earned by fulfillment of the applicable performance criteria. The Partnership does not recognize revenue during days that the vessel is off hire unless the contract provides for compensation while off hire.

Direct Financing Leases - Charter contracts that are accounted for as direct financing leases are reflected on the consolidated balance sheets as net investments in direct financing leases. The lease revenue is recognized on an effective interest rate method over the lease term and is included in revenues. Revenue from rendering of services are recognized as the service is performed. Revenues are not recognized during days that the vessel is off hire unless the contract provides for compensation while off hire.

The consolidated balance sheets reflect the deferred portion of revenues and expenses, which will be earned or incurred, respectively, in subsequent periods.

F - 8

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.

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.

Investment in equity accounted joint ventures

The Partnership’s investment in joint ventures is 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 income.

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, less an estimated residual value. Shuttle and conventional tankers are depreciated using an estimated useful life of 20 to 25 years commencing the date the vessel is delivered from the shipyard, or for a shorter period if regulations prevent the Partnership from operating the vessel for the estimated useful life. 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. Floating storage and off take (or FSO) units are depreciated over the term of the contract. UMS are depreciated over an estimated useful life of 35 years commencing the date the unit arrives at the oil field and is in a condition that is ready to operate. Towage vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. Depreciation of vessels and equipment from continuing operations (including depreciation attributable to the Dropdown Predecessor) for the years ended December 31, 2015, 2014 and 2013, totalled $247.8 million, $171.8 million, and $171.4 million, respectively. Depreciation and amortization includes depreciation on all owned vessels.

Interest costs capitalized to vessels and equipment for the years ended December 31, 2015, 2014 and 2013 totaled $10.3 million, $2.3 million and $19.6 million, respectively.

Generally, the Partnership dry docks each shuttle tanker, conventional oil tanker and towage 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.

F - 9

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)

Dry-docking activity for the three years ended December 31, 2015, 2014 and 2013 is summarized as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2015			2014			2013
	$			$			$
Balance at beginning of the year		54,259			41,535			45,909
Cost incurred for dry docking		14,609			36,221			19,020
Dry-docking amortization relating to continuing operations		(23,863	)		(22,682	)		(22,559	)
Dry-docking amortization relating to discontinued operations		—			—			(360	)
Write down / sale of capitalized dry-dock expenditure		(2,183	)		(815	)		(475	)

Balance at end of the year		42,822			54,259			41,535

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.

Direct financing leases

The long-term time charter of one of the Partnerships vessels is accounted for as a direct financing lease, with lease payments received by the Partnership being allocated between the net investment in the lease and revenue using the effective interest method so as to produce a constant periodic rate of return over the lease term.

Debt issuance costs

Debt issuance costs related to a recognized debt liability, including fees, commissions and legal expenses, are deferred and presented as a direct deduction from the carrying amount of that debt liability and amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included in interest expense. If the debt issuance costs are not attributable to a specific debt liability or the debt issuance costs exceed the carrying value of the related debt liability, the debt issuance costs are deferred and presented as other non-current assets and amortized on an effective interest rate method over the term of the relevant loan.

Goodwill and intangible assets

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 may elect to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Alternatively, the Partnership may bypass this step and use a fair value approach to identify potential goodwill impairment and, when necessary, measure the amount of impairment. The Partnership uses a discounted cash flow model to determine the fair value of reporting units, unless there is a readily determinable fair market value. Intangible assets are assessed for impairment when and if impairment indicators exist. An impairment loss is recognized if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

The Partnership’s intangible assets are amortized over their respective lives with the amount amortized each year being weighted based on the projected revenue to be earned under the contracts.

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 for hedge accounting. The Partnership does not apply hedge accounting to its derivative instruments, except for certain foreign exchange currency contracts, certain types of interest rate swaps and certain interest rate swaps in its equity accounted joint ventures (see note 12).

When a derivative is designated as 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 no longer possible of occurring.

For derivative financial instruments designated and qualifying as 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 income. The ineffective portion of the change in fair value of the derivative financial instruments is immediately recognized in earnings in the consolidated statements of income. If a cash flow hedge is terminated and the originally hedged item is still considered possible of occurring, the gains and losses initially recognized in 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 income. If the hedged item is no longer possible of occurring, amounts recognized in equity are immediately transferred to the earnings line item in the consolidated statements of income.

F - 10

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)

For derivative financial instruments that are not designated or that do not qualify as accounting hedges under Financial Accounting Standards Board (or FASB) Accounting Standards Codification (or ASC) 815, Derivatives and Hedging, 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 (losses) gains on derivative instruments in the consolidated statements of income. Gains and losses from the Partnership’s non-designated cross currency swaps are recorded in foreign currency exchange loss in the consolidated statements of income.

Unit-based compensation

The Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership (see note 17). The Partnership measures the cost of such awards using 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. Unit-based compensation expenses are recorded under general and administrative expenses in the Partnership’s consolidated statements of income.

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 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 recovery (expense) in the Partnership’s consolidated statements of income.

2.	Accounting Pronouncements

In April 2014, the FASB issued Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (or ASU 2014-08) which raises the threshold for disposals to qualify as discontinued operations. A discontinued operation is now defined as: (i) a component of an entity or group of components that has been disposed of or classified as held for sale and represents a strategic shift that has or will have a major effect on an entity’s operations and financial results; or (ii) an acquired business that is classified as held for sale on the acquisition date. ASU 2014-08 also requires additional disclosures regarding discontinued operations, as well as material disposals that do not meet the definition of discontinued operations. The Partnership prospectively adopted ASU 2014-08 effective on January 1, 2015. The impact of adopting ASU 2014-08 on the Partnership’s financial statements was that the Partnership’s disposition of its conventional tankers during 2015 were not presented as discontinued operations on the Partnership’s financial statements (see note 19).

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, (or ASU 2014-09). ASU 2014-09 will require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update creates a five-step model that requires entities to exercise judgment when considering the terms of the contract(s) which include (i) identifying the contract(s) with the customer, (ii) identifying the separate performance obligations in the contract, (iii) determining the transaction price, (iv) allocating the transaction price to the separate performance obligations, and (v) recognizing revenue as each performance obligation is satisfied. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 and shall be applied, at the Partnership’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is evaluating the effect of adopting this new accounting guidance.

In February 2015, the FASB issued Accounting Standards Update 2015-02, Amendments to the Consolidation Analysis (or ASU 2015-02) which eliminates the deferral of certain consolidation standards for entities considered to be investment companies, modifies the consolidation analysis performed on limited partnerships and modifies the impact of fee arrangements and related parties on the determination of the primary beneficiary of a variable interest entity. The Partnership adopted ASU 2015-02 on January 1, 2016 and the adoption did not have a material impact on the Partnership.

F - 11

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 April 2015, the FASB issued Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs (or ASU 2015-03). The Partnership adopted ASU 2015-03 effective December 31, 2015. Prior period information has been retrospectively adjusted. Prior to the adoption of ASU 2015-03, all debt issuance costs were presented as other non-current assets in the Partnership’s consolidated balance sheets. With the adoption of ASU 2015-03 the Partnership presents those debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability in the Partnership’s consolidated balance sheets. Debt issuance costs related to loan facilities without a recognized debt liability will continue to be presented as non-current assets in the Partnership’s consolidated balance sheets. As a result of adopting ASU 2015-03, non-current assets and total assets has decreased by $61.5 million (December 31, 2015) and $27.4 million (December 31, 2014), current portion of long-term debt and current liabilities has decreased by $1.2 million (December 31, 2015) and $0.5 million (December 31, 2014), long-term debt has decreased by $60.3 million (December 31, 2015) and $26.9 million (December 31, 2014) and total liabilities has decreased by $61.5 million (December 31, 2015) and $27.4 million (December 31, 2014). Such changes have also impacted the Partnership’s reconciliation of segment assets to total assets (see note 5) and the carrying value of long-term debt (see notes 4 and 8).

In November 2015, the FASB issued Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes (or ASU 2015-17), amending the accounting for income taxes and requiring all deferred tax assets and liabilities to be classified as non-current on the consolidated balance sheet. ASU 2015-17 is effective for reporting periods beginning after December 15, 2016, with early adoption permitted, and may be adopted either prospectively or retrospectively. The Partnership adopted ASU 2015-17 effective December 31, 2015 and ASU 2015-17 was prospectively applied in the Partnerships consolidated financial statements.

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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is evaluating the effect of adopting this new accounting guidance.

3.	Dropdown Predecessor

The Partnership has accounted for the acquisition of interests in vessels from Teekay Corporation as a transfer of net assets between entities under common control. The method of accounting for such transfers is similar to the pooling of interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. The excess of the proceeds paid, if any, by the Partnership over Teekay Corporation’s historical cost is accounted for as an equity distribution to Teekay Corporation. In addition, acquisition of vessels from Teekay Corporation that are businesses are accounted for as if the acquisition occurred on the date that the Partnership and the acquired vessels were both under the common control of Teekay Corporation and had begun operations. As a result, the Partnership’s financial statements prior to the date the interests in these vessels were actually acquired by the Partnership are retroactively adjusted to include the results of these vessels during the periods they were under common control of Teekay Corporation and had begun operations.

a)	*Voyageur L.L.C. acquisition*

On May 2, 2013, the Partnership acquired from Teekay Corporation its 100% interest in Voyageur L.L.C. for an original purchase price of $540.0 million that was effectively reduced to $503.1 million (see note 11d). Voyageur L.L.C. owns the Voyageur Spirit (referred to herein as the Dropdown Predecessor), an FPSO unit, which operates on the Huntington Field in the North Sea under a five-year contract, plus up to 10 one-year extension options, with E.ON Ruhrgas UK GP Limited (or E.ON) as the charterer.

The $71.4 million excess of the purchase price over Teekay Corporation’s carrying value of the Dropdown Predecessor has been accounted for as an equity distribution to Teekay Corporation. In addition, the acquisition of the Dropdown Predecessor has been accounted for as if the acquisition occurred from the date that the Partnership and the Voyageur Spirit FPSO were both under the common control of Teekay Corporation and had begun operations.

As a result, the Partnership’s financial statements prior to the Partnership’s May 2, 2013 acquisition of the Dropdown Predecessor are retroactively adjusted to include the financial results of the Dropdown Predecessor as if the Partnership had acquired it when the Voyageur Spirit FPSO had commenced operations under the control of Teekay Corporation on April 13, 2013. This had the effect of decreasing the Partnership’s net income by $2.2 million for the year ended December 31, 2013.

Teekay Corporation uses a centralized treasury system. As a result, cash and cash equivalents attributable to the operations of the Dropdown Predecessor were in certain cases co-mingled with cash and cash equivalents from other operations of Teekay Corporation. The cash and cash equivalents balances are not reflected in the balance sheet of the Dropdown Predecessor. However, any cash transactions from these bank accounts that were made on behalf of companies in the Dropdown Predecessor, which were acquired by the Partnership, are reflected as increases or decreases of advances from affiliates. Any other cash transactions from these bank accounts that were directly related to the operations of the Dropdown Predecessor are reflected as increases or decreases in owner’s equity in the Partnership’s financial statements.

The consolidated financial statements reflect the consolidated financial position, results of operations and cash flows of the Partnership and its subsidiaries, including, as applicable, the Dropdown Predecessor. In the preparation of these consolidated financial statements interest expense and realized and unrealized (losses) gains on derivative instruments were not identifiable as relating solely to each specific vessel. Amounts have been allocated to the Dropdown Predecessor for interest expense of $0.3 million and realized and unrealized losses (gains) on derivative instruments of $0.1 million for the year ended December 31, 2013. Management believes these allocations reasonably present the interest expense and realized and unrealized (losses) gains on derivative instruments of the Dropdown Predecessor. Estimates have been made when allocating expenses from Teekay Corporation to the Dropdown Predecessor and such estimates may not be reflective of actual results.

