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, 2013

¨	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)

Mark Cave

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

Telephone: (441) 298-2530

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

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.

85,452,079 Common Units

6,000,000 Series A 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		21
Item 4.	Information on the Partnership		22
	A. Overview, History and Development		22
	Overview and History		22
	Potential Additional Shuttle Tanker, FSO, and FPSO Projects		22
	B. Business Overview		22
	Shuttle Tanker Segment		22
	FPSO Segment		25
	Conventional Tanker Segment		26
	FSO Segment		27
	Business Strategies		27
	Customers		28
	Safety, Management of Ship Operations and Administration		28
	Risk of Loss, Insurance and Risk Management		29
	Flag, Classification, Audits and Inspections		29
	Regulations		30
	C. Organizational Structure		33
	D. Properties		33
	E. Taxation of the Partnership		33
Item 4A.	Unresolved Staff Comments		34
Item 5.	Operating and Financial Review and Prospects		34
	Overview		34
	Significant Developments		35
	Potential Additional Shuttle Tanker, FSO and FPSO Projects		37
	Our Contracts and Charters		37
	Important Financial and Operational Terms and Concepts		38
	Items You Should Consider When Evaluating Our Results		38
	Results of Operations		39
	Liquidity and Capital Resources		51
	Cash Flows		52
	Contractual Obligations and Contingencies		53
	Off-Balance Sheet Arrangements		54
	Critical Accounting Estimates		54
Item 6.	Directors, Senior Management and Employees		57
	A. Directors and Senior Management		57
	Management of Teekay Offshore Partners L.P.		57
	Directors and Executive Officers of Teekay Offshore GP L.L.C.		57
	B. Compensation		58
	Executive Compensation		58
	Compensation of Directors		58
	2006 Long-Term Incentive Plan		59
	C. Board Practices		59
	D. Employees		60
	E. Unit Ownership		60
Item 7.	Major Unitholders and Related Party Transactions		60
	A. Major Unitholders		60
	B. Certain Relationships and Related Party Transactions		61
Item 8.	Financial Information		64


	A. Consolidated Financial Statements and Other Financial Information	64
	Consolidated Financial Statements and Notes	64
	Legal Proceedings	64
	Cash Distribution Policy	65
	B. Significant Changes	66
Item 9.	The Offer and Listing	66
Item 10.	Additional Information	66
	Memorandum and Articles of Association	66
	Material Contracts	66
	Exchange Controls and Other Limitations Affecting Unitholders	67
	Material U.S. Federal Income Tax Considerations	68
	Non-United States Tax Consequences	71
	Documents on Display	72
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	72
	Interest Rate Risk	72
	Foreign Currency Fluctuation Risk	72
	Commodity Price Risk	73
Item 12.	Description of Securities Other than Equity Securities	73

PART II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	73
Item 14.	Material Modifications to the Rights of Unitholders and Use of Proceeds	73
Item 15.	Controls and Procedures	73
	Management’s Report on Internal Control over Financial Reporting	74
Item 16A.	Audit Committee Financial Expert	74
Item 16B.	Code of Ethics	74
Item 16C.	Principal Accountant Fees and Services	74
Item 16D.	Exemptions from the Listing Standards for Audit Committees	75
Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers	75
Item 16F.	Change in Registrant’s Certifying Accountant	75
Item 16G.	Corporate Governance	75
Item 16H.	Mine Safety Disclosure	75

PART III.
Item 17.	Financial Statements	75
Item 18.	Financial Statements	75
Item 19.	Exhibits	76
Signature		77

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;

•

growth prospects of the offshore and tanker markets;

•

our potential additional shuttle tanker, floating storage and off-take (or FSO) and floating production, storage and offloading (or FPSO) projects;

•

the recent economic downturn and financial crisis in the global market, and potential negative effects on our customers’ ability to charter our vessels and pay for our services;

•

the expected commencement date and estimated cost of FPSO projects;

•

the estimated cost and expected delivery dates of conversions of existing vessels, and the expected commencement of their time-charter contracts;

•

offshore and tanker market fundamentals, including the balance of supply and demand in the offshore and tanker markets;

•

our competitive advantage in the shuttle tanker market;

•

the expected lifespan of our vessels;

•

the estimated cost and expected delivery dates of our towage vessel newbuildings;

•

the estimated sales price or scrap value of vessels;

•

estimated capital expenditures and our ability to fund them;

•

expected increases in vessel operating expenses and charter rates for our vessels;

•

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;

•

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

•

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 with customers;

•

obtaining offshore projects that we or Teekay Corporation bid on or that Teekay Corporation is awarded;

•

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

•

our expected financial flexibility to pursue acquisitions and other expansion opportunities;

•

anticipated funds for liquidity needs and the sufficiency of cash flows;

•

the future valuation of goodwill;

•

our expectations as to any impairment of our vessels;

•

the adequacy of our insurance coverage;

•

the expected cost of, and our ability to comply with, governmental regulations and maritime self-regulatory organization standards applicable to our business;

•

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

•

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

•

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 (or the General Partner);

•

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

•

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

Forward-looking statements are necessarily 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 2009 through 2013, 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 therein (which are included herein), with respect to the consolidated financial statements for each of the fiscal years ended December 31, 2011 through 2013.

From time to time we purchase vessels from Teekay Corporation.

In September 2009, we acquired from Teekay Corporation its interest in an FPSO unit, the Petrojarl Varg, along with its operations and charter contracts. In April 2010, we acquired from Teekay Corporation an FSO unit, the Falcon Spirit, together with its charter contract. In October 2010, we acquired from Teekay Corporation the Cidade de Rio das Ostras (or Rio das Ostras) FPSO unit, along with its operations and charter contract. In October 2010 and October 2011, we also acquired from Teekay Corporation the newbuilding shuttle tankers, the Amundsen Spirit and the Scott Spirit, both on charter to Statoil. In May 2013, we acquired from Teekay Corporation the Voyageur Spirit 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, in which 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 reflect these vessels and the results of operations of the vessels, referred to herein as the Dropdown Predecessor, as if we had acquired them when each respective vessel began operations under the ownership of Teekay Corporation. These vessels began operations on October 1, 2006 (Petrojarl Varg), April 1, 2008 (Rio das Ostras), December 15, 2009 (Falcon Spirit), July 30, 2010 (Amundsen Spirit), July 22, 2011 (Scott Spirit) and April 13, 2013 (Voyageur Spirit). Please read Item 18 – Financial Statements: Note 2 – Dropdown Predecessor.

On October 1, 2010, we agreed to acquire Teekay Corporation’s interests in two entities, which each own a newbuilding shuttle tanker, the Nansen Spirit and the Peary Spirit. We acquired the Nansen Spirit on December 10, 2010 and the Peary Spirit on August 2, 2011. As these entities were considered variable interest entities prior to their acquisition by us, our consolidated financial statements reflect the financial position, results of operations and cash flows of the Peary Spirit from October 1, 2010 to August 2, 2011, and the Nansen Spirit from October 1, 2010 to December 10, 2010, the dates the Peary Spirit and the Nansen Spirit were acquired by us from Teekay Corporation. Subsequent to our acquisition of the entities which own these two vessels, these entities continue to be consolidated in our results as we hold voting control.

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


				Year Ended December 31,
	2009			2010			2011			2012			2013
	(in thousands of US dollars, except per unit, unit and fleet data)
Income Statement Data:
Revenues		777,655			816,056			840,982			901,227			930,739
Total operating expenses⁽¹⁾		672,285			685,070			729,848			734,650			827,321

Income from vessel operations		105,370			130,986			111,134			166,577			103,418
Interest expense		(48,762	)		(36,242	)		(35,929	)		(47,508	)		(62,855	)
Interest income		1,232			842			659			1,027			2,561
Realized and unrealized gain (loss) on derivative instruments		51,944			(55,666	)		(159,744	)		(26,349	)		34,820
Equity income		—			—			—			—			6,731
Foreign currency exchange (loss) gain ⁽²⁾		(11,184	)		941			1,500			(315	)		(5,278	)
Loss on bond repurchase		—			—			—			—			(1,759	)
Other income - net		9,429			6,810			3,683			1,538			1,144
Income tax (expense) recovery		(13,792	)		9,718			(6,679	)		10,477			(2,225	)

Net income (loss) from continuing operations		94,237			57,389			(85,376	)		105,447			76,557
Net income (loss) from discontinued operations		26,565			21,474			(11,495	)		17,568			(4,642	)

Net income (loss)		120,802			78,863			(96,871	)		123,015			71,915

Non-controlling and other interests in net income (loss) from continuing operations		46,040			13,710			7,601			12,885			62
Non-controlling and other interests in net income (loss) from discontinued operations		13,554			11,342			4,174			(1,772	)		(452	)
Limited partners’ interest:
Net income (loss) from continuing operations		48,197			43,679			(92,977	)		92,562			76,495
Net income (loss) from continuing operations per common unit (basic and diluted) ⁽³⁾		1.46			0.99			(1.49	)		1.26			0.93
Net income (loss) from discontinued operations		13,011			10,132			(15,669	)		19,340			(4,190	)
Net income (loss) from discontinued operations per common unit (basic and diluted) ⁽³⁾		0.39			0.23			(0.25	)		0.26			(0.05	)
Cash distributions declared per unit		1.80			1.88			1.98			2.04			2.11

Balance Sheet Data (at end of year):
Cash and cash equivalents		109,407			166,483			179,934			206,339			219,126
Vessels and equipment ⁽⁴⁾		2,120,688			2,299,507			2,585,586			2,454,623			3,089,582
Total assets		2,651,069			2,842,626			3,144,729			3,053,391			3,806,086
Total debt		2,045,055			1,717,140			2,029,076			1,769,632			2,368,976
Total equity		370,871			728,449			484,733			705,229			821,341

Common units outstanding		27,900,000			55,237,500			70,626,554			80,105,108			85,452,079

Other Financial Data:
Net revenues ⁽⁵⁾		688,465			710,685			743,398			790,744			827,096
EBITDA ⁽⁶⁾		316,230			252,639			128,303			330,815			338,082
Adjusted EBITDA ⁽⁶⁾		312,141			362,976			390,967			405,243			397,445
Expenditures for vessels and equipment		14,260			40,645			148,480			87,408			455,578

Fleet data:
Average number of shuttle tankers ⁽⁷⁾		35.9			35.2			36.5			35.5			33.8
Average number of FPSO units ⁽⁷⁾		2.0			2.0			2.1			3.0			4.2
Average number of conventional tankers ⁽⁷⁾		11.0			11.0			10.6			6.0			5.2
Average number of FSO units ⁽⁷⁾		5.0			6.0			5.2			5.0			5.8

(1)	Total operating expenses include, among other things, the following:


	Year Ended December 31,
	2009		2010		2011		2012		2013
Write down and loss on sale of vessels		—		9,441		37,039		24,542		76,782
Restructuring charge		5,008		119		3,924		1,115		2,607

		5,008		9,560		40,963		25,657		79,389

(2)

Substantially all 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. Starting in November 2010, foreign currency exchange gains and losses includes realized and unrealized gains and losses on the cross currency swaps.