F - 12

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)

b)	*Teekay Knarr AS and Knarr L.L.C. acquisition*

On July 1, 2015, the Partnership acquired from Teekay Corporation its 100% interest in Teekay Knarr AS and Knarr L.L.C. (the Knarr Companies). The purchase price of $529.4 million was based on the $1.26 billion fully built-up cost of the Petrojarl Knarr, a FPSO unit, and consisted of actual costs incurred for construction and mobilization of the unit less cash generated from operations during March 9, 2015 to July 1, 2015, plus $14.5 million of working capital of the Knarr Companies less $745.1 million of assumed debt. The purchase price was primarily financed with a $492.0 million convertible promissory note issued to Teekay Corporation. The convertible promissory note is due in full on July 1, 2016 and is interest bearing at an annual rate of 6.5% on the outstanding principal balance (see note 11k). Of the remaining $37.4 million for the purchase price, $35.0 million was paid in cash by the Partnership to Teekay Corporation upon the acquisition of the Knarr Companies. During July 2015, $300.0 million of the convertible promissory note was converted into 14.4 million common units of the Partnership and the Partnership repaid an additional $92.0 million of the convertible promissory note. Concurrent with the conversion of the promissory note, Teekay Corporation contributed $6.1 million to the Partnership to maintain its 2% general partner interest. The Petrojarl Knarr operates on the Knarr oil and gas field in the North Sea under a ten-year fixed-rate charter contract, which includes annual termination fees payable by the charterer to cancel the contract after the sixth year in operations, plus extension options, with BG Norge Limited, which is owned by Royal Dutch Shell Plc, as the operator.

The $103.3 million excess of the purchase price over Teekay Corporation’s carrying value of the Knarr Companies has been accounted for as an equity distribution to Teekay Corporation. In addition, the acquisition of the Knarr Companies has been accounted for as if the acquisition occurred from the date that the Partnership and the Petrojarl Knarr FPSO were both under the common control of Teekay Corporation and had begun operations.

As a result, the Partnership’s financial statements prior to the Partnership’s July 1, 2015 acquisition of the Knarr Companies are retroactively adjusted to include the financial results of the Knarr Companies as if the Partnership had acquired them when the Petrojarl Knarr FPSO had commenced operations under the control of Teekay Corporation on March 9, 2015. This had the effect of increasing the Partnership’s revenue by $69.5 million and net income by $10.1 million for the year ended December 31, 2015.

4.	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 value of the Partnership’s cash and cash equivalents and restricted cash approximate their carrying amounts reported in the accompanying consolidated balance sheets.

Vessels and equipment and vessels held for sale – The estimated fair value of the Partnership’s vessels and equipment and vessels held for sale is determined based on 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 generally the amount the Partnership would expect to receive if it were to sell the vessel. Such appraisal is normally completed by the Partnership.

Contingent consideration liabilities

In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS (Logitel), a Norway-based company focused on high-end UMS, from Cefront Technology AS (Cefront) for $4 million, which was paid in cash at closing, plus a potential additional amount of up to $27.6 million, depending on certain performance criteria, which is payable from mid-2015 through to mid-2020 (see note 18b).

The Partnership will owe the additional amount of up to $27.6 million if: there are no yard cost overruns and no charterer late delivery penalties; the two unchartered UMS under construction are chartered above specified rates; and no material defects from construction are identified within one year after the delivery of each UMS. To the extent such events occur, the potential additional amount of $27.6 million will be reduced in accordance with the terms of the purchase agreement. The estimated fair value of the contingent consideration liability of $14.8 million at December 31, 2015 is the amount the Partnership expects to pay to Cefront discounted to its present value using a weighted average cost of capital rate of 11.5%. As of December 31, 2015, the amount of the expected payments for each UMS was based upon the status of the construction project for the remaining two UMS newbuildings, the state of the charter market for the remaining two UMS newbuildings, the expectation of potential material defects for each UMS, and, to a lesser extent, the timing of delivery of the remaining two UMS newbuildings. An increase (decrease) in the Partnership’s estimates of yard cost overruns, charterer late delivery penalties, material defects and the discount rate, as well as a decrease (increase) in the Partnership’s estimates of day rates at which it expects to charter the two unchartered UMS, will decrease (increase) the estimated fair value of the contingent consideration liability.

F - 13

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)

Changes in the estimated fair value of the Partnership’s contingent consideration liability relating to the acquisition of Logitel, which is measured at fair value on a recurring basis using significant unobservable inputs (Level 3), during the years ended December 31, 2015 and 2014, is as follows:


	Year ended			Year ended
	December 31, 2015			December 31, 2014
	$			$
Balance at beginning of period		(21,448	)		—
Acquisition of Logitel		2,569			(21,170	)
Settlement of liability		3,540			—
Unrealized gain (loss) included in Other income – net		509			(278	)

Balance at end of period		(14,830	)		(21,448	)

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 analyses based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

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, however collateral is required by these institutions on some of the Partnership’s cross currency swap agreements and as at December 31, 2015 the Partnership had $60.5 million held as collateral (2014 - $46.8 million), which has been recorded as restricted cash and restricted cash – long-term on the Partnerships consolidated balances sheets. Given the current volatility in the credit markets, it is reasonably possible that the amount recorded as a derivative liability could vary by a material amount in the near term.

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.

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, 2015						December 31, 2014
	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		318,993			318,993			298,898			298,898
Logitel contingent consideration (see above)	Level 3		(14,830	)		(14,830	)		(21,448	)		(21,448	)
Derivative instruments (note 12)
Interest rate swap agreements	Level 2		(235,998	)		(235,998	)		(216,488	)		(216,488	)
Cross currency swap agreement	Level 2		(183,327	)		(183,327	)		(120,503	)		(120,503	)
Foreign currency forward contracts	Level 2		(11,509	)		(11,509	)		(11,268	)		(11,268	)

Non-Recurring:
Vessels held for sale (note 19)	Level 2		55,450			55,450			—			—
Vessels and equipment (note 19)	Level 2		100,600			100,600			—			—

Other:
Long-term debt - public (note 8)	Level 1		(620,746	)		(473,729	)		(679,257	)		(656,899	)
Long-term debt - non-public (note 8)	Level 2		(2,743,128	)		(2,783,597	)		(1,729,339	)		(1,743,378	)

F - 14

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)

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, 2015
$

Year Ended
December 31, 2014
$

Direct financing leases

Payment activity

Performing

17,471

22,458

5.	Segment Reporting

The Partnership is engaged in the international marine transportation of crude oil, the offshore processing and storage of crude oil, long-haul ocean towage and offshore installation services, and maintenance and safety services through the operation of its oil tankers, FSO units, FPSO units, towage vessels and UMS. The Partnership’s revenues are earned in international markets.

The Partnership has six reportable segments: its shuttle tanker segment; its FPSO segment; its FSO segment; its conventional tanker segment; its towage segment; and its UMS segment. 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 FPSO segment consists of its FPSO units to service its FPSO 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 conventional tanker segment consists of conventional tankers operating on fixed-rate, time-charter contracts, bareboat charter contracts, or spot voyage charters. The Partnership’s towage segment consists of four long-haul towing and anchor handling vessel newbuildings scheduled for delivery in 2016 and six on-the-water long-distance towing and anchor handling vessels, which operate on time-charter or voyage-charter towage contracts. The Partnership’s UMS segment consists of three units, of which one was delivered in early-2015 and the remaining two units are scheduled to deliver in late-2016 and, subject to the exercise of a deferred delivery option, mid-2019. These units are expected to operate on fixed-rate time-charter contracts. The results below exclude results included in discontinued operations. Segment results are evaluated based on income from vessel operations. The accounting policies applied to the reportable segments are the same as those used in the preparation of the Partnership’s consolidated financial statements.

The following table presents revenues and percentage of consolidated revenues for customers that accounted for more than 10% of the Partnership’s consolidated revenues from continuing operations during the periods presented.


	Year Ended	Year Ended	Year Ended
	December 31,	December 31,	December 31,
(U.S. Dollars in millions)	2015	2014	2013
Royal Dutch Shell Plc⁽¹⁾⁽²⁾	$315.3 or 26%	— ⁽⁵⁾	— ⁽⁵⁾
Petroleo Brasileiro S.A.⁽¹⁾	$224.6 or 18%	$228.1 or 22%	$228.9 or 25%
Statoil ASA⁽³⁾	$132.7 or 11%	$194.3 or 19%	$183.0 or 20%
E.ON⁽⁴⁾	$129.2 or 11%	$120.2 or 12%	— ⁽⁵⁾
Repsol S.A.⁽⁴⁾	— ⁽⁵⁾	$112.6 or 11%	$122.1 or 13%

(1)	Shuttle tanker and FPSO segments

(2)	In February 2016, Royal Dutch Shell Plc acquired BG Group Plc and therefore includes revenues from both Royal Dutch Shell Plc and BG Group Plc for the periods presented

(3)	Shuttle tanker segment

(4)	FPSO segment

(5)	Percentage of consolidated revenue was less than 10%

The following tables include results for the Partnership’s shuttle tanker segment, FPSO unit segment, FSO unit segment, conventional tanker segment, towage segment and UMS segment for the periods presented in these consolidated financial statements. The results below exclude three conventional tankers determined to be discontinued operations (see note 19).


Year ended December 31, 2015
	Shuttle			FPSO						Conventional
	Tanker			FPSO			FSO			Tanker			Towage			UMS
	Segment			Segment			Segment			Segment			Segment			Segment			Total
Revenues		541,792			531,554			57,391			30,230			40,112			28,334			1,229,413
Voyage expenses		(82,777	)		—			(851	)		(2,326	)		(12,052	)		—			(98,006	)
Vessel operating expenses		(128,156	)		(189,900	)		(26,394	)		(6,234	)		(13,920	)		(13,876	)		(378,480	)
Time-charter hire expense		(51,088	)		—			—			—			(662	)		—			(51,750	)
Depreciation and amortization		(106,190	)		(137,914	)		(11,775	)		(6,583	)		(8,362	)		(3,775	)		(274,599	)
General and administrative ⁽¹⁾⁽²⁾		(22,884	)		(38,588	)		(1,372	)		(1,062	)		(4,598	)		(4,109	)		(72,613	)
(Write down) and gain on sale of vessel		(65,101	)		—			—			(3,897	)		—			(1,000	)		(69,998	)
Restructuring charge		(568	)		—			—			—			—			—			(568	)

Income from vessel operations		85,028			165,152			16,999			10,128			518			5,574			283,399

Equity income		—			7,672			—			—			—			—			7,672
Investment in joint venture		—			77,647			—			—			—			—			77,647
Expenditures for vessels and equipment,including advances on newbuilding contracts and conversion costs⁽³⁾		26,980			116,473			94,317			97			243,436			183,364			664,667
Expenditures for dry docking		14,609			—			—			—			—			—			14,609

F - 15

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, 2014
	Shuttle Tanker Segment			FPSOSegment⁽⁴⁾			FSO Segment			Conventional Tanker Segment			Towage Segment			UMS Segment			Total
Revenues		577,064			354,518			53,868			33,566			523			—			1,019,539
Voyage expenses		(105,562	)		—			(1,500	)		(5,373	)		(105	)		—			(112,540	)
Vessel operating expenses		(159,438	)		(158,216	)		(28,649	)		(5,906	)		—			—			(352,209	)
Time-charter hire expense		(31,090	)		—			—			—			—			—			(31,090	)
Depreciation and amortization		(110,686	)		(72,905	)		(8,282	)		(6,680	)		—			—			(198,553	)
General and administrative⁽¹⁾⁽²⁾		(29,154	)		(27,406	)		(3,870	)		(2,136	)		(4,328	)		(622	)		(67,516	)
(Write down) and gain on sale of vessels		(1,638	)		—			—			—			—			—			(1,638	)
Restructuring recovery		225			—			—			—			—			—			225

Income (loss) from vessel operations		139,721			95,991			11,567			13,471			(3,910	)		(622	)		256,218

Equity income		—			10,341			—			—			—			—			10,341
Investment in joint venture		—			54,955			—			—			—			—			54,955
Expenditures for vessels and equipment,including advances on newbuilding contracts and conversion costs⁽⁵⁾		50,096			17,022			33,734			251			59,516			11,550			172,169
Expenditures for dry docking		22,552			—			11,560			2,109			—			—			36,221

Year ended December 31, 2013
	Shuttle Tanker Segment			FPSOSegment⁽⁴⁾			FSO Segment			Conventional Tanker Segment			Towage Segment			UMS Segment			Total
Revenues		552,019			284,932			59,016			34,772			—			—			930,739
Voyage expenses		(99,543	)		—			432			(4,532	)		—			—			(103,643	)
Vessel operating expenses		(152,986	)		(152,616	)		(32,713	)		(5,813	)		—			—			(344,128	)
Time-charter hire expense		(56,682	)		—			—			—			—			—			(56,682	)
Depreciation and amortization		(115,913	)		(66,404	)		(10,178	)		(6,511	)		—			—			(199,006	)
General and administrative⁽¹⁾		(21,821	)		(17,742	)		(2,553	)		(2,357	)		—			—			(44,473	)
Write down and loss on sale of vessels		(76,782	)		—			—			—			—			—			(76,782	)
Restructuring charge		(2,169	)		—			—			(438	)		—			—			(2,607	)

Income from vessel operations		26,123			48,170			14,004			15,121			—			—			103,418

Equity income		—			6,731			—			—			—			—			6,731
Investment in joint venture		—			52,120			—			—			—			—			52,120
Expenditures for vessels and equipment,including advances on newbuilding contracts and conversion costs⁽⁶⁾		427,069			28,260			181			68			—			—			455,578
Expenditures for dry docking		17,487			—			—			1,533			—			—			19,020

(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)

General and administrative expenses for the year ended December 31, 2015 includes business development fees of $9.7 million, $2.2 million and $2.0 million to Teekay Corporation in connection with the acquisition of the Knarr Companies in the FPSO segment, six long-distance towing and offshore installation vessels in the towage segment, and the Arendal Spirit UMS in the UMS segment, respectively (see notes 3 and 18b).

General and administrative expenses for the year ended December 31, 2014 includes a $1.0 million fee to a third party associated with the acquisition of ALP Maritime Services B.V. (or ALP), a $1.6 million business development fee to Teekay Corporation for assistance with the acquisition of ALP, both of which fees have been allocated to the Partnership’s towage segment, and also includes a $2.1 million fee to Teekay Corporation for assistance with securing a charter contract for the Petrojarl I FPSO unit (or Petrojarl I), which fee has been allocated to the Partnership’s FPSO segment. (see notes 11j and 18a).

(3)	Excludes the purchase price of the Petrojarl Knarr FPSO unit (see notes 3 and 11h).

(4)

Income from vessel operations for the year ended December 31, 2014 excludes $3.1 million of the Voyageur Spirit FPSO unit indemnification payments received from Teekay Corporation relating to the production shortfall during the period from January 1, 2014 through February 21, 2014 and a further $0.4 million relating to unreimbursed vessel operating expenses incurred before the unit was declared on-hire as of February 22, 2014.

Income from vessel operations for the year ended December 31, 2013 excludes $31.3 million of indemnification payments received from Teekay Corporation relating to production shortfalls for both the Dropdown Predecessor period from April 13, 2013 to May 1, 2013 and the period during which the unit was owned by the Partnership from May 2, 2013 to December 31, 2013 as the Voyageur Spirit FPSO unit was declared off-hire retroactive to first oil given the delay in achieving final acceptance from the charterer.

These indemnification payments received from Teekay Corporation have effectively been treated as a reduction to the purchase price of the Voyageur Spirit (see note 11d).

(5)	Excludes the vessel and equipment acquired in conjunction with the purchase of Logitel (note 18b) and Petrojarl I (note 11g).

(6)	Excludes the purchase price of the Voyageur Spirit (note 11d) and the Itajai (note 11e) FPSO units.

F - 16

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 reconciliation of total segment assets to total assets presented in the accompanying consolidated balance sheets is as follows:


	December 31, 2015 $		December 31, 2014 $
Shuttle tanker segment		1,732,769		1,929,636
FPSO segment		2,717,193		1,261,569
FSO segment		281,776		133,341
Conventional tanker segment		63,900		150,044
Towage segment		309,009		61,795
UMS segment		267,935		62,017
Unallocated:
Cash and cash equivalents and restricted cash		318,993		298,898
Other assets		52,591		20,537

Consolidated total assets		5,744,166		3,917,837

6.	Goodwill, Intangible Assets and In-Process Revenue Contracts

Goodwill

The carrying amount of goodwill for the shuttle tanker segment was $127.1 million as at December 31, 2015 and 2014. In 2015, 2014 and 2013, the Partnership conducted a goodwill impairment review of its shuttle tanker segment and concluded that no impairment had occurred.

The carrying amount of goodwill for the towage segment was $2.0 million as at December 31, 2015 and 2014. In 2015 and 2014, the Partnership conducted a goodwill impairment review of its towage segment and concluded that no impairment had occurred.

In-Process Revenue Contracts

As part of the Partnership’s acquisition of the Piranema Spirit on November 30, 2011, the Partnership assumed an FPSO service contract with terms that were less favorable than the then prevailing market terms. As at December 31, 2015, the Partnership has a liability based on the estimated fair value of the contract. The Partnership is amortizing this liability over the estimated remaining term of the contract on a weighted basis based on the projected revenue to be earned under the contract.

Amortization of in-process revenue contracts for the year ended December 31, 2015 was $12.7 million (2014 - $12.7 million, 2013 - $12.7 million), which is included in revenues on the consolidated statements of income. Amortization for the five years subsequent to December 31, 2015 is expected to be $12.8 million (2016), $12.7 million (2017), $9.1 million (2018), $7.8 million (2019), $7.9 million (2020), and $25.5 million (thereafter).

7.	Accrued Liabilities


	December 31, 2015 $		December 31, 2014 $
Voyage and vessel expenses		37,730		33,845
Audit, legal and other general expenses		17,058		3,344
Interest including interest rate swaps		23,185		20,946
Payroll and benefits		8,731		8,461
Income tax payable and other		4,361		1,417

		91,065		68,013

F - 17

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)

8.	Long-Term Debt


	December 31, 2015 $			December 31, 2014 $
U.S. Dollar-denominated Revolving Credit Facilities due through 2019		429,279			544,969
Norwegian Kroner Bonds due through 2019		327,941			389,157
U.S. Dollar-denominated Term Loans due through 2018		129,133			158,547
U.S. Dollar-denominated Term Loans due through 2028		2,037,766			850,433
U.S. Dollar Non-Public Bond due through 2024		202,449			196,098
U.S. Dollar Bonds due through 2019		300,000			300,000

Total principal		3,426,568			2,439,204
Less unamortized discount and debt issuance costs		(62,694	)		(30,608	)

Total debt		3,363,874			2,408,596
Less current portion		485,069			257,501

Long-term portion		2,878,805			2,151,095

As at December 31, 2015, the Partnership had five revolving credit facilities, which, as at such date, provided for borrowings of up to $453.5 million (2014 - $644.6 million), of which $24.2 million (2014 - $99.6 million) was undrawn. The total amount available under the revolving credit facilities reduces by $210.9 million (2016), $97.5 million (2017), $97.8 million (2018), and $47.3 million (2019). Four of the revolving credit facilities are guaranteed by the Partnership and certain of its subsidiaries for all outstanding amounts and contain covenants that require the Partnership to maintain the greater of a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) of at least $75.0 million and 5.0% of the Partnership’s total consolidated debt. One revolving credit facility is guaranteed by Teekay Corporation and contains a covenant that requires Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. The revolving credit facilities are collateralized by first-priority mortgages granted on 18 of the Partnership’s vessels, together with other related security. As at December 31, 2015, the Partnership has guaranteed $406.5 million of these revolvers and Teekay Corporation has guaranteed $22.8 million.

In January 2014, the Partnership issued Norwegian Kroner (or NOK) 1,000 million in senior unsecured bonds that mature in January 2019 in the Norwegian bond market. As of December 31, 2015, the carrying amount of the bonds was $113.1 million. The bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 4.25%. The Partnership entered into a cross currency swap to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 6.42%, and the transfer of the principal amount fixed at $162.2 million upon maturity in exchange for NOK 1,000 million (see note 12).

In January 2013, the Partnership issued NOK 1,300 million in senior unsecured bonds in the Norwegian bond market. The bonds were issued in two tranches maturing in January 2016 (NOK 500 million) and January 2018 (NOK 800 million). As at December 31, 2015, the carrying amount of the bonds was $147.0 million. The bonds are listed on the Oslo Stock Exchange. Interest payments on the tranche that matured in January 2016 were based on NIBOR plus a margin of 4.00%. Interest payments on the tranche maturing in 2018 are based on NIBOR plus a margin of 4.75%. The Partnership entered into cross currency rate swaps to swap all interest and principal payments into U.S. Dollars, with interest payments fixed at a rate of 4.94% on the tranche maturing in 2016 and 6.07% on the tranche maturing in 2018 and the transfer of the principal amount fixed at $89.7 million upon maturity in exchange for NOK 500 million on the tranche that matured in 2016 and fixed at $143.5 million upon maturity in exchange for NOK 800 million on the tranche maturing in 2018 (see note 12).

In January 2012, the Partnership issued NOK 600 million in senior unsecured bonds that mature in January 2017 in the Norwegian bond market. As at December 31, 2015, the carrying amount of the bonds was $67.8 million. The bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 5.75%. The Partnership entered into a cross currency rate swap to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 7.49%, and the transfer of the principal amount fixed at $101.4 million upon maturity in exchange for NOK 600 million (see note 12).

As at December 31, 2015, three of the Partnership’s 50% owned subsidiaries each had an outstanding term loan, which in the aggregate totaled $129.1 million. These term loans reduce over time with quarterly and semi-annual payments and have varying maturities through 2018. These term loans are collateralized by first-priority mortgages on the three shuttle tankers to which the loans relate, together with other related security. As at December 31, 2015, the Partnership had guaranteed $31.2 million of these term loans, which represents its 50% share of the outstanding term loans of two of these 50% owned subsidiaries. The other owner and Teekay Corporation have guaranteed $64.5 million and $33.4 million, respectively.

As at December 31, 2015, the Partnership had term loans outstanding for the shuttle tankers the Amundsen Spirit, the Nansen Spirit, the Peary Spirit, the Scott Spirit, the Samba Spirit and the Lambada Spirit, for the Suksan Salamander and Gina Krog FSO units, for the Piranema Spirit, the Voyageur Spirit, the Petrojarl Knarr and the Petrojarl I FPSO units, for the ALP towing vessels, and for the Arendal Spirit UMS, which totaled $2.0 billion. For the term loan for the Amundsen Spirit and the Nansen Spirit, one tranche reduces in semi-annual payments while the other tranche correspondingly is drawn up every six months with final bullet payments of $29.0 million due in 2022 and $29.1 million due in 2023, respectively. The other term loans reduce over time with quarterly or semi-annual payments. These term loans have varying maturities through 2028 and are collateralized by first-priority mortgages on the vessels to which the loans relate, together with other related security. As at December 31, 2015, the Partnership had guaranteed $1.7 billion of these term loans and Teekay Corporation had guaranteed $295.6 million.

In February 2015, the Partnership issued $30.0 million in senior bonds that mature in June 2024 in a U.S. private placement. As of December 31, 2015, the carrying amount of the bonds was $27.1 million. The interest payments on the bonds are fixed at a rate of 4.27%. The bonds are collateralized by first-priority mortgage on the Dampier Spirit FSO unit to which the bonds relate, together with other related security, and are guaranteed by the Partnership.

F - 18

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 August 2014, the Partnership assumed Logitel’s obligations under a bond agreement from Sevan Marine ASA (or Sevan) as part of the Logitel acquisition (see note 18b). The bonds are retractable at par at any time by the Partnership. As of December 31, 2015, the outstanding amount of the bonds was $20.0 million with a carrying value of $18.8 million and the bonds are guaranteed by the Partnership.

In September 2013 and November 2013, the Partnership issued a total of $174.2 million of ten-year senior bonds, that mature in December 2023, and that were issued in a U.S. private placement to finance the Bossa Nova Spirit and the 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. The Partnership makes semi-annual repayments on the bonds and as at December 31, 2015, the carrying amount of the bonds was $155.3 million.

In May 2014, the Partnership issued $300.0 million in five-year senior unsecured bonds that mature in July 2019 in the U.S. bond market. As at December 31, 2015, the carrying amount of the bonds was $300.0 million. The bonds are listed on the New York Stock Exchange. The interest payments on the bonds are fixed at a rate of 6.0%.