(3)	Net income (loss) per unit is determined by dividing net income (loss), after deducting the amount of net income (loss) attributable to the Dropdown Predecessor, the non-controlling interests, the General Partner’s interest and the distributions on the Series A preferred units, by

the weighted-average number of common units outstanding during the applicable period. We allocate the limited partners’ interest in net income (loss), including both distributed and undistributed net income (loss), between continuing operations and discontinued operations based on the proportion of net income (loss) from continuing and discontinuing operations to total net income (loss).

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

(5)

Consistent with general practice in the shipping industry, we use “net revenues” (defined as revenues less voyage expenses) 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,
	2009		2010		2011		2012		2013
Revenues		777,655		816,056		840,982		901,227		930,739
Voyage expenses		89,190		105,371		97,584		110,483		103,643

Net revenues		688,465		710,685		743,398		790,744		827,096

(6)	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 measure 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 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, 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 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 units.

Neither EBITDA nor Adjusted EBITDA, which are non-GAAP measures, should be considered as an alternative to net income (loss), 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 income (loss), and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA as presented in this 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 income (loss), and our historical consolidated Adjusted EBITDA to net operating cash flow.


	Year Ended December 31,
	2009			2010			2011			2012			2013
	(in thousands of US dollars)
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income (loss)”:
Net income (loss) from continuing operations		94,237			57,389			(85,376	)		105,447			76,557
Depreciation and amortization		160,671			169,568			171,730			189,364			199,006
Interest expense, net of interest income		47,530			35,400			35,270			46,481			60,294
Income tax expense (recovery)		13,792			(9,718	)		6,679			(10,477	)		2,225

EBITDA		316,230			252,639			128,303			330,815			338,082

Write down and loss of sale of vessels		—			9,441			37,039			24,542			76,782
Restructuring charge		5,008			119			3,924			1,115			2,607
Unrealized (gain) loss on derivative instruments		(113,570	)		5,618			107,860			(39,538	)		(91,837	)
Realized loss on interest rate swaps		51,084			49,224			58,475			58,596			94,848
Foreign exchange loss (gain)⁽ⁱ⁾		11,242			3,090			(3,081	)		11,015			(33,318	)
Loss on bond repurchase		—			—			—			—			1,759
Amortization of in-process revenue contracts		(6,952	)		(571	)		(1,075	)		(12,634	)		(12,704	)
Adjustments relating to equity income⁽ⁱⁱ⁾		—			—			—			—			6,057
Adjustments relating to discontinued operations⁽ⁱⁱⁱ⁾		49,099			43,416			59,522			31,332			15,169

Adjusted EBITDA		312,141			362,976			390,967			405,243			397,445

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
Net operating cash flow		162,361			286,585			254,162			267,494			255,387
Expenditures for dry docking		41,864			23,637			26,407			19,122			19,332
Interest expense, net of interest income		47,530			35,400			35,270			46,481			60,294
Current income tax expense (recovery)		5,583			6,038			7,293			(1,669	)		75
Realized loss on interest rate swaps		51,084			49,224			58,475			58,596			94,848
Equity income		—			—			—			—			6,731
Change in working capital		(8,931	)		(34,464	)		11,296			17,447			(51,999	)
Restructuring charge		5,008			119			3,924			1,115			2,607
Loss on bond repurchase		—			—			—			—			1,759
Other, net		5,613			(4,732	)		(6,828	)		(4,165	)		2,244
Adjustments relating to equity income⁽ⁱⁱ⁾		—			—			—			—			6,057
Interest expense, net of interest income related to discontinued operations⁽ⁱⁱⁱ⁾		2,029			1,169			968			822			110

Adjusted EBITDA		312,141			362,976			390,967			405,243			397,445

(i)	Foreign exchange loss (gain) excludes the unrealized loss of $38.6 million (2012 – gain of $10.7 million, 2011 - loss of $1.6 million, 2010 – gain of $4.0 million and 2009 - $nil) on cross currency swaps, which is incorporated in unrealized (gain) loss on derivative instruments in the table.

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


	Year Ended December 31,
	2009		2010		2011		2012		2013
Depreciation and amortization		—		—		—		—		4,239
Interest expense, net of interest income		—		—		—		—		2,715
Income tax recovery		—		—		—		—		(184	)
Unrealized gain on derivative instruments		—		—		—		—		(2,302	)
Realized loss on interest rate swaps		—		—		—		—		1,589

Adjustments relating to equity income		—		—		—		—		6,057

(iii)

Adjustments relating to our discontinued operations are as follows:


	Year Ended December 31,
	2009		2010		2011			2012		2013
Net income (loss) from discontinued operations		26,565		21,474		(11,495	)		17,568		(4,642	)
Depreciation and amortization		20,505		20,773		15,980			5,267		1,236
Interest expense, net of interest income		2,029		1,169		968			822		110
Write down and loss on sale of vessels		—		—		54,069			7,675		18,465

Adjustments relating to discontinued operations		49,099		43,416		59,522			31,332		15,169

(7)	Average number of vessels consists of the average number of owned and chartered-in vessels that were in our possession during a period, including the Dropdown Predecessor and those in discontinued operations. This includes one FPSO unit in an equity accounted joint venture at 100%.

Risk Factors

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 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);

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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;

•

delays in the delivery of any newbuildings or vessels undergoing conversion 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 instruments;

•

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 their 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. 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;

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

•

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 our general partner believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

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 maintenance capital expenditures, working capital and other matters. We also rely upon external financing sources, including commercial borrowings, to fund our capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may significantly impair our ability to meet our financial needs or to grow.

We 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:

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the cost of labor and materials;

•

customer requirements;

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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 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 to expand the size of our fleet. We 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. Depending on whether we finance our expenditures through 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.

Currently, the total delivered cost for an Aframax or Suexmax-size shuttle tanker is approximately $95 to $115 million, the cost of converting an existing tanker to an FSO unit is approximately $50 to $300 million and the cost of an FPSO unit is approximately $350 million to $2 billion, although actual costs vary significantly depending on the market price charged by shipyards, the size and specifications of the vessel, governmental regulations and maritime self-regulatory organization standards.

We 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, within 365 days of their deliveries, certain shuttle tankers, FSO units and FPSO units Teekay Corporation owns or may acquire in the future, including certain vessels of Teekay Corporation’s subsidiary Teekay Petrojarl AS (or Teekay Petrojarl), 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 are pursuing 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.

To fund the remaining portion of existing or future capital expenditures, we will be required to use cash from operations or incur borrowings or raise capital through the sale of debt or additional equity securities. Use of cash from operations 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 resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make cash distributions. Even if we are successful in obtaining necessary funds, the terms of such financings could limit our ability to pay cash distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain our current level of quarterly distributions to unitholders, which could have a material adverse effect on our ability to make 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.

If we are awarded contracts for additional offshore projects or otherwise acquire additional vessels or businesses, our consolidated debt may significantly increase. As at December 31, 2013, our total debt was approximately $2.4 billion and we had the ability to borrow an additional $111.9 million under our revolving credit facilities, subject to limitations in the credit facilities. We may incur additional debt under these or future credit facilities. In October 2014, we have $410.4 million of balloon payments due on two revolving credit facilities. Both of these revolving credit facilities bear interest at rates that are considered below current market rates relative to the current market levels and as such, we intend to refinance these balloon payments by entering into a new credit facility closer to the date of their maturities. In September 2014, we have a $15.7 million balloon payment due on one of our revolving credit facilities, which we intend on refinancing with a new loan facility closer to the date this facility comes due. 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 reducing dividends/cash distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

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.

Five 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. Our remaining two revolving credit facilities are guaranteed by Teekay

Corporation and contain covenants that require Teekay Corporation 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 $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 24 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 of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. Neither Teekay Corporation nor we might have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, 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 that requires us to maintain a vessel value to outstanding drawn principal balance ratio of a minimum of 105%. As at December 31, 2013, this ratio was 123%. The vessel value used in this ratio is the appraised value prepared by us based on second-hand sale and purchase market data. A further delay in the recovery of the conventional tanker market could negatively affect this ratio.

At December 31, 2013 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;

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

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breach of certain financial covenants;

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

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default under other indebtedness;

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bankruptcy or insolvency events;

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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. Petrobras Transporte S.A., Statoil ASA, and Talisman Energy Inc accounted for approximately 25%, 20%, and 13%, 28%, 21%, and 13%, and 24%, 24%, and 13% respectively, of consolidated revenues from continuing operations during 2013, 2012 and 2011. No other customer accounted for 10% or more of revenues from continuing operations during any of these periods.

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, we may be unable to acquire an adequate replacement vessel. 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 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 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.

Our ability to compete for offshore oil marine transportation, processing 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 and its reputation and relationships in the shipping industry. If Teekay Corporation suffers material damage to its reputation or relationships, it may harm the ability of us or other subsidiaries to:

•

renew existing charters and contracts of affreightment upon their expiration;

•

obtain new charters and contracts of affreightment;

•

successfully interact with shipyards during periods of shipyard construction constraints;

•

obtain financing on commercially acceptable terms; or

•

maintain satisfactory relationships with suppliers and other third parties.

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

Our operating subsidiaries may also contract with certain subsidiaries of Teekay Corporation for the Teekay Corporation subsidiaries to have newbuildings constructed or existing vessels converted on behalf of the operating subsidiaries and to incur the construction-related financing. The operating subsidiaries would purchase the vessels on or after delivery based on an agreed-upon price. None of our operating subsidiaries currently has this type of arrangement with Teekay Corporation or any of its affiliates.

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

Our growth strategy focuses on expansion in the shuttle tanker, FSO, FPSO and towage 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:

•

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

•

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

•

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

•

availability of new, alternative energy sources; and

•

negative global or regional economic or political conditions, particularly in oil consuming regions, which could reduce energy consumption or its growth. Reduced demand for offshore marine transportation, processing, storage services or towage 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 or future 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 may receive a reduced production incentive payment or no production incentive payment under the Petrojarl Varg FPSO operations contract depending on production levels. We also 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. Talisman Energy Norge AS (or Talisman Energy) may terminate the Petrojarl Varg operations contract if the Varg field does not yield sufficient revenues. E.ON Ruhrgas UK GP Limited (or E.ON) may terminate the Voyageur Spirit operations contract if the Huntington field does not yield sufficient revenues, however 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 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 cash distributions. FPSO units, in particular, 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. 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.

In recent years, the global economy experienced an economic downturn and crisis in the global financial markets that produced illiquidity in the capital markets, market volatility, heightened exposure to interest rate and credit risks and reduced access to capital markets. If there is economic instability in the future, we may face restricted access to the capital markets or secured debt lenders, such as our revolving credit facilities. The decreased access to such resources could have a material adverse effect on our business, financial condition and results of operations.