Interest payments on the revolving credit facilities and the term loans are based on LIBOR plus margins, except for $20.6 million of one tranche of the term loan for the ALP newbuilding towing vessels, which are fixed at 2.93%. At December 31, 2015 and December 31, 2014, the margins ranged between 0.30% and 3.25%. The weighted-average effective interest rate on the Partnership’s variable rate long-term debt as at December 31, 2015 was 3.2% (December 31, 2014 – 3.5%). This rate does not include the effect of the Partnership’s interest rate swaps (see note 12).

The aggregate annual long-term debt principal repayments required to be made subsequent to December 31, 2015 are $486.2 million (2016), $636.9 million (2017), $580.4 million (2018), $728.4 million (2019), $221.9 million (2020), and $772.8 million (thereafter).

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 one revolving credit facility and four term loans that require the Partnership to maintain vessel values to drawn principal balance minimum ratios of a range of 113% to 125%. As at December 31, 2015, these ratios ranged from 126% to 212%. The vessel values used in these ratios are the appraised values prepared by the Partnership based on second hand sale and purchase market data. Changes in the conventional or shuttle tanker, towing, UMS or FPSO markets could negatively affect these ratios.

As at December 31, 2015 the Partnership and Teekay Corporation were in compliance with all covenants in the credit facilities and long-term debt.

9.	Leases

Charters-out

Time charters and bareboat charters of the Partnership’s vessels to customers are accounted for as operating leases. The cost, accumulated depreciation and carrying amount of the vessels accounted for as operating leases at December 31, 2015 were $4.8 billion, $1.1 billion and $3.7 billion, respectively. As at December 31, 2015, minimum scheduled future revenues under these then in place time charters and bareboat charters to be received by the Partnership, were approximately $4.3 billion, comprised of $873.3 million (2016), $908.4 million (2017), $706.0 million (2018), $576.4 million (2019), $489.0 million (2020), and $767.6 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, 2015, revenue from unexercised option periods of contracts that existed on December 31, 2015, or variable or contingent revenues. In addition, minimum scheduled future revenues presented in this paragraph have been reduced by estimated off-hire time for periodic maintenance. The amounts may vary given unscheduled future events such as vessel maintenance.

Direct Financing Lease

Leasing of the Falcon Spirit FSO unit is accounted for as a direct financing lease. As at December 31, 2015, the minimum lease payments receivable under the direct financing lease approximated $12.6 million (2014 - $21.2 million), including unearned income of $3.6 million (2014 - $7.3 million). The estimated unguaranteed residual value of the leased vessel is $8.5 million. As at December 31, 2015, the future scheduled payments under the direct financing lease to be received by the Partnership were approximately $12.6 million, comprised of $8.8 million (2016) and $3.8 million (2017).

Charters-in

As at December 31, 2015, minimum commitments owing by the Partnership under vessel operating leases by which the Partnership charters-in vessels were approximately $63.3 million in (2016), $41.4 million (2017), $16.7 million (2018) and $4.1 million (2019). The Partnership recognizes the expense from these charters, which is included in time-charter hire expense, on a straight-line basis over the firm period of the charters.

F - 19

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)

10.

Restructuring Charge

During the year ended December 31, 2013, the Partnership recognized a restructuring charge of $1.6 million, relating to the reorganization of the Partnership’s shuttle tanker marine operations and a restructuring charge of $0.4 million, relating to the reorganization of the Partnership’s conventional tanker marine operations. The purpose of the restructuring was to create better alignment with the Partnership’s marine operations resulting in a lower cost organization going forward. Both reorganizations were completed in 2013.

During the year ended December 31, 2013, the Partnership incurred $0.6 million of restructuring charges related to the reflagging of one shuttle tanker which commenced in September 2013 and was completed in October 2013.

11.

Related Party Transactions

The Partnership has entered into an omnibus agreement with Teekay Corporation, Teekay LNG Partners L.P., the general partner and others governing, among other things, when the Partnership, Teekay Corporation and Teekay LNG Partners L.P. may compete with each other and certain rights of first offering on liquefied natural gas carriers, conventional tankers, shuttle tankers, FSO units and FPSO units.

In May 2013, the Partnership entered into a ten-year charter contract, plus extension options, with Salamander Energy plc (or Salamander) to supply a FSO unit in Asia. The Partnership converted its 1993-built shuttle tanker, the Navion Clipper, into an FSO unit, which commenced its charter contract with Salamander in August 2014. The Partnership has received project management and execution services from certain subsidiaries of Teekay Corporation relating to the FSO conversion. These costs were capitalized and are included in vessels and equipment. Project management and execution costs paid to Teekay Corporation subsidiaries amounted to $3.6 million as of December 31, 2015.

In May 2013, the Partnership entered into an agreement with Statoil, on behalf of the field license partners, to provide an FSO unit for the Gina Krog oil and gas field located in the North Sea. The contract will be serviced by a new FSO unit that is being converted from the Randgrid shuttle tanker, which commenced its conversion during the second quarter of 2015. The Partnership has received project management and engineering services from certain subsidiaries of Teekay Corporation relating to this FSO unit conversion. These costs are capitalized and included as part of advances on newbuilding contracts and will be reclassified to vessels and equipment upon completion of the conversion in early-2017. Project management and engineering costs paid to Teekay Corporation subsidiaries amounted to $6.7 million as of December 31, 2015.

On May 2, 2013, the Partnership acquired from Teekay Corporation its 100% interest in Voyageur L.L.C., which owns the Voyageur Spirit FPSO unit, which operates on the Huntington Field in the North Sea under a five-year contract, plus up to 10 one-year extension options, with E.ON, for an original purchase price of $540.0 million. Due to a defect encountered in one of its two gas compressors, the FPSO unit was unable to achieve final acceptance by E.ON within the allowable timeframe, resulting in the FPSO unit being declared off-hire by the charterer retroactive to April 13, 2013.

On September 30, 2013, the Partnership entered into an interim agreement with E.ON whereby the Partnership was compensated for production beginning August 27, 2013 until the receipt of final acceptance by E.ON. Until receipt of final acceptance, Teekay Corporation agreed to indemnify the Partnership for certain production shortfalls and unreimbursed vessel operating expenses. For the period from April 13, 2013 to December 31, 2013, Teekay Corporation indemnified the Partnership a total of $34.9 million for production shortfalls and unreimbursed repair costs. During 2014, Teekay Corporation indemnified the Partnership for a further $3.5 million for production shortfalls and unrecovered repair costs to address the compressor issues, and paid another $2.7 million in late-2014 relating to a final settlement of pre-acquisition capital expenditures for the Voyageur Spirit FPSO unit. On April 4, 2014, the Partnership received the certificate of final acceptance from the charterer, which declared the unit on-hire retroactive to February 22, 2014.

Amounts paid as indemnification from Teekay Corporation to the Partnership were effectively treated as a reduction in the purchase price paid by the Partnership for the FPSO unit. The original purchase price of $540.0 million was effectively reduced to $503.1 million ($273.1 million net of assumed debt of $230.0 million) to reflect total indemnification payments from Teekay Corporation of $41.1 million, partially offset by the excess value of $4.3 million relating to the 1.4 million common units issued as part of the purchase price to Teekay Corporation on the date of closing of the transaction in May 2013 compared to the value of the common units at the date Teekay Corporation offered to sell the FPSO unit to the Partnership. The excess of the purchase price (net of assumed debt) over the book value of the net assets of $201.8 million has been accounted for as an equity distribution to Teekay Corporation of $71.4 million.

On June 10, 2013, the Partnership acquired Teekay Corporation’s 50% interest in OOG-TKP FPSO GmbH & Co KG, a joint venture with Odebrecht Oil & Gas S.A (or Odebrecht), which owns the Cidade de Itajai (or Itajai) FPSO unit, for a cash purchase price of $53.8 million. The Partnership’s investment in the Itajai FPSO unit is accounted for using the equity method.

The purchase price was based on an estimate of the fully built-up cost of the Itajai FPSO unit, including certain outstanding contractual items. During 2014, the joint venture received in connection with the resolution of these contractual items an aggregate of $6.1 million in reimbursements from the charterer and insurer, which was originally deducted from the Partnership’s purchase price of the Itajai FPSO unit. Accordingly, the Partnership remitted this reimbursed amount to Teekay Corporation.

The long-term bareboat contracts relating to two of the Partnership’s conventional tankers, the SPT Explorer and Navigator Spirit, with a joint venture in which Teekay Corporation had a 50% interest, were novated under the same terms to a subsidiary of Teekay Corporation in January 2014 and March 2014, respectively. The excess of the contractual rates over the market rates at the time of the novations were $0.9 million and $1.0 million for the years ended December 31, 2015 and 2014, respectively, and is accounted for as an equity contribution from Teekay Corporation.

F - 20

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 2015, the Partnership terminated the long-term bareboat contracts for these two conventional tankers (see notes 11i and 19). Immediately following the contract terminations, the Partnership sold its 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd. (see note 19).

In December 2014, the Partnership entered into an agreement with a consortium led by Queiroz Galvão Exploração e Produção SA (or QGEP) to provide an FPSO unit for the Atlanta field located in the Santos Basin offshore Brazil. In connection with the contract with QGEP, the Partnership acquired the Petrojarl I FPSO from Teekay Corporation for a purchase price of $57 million. The purchase price was financed by means of an intercompany loan payable to a subsidiary of Teekay Corporation, which was repaid in July 2015. Interest payments on the loan were at a fixed rate of 6.5%. The Petrojarl I is currently undergoing upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard in the Netherlands for an estimated cost of approximately $267 million, which includes the cost of acquiring the Petrojarl I (see note 14f). The excess of the purchase price over Teekay Corporation’s carrying value of the Petrojarl I FPSO unit has been accounted for as an equity distribution to Teekay Corporation of $12.4 million in 2014.

On July 1, 2015, the Partnership acquired from Teekay Corporation its 100% interest in the Knarr Companies, which own the Petrojarl Knarr FPSO unit, which operates on the Knarr Field in the North Sea, for an equity purchase price of $529.4 million (see note 3).

During 2015, four conventional tankers, two shuttle tankers and three FSO units of the Partnership were employed on long-term bareboat and time-charter-out contracts with subsidiaries of Teekay Corporation. In 2015, the Partnership terminated the long-term bareboat and time-charter-out contracts under which three of these conventional tankers were employed with a subsidiary of Teekay Corporation. The Partnership concurrently paid total net early termination fees to Teekay Corporation of $1.8 million (see note 19), which is recorded in revenue on the consolidated statements of income.

In 2013, the Partnership terminated the long-term time-charter-out contracts under which two of its conventional tankers were employed with a subsidiary of Teekay Corporation. The Partnership received early termination fees from a subsidiary of Teekay Corporation of $11.3 million, which is recorded in net loss from discontinued operations on the consolidated statements of income.

Teekay Corporation and its wholly-owned subsidiaries provide substantially all of the Partnership’s commercial, technical, crew training, strategic, business development and administrative service needs. In addition, the Partnership reimburses the general partner for expenses incurred by the general partner that are necessary or appropriate for the conduct of the Partnership’s business. Such related party transactions were as follows for the periods indicated:


	Year Ended December 31,
	2015			2014			2013
	$			$			$
Revenues⁽¹⁾		68,734			68,172			71,905
Vessel operating expenses⁽²⁾		(39,779	)		(39,237	)		(39,820	)
General and administrative⁽³⁾⁽⁴⁾		(52,257	)		(42,396	)		(29,528	)
Interest income⁽⁵⁾		—			—			1,217
Interest expense⁽⁶⁾⁽⁷⁾		(5,556	)		(933	)		(818	)
Other expense⁽⁸⁾		—			—			(319	)
Net income from related party transactionsfrom discontinued operations⁽⁹⁾		—			—			19,255

(1)

Includes revenue from time-charter-out or bareboat contracts with subsidiaries or affiliates of Teekay Corporation, including management fees from ship management services provided by the Partnership to a subsidiary of Teekay Corporation, and net early termination fees paid by the Partnership to Teekay Corporation (see above and note 19).

(2)	Includes ship management and crew training services provided by Teekay Corporation.

(3)	Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and reimbursements to Teekay Corporation and the Partnership’s general partner for costs incurred on the Partnership’s behalf.