Future adverse economic conditions 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 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 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 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. 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 and FPSO contracts are awarded based upon a variety of factors relating to the vessel operator, including:

•

industry relationships and reputation for customer service and safety;

•

experience and quality of ship operations;

•

quality, experience and technical capability of the crew;

•

relationships with shipyards and the ability to get suitable berths;

•

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

•

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

•

competitiveness of the bid in terms of overall price.

We expect substantial competition for providing services for potential shuttle tanker, FSO and FPSO projects from a number of experienced companies, including state-sponsored entities. Our Aframax conventional tanker business also faces substantial competition from major oil companies, independent owners and operators and other sized tankers. Many of our competitors have significantly greater financial resources than do we, or Teekay Corporation, which also may compete with us. We anticipate that an increasing number of marine transportation companies — including many with strong reputations and extensive resources and experience — will enter the FSO and FPSO sectors. 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 cash distributions.

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

The operational start-up of FPSO units or the deliveries of any newbuildings or of vessel conversions we may order 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 could be delayed because of:

•

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

•

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

•

work stoppages or other labor disturbances at the shipyard;

•

bankruptcy or other financial crisis of the shipbuilder;

•

a backlog of orders at the shipyard;

•

political or economic disturbances;

•

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

•

requests for changes to the original vessel specifications;

•

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

•

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

•

inability to obtain requisite permits or approvals.

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

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

Our ability to recharter our conventional oil tankers following expiration of existing time-charter contracts and the rates payable upon any renewal or replacement charters will depend upon, among other things, the state of the conventional tanker market. Conventional oil tanker trades are highly competitive and have experienced significant fluctuations in charter rates based on, among other things, oil and vessel demand. For example, an oversupply of conventional oil tankers can significantly reduce their charter rates. There also exists some volatility in charter rates for shuttle tankers and FSO and FPSO units.

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

Vessel values for shuttle tankers, conventional oil tankers, FSO and FPSO 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 might otherwise be deployed.

Vessel values may decline from existing levels, and vessel values in particular have declined over the past few years. If 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 and FSO and FPSO units, 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. Recently, we entered the long-haul ocean towage and offshore installation services business through our acquisition of ALP Maritime Services B.V. (or ALP) in March 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.

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

Because our operations are primarily conducted outside of the United States, they may be affected by economic, political and governmental conditions in the countries where we engage in business or where our vessels are registered. Any disruption caused by these factors could harm our business, including by reducing the levels of oil exploration, development and production activities in these areas. We derive some of our revenues from shipping oil from politically unstable regions. 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 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 and Voyageur Spirit 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 and FSO and FPSO units is inherently risky. All risks may not be adequately insured against, and any particular claim may not be paid by insurance. In addition, substantially all of our vessels 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 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 self-regulatory organizations.

Changes in the insurance markets attributable to terrorist attacks 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 units and FPSO units are complex and their operations are technically challenging. Marine transportation and oil production operations are subject to mechanical risks and problems. 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 conflicts in the Middle East, and other current and future conflicts, may adversely affect our business, operating results, financial condition, and ability to raise capital and future growth. Continuing hostilities in the Middle East may lead to additional armed conflicts or to further acts of terrorism and civil disturbance in the United States or elsewhere, which may contribute further to economic instability and disruption of oil production and distribution, which could result in reduced demand for our services.

In addition, oil facilities, shipyards, vessels, pipelines, oil fields or other infrastructure could be targets of future terrorist attacks and our vessels could be targets of pirates or hijackers. 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, which would harm our cash flow and business.

Acts of piracy on ocean-going vessels have recently increased in frequency, 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 continue to be significant numbers of piracy incidents in the Gulf of Aden and Indian Ocean, recently there have been increases in the frequency and severity of piracy incidents off the coast of West Africa. If these piracy attacks result in regions in which our vessels are deployed being named on the Joint War Committee Listed Areas, war risk insurance premiums payable for such coverage can increase significantly and such insurance coverage may be more difficult to obtain. In addition, crew costs, including costs which 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 contracts of affreightment. 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 and ability to make cash distributions.

Teekay Corporation 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. Competition to attract and retain qualified crew members is intense, and crew manning costs continue to increase. If we are not able to increase our rates to compensate for any crew cost increases, our financial condition and results of operations may be adversely affected. 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

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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:

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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;

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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;

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provide ship management services relating to owning, operating or chartering offshore vessels and related time charters and contracts of affreightment; or

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own a limited partner interest in Teekay Offshore Operating L.P. (or OPCO) or own shares of Teekay Petrojarl.

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 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 March 1, 2014, Teekay Corporation indirectly owns the 2.0% general partner interest and a 27.9% 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:

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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;

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the Chief Executive Officer and Chief Financial Officer and one of the directors of our general partner also serve as executive officers or directors of Teekay Corporation and the general partner of Teekay LNG Partners L.P.;

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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;

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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;

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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;

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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);

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

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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;

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

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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;

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

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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 and Chief Financial Officer and all of the non-independent directors of our general partner also serve as executive officers or directors of Teekay Corporation. Consequently, these officers and directors may encounter situations in which their fiduciary obligations to Teekay Corporation, 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 taxed as a corporation for U.S. federal income tax purposes will be treated as a “passive foreign investment company” (or PFIC), for U.S. federal income tax purposes if at least 75.0% of its gross income for any taxable year consists of certain types of “passive income,” or at least 50.0% of the average value of the entity’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest, and 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 U.S. Internal Revenue Code of 1986, as amended (or the Code). However, the Internal Revenue Service (or IRS) stated in an Action on Decision (AOD 2010-01) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the Tidewater decision, and in its discussion stated that the time charters at issue in Tidewater would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to Tidewater cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the Tidewater decision in interpreting the PFIC provisions of the Code. Nevertheless, based on our 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 assets, income or operations.

If the IRS were to determine that we are or have been a PFIC for any taxable year, U.S. unitholders will face adverse U.S. federal income tax consequences. Under the PFIC rules, unless those U.S. unitholders make certain elections available under the Code, such unitholders would be liable to pay tax at ordinary income tax rates plus interest upon certain distributions and upon any gain from the disposition of our common units, as if such distribution or gain had been recognized ratably over the unitholder’s holding period. 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. For example, authorities in Norway have asserted certain positions that may result in additional tax imposed on our subsidiaries in Norway. 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 Norwegian 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.

Common unitholders may be subject to income tax in one or more non-U.S. countries, including Canada, as a result of owning our common units if, under the laws of any such country, we are considered to be carrying on business there. Such laws may require common 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 common 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 imposed upon us and our subsidiaries or which may be imposed upon you as a result of owning our common units. However, there is a risk that common unitholders will be subject to tax in one or more countries, including Canada, as a result of owning our common units if, under the laws of any such country, we are considered to be carrying on business there. If common unitholders are subject to tax in any such country, common

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 common unitholders on account of any withholding obligations imposed upon us by that country in respect of such allocation to common unitholders. The United States may not allow a tax credit for any foreign income taxes that common unitholders directly or indirectly incur. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for common unitholders.

Item 4. Information on the Partnership

A. Overview, History and Development

Overview and History

We are an international provider of marine transportation, oil production and storage services to the offshore oil industry. We were formed as a Marshall Islands limited partnership in August 2006 by Teekay Corporation (NYSE: TK), a leading provider of international crude oil and gas marine transportation services that also offers offshore oil production, storage and offloading services, to further develop its operations in the offshore market. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and our controlled affiliates to pursue growth opportunities in this market. As of March 1, 2014, Teekay Corporation, which owns and controls our general partner, owned 27.86% of the limited partner interest in us.

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, 2013, our fleet consisted of:

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Shuttle Tankers. Our shuttle tanker fleet consisted of 36 vessels (including one vessel committed for an FSO conversion upon expiry of its current contract in 2015 and the HiLoad Dynamic Positioning (or DP) unit scheduled to complete operational testing in the second quarter of 2014) that mainly operate under fixed-rate contracts of affreightment, time charters and bareboat charters. Of the 36 shuttle tankers, six were held through 50% owned subsidiaries, three through a 67% owned subsidiary and three are chartered-in by us, with the remainder owned 100% by us. All of these shuttle tankers provide transportation services to energy companies, primarily in the North Sea and Brazil. The average term of the contracts of affreightment, weighted based on vessel years, is 3.2 years. The time charters and bareboat charters have an average remaining contract term of approximately 5.7 years. As of December 31, 2013, our shuttle tanker fleet had a total cargo capacity of approximately 4.4 million deadweight tonnes (or dwt), representing more than 40% of the total tonnage of the world shuttle tanker fleet.

•

FPSO Units. We had four FPSO units in which we have 100% ownership interests and one FPSO unit in which we have a 50% ownership. These vessels operate under operations and charter 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 have an average remaining term of approximately 4.6 years. As of December 31, 2013, our FPSO units had a total production capacity of approximately 0.2 million barrels of oil per day.

•

Conventional Tankers. We had a fleet of four Aframax conventional crude oil tankers, two of which operate under fixed-rate time charters with Teekay Corporation. In addition, two of these tankers have additional equipment for lightering and operated under fixed-rate bareboat charters with Skaugen PetroTrans. Subsequent to December 31, 2013, the bareboat charters for these two tankers were novated under the same terms to a subsidiary of Teekay Corporation. We have 100% ownership in all of these vessels. The average remaining term on these time charter and bareboat charter contracts is approximately 4.5 years. As of December 31, 2013, our conventional tankers had a total cargo capacity of approximately 0.4 million dwt.

•

FSO Units. We had a fleet of six FSO units (including one committed FSO conversion unit), in which we have 100% ownership interests in five FSO units and 89% interests in one FSO unit. All of the FSO units operate under fixed-rate contracts, with an average remaining term of approximately 3.0 years. As of December 31, 2013, our FSO units had a total cargo capacity of approximately 0.7 million dwt.

We were formed under the laws of the Republic of The Marshall Islands as Teekay Offshore Partners L.P. and maintain our principal executive headquarters at 4^th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530. Our principal operating office is located at Suite 2000, Bentall 5, 550 Burrard Street, Vancouver, British Columbia, Canada, V6C 2K2. Our telephone number at such address is (604) 683-3529.

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. Technical sophistication of the vessel is especially important in harsh operating environments such as the North Sea. 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.

As of December 31, 2013, there were approximately 93 vessels in the world shuttle tanker fleet (including eight newbuildings), the majority of which operate in the North Sea. Shuttle tankers also operate in Africa, Brazil, Canada, Asia and the US Gulf. As of December 31, 2013, we owned 33 shuttle tankers, 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, Transpetro, Viken Shipping, AET and J Lauritzen, which as of December 31, 2013 controlled fleets ranging from 2 to 22 shuttle tankers each. We believe that we have certain 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 and Brazil.

The following tables provide additional information about our shuttle tankers as of December 31, 2013:

Vessel

Capacity
(dwt)

Built

Ownership

Positioning

system

Operating

Region

Contract

Type ⁽¹⁾

Contract

Charterer

End Date

Scott Spirit

106,000

2011

100%

DP2

North Sea

CoA

Chevron, Hess, Marathon Oil, ENI, Draugen Transport, BP, ConocoPhillips, Total, Talisman, Nexen, MTDA, Dana Petroleum, Shell Int’l Trading & Shipping Co Ltd. and PetroCanada.⁽⁶⁾

Navion Oslo

100,300

2001

100%

DP2

North Sea

CoA

Karen Knutsen

153,600

1999

In-chartered (until January
2014)

DP2

North Sea

CoA

Navion Hispania

126,200

1999

100%

DP2

North Sea

CoA

Navion Britannia ⁽²⁾

124,200

1998

100%

DP2

North Sea

CoA

Navion Scandia

126,700

1998

100%

DP2

North Sea

CoA

Aberdeen

87,000

1996

In-chartered (until
December 2014)

North Sea

CoA

Navion Europa ⁽²⁾

130,300

1995

67%⁽⁵⁾

North Sea

CoA

Randgrid ^{(2) (3)}

124,500

1995

67%⁽⁵⁾

North Sea

CoA

Navion Norvegia

130,600

1995

67%⁽⁵⁾

North Sea

CoA

Majority of volumes are life-of-field

Navion Oceania

126,400

1999

100%

DP2

North Sea

CoA

Stena Natalita

108,100

2001

50%⁽⁷⁾

DP2

North Sea

CoA

Samba Spirit

154,100

2013

100%

DP2

Brazil

Time charter

June 2023

Lambada Spirit

154,000

2013

100%

DP2

Brazil

Time charter

July 2023

Bossa Nova Spirit

154,200

2013

100%

DP2

Brazil

Time charter

November 2023

Sertanejo Spirit

154,200

2013

100%

DP2

Brazil

Time charter

January 2024

Amundsen Spirit

106,000

2010

100%

DP2

North Sea

Time charter

Statoil ⁽⁸⁾

Peary Spirit

106,000

2011

100%

DP2

North Sea

Time charter

Statoil ⁽⁸⁾

Nansen Spirit

106,000

2010

100%

DP2

North Sea

Time charter

Statoil ⁽⁸⁾

Sallie Knutsen

153,600

1999

In-chartered (until 2015)

DP2

North Sea

Time charter

Statoil ⁽⁸⁾

Stena Sirita

126,900

1999

50%⁽⁷⁾

DP2

North Sea

Time charter

Esso

September 2015

Stena Alexita

127,000

1998

50%⁽⁷⁾

DP2

North Sea

Time charter

Esso

March 2014

Navion Anglia

126,400

1999

100%

DP2

Brazil

Time charter

Petrobras

June 2016

Navion Svenita

106,500

1997

100%

Brazil

Time charter

Petrobras

December 2014

HiLoad DP Unit ⁽⁴⁾

n/a

2010

100%

Brazil

Time charter

Petrobras

March 2024

Navion Gothenburg

152,200

2006

50%⁽⁷⁾

DP2

Brazil

Bareboat

Petrobras ⁽⁹⁾

July 2020

Nordic Brasilia

151,300

2004

100%

Brazil

Bareboat

Petrobras ⁽⁹⁾

July 2017

Nordic Rio

151,300

2004

50%⁽⁷⁾

Brazil

Bareboat

Petrobras ⁽⁹⁾

July 2017

Navion Stavanger

148,700

2003

100%

DP2

Brazil

Bareboat

Petrobras ⁽⁹⁾

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 ⁽⁹⁾

April 2018

Stena Spirit

151,300

2001

50%⁽⁷⁾

Brazil

Bareboat

Petrobras ⁽⁹⁾

July 2018

Navion Bergen

105,600

2000

100%

DP2

Brazil

Bareboat

Petrobras ⁽⁹⁾

April 2020

Navion Marita

103,900

1999

100%

Far-East

Spot

Navion Torinita ⁽¹⁰⁾

106,900

1992

100%

DP2

Lay-up

Total capacity

4,427,300

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

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

(3)	The vessel is committed to a conversion into an FSO unit upon the expiry of its existing shuttle tanker charter contract in 2015.

(4)	Self-propelled DP system that attaches to and keeps conventional tankers in position when loading from offshore installations. Scheduled to complete operational testing and commence its time-charter contract in the second quarter of 2014.

(5)	Owned through a 67% owned subsidiary. The parties share in the profits and losses of the subsidiary in proportion to each party’s relative capital contributions.

(6)	Not all of the contracts of affreightment customers utilize every ship in the contract of affreightment fleet.

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

(8)

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 five vessels will be required by Statoil annually. Statoil will require four vessels during 2014. The vessels currently on time charter to Statoil may be replaced by vessels currently servicing contracts of affreightment or other time-charter contracts.

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

(10)	The vessel was 20 years old in 2012 and could no longer trade as a shuttle tanker in the North Sea and Brazil. The vessel is in lay-up following its redelivery to us in April 2012.

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 “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 28 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 11 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 2013, approximately 55% of our consolidated net revenues from continuing operations were earned by the vessels in the shuttle tanker segment, compared to approximately 59% in 2012 and 64% in 2011. 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, 2013, there were approximately 174 FPSO units operating and 38 FPSO units on order in the world fleet. At December 31, 2013, we owned four FPSO units, in which we have 100% ownership interests and one FPSO unit in which we have a 50% ownership. Most independent FPSO contractors have backgrounds in marine energy transportation, oil field services or oil field engineering and construction. The other major independent FPSO contractors are SBM Offshore N.V., BW Offshore, MODEC, Bluewater and Bumi Armada.

The following table provides additional information about our FPSO units as of December 31, 2013:

Vessel

Production
Capacity
(bbl/day)

Built

Ownership

Field name and location

Charterer

Contract End

Date

Voyageur Spirit ⁽¹⁾

30,000

2008

100%

Huntington, U.K.

E.ON

April 2018

Cidade de Itajai ⁽¹⁾⁽²⁾

80,000

2010

50%

Bauna and Piracaba, Brazil

Petrobras

February 2022

Petrojarl Cidade de Rio das Ostras ⁽³⁾

25,000

2008

100%

Espadarte, Brazil

Petrobras

November 2017

Piranema Spirit ⁽¹⁾

30,000

2007

100%

Piranema, Brazil

Petrobras

March 2018

Petrojarl Varg ⁽¹⁾

57,000

1998

100%

Varg, Norway

Talisman Energy

June 2016

Total capacity

222,000

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

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

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

During 2013, approximately 34% of our consolidated net revenues from continuing operations and including the results of the Dropdown Predecessor, were earned by our FPSO units, compared to approximately 29% in 2012 and 23% in 2011. 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. Conventional oil tankers are operated by both major oil companies (including state-owned companies) that generally operate captive fleets, and independent operators that charter out their vessels for voyage or time charter use. Most conventional oil tankers controlled by independent fleet operators are hired for one or a few voyages at a time at fluctuating market rates based on the existing tanker supply and demand. These charter rates are extremely sensitive to this balance of supply and demand, and small changes in tanker utilization have historically led to relatively large changes in short-term rates. Long-term, fixed-rate charters for crude oil transportation, such as those applicable to the majority of our conventional tanker fleet, are less typical in the industry. 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.

Oil tanker demand is a function of several factors, including the location of oil production, refining and consumption and world oil demand and supply. Tanker demand is based on the amount of crude oil transported in tankers and the distance over which the oil is transported. The distance over which oil is transported is determined by seaborne trading and distribution patterns, which are principally influenced by the relative advantages of the various sources of production and locations of consumption.

The majority of crude oil tankers ranges in size from approximately 80,000 to approximately 320,000 dwt. Aframax tankers are the mid-size of the various primary oil tanker types, typically sized from 80,000 to 120,000 dwt. As of December 31, 2013, the world Aframax tanker fleet consisted of approximately 877 vessels, of which 629 crude tankers and 248 coated tankers are termed conventional tankers. As of December 31, 2013, there were approximately 37 conventional Aframax newbuildings on order for delivery through 2017. Delivery of a vessel typically occurs within two to three years after ordering.

As of December 31, 2013, our Aframax conventional crude oil tankers had an average age of approximately 7.3 years, compared to the average age of 8.8 years for the world Aframax conventional tanker fleet. New Aframax tankers generally are expected to have a lifespan of approximately 25 to 30 years, based on estimated hull fatigue life. However, United States and international regulations require double-hulled vessels to be phased out after 25 years. All of our Aframax tankers are double-hulled.

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.

The following table provides additional information about our conventional tankers as of December 31, 2013:

Vessel

Capacity (dwt)

Built

Ownership

Contract Type

Charterer

Contract End Date

SPT Explorer ⁽¹⁾

106,000

2008

100%

Bareboat

Skaugen Petro Trans⁽²⁾

January 2018

SPT Navigator ⁽¹⁾

106,000

2008

100%

Bareboat

Skaugen Petro Trans⁽²⁾

March 2018

Kilimanjaro Spirit ⁽³⁾

115,000

2004

100%

Time charter

Teekay Corporation

November 2018

Fuji Spirit ⁽³⁾

106,400

2003

100%

Time charter

Teekay Corporation

November 2018

Total capacity

433,400

(1)	Charterer has options to extend each bareboat charter for periods of two years, two years and one year for a total of five years after the initial term.

(2)	Subsequent to December 31, 2013, the bareboat charter agreement was novated under the same terms to a subsidiary of Teekay Corporation.

(3)	Charterer has options to extend each time charter on an annual basis for a total of five years after the initial term. Charterer also has the right to purchase the vessel beginning on the third anniversary of the contract at a specified price.

During 2013, 2012, and 2011, approximately 4% of our consolidated net revenues from continuing operations were earned by the vessels in the conventional tanker segment. All earnings from discontinued operations were from the conventional tanker segment. 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 the cargo from the production facility via a dedicated loading system. An FSO unit is also equipped with an export system that transfers cargo to shuttle or conventional tankers. Depending on the selected mooring arrangement and where they are located, FSO units may or may not have any propulsion systems. FSO units are usually conversions of older single-hull conventional oil tankers. These conversions, which include installation of a loading and off-take system and hull refurbishment, can generally extend the lifespan of a vessel as an FSO unit by up to 20 years over the normal 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, 2013, there were approximately 90 FSO units operating and ten FSO units on order in the world fleet, and we had six FSO units (including one shuttle tanker which is currently being converted into an FSO unit), in which our ownership interests ranged from 89% to 100%. The major markets for FSO units are South East Asia, West Africa, Northern Europe, the Mediterranean and South West Asia/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, 2013:

Vessel

Capacity (dwt)

Built

Ownership

Field name and
location

Contract Type

Charterer

Contract End

Date

Navion Clipper ⁽¹⁾

78,200

1993

100%

Bualuang, Thailand

Time charter

Salamander Energy plc

September 2024

Navion Saga ⁽²⁾

149,000

1991

100%

Volve, Norway

Time charter

Statoil ASA

December 2014

Pattani Spirit ⁽²⁾

113,800

1988

100%

Platong, Thailand

Bareboat

Teekay Corporation

April 2014

Dampier Spirit ⁽²⁾⁽³⁾

106,700

1987

100%

Stag, Australia

Time charter

Apache Energy

August 2014

Falcon Spirit ⁽²⁾

124,500

1986

100%

Al Rayyan, Qatar

Time charter

Occidental Qatar Energy

May 2017

Apollo Spirit ⁽⁴⁾

129,000

1978

89%

Banff, U.K.