(4)

Includes business development fees of $9.7 million, $2.2 million and $2.0 million to Teekay Corporation in connection with the acquisition of the Knarr Companies, six long-distance towing and offshore installation vessels, and the Arendal Spirit UMS, respectively, during the year ended December 31, 2015; business development fees of $1.6 million and $2.1 million to Teekay Corporation in connection with the acquisition of ALP and the Petrojarl I FPSO unit, respectively, during the year ended December 31, 2014; and a $1.0 million business development fee to Teekay Corporation in connection with the acquisition of the 2010-built HiLoad Dynamic Positioning unit from Remora AS during the year ended December 31, 2013.

(5)

Interest income for the year ended December 31, 2013 relates to the interest received from Teekay Corporation and the Partnership’s general partner on a $150 million partial prepayment for the Voyageur Spirit FPSO unit. The Partnership received interest at a rate of LIBOR plus a margin of 4.25% on the prepaid funds to Teekay Corporation from February 26, 2013 until the Partnership acquired the FPSO unit on May 2, 2013.

(6)	Includes a guarantee fee related to the final bullet payment of the Piranema Spirit FPSO debt facility guaranteed by Teekay Corporation and interest expense incurred on due to affiliates balances.

(7)

Includes interest expense of $5.1 million for the year ended December 31, 2015, incurred on the convertible promissory note issued to Teekay Corporation in connection with the financing of the acquisition of the Knarr Companies (see note 3). The convertible promissory note incurs interest at a rate of 6.50% on the outstanding principal balance, which as at December 31, 2015 was $100.0 million. The outstanding principal balance, together with accrued interest, is payable in full on July 1, 2016.

F - 21

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)

(8)	Unrealized loss from the change in fair value of the Partnership’s contingent consideration liability relating to the acquisition of the Scott Spirit.

(9)

Related party transactions relating to three conventional tankers determined to be discontinued operations. This includes revenue from long-term time-charter-out contracts with subsidiaries or affiliates of Teekay Corporation, including early termination fees described above; crew training fees charged by Teekay Corporation accounted for as vessel operating expenses; and commercial, technical, strategic and business development management fees charged by Teekay Corporation.

At December 31, 2015, due from affiliates totaled $81.3 million (December 31, 2014 - $44.2 million) and due to affiliates totaled $304.6 million (December 31, 2014 - $108.9 million). Due to and from affiliates, other than the convertible promissory note issued to Teekay Corporation (see note 3), are non-interest bearing and unsecured, and are expected to be settled within the next fiscal year in the normal course of operations or from financings.

12.

Derivative Instruments

The Partnership uses derivatives 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, 2015 and 2014, as cash flow hedges.

As at December 31, 2015, 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) Non-hedge			AverageForward Rate⁽¹⁾		Expected Maturity
								2016		2017
								(in thousands of U.S. Dollars)
Norwegian Kroner		590,000		(10,688	)		7.62		54,577		22,896
Euro		11,103		(45	)		0.91		12,153		—
Singapore dollar		22,442		(776	)		1.36		16,537		—

				(11,509	)				83,267		22,896

(1)	Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

In connection with its issuance of NOK bonds, the Partnership has entered into cross currency swaps pursuant to which it receives the principal amount in NOK on the maturity date of the swap, in exchange for payment of a fixed U.S. Dollar amount. In addition, the cross currency swaps exchange a receipt of floating interest in NOK based on NIBOR plus a margin for a payment of U.S. Dollar fixed interest. The purpose of the cross currency swaps is to economically hedge the foreign currency exposure on the payment of interest and principal at maturity of the Partnership’s NOK bonds due from 2016 through 2019. In addition, the cross currency swaps due from 2016 through 2019 economically hedge the interest rate exposure on the NOK bonds due from 2016 through 2019. The Partnership has not designated, for accounting purposes, these cross currency swaps as cash flow hedges of its NOK bonds due from 2016 through 2019. As at December 31, 2015, the Partnership was committed to the following cross currency swaps:


Principal Amount NOK		PrincipalAmountUSD		Floating Rate Receivable				Fixed RatePayable			Fair Value / Asset (Liability)			Remaining Term (years)
Principal Amount NOK		PrincipalAmountUSD		Reference Rate	Margin			Fixed RatePayable			Fair Value / Asset (Liability)			Remaining Term (years)
	600,000		101,351	NIBOR		5.75	%		7.49	%		(36,504	)	1.1
	500,000		89,710	NIBOR		4.00	%		4.94	%		(33,714	)	0.1
	800,000		143,536	NIBOR		4.75	%		6.07	%		(56,985	)	2.1
	1,000,000		162,200	NIBOR		4.25	%		6.42	%		(56,124	)	3.1

												(183,327	)

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.

F - 22

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)

As at December 31, 2015, the Partnership was committed to the following interest rate swap agreements:


	Interest Rate Index	Notional Amount $		Fair Value / Carrying Amount of Assets (Liability) $			Weighted- Average Remaining Term (years)		FixedInterestRate(%)⁽¹⁾
U.S. Dollar-denominated interest rate swaps⁽²⁾	LIBOR		950,000		(163,868	)		6.7		3.9
U.S. Dollar-denominated interest rate swaps⁽³⁾	LIBOR		1,268,357		(72,130	)		5.7		2.6

			2,218,357		(235,998	)

(1)	Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2015, ranged from 0.30% and 3.25%.

(2)	Notional amount remains constant over the term of the swap.

(3)	Principal amount reduces quarterly or semi-annually.

For the periods indicated, the following table presents the effective portion of gains (losses) on interest rate swap agreements designated and qualifying as cash flow hedges that were (1) recognized in other comprehensive income, (2) recorded in accumulated other comprehensive income (or AOCI) during the term of the hedging relationship and reclassified to earnings, and (3) recognized in the ineffective portion of losses on derivative instruments designated and qualifying as cash flow hedges.


Year Ended December 31, 2015
Balance Sheet (AOCI)		Statement of Income
Effective Portion		Effective Portion			Ineffective Portion
	696		—			(1,050	)	Interest expense

	696		—			(1,050	)


Year Ended December 31, 2013
Balance Sheet (AOCI)		Statement of Income
Effective Portion		Effective Portion			Ineffective Portion
	6		—			—		Vessel operating expenses
	—		(52	)		(59	)	General and administrative expenses

	6		(52	)		(59	)

Year Ended December 31, 2014

Balance
Sheet
(AOCI)

Statement of Income

Effective
Portion

Ineffective
Portion

—

As at December 31, 2015, the Partnership had multiple interest rate swaps and cross currency swaps governed by the same master agreement. Each of these master agreements provides for the net settlement of all swaps subject to that master agreement through a single payment in the event of default or termination of any one swap. The fair value of these interest rate swaps are presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, 2015, these interest rate swaps and cross currency swaps had an aggregate fair value liability amount of $360.6 million (December 31, 2014 - $303.8 million). As at December 31, 2015, the Partnership had $60.5 million on deposit with the relevant counterparties as security for swap liabilities under certain master agreements (December 31, 2014 - $46.8 million). The deposit is presented in restricted cash and restricted cash - long-term on the consolidated balance sheets.

F - 23

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, 2015
Foreign currency contracts		80		—		—			(10,266	)		(1,323	)
Cross currency swap		—		—		(2,196	)		(42,878	)		(138,253	)
Interest rate swaps		—		1,894		(7,827	)		(148,312	)		(81,753	)

		80		1,894		(10,023	)		(201,456	)		(221,329	)


As at December 31, 2014
Foreign currency contracts		—		—		—			(8,490	)		(2,778	)
Cross currency swap		—		—		(1,105	)		(6,496	)		(112,902	)
Interest rate swaps		—		4,660		(8,742	)		(70,332	)		(142,074	)

		—		4,660		(9,847	)		(85,318	)		(257,754	)

Realized and unrealized (losses) gains 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 (losses) gains on derivative instruments in the consolidated statements of income. The effect of the (losses) gains on these derivatives on the consolidated statements of income for the years ended December 31, 2015, 2014 and 2013 is as follows:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $
Realized losses relating to:
Interest rate swap termination		(10,876	)		—			(31,798	)
Interest rate swaps		(60,741	)		(55,588	)		(63,050	)
Foreign currency forward contracts		(13,799	)		(1,912	)		(824	)

		(85,416	)		(57,500	)		(95,672	)

Unrealized gains (losses) relating to:
Interest rate swaps		11,952			(75,777	)		133,488
Foreign currency forward contracts		(240	)		(10,426	)		(2,996	)

		11,712			(86,203	)		130,492

Total realized and unrealized (losses) gains on derivative instruments		(73,704	)		(143,703	)		34,820

Realized and unrealized (losses) gains of cross currency swaps are recognized in earnings and reported, including the impact of the partial termination of a cross currency swap in connection with the repurchase of NOK bonds, in foreign currency exchange loss in the consolidated statements of income. The effect of the (loss) gain on cross currency swaps on the consolidated statements of income for the years ended December 31, 2015, 2014 and 2013 is as follows:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $
Realized gain on partial termination of cross-currency swap		—			—			6,800
Realized (losses) gains		(10,140	)		(1,992	)		1,563
Unrealized losses		(61,734	)		(93,953	)		(38,596	)

Total realized and unrealized losses on cross currency swaps		(71,874	)		(95,945	)		(30,233	)

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, the Partnership only enters into derivative transactions with counterparties that are rated A- or better by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

F - 24

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, 2015 $			December 31, 2014 $
Deferred tax assets:
Tax losses carried forward⁽¹⁾		116,894			146,851
Other		2,815			3,726

Total deferred tax assets		119,709			150,577

Deferred tax liabilities:
Vessels and equipment		10,577			12,514
Long-term debt		3,218			2,295
Other		1,204			1,371

Total deferred tax liabilities		14,999			16,180

Net deferred tax assets		104,710			134,397

Valuation allowance		(75,277	)		(128,438	)

Net deferred tax assets		29,433			5,959


Disclosed in:
Deferred tax asset		30,050			5,959
Other long-term liabilities		617			—

Net deferred tax assets		29,433			5,959

(1)	As at December 31, 2015, the income tax losses carried forward of $466.3 million ($559.1 million – December 31, 2014) are available to offset future taxable income in the applicable jurisdictions, and can be carried forward indefinitely.

The components of the provision for income taxes are as follows:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $
Current		(1,650	)		(1,290	)		(75	)
Deferred		23,007			(889	)		(2,150	)

Income tax recovery (expense)		21,357			(2,179	)		(2,225	)

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, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $
Net income before taxes		78,786			19,835			78,782
Net income (loss) not subject to taxes		12,601			(72,469	)		41,100

Net income subject to taxes		66,185			92,304			37,682


At applicable statutory tax rates		14,527			12,484			2,559
Permanent differences		387			(4,677	)		(3,619	)
Adjustments related to currency differences		(1,060	)		3,349			(14,231	)
Valuation allowance		(35,211	)		(8,977	)		17,516

Tax (recovery) expense related to current year		(21,357	)		2,179			2,225

F - 25

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 2015, 2014 and 2013:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $
Balance of unrecognized tax benefits as at beginning of the year		6,779			7,037			3,692
Decreases for positions related to prior years		(3,082	)		(258	)		(336	)
Increases for positions related to the current year		350			—			—
Increase for positions attributable to the Dropdown Predecessor		—			—			3,681

Balance of unrecognized tax benefits as at end of the year		4,047			6,779			7,037

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 2015 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 were not material.

14.

Commitments and Contingencies

During 2010, an unrelated party contributed a shuttle tanker to a subsidiary of the Partnership for a 33% equity interest in the subsidiary. The non-controlling interest owner in the subsidiary holds a put option which, if exercised, would obligate the Partnership to purchase the non-controlling interest owner’s 33% share in the entity for cash in accordance with a defined formula. The redeemable non-controlling interest is subject to remeasurement if the formulaic redemption amount exceeds the carrying value. No remeasurement was required as at December 31, 2015.

In May 2013, the Partnership entered into an agreement with Statoil, on behalf of the field license partners, to provide an FSO unit for the Gina Krog oil and gas field located in the North Sea. The contract will be serviced by a new FSO unit that is being converted from the Randgrid shuttle tanker, which the Partnership purchased in August 2015 from a 67%-owned subsidiary. The FSO conversion project is expected to cost approximately $279 million, including amounts reimbursable upon delivery of the unit relating to installation and mobilization. As at December 31, 2015, payments made towards this commitment totaled $141.1 million and the remaining payments required to be made are $120.7 million (2016) and $17.3 million (2017). Following scheduled completion of the conversion in early-2017, the newly converted FSO unit will commence operations under a three-year time-charter contract to Statoil, which includes 12 additional one-year extension options.

In March 2014, the Partnership acquired 100% of the shares of ALP, a Netherlands-based provider of long-haul ocean towage and offshore installation services to the global offshore oil and gas industry. Concurrently with this transaction, the Partnership and ALP entered into an agreement with Niigata Shipbuilding & Repair of Japan for the construction of four state-of-the-art SX-157 Ulstein Design ultra-long distance towing and anchor handling vessel newbuildings. These vessels will be equipped with dynamic positioning capability and are scheduled for delivery in 2016. The Partnership has agreed to acquire these newbuildings for a total cost of approximately $232 million. As at December 31, 2015, payments made towards these commitments totaled $91.7 million and the remaining payments required to be made under these newbuilding contracts are $140.6 million (2016). The Partnership will finance the newbuilding installments primarily from long-term debt financing of $185 million secured for these vessels in July 2015, and to a lesser extent, through existing liquidity.

In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS, a Norway-based company focused on high-end UMS. Concurrently with this transaction, the Partnership acquired three UMS newbuildings ordered from COSCO (Nantong) Shipyard (COSCO) in China that are expected to cost approximately $596 million in aggregate, including estimated site supervision costs and license fees to be paid to Sevan to allow for use of its cylindrical hull design in these UMS and $30.0 million from the Partnership’s assumption of Logitel’s obligations under a bond agreement from Sevan. As at December 31, 2015, payments made towards these commitments totaled $193.8 million and the remaining payments required to be made under these newbuilding contracts are $186.8 million (2016), $15.7 million (2017), $15.6 million (2018) and $184.1 million (2019). During the second quarter of 2015, the Partnership exercised its options to defer the delivery of its second UMS newbuilding by up to one year, and the delivery and all related construction work of its third UMS by 120 days. The Partnership may decide to exercise an additional option to further defer the delivery of its third UMS by an additional two years. The Partnership is also considering cancelling the newbuilding contracts for the two UMS newbuildings, which are owned in separate subsidiaries of the Partnership. The Partnership took delivery of one UMS, the Arendal Spirit, in February 2015 and, subsequent to an additional deferral relating to the third UMS, the remaining two units are scheduled to deliver in late-2016 and mid-2019, respectively. The Partnership financed the Arendal Spirit through long-term debt financing and its existing liquidity.

F - 26

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 October 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to a 50/50 joint venture with Odebrecht. The vessel is committed to a new FPSO conversion for the Libra field located in the Santos Basin offshore Brazil. The conversion project will be completed at Sembcorp Marine’s Jurong Shipyard in Singapore and the FPSO unit is scheduled to commence operations in early-2017 under a 12-year fixed-rate contract with Petroleo Brasileiro S.A. (Petrobras). The FPSO conversion is expected to cost approximately $1.0 billion. As at December 31, 2015, payments made by the joint venture towards these commitments totaled $251.6 million and the remaining payments required to be made by the joint venture are $739.4 million (2016) and $13.6 million (2017). The Partnership intends to finance its share of the conversion through existing long-term debt financing within the joint venture, and to a lesser extent, through existing liquidity. The joint venture secured a $248 million short-term loan in late-2014, which was refinanced in 2015 with a long-term debt facility providing total borrowings of up to $804 million for the FPSO unit (see note 20).

In December 2014, the Partnership acquired the Petrojarl I FPSO unit from Teekay Corporation for $57 million (see note 11g). The Petrojarl I is undergoing upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard in the Netherlands with an estimated cost of approximately $267 million, which includes the cost of acquiring the Petrojarl I. The FPSO is scheduled to commence operations in the fourth quarter of 2016 under a five-year fixed-rate charter contract with QGEP. As at December 31, 2015, payments made towards these commitments, including the acquisition of the Petrojarl I FPSO unit from Teekay Corporation, totaled $146.1 million and the remaining payments required to be made are $121.0 million (2016). The Partnership intends to finance the remaining upgrade payments through existing long term debt financing for the FPSO unit and, to a lesser extent, with its existing liquidity. The Partnership secured a $180 million long-term loan in June 2015 and made partial draw downs on the facility during 2015 to finance the Petrojarl I FPSO upgrade payments.

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. These contracts were initially being serviced by three third party-owned shuttle tankers operating on the East Coast of Canada, which were chartered-in to the Partnership. One of these vessels was replaced by one of the Partnership’s existing shuttle tankers, the Navion Hispania, during the third quarter of 2015. The Partnership has entered into contracts to construct three Suezmax DP2 shuttle tanker newbuildings for a fully built-up cost of approximately $368 million. These vessels will replace the existing vessels servicing the East Coast of Canada. The three newbuildings are expected to be delivered in the fourth quarter of 2017 through the first half of 2018. As at December 31, 2015, payments made towards these commitments totaled $33.8 million and the remaining payments required to be made under these newbuilding contracts are $35.6 million (2016), $229.7 million (2017), and $68.6 million (2018). The Partnership intends to finance the newbuilding installments through its existing liquidity and expects to secure long-term debt financing for these vessels prior to their scheduled deliveries.

In December 2015, the Partnership entered into a put and call option agreement with its 50/50 joint venture partner, Odebrecht, relating to the FPSO conversion for the Libra field. The agreement provides Odebrecht with a put option to sell 15%, 20% or 25% of its shares in the joint venture to the Partnership for consideration of $24.1 million, $32.1 million and $40.2 million, respectively. The exercise date for the put option is April 25, 2016 with a settlement date on May 25, 2016. Upon exercising of the put option, the agreement further provides Odebrecht with a call option to repurchase the shares sold pursuant to the put option, for the same consideration from the put option plus 20% per annum from the put option date until the call option date as well as an additional $7.5 million. The exercise date for the call option is August 31, 2017 with settlement on January 5, 2018. The Partnership expects to finance the put option, if exercised, with its existing liquidity.

In March 2016, Petrobras claimed that the Partnership’s November 2011 cessation of paying certain agency fees with respect to the Piranema Spirit FPSO unit’s charter contract should have resulted in a corresponding 2% rate reduction on the FPSO charter contract with Petrobras. The Partnership disagrees with this claim. The Partnership has estimated the total claim to be approximately $7.5 million, consisting of $4.4 million relating to 2% of the charter hire previously paid by Petrobras to the Partnership for the period from November 2011 up to the end of 2015, and $3.1 million relating to 2% of estimated future charter hire from 2016 to the end of the term of the FPSO contract with Petrobras.

In February 2016, a special committee of the Board of Directors of Sevan Marine ASA (or Special Committee), responding to allegations made by certain minority shareholders of Sevan Marine ASA (or Sevan), advised that they had initiated a review of the legality of the agreements between Sevan and CeFront Technology AS (or CeFront) relating to the transfer to Logitel Offshore Pte. Ltd. or its wholly-owned subsidiaries (collectively Logitel Offshore) in 2013 of two hulls to be converted into floating accommodation units, including the $60 million bond loan (of which $41 million was a vendor credit and $19 million was a cash loan) granted by Sevan Holding V AS to Logitel Offshore Pte. Ltd. (or the 2013 Transaction). This review also included a review of the legality of the agreements between Sevan and the Partnership entered into in connection with the 2014 transaction whereby the Partnership acquired Logitel Offshore from CeFront (or the 2014 Transaction). The Special Committee advised the Partnership by letter dated February 16, 2016 that it had obtained legal advice indicating that Sevan had failed to obtain the necessary shareholder approvals in connection with both the 2013 Transaction and the 2014 Transaction. The Special Committee also advised that, in its view, the $60 million bond loan to Logitel Offshore represents lending to a related party of a Sevan shareholder, which is in breach of mandatory limitations on such financings in Norwegian corporate law. The Special Committee has advised the Partnership that the failure to obtain the necessary approval of their shareholders would render certain of the agreements in the 2013 Transaction and 2014 Transaction either void or voidable, exposing the Partnership to potential claims for restitution as mandated by Norwegian corporate law. As a result, Sevan claims that the Partnership/Logitel owes Sevan approximately $50 million, respresenting the unpaid amount of the original $60 million bond loan. As at December 31, 2015, the Partnership had accrued a bond loan payable amount of $18.8 million, based upon the terms of the agreements as entered into by Sevan, Logitel and the Partnership. The Partnership is in discussions with Sevan regarding the potential financial impact on the Partnership of the failure of Sevan to obtain the necessary shareholder approvals of the 2013 Transaction and 2014 Transaction.

F - 27

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

The changes in non-cash working capital items related to operating activities for the years ended December 31, 2015, 2014 and 2013 are as follows:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $			Year ended December 31, 2013 $



Accounts receivable		(24,285	)		73,020			(59,003	)
Prepaid expenses and other assets		804			1,899			(2,884	)
Accounts payable and accrued liabilities		(23,745	)		(87,597	)		46,266
Advances from (to) affiliate		73,129			(98,806	)		67,620

		25,903			(111,484	)		51,999

Cash interest paid (including interest paid by the Dropdown Predecessor and Knarr Companies and realized losses on interest rate swaps) during the years ended December 31, 2015, 2014 and 2013 totaled $179.5 million, $135.4 million, and $146.0 million, respectively.

Income taxes paid (including taxes paid by the Dropdown Predecessor and Knarr Companies) during the years ended December 31, 2015, 2014 and 2013 totaled $0.8 million, $2.1 million and $0.6 million, respectively.

The Partnership’s consolidated statement of cash flows for the years ended December 31, 2015 and 2013 reflects the Knarr Companies and the Dropdown Predecessor as if the Partnership had acquired Knarr Companies and the Dropdown Predecessor when the vessels began operations under the ownership of Teekay Corporation. For non-cash charges related to Knarr Companies and the Dropdown Predecessor (see notes 3, 11d and 11h).

The cash portion of the purchase price of vessels acquired from Teekay Corporation is as follows:


	Year ended December 31, 2015 $			Year ended December 31, 2014 $		Year ended December 31, 2013 $



Petrojarl Knarr (net of cash acquired of $14.2 million)⁽¹⁾ (note 11h)		(112,710	)		—		—
Voyageur Spirit (net of cash acquired of $0.9 million)⁽²⁾⁽³⁾ (note 11d)		—			6,181		(234,125	)
Cidade de Itajai (net of cash acquired of $1.3 million) (note 11e)		—			—		(52,520	)

		(112,710	)		6,181		(286,645	)

(1)	The cash portion of the purchase price does not include the conversion of $300.0 million of the convertible promissory note into 14.4 million common units of the Partnership issued to Teekay Corporation (see note 3b).

(2)	As at December 31, 2014, the cash portion of the original purchase price of the Voyageur Spirit FPSO unit of $270.0 million was effectively reduced to reflect the $41.1 million indemnification payments from Teekay Corporation recorded during 2014 and 2013 (see note 11d).

(3)

The cash portion of the purchase price does not include the issuance of $44.3 million of the Partnership’s common units to Teekay Corporation to partially finance the acquisition of the Voyageur Spirit FPSO (see note 16), which includes a $4.3 million excess value of the common units when comparing valuation of the common units at the date of closing the transaction to the valuation of the common units as the date Teekay Corporation offered to sell the Voyageur Spirit FPSO to the Partnership (see note 11d).

Contribution of capital from Teekay Corporation to the Dropdown Predecessor relating to Voyageur Spirit was $5.6 million for the year ended December 31, 2013, and was included in other financing activities on the consolidated statement of cash flows for 2013.

16.

Total Capital and Net Income Per Unit

At December 31, 2015, a total of 64.3% of the Partnership’s common units outstanding were held by the public. The remaining common units, as well as the 2% general partner interest, were held by a subsidiary of Teekay Corporation. All of the Partnership’s outstanding Series A Cumulative Redeemable Preferred Units (the Series A Preferred Units) and Series B Cumulative Redeemable Preferred Units (the Series B Preferred Units) are held by the public and the Series C Preferred Units are held by private investors.