Bareboat

Teekay Corporation

June 2016

Total capacity

701,200

(1)	Vessel is currently being converted to an FSO unit and is expected to commence its charter contract in the third quarter of 2014. The charterer has options to extend the time charter after the initial fixed period.

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

(3)	In April 2014, the charterer indicated its intention to extend the firm period of the contract for a further 10 years after the initial fixed period.

(4)	Charterer is required to charter the vessel for as long as a specified FPSO unit, the Petrojarl Banff, produces the Banff field in the North Sea, which is expected to remain under contract until the end of 2018.

During 2013, approximately 7% of our consolidated net revenues from continuing operations were earned by the vessels in the FSO segment, compared to 8% in 2012 and 8% in 2011. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Business Strategies

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

•

Expand global operations in high growth regions. We seek to expand our shuttle tanker, FPSO unit and FSO unit operations into growing offshore markets such as Brazil. In addition, we intend to pursue offshore oil production, storage and transportation opportunities in existing markets such as the North Sea.

•

Pursue further opportunities in the offshore sector. We believe that Teekay Corporation’s ownership of Teekay Petrojarl, a leading operator in the FPSO sector, will enable us to competitively pursue additional FPSO projects anywhere in the world by combining Teekay Petrojarl’s engineering and operational expertise with Teekay Corporation’s global marketing organization and extensive customer and shipyard relationships. We believe that Teekay Corporation’s (a) 2011 joint venture agreement with Odebretcht Oil & Gas S.A. (a member of the Odebretcht group) to jointly pursue FPSO projects in Brazil and (b) arrangements with Sevan and Remora AS by which Teekay Corporation will have access to offshore production projects developed by both companies in the future, will also expand our offshore opportunities. In addition, we intend on expanding into related offshore services, including specialized towage.

•

Acquire or construct additional vessels to serve under long-term, fixed-rate contracts. We intend to continue acquiring and constructing shuttle tankers, FSO units and FPSO units with long-term contracts, rather than ordering vessels on a speculative basis. We believe this approach facilitates the financing of new vessels based on their anticipated future revenues and ensures that new vessels will be employed upon acquisition, which should provide stable cash flows.

•

Provide superior customer service by maintaining high reliability, safety, environmental and quality standards. Energy companies seek transportation partners that have a reputation for high reliability, safety, environmental and quality standards. We intend to leverage Teekay Corporation’s operational expertise and customer relationships to further expand a sustainable competitive advantage with consistent delivery of superior customer service.

Customers

We provide marine transportation and storage services to energy and oil service companies or their affiliates. Our most important customer measured by annual revenue excluding Teekay Corporation, is Petrobras Transporte S.A, which is Brazil’s largest company and the third largest energy company in the world.

Petrobras Transporte S.A., Statoil ASA, and Talisman Energy Inc accounted for approximately 25%, 20%, and 13%, 28%, 21%, and 13%, and 24%, 24%, and 13% of consolidated revenues from continuing operations during 2013, 2012 and 2011, respectively.

Safety, Management of Ship 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 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 new Maritime Labor Convention 2006 (or MLC 2006) that became effective on August 20, 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 and Spanish 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.

Ship management services are provided by subsidiaries of Teekay Corporation, located in various offices around the world. These include critical ship 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 and newbuilding 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 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. Substantially all of our vessels 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, Classifica tion, 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. As most of our vessels are modern and 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 vessel’s flag state also verifies the condition of the vessel during annual flag state inspections, either independently or by additional authorization to Class. Also, Port State Authorities of a vessel’s port of call are authorized under international conventions to undertake regular and spot checks of vessels visiting their jurisdiction.

Processes followed on board are audited by either the flag state or the classification society acting on behalf of a flag state to ensure that they meet the requirements of the 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:

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our vessels and operations adhere to our operating standards;

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the structural integrity of the vessel is being maintained;

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machinery and equipment is being maintained to give reliable service;

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

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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 relatively new, 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 adversely 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. 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, be of a mid-deck design with double-side construction 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 equipment required for commercial vessels and includes regulations for 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.

Annex VI to the IMO’s International Convention for the Prevention of Pollution from Ships (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 are built starting in 2012 contain ballast water treatment systems, and that all other similarly sized shuttle tankers install treatment systems by their first intermediate or renewal survey after 2016 in order to comply with the renewal survey required for the International Oil Pollution Prevention certificate. 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.

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) 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).

The EU has adopted regulations requiring the use of low sulfur fuel. Currently, vessels are required to burn fuel with a sulfur content not exceeding 1% (while within EU member states’ territorial seas, exclusive economic zones and pollution control zones that are included in SOX Emission Control Areas). Beginning January 1, 2015, vessels are 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. The California Air Resources Board will require vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles of California as of January 1, 2014. IMO regulations require that as of January 1, 2015, all vessels operating within Emissions Control Areas worldwide 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). 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 includes requirements to recycle vessels in an environmentally sound manner at certain 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 to ratify 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 will generally become effective between December 31, 2015 and December 31, 2018, although certain of its provisions are set to become effective on December 31, 2014 and certain others on December 31, 2020.

North Sea and Brazil

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

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. 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 guaranties 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 guaranties 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 immediately upon the effective date of the 2013 Vessel General Permit. 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. Certain new IMO regulations became effective on January 1, 2013. The new technical and operational 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. 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. 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 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, 2013.

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 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.

Transportation Income that is attributable to transportation that begins or ends, but that does not both begin and end, in the United States (or U.S. Source International Transportation Income) will be considered to be 50.0% 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) will be considered to be 100.0% derived from sources within the United States. Transportation Income attributable to transportation exclusively between non-U.S. destinations will be considered to be 100.0% 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 will be subject to U.S. federal income taxation under either the net basis tax and the branch profits tax or the 4.0% gross basis tax, all of which are 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 4.0% gross basis tax described below on its U.S. Source International Transportation Income. The Section 883 Exemption only applies to 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 is organized in a jurisdiction outside the United States that grants an equivalent exemption from tax to corporations organized in the United States (or an Equivalent Exemption), it meets one of three ownership tests described in the Section 883 Regulations (or the Ownership Test), and it 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 Test 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 Tax and Branch Profits Tax. If we earn U.S. Source International Transportation Income and the Section 883 Exemption does not apply, such 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 35.0%). In addition, if we earn income that is treated as Effectively Connected Income, a 30.0% branch profits tax imposed under Section 884 of the Code generally would apply to such income, and 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 could be subject to the net basis corporate income tax and to the 30.0% branch profits tax 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 4.0% Gross Basis Tax. If the Section 883 Exemption does not apply and the net basis tax does not apply, we would be subject to a 4.0% U.S. federal income tax on U.S. source portion of our gross U.S. Source International Transportation Income, without benefit of deductions. For 2014, 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 2013. The amount of such tax for which we are liable for 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. We intend that our business and the business of our subsidiaries will be conducted and operated in a manner that minimizes taxes imposed upon us and our subsidiaries. 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 12 – 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 Condition and Results of Operations

OVERVIEW

We are an international provider of marine transportation, oil production and storage services to the offshore oil industry focusing on the fast-growing, deep-water offshore oil regions of the North Sea and Brazil. We were formed in August 2006 by Teekay Corporation, a leading provider of marine services to the global oil and natural gas industries, to further develop its operations in the offshore market. We operate shuttle tankers, floating production, storage and off-loading (or FPSO) units, floating storage and off-take (or FSO) units and conventional crude oil tankers. Our current fleet consists of 35 shuttle tankers (including two chartered-in vessels, one vessel committed for an FSO conversion upon expiry of its current contract in 2015 and the HiLoad Dynamic Positioning (or DP) unit scheduled to complete operational testing in the second quarter of 2014), five FPSO units, six FSO units (including one committed FSO conversion unit) and four conventional oil tankers. Our interests in these tankers and units range from 50% to 100%.

Our growth strategy focuses on expanding our fleet of shuttle tankers and FPSO and FSO units under long-term, fixed-rate time charters and expanding into related offshore services, including specialized towage. We intend to continue our practice of acquiring shuttle tankers and FPSO and FSO units 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 emerging from the global expansion of 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 and shuttle tanker opportunities provided by Teekay Corporation, Sevan Marine ASA (or Sevan) and Remora AS (or Remora). Our operating fleet trades on medium to long-term, stable contracts and we are structured as a publicly-traded master limited partnership.

SIGNIFICANT DEVELOPMENTS

ALP Acquisition and Newbuilding Order

On March 14, 2014, we acquired 100% of the shares of ALP Maritime Services B.V. (or ALP), a Netherlands-based provider of long-haul ocean towage and offshore installation services to the global offshore oil and gas industry. Concurrent with this transaction, we 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 2015 and 2016. We are committed to acquire these newbuildings for a total cost of approximately $258 million. These newbuildings will be capable of ultra-long distance towing and offshore unit installation and decommissioning of large floating exploration, production and storage units, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs.

We acquired ALP for a purchase price of $6.1 million, of which $2.6 million was paid in cash on closing and a further $3.5 million representing the fair value of contingent consideration. The contingent consideration consists of $2.4 million which is contingently payable upon the delivery and employment of ALP’s four newbuildings. In addition, the contingent consideration includes a further amount of up to $2.6 million, based on ALP’s annual operating results from 2017 to 2021. We have the option to pay up to one half of the contingent consideration through the issuance of our common units. We also incurred $1.0 million of acquisition-related costs which have been recognized in general and administrative expenses in March 2014. We financed the ALP acquisition and initial newbuilding payments through our existing liquidity and expect to secure long-term debt financing for the newbuildings prior to their deliveries.

This acquisition represents our entrance into the long-haul ocean towage and offshore installation services business. This acquisition allows us to combine our infrastructure and access to capital with ALP’s experienced management team to further grow this niche business that is in an adjacent sector to our FPSO and shuttle tanker businesses.

Awarded Shuttle Tanker Contract for Knarr field

In December 2013, we were awarded a six year shuttle tanker contract of affreightment, with extension options up to an additional four years, with BG Group plc, which will service the Knarr oil and gas field in the North Sea. The expected start date for the shuttle tanker contract of affreightment coincides with the expected start-up of the Petrojarl Knarr FPSO in the North Sea in the fourth quarter of 2014.