F - 28

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)

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 2/3% of the outstanding units voting as a single class, including units held by the general partner and its affiliates.

Incentive Distribution Rights

The general partner is entitled to incentive distributions if the amount the Partnership distributes to common unitholders with respect to any quarter exceeds specified target levels shown below:


Quarterly Distribution Target Amount (per unit)	Common Unitholders			General Partner
Minimum quarterly distribution of $0.35		98	%		2	%
Up to $0.4025		98	%		2	%
Above $0.4025 up to $0.4375		85	%		15	%
Above $0.4375 up to $0.525		75	%		25	%
Above $0.525		50	%		50	%

During 2015, cash distributions with respect to the first three quarters of 2015 exceeded $0.4025 per common units, and were below $0.4025 per common unit with respect to the distribution for the fourth quarter of 2015. Consequently, the assumed distribution of net income resulted in the use of the increasing percentages to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation up to September 30, 2015 and increasing percentages were not used to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation from October 1, 2015 to December 31, 2015.

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 C 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.

Net Income Per Unit

Limited partners’ interest in net income per common unit – basic is determined by dividing net income, after deducting the amount of net income attributable to the non-controlling interests, the general partner’s interest and the distributions on the Series A Preferred Units, the Series B Preferred Units and the Series C Preferred Units, by the weighted-average number of common units outstanding during the period. The distributions payable and paid on the preferred units for the year ended December 31, 2015 were $28.6 million (2014 - $10.9 million, 2013 - $7.3 million).

The computation of limited partners’ interest in net income per common unit – diluted assumes the exercise of all dilutive restricted units using the treasury stock method and the if-converted method relating to the Series C Preferred Units. At any time after the 18-month anniversary of the closing date, the Series C Preferred Units are convertible on a one-for-one basis into common units of the Partnership. The computation of limited partners’ interest in net income per common unit – diluted does not assume such exercises or conversions if the effect would be anti-dilutive.

5.1 million Series C Preferred Units for the year ended December 31, 2015 and 0.1 million total restricted units for the year ended December 31, 2014 (2013 – nil), were excluded from the computation of limited partners’ interest in net income per common unit – diluted, as they have an anti-dilutive effect. In periods where a loss is attributable to common unitholders all restricted units and Series C Preferred Units are anti-dilutive.

The general partner’s and common unitholders’ interests in net income are calculated as if all net income 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 income; 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 the amount of cash reserves established by the Partnership’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 Preferred Units, Series B Preferred Units and Series C Preferred Units. Unlike available cash, net income is affected by non-cash items such as depreciation and amortization, unrealized gains and losses on derivative instruments and unrealized foreign currency translation gains and losses.

Pursuant to the partnership agreement, allocations to partners are made on a quarterly basis.

F - 29

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 Partnership allocates the limited partners’ interest in net income, including both distributed and undistributed net income, between continuing operations and discontinued operations based on the proportion of net income from continuing and discontinued operations to total net income.

Preferred Units

In April 2013, the Partnership issued 6.0 million 7.25% Series A Preferred Units in a public offering for net proceeds of $144.8 million. Pursuant to the partnership agreement, distributions on the 7.25% 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 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 July 2015, the Partnership issued 10.4 million 8.60% Series C Preferred Units in a private placement for net proceeds of $249.8 million. At any time after the 18-month anniversary of the closing date, at the election of each holder, the Series C Preferred Units may be converted on a one-for-one basis into common units of the Partnership. Pursuant to the partnership agreement, distributions on the Series C 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. The Series C Preferred Units may be redeemed in cash if a change of control occurs in the Partnership. As a result, the Series C Preferred Units that are subject to this redemption feature are not included on the Partnership’s consolidated balance sheet as part of the total equity and are presented as temporary equity above the equity section but below the liabilities section. A summary description of the Series C Preferred Units is included in the Partnership’s Report on Form 6-K filed with the SEC on July 6, 2015.

Public and Private Offerings of Common Units

The following table summarizes the issuances of common units over the three years ending December 31, 2015:


Date	Offering	Number ofCommonUnits		Offering		GrossProceeds ⁽ⁱ⁾		Net Proceeds		Teekay Corporation’sOwnershipAfter the			Use of Proceeds
Date	Type	Issued		Price		(in millions of U.S. Dollars)				Offering⁽ⁱⁱ⁾			Use of Proceeds
April 2013	Private		2,056,202	$	29.18		61.2		61.2		28.67	%	Partially finance four newbuilding shuttle tankers installments and for general partnership purposes.
May 2013	Private		1,446,654	$	30.60		45.1		45.1		29.91	%	Partially finance the acquisition of Voyageur Spirit FPSO unit
During 2013	COP		85,508		(iii)		2.8		2.4		(iii)		General partnership purposes
December 2013	Private		1,750,000	$	30.50		54.5		54.4		29.31	%	For general partnership purposes, which included funding vessel conversion projects and future vessel acquisitions.
During 2014	COP		213,350		(iii)		7.8		7.6		(iii)		General partnership purposes
November 2014	Private		6,704,888	$	26.10		178.6		178.5		27.26	%	For general partnership purposes, which included funding vessel conversion projects and finance newbuilding UMS and towage vessels.
During 2015	COP		211,077		(iii)		3.6		3.5		(iii)		General partnership purposes
July 2015	Private		14,402,304	$	20.83		306.1		306.1		37.06	%	Partially finance the acquisition of the Knarr companies.

(i)	Including the General Partner’s 2% proportionate capital contribution

(ii)	Including Teekay Corporation’s indirect 2% general partner interest

(iii)

In May 2013, the Partnership implemented a continuous offering program (or COP), under which the Partnership may issue new common units, representing limited partner interests, at market prices from time to time up to a maximum aggregate amount of $100 million.

17.

Unit Based Compensation

During the year ended December 31, 2015, a total of 14,603 common units, with an aggregate value of $0.3 million, were granted and issued to the non-management directors of the general partner as part of their annual compensation for 2015.

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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 Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership. During March 2015, 2014 and 2013, the Partnership granted restricted unit-based compensation awards with respect to 102,834, 67,569 and 63,309 units, respectively, with aggregate grant date fair values of $2.1 million for 2015 and 2014 and $1.8 million for 2013, 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 cancelled, unless their 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.

During the year ended December 31, 2015, restricted unit-based awards with respect to a total of 48,488 common units with a fair value of $1.5 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 12,612 common units and by paying $0.5 million in cash.

During the year ended December 31, 2014, restricted unit-based awards with respect to a total of 20,988 common units with a fair value of $0.6 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 6,584 common units and by paying $0.3 million in cash.

The Partnership recorded unit-based compensation expense of $0.9 million, $1.9 million and $0.9 million, during the years ended December 31, 2015, 2014 and 2013, respectively, in general and administrative expenses in the Partnership’s consolidated statements of income.

As of December 31, 2015 and December 31, 2014, liabilities relating to cash settled restricted unit-based compensation awards of $0.4 million and $1.0 million, respectively, were recorded in accrued liabilities on the Partnership’s consolidated balance sheets. As at December 31, 2015, the Partnership had $0.8 million of non-vested awards not yet recognized, which the Partnership expects to recognize over a weighted average period of 1.0 years.

18.

Acquisitions

Acquisition of ALP Maritime Services B.V.

On March 14, 2014, the Partnership acquired 100% of the shares of ALP. Concurrently with this transaction, the Partnership and ALP entered into an agreement with Niigata Shipbuilding & Repair of Japan for the construction of four state-of-the-art SX-157 Ulstein Design ultra-long distance towing and anchor handling vessel newbuildings. These vessels will be equipped with dynamic positioning capability and are scheduled for delivery in 2016. The Partnership is committed to acquire these newbuildings for a total cost of approximately $232 million (see note 14c).

The Partnership acquired ALP for a purchase price of $2.6 million, which was paid in cash, and also entered into an arrangement to pay additional compensation to three former shareholders of ALP if certain requirements are satisfied. This contingent compensation consists of $2.4 million, which is payable upon the delivery and employment of ALP’s four newbuildings, which are scheduled throughout 2016, and a further amount of up to $2.6 million, which is payable if ALP’s annual operating results from 2017 to 2021 meet certain targets. The Partnership has the option to pay up to 50% of this compensation through the issuance of common units of the Partnership. Each of the contingent compensation amounts are payable only if the three shareholders are employed by ALP at the time performance conditions are met. For the year ended December 31, 2015, compensation cost was $0.7 million and was recorded in general and administrative expenses in the Partnership’s consolidated statements of income (December 31, 2014 - $0.5 million). The Partnership also incurred a $1.0 million fee to a third party associated with the acquisition of ALP in 2014 and a $1.6 million business development fee to Teekay Corporation in 2014 (see note 11j) for assistance with the acquisition, which have been recognized in general and administrative expenses during 2014.

The acquisition of ALP was accounted for using the purchase method of accounting, based upon finalized estimates of fair value.

The following table summarizes the finalized fair values of the ALP assets acquired and liabilities assumed by the Partnership on the acquisition date.


(in thousands of U.S. Dollars)	As at March 14, 2014 $
	As at March 14, 2014 $
ASSETS
Cash and cash equivalents		294
Other current assets		404
Advances on newbuilding contracts		164
Other assets - long-term		395
Goodwill (towage segment)		2,032

Total assets acquired		3,289

LIABILITIES
Current liabilities		387
Other long-term liabilities		286

Total liabilities assumed		673

Net assets acquired		2,616

Consideration		2,616

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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 goodwill recognized in connection with the ALP acquisition is attributable primarily to the assembled workforce of ALP, including their experience, skills and abilities. Operating results of ALP are reflected in the Partnership’s financial statements commencing March 14, 2014, the effective date of the acquisition. For the year ended December 31, 2014, the Partnership recognized $0.5 million of revenue and $2.3 million of net loss resulting from this acquisition. The following table shows comparative summarized consolidated pro forma financial information for the Partnership for the years ended December 31, 2014 and 2013, giving effect to the Partnership’s acquisition of ALP as if it had taken place on January 1, 2013:


(in thousands of U.S. Dollars, except per unit data)	Pro Forma Year ended December 31, 2014 $			Pro Forma Year ended December 31, 2013 $
Revenues		1,019,674			938,309
Net income from continuing operations		17,495			76,044
Limited partners’ interest in net income from continuing operations per common unit:
- Basic		(0.23	)		0.92
- Diluted		(0.23	)		0.92

Acquisition of Logitel Offshore Holding AS

On August 11, 2014, the Partnership acquired 100% of the outstanding shares of Logitel. The purchase price for the shares of Logitel consisted of $4.0 million in cash paid at closing and a potential additional cash amount of $27.6 million, subject to reductions of some or all of this potential additional amount if certain performance criteria are not met, primarily relating to the construction of the three UMS ordered from COSCO in China (see note 4a).

The Partnership is committed to acquire the three UMS ordered from COSCO for a total cost of approximately $596 million, including estimated site supervision costs and license fees to be paid to Sevan to allow for use of its cylindrical hull design in these UMS (see note 14d), and $30.0 million from the Partnership’s assumption of Logitel’s obligations under a bond agreement from Sevan. Prior to the acquisition, Logitel secured a three-year fixed-rate charter contract with Petrobras in Brazil for the first UMS, the Arendal Spirit, which delivered in February 2015 and commenced its contract with Petrobras in June 2015. The second UMS is currently in lay-up. During the second quarter of 2015, the Partnership exercised its option to defer the delivery of its second UMS newbuilding by up to one year. During this period, COSCO will maintain and preserve this unit for the account of the Partnership, including the Partnership incurring interest at 5.0% per annum on the unpaid balance of the final yard installment. In August 2014, the Partnership exercised one of its existing six options with COSCO to construct a third UMS. During the second quarter of 2015, the Partnership exercised its option to defer the delivery and all related construction work of its third UMS by 120 days, and may decide to exercise an option to further defer the delivery of the unit by an additional two years. While the Partnership is pursuing charter contracts for the remaining two UMS newbuildings prior to their respective deferred deliveries in late-2016 and subject to the exercise of a deferred delivery option, mid-2019, it may decide to cancel the two newbuilding contracts.

The Partnership has assumed Logitel’s obligations under a bond agreement from Sevan as part of this acquisition. The bond is non-interest bearing and is repayable in amounts of $10.0 million within six months of delivery of each of the three UMS ordered from COSCO, for a total of $30.0 million, of which $10.0 million has been repaid as of December 31, 2015. If Logitel orders additional UMS’s with the Sevan cylindrical design, Logitel will be required to pay Sevan up to $11.9 million for each of the next three UMS ordered. If the fourth of six options with COSCO is not exercised by its option expiry date on November 30, 2016, Sevan has a one-time option to receive the remaining two options with COSCO.

The acquisition of Logitel was accounted for using the acquisition method of accounting, based upon finalized estimates of fair value.

The following table summarizes the preliminary and final valuations of the Logitel assets and liabilities on the acquisition date. The estimates of fair values of the Logitel assets acquired and liabilities assumed by the Partnership were finalized during the second quarter of 2015.


(in thousands of U.S. Dollars)	Preliminary Valuation August 11, 2014 $		Adjustments $			Final Valuation August 11, 2014 $
ASSETS
Cash and cash equivalents		8,089		—			8,089
Prepaid expenses		640		—			640
Advances on newbuilding contracts		46,809		(2,239	)		44,570
Intangible assets		—		1,000			1,000

Total assets acquired		55,538		(1,239	)		54,299

LIABILITIES
Accrued liabilities		4,098		—			4,098
Long-term debt		26,270		1,330			27,600

Total liabilities assumed		30,368		1,330			31,698

Net assets acquired		25,170		(2,569	)		22,601

Cash consideration		4,000		—			4,000

Contingent consideration		21,170		(2,569	)		18,601

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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 results of Logitel are reflected in the Partnership’s financial statements commencing August 11, 2014, the effective date of acquisition. For the year ended December 31 2014, the Partnership recognized $nil revenue and $1.0 million of net loss resulting from this acquisition. The following table shows comparative summarized consolidated pro forma financial information for the Partnership for the years ended December 31, 2014 and 2013, giving effect to the Partnership’s acquisition of Logitel as if it had taken place on January 1, 2013:


(in thousands of U.S. Dollars, except per unit data)	Pro Forma Year Ended December 31, 2014			Pro Forma Year Ended December 31, 2013
Revenues		1,019,539			930,739
Net income from continuing operations		16,717			75,827
Limited partners’ interest in net income from continuing operations per common unit:
- Basic		(0.24	)		0.92
- Diluted		(0.24	)		0.92

19.

(Write-down) and Gain (Loss) on Sale of Vessels, Conventional Tankers Dispositions and Discontinued Operations

(Write-down) and Gain (Loss) on Sale of Vessels

In 2015, the carrying values of two of the Partnership’s 2000’s-built conventional tankers and seven of the Partnership’s 1990s-built shuttle tankers were written down to their estimated fair value, using appraised values. The write-down of the two conventional tankers was the result of the expected sale of the vessels and the vessels were classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015 (see below). The Partnership’s consolidated statement of income for the year ended December 31, 2015, includes a $3.9 million write-down related to these two conventional tankers. The write-down is included in the Partnership’s conventional tanker segment. Of the seven shuttle tankers, during the first quarter of 2015, one shuttle tanker was written down as a result of the expected sale of the vessel and the vessel was classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015. The vessel was subsequently sold in January 2016 for gross proceeds of $5.1 million (see note 21). An additional shuttle tanker was written down during the first quarter of 2015 as a result of a change in the operating plan of the vessel. In the fourth quarter of 2015, the write-down of five shuttle tankers, which have an average age of 17.5 years, was the result of changes in our expectations of their future opportunities, primarily due to their advanced age. While we expect four of the five vessels to continue to actively trade as shuttle tankers over the near-term and the fifth vessel to actively trade in the conventional tanker market, we anticipate fewer opportunities for alternative usage and increased age discrimination over time. The Partnership’s consolidated statement of income for the year ended December 31, 2015, includes total write-downs of $66.7 million related to these seven shuttle tankers. The write-downs are included in the Partnership’s shuttle tanker segment. In 2015, the Partnership sold a 1997-built shuttle tanker, the Navion Svenita, for net proceeds of $8.6 million. The Partnership’s consolidated statement of income for the year ended December 31, 2015 includes a $1.6 million gain related to the sale of this vessel. The gain on sale is included in the Partnership’s shuttle tanker segment.

In 2014, the carrying value of one of the Partnership’s 1990s-built shuttle tankers was written down to its estimated fair value, using an appraised value. The write-down was the result of the vessel charter contract expiring in early-2015. The Partnership’s consolidated statement of income for the year ended December 31, 2014, includes a $4.8 million write-down related to this vessel. The write-down is included in the Partnership’s shuttle tanker segment. In the fourth quarter of 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to a joint venture between the Partnership and a joint venture partner (see note 20). The Partnership’s consolidated statement of income for the year ended December 31, 2014, includes a $3.1 million gain related to the sale of this vessel. The gain on sale of vessel is included in the Partnership’s shuttle tanker segment.

In 2013, the carrying values of six of the Partnership’s 1990s-built shuttle tankers were written down to their estimated fair value using appraised values. Of the six vessels, during the third quarter of 2013, four of the shuttle tankers were written down as the result of the re-contracting of one of the vessels, which the Partnership owns through a 50%-owned subsidiary, at lower rates than expected, the cancellation of a short-term contract and a change in expectations for the contract renewal for two of the shuttle tankers, one operating in Brazil, and the other, which the Partnership owns through a 50%-owned subsidiary, in the North Sea. In the fourth quarter of 2013, two shuttle tankers, which the Partnership owns through a 67%-owned subsidiary, were written down due to a cancellation of a contract renewal and expected sale of an aging vessel to their estimated fair value. One of these two vessels was also written down in 2012. The Partnership’s consolidated statement of income for 2013 includes a total write-down of $76.8 million related to these vessels, of which $37.2 million relates to two shuttle tankers, which the Partnership owns through a 50%-owned subsidiary, and $19.3 million relates to two shuttle tankers, which the Partnership owns through a 67%-owned subsidiary.

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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)

Conventional Tankers Dispositions

In December 2015, bareboat and time-charter contracts with a subsidiary of Teekay Corporation for the SPT Explorer, Navigator Spirit and Fuji Spirit were terminated by the Partnership. The Partnership concurrently paid total net charter termination fees to Teekay Corporation of $1.8 million. Immediately following the charter terminations, the Partnership sold its 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd., a company under common control, for net proceeds of $39.0 million, consisting of $80.0 million for the vessels and $8.6 million for working capital less $49.6 million for assumption of long-term debt. The $14.3 million excess of the purchase price over the Partnership’s carrying value of SPT Explorer L.L.C. and Navigator Spirit L.L.C. has been accounted for as an equity contribution in the Partnership’s consolidated statement of changes in total equity. As at December 31, 2015, the Partnership classified its two remaining conventional tankers, the Fuji Spirit and Kilimanjaro Spirit as held for sale due to the expected sale of these vessels in early-2016. The following table summarizes the pretax profit and components thereof for the SPT Explorer, Navigator Spirit, Fuji Spirit and Kilimanjaro Spirit for the periods presented in the consolidated statements of income:


	Year Ended December 31, 2015 $			Year Ended December 31, 2014 $			Year Ended December 31, 2013 $
Revenues		30,230			33,566			34,772

Voyage expenses		(2,326	)		(5,373	)		(4,532	)
Vessel operating expenses		(6,234	)		(5,906	)		(5,813	)
Depreciation and amortization		(6,583	)		(6,680	)		(6,511	)
General and administrative		(11	)		(8	)		(6	)
Restructuring charge		—			—			(438	)

Income from vessel operations		15,076			15,599			17,472

Interest expense		(1,007	)		(902	)		(981	)
Foreign currency exchange loss		(7	)		(6	)		(9	)
Other expense - net		—			(4	)		(4	)

Net income before income tax expense		14,062			14,687			16,478

Discontinued Operations

Prior to being considered discontinued operations, the operations of the Leyte Spirit, the Poul Spirit and the Gotland Spirit were reported within the conventional tanker segment. The Leyte Spirit was written down in 2012 and sold in the first quarter of 2013. The Poul Spirit was written down to its estimated fair value in the first quarter of 2013 and further written down upon sale in the second quarter of 2013. The Gotland Spirit was written down to its estimated fair value in the second quarter of 2013 and a gain was recognized upon its sale in the third quarter of 2013. The estimated fair value for each of these vessels was determined using appraised values.

In the second quarter and first quarter of 2013, the Partnership terminated the long-term time-charter-out contracts employed by the Gotland Spirit and the Poul Spirit, respectively, with a subsidiary of Teekay Corporation. The Partnership received early termination fees from Teekay Corporation of $4.5 million and $6.8 million in the second quarter and first quarter of 2013, respectively.

The following table summarizes the net loss from discontinued operations for the period presented in the consolidated statements of income:


	Year Ended December 31, 2013 $
Revenues		20,238

Voyage expenses		(682	)
Vessel operating expenses		(3,903	)
Depreciation and amortization		(1,236	)
General and administrative		(479	)
(Write down) and gain (loss) on sale of vessels		(18,465	)

Loss from vessel operations		(4,527	)

Interest expense		(110	)
Foreign currency exchange loss		(4	)
Other expense - net		(1	)

Net loss from discontinued operations		(4,642	)

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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)

20.

Investment in Equity Accounted Joint Ventures and Advances to Joint Venture

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 with Odebrecht. The vessel is committed to a new FPSO unit conversion for the Libra field. The FPSO unit is scheduled to commence operations in early-2017 (see note 14e). In connection with the conversion project, the Libra Joint Venture entered into a $248 million loan facility, which was refinanced in late-2015 with a 10-year plus construction period loan facility providing total borrowings of up to $804 million, of which $220 million was drawn as of December 31, 2015. This loan facility will be used to fund future capital expenditure for the FPSO conversion. The interest payments on the loan facility are based on LIBOR, plus margins which range between 2.50% and 2.65%. The final payment under the loan facility is due March 2027. The Partnership has guaranteed its 50% share of the loan facility.

In June 2013, the Partnership acquired Teekay Corporation’s 50% interest in OOG-TKP FPSO GmbH & Co KG, a joint venture with Odebrecht, which owns the Itajai FPSO unit (see note 11e). As at December 31, 2014, the Partnership had advanced $5.2 million to the joint venture, which was repaid during 2015.

As at December 31, 2015 and 2014, the Partnership had total investments of $77.6 million and $55.0 million, respectively, in joint ventures. No indicators of impairment existed at December 31, 2015 and 2014.

The following table presents aggregated summarized financial information assuming a 100% ownership interest in the Partnership’s equity method investments. The results included are for the Itajai FPSO joint venture from June 2013 and the Libra Joint Venture from October 2014.


	As at December 31,
	2015 $		2014 $
Cash and cash equivalents		17,212		46,147
Other assets - current		18,846		13,541
Vessels and equipment and conversion costs		589,731		416,278
Other assets - non-current		5,385		10,639

Current portion of long-term debt		28,889		75,558
Other liabilities - current		18,514		37,776
Long-term debt		390,219		225,750
Other liabilities - non-current		34,978		35,976


	Year ended December 31,
	2015 $			2014 $			2013 $
Revenues		82,831			82,845			41,575
Income from vessel operations		37,351			35,273			17,132
Realized and unrealized (losses) gains on derivative instruments		(13,214	)		(6,656	)		1,426
Net income		15,344			20,682			13,462

21.

Subsequent Events

In January 2016, the Partnership sold a 1992-built shuttle tanker, the Navion Torinita, which was classified as held for sale on the Partnership’s consolidated balance sheet as of December 31, 2015, for gross proceeds of $5.1 million, consistent with the amount reported on the balance sheet.

As at December 31, 2015, the Kilimanjaro Spirit and Fuji Spirit conventional tankers were classified as held for sale on the Partnership’s consolidated balance sheets due to the expected sale of these vessels in early-2016. As part of the sale, the Partnership is in-chartering these vessels for a period of three years with an additional one-year extension option. One vessel is fixed on a two-year time-charter-out contract and the other vessel is trading in the spot conventional tanker market.

F - 35