FPSO Acquisitions

In June 2013, we completed the acquisition from Teekay Corporation of its 50 percent interest in a FPSO unit, the Cidade de Itajai (or Itajai) and assumed 50 percent of the joint venture’s outstanding debt of $289.5 million for a purchase price of $53.8 million. The Itajai FPSO has been operating on the Baúna and Piracaba (previously named Tiro and Sidon) fields in the Santos Basin offshore Brazil since February 2013 under a nine-year fixed-rate time-charter contract, plus extension options, with Petroleo Brasileiro SA (or Petrobras). The remaining 50% interest in the Itajai FPSO unit is owned by Brazilian-based Odebrecht Oil & Gas S.A. (a member of the Odebrecht group) (or Odebrecht).

On May 2, 2013, we acquired from Teekay Corporation its 100% interest in Voyageur LLC, 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 Ruhrgas UK E&P Limited (or E.ON), for a purchase price of $540.0 million. The purchase price was financed with the assumption of the $230.0 million debt facility secured by the unit, $270.0 million with cash, of which a partial prepayment of $150.0 million was made to Teekay Corporation in February 2013, and the issuance of 1.4 million common units to Teekay Corporation, which had a value of $40.0 million at the time Teekay Corporation offered to sell the unit to us.

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 and our sponsor, Teekay Corporation, had a specified time period to receive final acceptance from the charterer, E.ON, at which point the unit would commence full operations under the contract with E.ON. 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. We have been indemnified by Teekay Corporation for lost revenues and certain unrecovered vessel operating expenses up until receipt of the certificate of final acceptance from E.ON, subject to a maximum of $54 million.

On August 27, 2013, repairs to the defective gas compressor on the Voyageur Spirit FPSO were completed and the unit achieved full production capacity. Since that time, we had been receiving full rate either directly from the charterer or through the indemnification from Teekay Corporation as though the unit was producing at full capacity under the charter contract.

On April 4, 2014, we received the certificate of final acceptance from the charterer, which declared the unit on-hire retroactive to February 22, 2014.

Any amounts paid as indemnification from Teekay Corporation to us were effectively treated as a reduction in the purchase price paid to Teekay Corporation for the Voyageur Spirit FPSO by us. Any future compensation received by us from the charterer related to the indemnification period will reduce the amount of Teekay Corporation’s indemnification to us. As at December 31, 2013, the $540.0 million original purchase price of the Voyageur Spirit FPSO unit has been effectively reduced to $509.3 million ($279.3 million net of assumed debt of $230.0 million) to reflect the indemnification amount of $34.9 million for the year ended December 31, 2013, partially offset by the excess value of $4.3 million relating to the 1.4 million common units issued to Teekay Corporation on the date of closing the transaction in May 2013 compared to the date Teekay Corporation offered to sell the unit to us.

HiLoad Acquisition

In September 2013, we acquired a 2010-built HiLoad DP unit from Remora, a Norway-based offshore marine technology company, for a total purchase price of approximately $55 million, including modification costs. The HiLoad DP unit arrived in Brazil in November 2013 and is expected to commence operations under its full time-charter rate under a ten-year time-charter contract with Petrobras in Brazil in the second quarter of 2014, once operational testing has been completed. Under the terms of an agreement between Remora and us, we have a right of first refusal to acquire any future HiLoad projects developed by Remora. In July 2013, Remora was awarded a contract by BG E&P Brasil Ltda. to perform a front-end engineering and design study to develop the next generation of HiLoad DP units. The design of the next generation of HiLoad DP units, which is based on the main parameters of the first generation design, is expected to include new features, such as increased engine power and the capability to maneuver vessels larger than Suezmax conventional tankers.

Shuttle Newbuildings and Deliveries

In June 2011, we entered into a new long-term contract with a subsidiary of BG Group plc (or BG) to provide shuttle tanker services in Brazil. The contract with BG is being serviced by four Suezmax newbuilding shuttle tankers (or the BG Shuttle Tankers) under ten-year time-charter contracts, constructed by Samsung Heavy Industries for a total cost of $464.0 million. In May, June, September and November 2013, respectively, we took delivery of the Samba Spirit, the Lambada Spirit, the Bossa Nova Spirit and the Sertanejo Spirit, which commenced their charter contracts in June, August, and November 2013, and January 2014, respectively. The contracts with BG also include certain extension options exercisable by the charterer.

FSO Contracts

In May 2013, we entered into an agreement with Statoil Petroleum AS (or 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 will be converted from the 1995-built shuttle tanker, the Randgrid, which we currently own through a 67% owned subsidiary. The FSO conversion project is expected to be completed for a gross capital cost of approximately $260 million, including amounts reimbursable upon delivery of the unit relating to installation and mobilization costs, and the cost of acquiring the remaining 33% ownership interest in the Randgrid shuttle tanker. Following scheduled completion in early 2017, the newly converted FSO unit will commence operations under a three-year time-charter contract to Statoil, which also includes 12 additional one-year extension options.

In May 2013, we entered into a ten-year charter contract, plus extension options, with Salamander Energy plc (or Salamander) to supply an FSO unit in Asia. We are converting our 1993-built shuttle tanker, the Navion Clipper, into an FSO unit for an estimated fully built-up cost of approximately $51 million. The unit is expected to commence its charter contract with Salamander in the third quarter of 2014.

Equity Issuances

In December 2013, we issued approximately 1.75 million common units in a private placement to an institutional investor for net proceeds of $54.4 million (including our general partner’s proportionate capital contribution). We used the net proceeds from the issuance of these common units for general partnership purposes.

In May 2013, we implemented a continuous offering program (or COP), under which we may issue new common units, representing limited partner interests, at market prices up to a maximum aggregate amount of $100 million. Through December 31, 2013, we sold an aggregate of 85,508 common units under the COP, generating proceeds of approximately $2.4 million (including our general partner’s 2% proportionate capital contribution and net of approximately $0.4 million of offering costs). We used the net proceeds from the issuance of these common units for general partnership purposes.

In April 2013, we issued approximately 2.06 million common units in a private placement to an institutional investor for net proceeds of $61.2 million (including our general partner’s proportionate capital contribution). We used the net proceeds from the issuance of these common units to partially fund the acquisition of the BG Shuttle Tankers and for general partnership purposes.

In April 2013, we issued 6.0 million 7.25% Series A Cumulative Redeemable Preferred Units in a public offering, for net proceeds of $144.9 million. We used a portion of the net proceeds from the issuance of these preferred units to prepay a portion of our outstanding debt under three of our revolving credit facilities and to partially finance the purchase of the Voyageur Spirit FPSO unit and our interest in the Itajai FPSO unit, and used the remainder for general partnership purposes.

Bond Issuances

In January 2014, we issued in the Norwegian bond market NOK 1,000 million in senior unsecured bonds, maturing in January 2019. The aggregate principal amount of the bonds was equivalent to $162.2 million and all interest and principal payments have been swapped into U.S. dollars at a fixed rate of 6.28%. The net proceeds from the bond offering are intended for general partnership purposes. We are applying to list the bonds on the Oslo Stock Exchange.

In September 2013 and November 2013, we issued in a U.S. private placement a total of $174.2 million ten-year senior secured bonds to finance the Bossa Nova Spirit and Sertenejo Spirit BG shuttle tanker newbuildings. The bonds mature in December 2023 and accrue interest at a fixed combined rate of 4.96%. The bonds are collateralized by a first-priority mortgages on the Bossa Nova Spirit and Sertenejo Spirit, together with other related security.

In January 2013, we issued in the Norwegian bond market NOK 1,300 million in senior unsecured bonds. The bonds were issued in two tranches maturing in January 2016 (NOK 500 million) and January 2018 (NOK 800 million). The aggregate principal amount of the bonds was equivalent to $233.2 million and all interest and principal payments under each of the two tranches have been swapped into U.S. dollars at fixed rates of 4.80% on the tranche maturing in 2016 and 5.93% on the tranche maturing in 2018. In connection with this financing, we repurchased NOK 388.5 million of the existing NOK 600 million bond issue maturing in November 2013. We used the net proceeds of approximately $167 million to reduce a portion of amounts outstanding under our revolving credit facilities and for general partnership purposes. The bonds are listed on the Oslo Stock Exchange.

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 its fair market value.

In May 2011, Teekay Corporation entered into a joint venture agreement with Odebrecht to jointly pursue FPSO projects in Brazil. Odebrecht is a well established Brazil-based company that operated in the engineering and construction, petrochemical, bioenergy, energy, oil and gas, real estate and environmental engineering sectors, with over 120,000 employees and a presence in over 20 countries. Through the joint venture agreement, Odebrecht has become a 50 percent partner in the Cidade de Itajai FPSO project and Teekay Corporation is currently working with Odebrecht on other FPSO project opportunities that, if awarded, may result in offers to us to acquire Teekay Corporation’s interests in such projects, pursuant to the omnibus agreement.

In June 2011, Teekay Corporation entered into a contract with BG Norge Limited to provide a harsh weather FPSO unit to operate in the North Sea. The contract will be serviced by a newbuilding FPSO unit, the Petrojarl Knarr (or Knarr), which is being constructed by Samsung Heavy Industries for a fully built-up cost of approximately $1 billion. Pursuant to the omnibus agreement, Teekay Corporation is obligated to offer to us its interest in the Knarr FPSO project at Teekay Corporation’s fully built-up cost within a year after the commencement of the charter, which commencement is expected to occur in the fourth quarter of 2014.

In November 2011, Teekay Corporation acquired the Hummingbird Spirit FPSO unit from Sevan, a Norway-based developer of cylindrical-shaped FPSO units. In September 2013, Teekay Corporation entered into an agreement with Centrica Energy, the charterer of the Hummingbird Spirit FPSO, to extend the firm period of the contract for this FPSO unit until December 31, 2014, with the charterer’s options to extend out to March 31, 2016. In addition, Centrica Energy has an option, exercisable by February 28, 2014, to extend the firm period of the contract by a further 12 months. Pursuant to the omnibus agreement, Teekay Corporation is only obligated to offer us the Hummingbird Spirit FPSO unit following the commencement of a charter contract with a firm period of greater than three years duration.

Teekay Corporation owns two additional FPSO units, the Petrojarl Banff and the Petrojarl 1, which may also be offered to us in the future pursuant to the omnibus agreement.

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 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, but contain a variable component for incentive-based revenues dependent upon operating performance.

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


	Contract of Affreightment	Time Charter	Bareboat Charter	Voyage Charter ⁽¹⁾	FPSO Service Contracts

Typical contract length	One year or more	One year or more	One year or more	Single voyage	Long-term

Hire rate basis⁽²⁾	Typically daily	Daily	Daily	Varies	Daily

Voyage expenses⁽³⁾	We pay	Customer pays	Customer pays	We pay	Not applicable

Vessel operating expenses⁽³⁾	We pay	We pay	Customer pays	We pay	We pay

Off hire⁽⁴⁾	Customer typically does not pay	Varies	Customer typically pays	Customer does not pay	Not applicable

Shutdown⁽⁵⁾	Not applicable	Not applicable	Not applicable	Not applicable	Varies

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

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

(3)	Defined below under “Important Financial and Operational Terms and Concepts.”

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

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

Important Financial and Operational Terms and Concepts

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

Revenues. Revenues primarily include revenues from contracts of affreightment, time charters, bareboat charters, voyage charters and FPSO 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 and FPSO 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 accounting principles generally accepted in the United States (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.

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, taxes, realized and unrealized gains (losses) on non-designated derivative instruments, foreign currency exchange gains and losses and other income and losses.

Dry docking. We must periodically dry dock our shuttle tankers and conventional oil tankers 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. 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;

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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 to show changes in 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% and 67% owned subsidiaries.

VOC Equipment. We assemble, install, operate and lease equipment that reduces volatile organic compound (or “VOC”) emissions during loading, transportation and storage of oil and oil products. Leasing of the VOC equipment is accounted for either as a direct financing lease or as an operating lease. For VOC equipment accounted for as a direct financing lease, payments received are allocated between the net investment in the lease and other income using the effective interest method so as to produce a constant periodic rate of return over the lease term.

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:

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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 October 2011, we acquired from Teekay Corporation the Scott Spirit newbuilding shuttle tanker. In May 2013, we acquired the Voyageur Spirit 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 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 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 July 22, 2011 and April 13, 2013, respectively. Please read Item 18 – Financial Statements: Note 2 – Dropdown Predecessor.

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

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Vessel operating and other costs are facing industry-wide cost pressures. The shipping industry continues to experience a global manpower shortage of qualified seafarers in certain sectors due to growth in the world fleet and competition for qualified personnel. In recent years, upward pressure on manning costs has temporarily stabilized and resulted in lower wage increases than have been seen in the past. However, this situation will likely not continue in the long term. Going forward, there may be significant increases in crew compensation as vessel and officer supply dynamics continue to change. In addition, factors such as pressure on commodity and raw material prices, as well as changes in regulatory requirements could also contribute to operating expenditure increases. We continue to take action aimed at improving operational efficiencies, and to temper the effect of inflationary and other price escalations, however increases to operational costs are still likely to occur in the future.

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Our financial results of operations are affected by fluctuations in currency exchange rates. Under GAAP, all foreign currency-denominated monetary assets and liabilities (such as cash and cash equivalents, accounts receivable, accounts payable, advances from affiliates 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 payments under the services agreements if the strength of the U.S. Dollar declines relative to the Norwegian Kroner.

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Our net income (loss) is affected by fluctuations in the fair value of our derivatives instruments. Our interest rate swaps, cross currency swaps and foreign currency forward contracts are not designated as hedges for accounting purposes. Although we believe these derivative instruments are economic hedges, the changes in their fair value are included in our statements of income (loss) as unrealized gains or losses on derivatives for interest rate swaps and foreign currency forward contracts and as foreign exchange gains or losses for the cross currency swaps. The changes in fair value 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. Ten vessels, including conventional and shuttle tankers, and FSO units, are scheduled for dry docking in 2014. 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 four business segments: the shuttle tanker segment, the FPSO segment, the conventional tanker segment and the FSO segment, each of which are discussed below.

Results of Operations

Year Ended December 31, 2013 versus Year Ended December 31, 2012

Shuttle Tanker Segment

As at December 31, 2013, our shuttle tanker fleet consisted of 36 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters. Of the 36 shuttle tankers, six were owned through 50% owned subsidiaries, three through a 67% owned subsidiary and three were chartered-in (of which one was redelivered to its owner in January 2014), with the remainder owned 100% by us. All of these shuttle tankers provide transportation services to energy companies, primarily in the North Sea and Brazil. Our shuttle tankers service the conventional spot tanker market from time to time. One of these shuttle tankers, the Randgrid, is committed to a conversion into an FSO unit upon the expiry of its existing shuttle tanker charter contract in 2015. The HiLoad DP unit is scheduled to complete operational testing in the second quarter of 2014.

The following table presents our shuttle tanker segment’s operating results for 2013 and 2012, and compares its net revenues (which is a non-GAAP financial measure) for 2013 and 2012, 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,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2013		2012		% Change
Revenues		552,019		569,519		(3.1	)
Voyage expenses		99,543		104,394		(4.6	)

Net revenues		452,476		465,125		(2.7	)
Vessel operating expenses		152,986		160,957		(5.0	)
Time-charter hire expense		56,682		56,989		(0.5	)
Depreciation and amortization		115,913		122,921		(5.7	)
General and administrative⁽¹⁾		21,821		20,146		8.3
Write-down and loss on sale of vessels		76,782		24,542		212.9
Restructuring charge		2,169		647		235.2

Income from vessel operations		26,123		78,923		(66.9	)

Calendar-Ship-Days
Owned Vessels		10,914		11,530		(5.3	)
Chartered-in Vessels		1,456		1,459		(0.2	)

Total		12,370		12,989		(4.8	)

(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).

The average size of our owned shuttle tanker fleet decreased in 2013 compared to 2012, primarily due to the sale of the Navion Fennia in July 2012, the sale of the Navion Savonita in December 2012, the sale of the Basker Spirit in January 2013, the in-progress conversion of the Navion Clipper to an FSO unit, and the redelivery of one of our in-chartered shuttle tankers in December 2013, partially offset by the delivery of the four BG Shuttle Tankers to us during 2013. Included in calendar-ship-days is one owned shuttle tanker that has been in lay-up since May 2012 following its redelivery to us upon maturity of its time-charter-out contract in April 2012.

Net Revenues. Net revenues decreased for 2013 from 2012, primarily due to:

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a decrease of $18.8 million due to the lay-up of two vessels following their redelivery to us in April 2012 and November 2012, respectively, upon maturity of their time-charter-out contracts; one of these vessels, the Navion Clipper, is currently being converted to an FSO unit;

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a decrease of $12.0 million due to the sale of the Navion Savonita in December 2012;

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a net decrease of $5.9 million primarily due to fewer revenue days from the redelivery of four vessels to us in February 2012, March 2012, April 2012 and July 2013, as they completed their time-charter-out agreements, partially offset by an increase in revenues in our contract of affreightment fleet and an increase in revenues in our time-chartered-out fleet from entering into new contracts and an increase in rates as provided in certain contracts;

•

a decrease of $2.0 million due to fewer opportunities to trade excess capacity in the conventional spot market; and

•

a decrease of $0.5 million due to a decrease in reimbursable bunker expenses

partially offset by

•

a net increase of $15.4 million due to the commencement of the ten-year time-charter contracts in June 2013, August 2013 and November 2013 for three of the four BG Shuttle Tankers, the Samba Spirit, the Lambada Spirit and the Bossa Nova Spirit, respectively;

•

an increase of $7.5 million, due to an increase in rates as provided in certain contracts from our bareboat fleet; and

•

an increase of $3.8 million due to less repair off-hire days in our time-chartered-out fleet.

Vessel Operating Expenses. Vessel operating expenses decreased for 2013 from 2012, primarily due to:

•

a decrease of $11.6 million relating to the lay-up of two of our shuttle tankers since May 2012 and February 2013, and the reduction in costs associated with the sale of two of our older shuttle tankers in July 2012 and December 2012; one of these vessels, the Navion Clipper, is currently being converted to an FSO unit; and

•

a decrease of $5.5 million due to a decrease in ship management costs from the reduction in our contract of affreightment and time-charter fleet and cost saving initiatives;

partially offset by

•

an increase of $7.5 million due to the delivery of the BG Shuttle Tankers during 2013;

•

an increase of $0.9 million due to the timing of port expenses; and

•

an increase of $0.9 million due to an increase in crew training expenses.

Time-Charter Hire Expense. Time-charter hire expense decreased for 2013 from 2012, primarily due to:

•

a decrease of $2.0 million due to the redelivery of one vessel to its owner in November 2013; and

•

a decrease of $0.9 million due to decreased spot in-chartering during 2013;

partially offset by

•

an increase of $2.8 million due to fewer off-hire days in 2013.

Depreciation and Amortization. Depreciation and amortization expense decreased for 2013 from 2012, primarily due to the write-down of two older shuttle tankers in 2012 to their estimated fair value, the write-down of four older shuttle tankers in 2013 to their estimated fair value, the sale of the two older shuttle tankers in 2012 and one older shuttle tanker in 2013, lower vessel contract amortization and the completion of dry-dock depreciation for various shuttle tankers, partially offset by additional depreciation relating to the deliveries of the BG Shuttle Tankers, vessel upgrades and dry dockings.

Write-down and loss on sale of vessels. 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 value using appraised values. Of these six vessels, during the fourth quarter of 2013, two shuttle tankers were written down due to a cancellation of a contract renewal and expected sale of an aging vessel. One of these two vessels was also written down in 2012. In the third quarter of 2013, four of the shuttle tankers were written down as a result of the re-contracting of one of the vessels at lower rates than expected during the third quarter of 2013, the cancellation of a short-term contract which occurred in September 2013, a change in expectations for the contract renewal for two of our shuttle tankers, one currently operating in Brazil and the other one in the North Sea.

Write-down and loss on sale of vessels was $24.5 million for 2012. In 2012, the carrying values of five of our shuttle tankers were written down to their estimated fair value. In the third quarter of 2012, a 1993-built shuttle tanker was written down to its estimated fair value due to a change in the operating plan for the vessel. In the third and fourth quarters of 2012, two shuttle tankers, which were written down in 2011, were further written down to their estimated fair value upon sale in 2012. In the fourth quarter of 2012, a 1992-built shuttle tanker, which was written down in 2010, was further written down to its estimated fair value and classified as held-for-sale at December 31, 2012. The vessel was sold in 2013. In the fourth quarter of 2012, a 1995-built shuttle tanker was written down to its estimated fair value using discounted cash flows. The write-down was caused by the combination of the age of the vessel, the requirements of trading in the North Sea and Brazil and the weak tanker market. The estimated fair value for each of the other four vessels written down in 2012 was determined using appraised values.

Restructuring Charge. Restructuring charges were $2.2 million for 2013 due to:

•

$1.6 million resulting from a reorganization of marine operations to create better alignment within the shuttle tanker business unit to create a reduced-cost organization going forward; and

•

$0.6 million resulting from the reflagging of one shuttle tanker.

Restructuring charges were $0.6 million for 2012, resulting from a reorganization of marine operations to create better alignment within the shuttle tanker business unit to create a reduced-cost organization going forward.

FPSO Segment

Our FPSO fleet consists of the Petrojarl Varg, the Cidade de Rio das Ostras (or Rio das Ostras), the Piranema Spirit and the Voyageur Spirit FPSO units, all of which we own 100%, and a 50% interest in the Itajai FPSO unit. 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. 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 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 and Voyageur Spirit 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.

The following table presents our FPSO segment’s operating results for 2013 and 2012, and also provides a summary of the calendar-ship-days for our FPSO segment. The table excludes the results of the Itajai FPSO unit, which is accounted for under the equity method.


	Year Ended December 31,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2013		2012		% Change
Revenues		284,932		231,688		23.0
Vessel operating expenses		152,616		111,855		36.4
Depreciation and amortization		66,404		50,905		30.4
General and administrative⁽¹⁾		17,742		11,208		58.3

Income from vessel operations		48,170		57,720		(16.5	)

Calendar-Ship-Days
Owned Vessels		1,339		1,098		21.9

(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 number of our FPSO units for 2013 increased compared to last year due to the acquisition of the Voyageur Spirit on May 2, 2013.

Revenues. Revenues increased for 2013 from 2012, primarily due to:

•

an increase of $53.2 million relating to the acquisition of the Voyageur Spirit FPSO unit, of which $25.2 million relates to the charter-hire of the unit beginning August 27, 2013 under an interim agreement with EON; and

•

an increase of $1.2 million due to an increase in rates on the Piranema Spirit in accordance with the annual escalation of the charter component;

partially offset by

•

a decrease of $1.9 million due to the Rio das Ostras earning only a 95% standby rate, while it was shutdown and being relocated to a new oil field in 2013, and a lower credit earned from the charterer for unused maintenance days under the service contract of the Rio das Ostras compared to last year, partially offset by the recovery of certain upgrade costs.

Teekay Corporation has indemnified us for lost revenue from the Voyageur Spirit being off-hire since the start of the Dropdown Predecessor period on April 13, 2013. The indemnification amount was $31.3 million for the last three quarters of 2013. This has been recorded in equity as a reduction to the purchase price we paid for the FPSO unit.

Vessel Operating Expenses. Vessel operating expenses increased for 2013 from 2012, primarily due to:

•

an increase of $32.1 million due to the acquisition of the Voyageur Spirit FPSO unit;

•

an increase of $4.1 million due to higher crew and manning costs mainly relating to the Petrojarl Varg and the Piranema Spirit due to higher salaries, crew levels and crew expenses;

•

an increase of $3.7 million due to higher maintenance work on the Rio das Ostras while on shutdown and being relocated to a new oil field in 2013; and

•

an increase of $2.0 million due to higher maintenance costs on the Petrojarl Varg due to increased class work performed during 2013;

partially offset by

•

a decrease of $1.1 million due to a decrease in our ship management costs on the Petrojarl Varg, Rio das Ostras and Piranema Spirit; and

•

a decrease of $0.6 million due to the appreciation of the U.S. Dollar against the Norwegian Kroner.

Depreciation and Amortization Expense. Depreciation and amortization expense increased for 2013 from 2012, primarily due to the acquisition of the Voyageur Spirit FPSO unit during the second quarter of 2013.

Conventional Tanker Segment

As at December 31, 2013, we owned 100% interests in two Aframax conventional crude oil tankers (which operate 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 Skaugen PetroTrans (Teekay Corporation’s 50% owned joint venture).

The table below excludes six additional conventional tankers as they have been determined to be discontinued operations, including one tanker sold during the third quarter of 2013, two tankers sold during the first half of 2013 and three tankers sold in the second half of 2012. During the first and second quarters of 2013 and the second quarter of 2012, we terminated the long-term time-charter-out contracts employed by three of our conventional tankers with a subsidiary of Teekay Corporation. We received early termination fees from Teekay Corporation of $6.8 million, $4.5 million and $14.7 million in the first and second quarter of 2013 and the second quarter of 2012, respectively, which are recorded in discontinued operations.

The following table presents our conventional tanker segment’s operating results for 2013 and 2012, and compares its net revenues (which is a non-GAAP financial measure) for 2013 and 2012, 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,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2013		2012		% Change
Revenues		34,772		37,119		(6.3	)
Voyage expenses		4,532		5,689		(20.3	)

Net revenues		30,240		31,430		(3.8	)
Vessel operating expenses		5,813		6,509		(10.7	)
Depreciation and amortization		6,511		6,500		0.2
General and administrative⁽¹⁾		2,357		1,389		69.7
Restructuring charge		438		468		(6.4	)

Income from vessel operations		15,121		16,564		(8.7	)

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 2013 from 2012, primarily due to more off-hire days associated with the drydocking of one vessel in 2013.

Vessel Operating Expenses and Restructuring Charge. Vessels operating expenses decreased for 2013 from 2012, primarily due to a decrease in our ship management costs relating to the reorganization of our conventional tanker marine operations to create better alignment with marine operations. The reorganization was completed in 2013. We recorded restructuring charges of $0.4 million and $0.5 million during 2013 and 2012, respectively, since this plan began in 2012.

FSO Segment

Our FSO fleet consisted of five units that operate under fixed-rate time charters or fixed-rate bareboat charters. During the second quarter of 2013, we committed to converting one of our shuttle tankers, the Navion Clipper, into an FSO unit. In addition, we have committed one shuttle tanker, the Randgrid, to conversion into an FSO unit upon the expiry of its existing shuttle tanker charter contract in 2015. We have 100% ownership interests in the operating FSO units. FSO units provide an on-site storage solution to oil field installations that have no oil storage facilities or that require supplemental storage. Our revenues and 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 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 2013 and 2012, and compares its net revenues (which is a non-GAAP financial measure) for 2013 and 2012, 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,					% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2013			2012		% Change
Revenues		59,016			62,901		(6.2	)
Voyage (recoveries) expenses		(432	)		400		(208.0	)

Net revenues		59,448			62,501		(4.9	)
Vessel operating expenses		32,713			38,255		(14.5	)
Depreciation and amortization		10,178			9,038		12.6
General and administrative⁽¹⁾		2,553			1,838		38.9

Income from vessel operations		14,004			13,370		4.7

Calendar-Ship-Days
Owned Vessels		2,100			1,830		14.8

(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 for 2013 increased from 2012 due to the commencement of the conversion of the Navion Clipper shuttle tanker to an FSO unit in April 2013.

Net Revenues. Net revenues decreased for 2013 from 2012, primarily due to:

•

a decrease of $5.5 million from engineering studies completed in 2012 to support our FSO tenders; and

•

a decrease of $0.7 million due to reduced rates on the Falcon Spirit;

partially offset by

•

an increase of $3.0 million 2013 due to the drydocking of the Navion Saga during the third quarter of 2012; and

•

an increase of $0.5 million due to a recovery of expenses in 2013 relating to the 2012 drydocking of the Navion Saga.

Vessel Operating Expenses. Vessel operating expenses decreased for 2013 from 2012, primarily due to:

•

a decrease of $5.7 million relating to expenditures on engineering studies completed in 2012 to support our FSO tenders;

•

a decrease of $0.8 million due to a reduction in services and spares for the Navion Saga relating to its drydocking during the third quarter of 2012; and

•

a decrease of $0.5 million relating to lower crew costs and the timing of services and spares for the Dampier Spirit primarily due to the appreciation of the U.S Dollar against the Australian Dollar;

partially offset by

•

an increase of $0.8 million due to lay up costs for the Navion Clipper prior to the commencement of its conversion to an FSO unit; and

•

an increase of $0.8 million due to costs to transition the management of the Navion Saga in-house.

Depreciation and amortization. Depreciation and amortization expense increased for 2013 from 2012, primarily due to additional dry-dock depreciation for the dry docking of the Navion Saga completed in the third quarter of 2012.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased to $44.5 million for 2013, from $34.6 million for 2012, mainly due to the acquisition of the Voyageur Spirit FPSO unit during the second quarter of 2013, an increase in business development and project activities supporting our shuttle tanker fleet and FSO units, a success fee paid to Teekay Corporation relating to the acquisition of the HiLoad DP unit and an increase in administrative costs associated with our other FPSO units.

Interest Expense. Interest expense, which excludes realized and unrealized gains and losses from interest rate swaps, increased to $62.9 million for 2013, from $47.5 million for 2012, primarily due to:

•

an increase of $14.5 million due to the drawdown of new debt facilities relating to the Voyageur Spirit FPSO and the BG Shuttle Tankers that delivered during the last three quarters of 2013; and

•

a net increase of $7.3 million primarily from the issuance of the NOK 1,300 million senior unsecured bonds in January 2013, partially offset by the repurchase of NOK 388.5 million of the NOK 600 million senior unsecured bond issue that matured in November 2013; and

•

an increase of $0.9 million due to an increase in intercompany loan balances;

partially offset by

•

a decrease of $5.0 million due to lower debt balances on existing debt facilities compared to 2012; and

•

a decrease of $2.4 million due to decreased interest rates compared to 2012.

Interest Income. Interest income increased to $2.6 million for 2013, from $1.0 million for 2012, primarily due to interest income earned on the $150.0 million partial prepayment in February 2013 to Teekay Corporation for our acquisition of 100% interest in Voyageur LLC, which owns the Voyageur Spirit FPSO.

Realized and Unrealized Gains (Losses) on Derivatives. Net realized and unrealized gains (losses) on non-designated derivatives were $34.8 million for 2013, compared to ($26.3) million for 2012.

During 2013 and 2012, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.6 billion, with average fixed rates of approximately 3.6% and 4.3%, respectively. Short-term variable benchmark interest rates during these periods were generally 1.1% or less and, as such, we incurred realized losses of $94.8 million and $58.6 million during 2013 and 2012, 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. Also included in realized losses for 2013 is a $31.8 million loss due to the early termination of an interest rate swap.

During 2013 and 2012, we recognized unrealized gains on our interest rate swaps of $133.5 million and $26.1 million, respectively. The unrealized gains during 2013 resulted from the transfer of $94.8 million of previously recognized unrealized losses to realized losses related to actual cash settlements including $31.8 million from the early termination of an interest rate swap, and an additional $38.7 million of unrealized gains relating to increases in long-term LIBOR benchmark interest rates relative to the prior period. The net unrealized gain during 2012 resulted from the transfer of $58.6 million of previously recognized unrealized losses to realized losses related to actual cash settlements, offset by an incremental $32.5 million of unrealized losses relating to further declines in long-term LIBOR benchmark interest rates relative to the prior 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 gains (losses) on derivative instruments.

Foreign Currency Exchange (Losses) Gains. Foreign currency exchange losses were $5.3 million for 2013, compared to $0.3 million for 2012. 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 2013, we repurchased NOK 388.5 million of our NOK 600 million senior unsecured bond issue 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 associated cross currency swap. Excluding this, for 2013 foreign currency exchange losses include a realized gain of $1.6 million (2012 - $3.0 million) and an unrealized (loss) gain of ($38.6) million (2012 – $10.7 million) on the cross currency swap and an unrealized gain (loss) of $38.0 million (2012 - ($13.9) million) on the revaluation of the Norwegian Kroner denominated debt. There were additional realized and unrealized foreign exchange losses of $6.5 million, (2012 - $0.1 million) on all other monetary assets and liabilities.

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 NOK 600 million senior unsecured bond issue that matured in November 2013.

Other Income. Other income was $1.1 million for 2013, compared to $1.5 million for 2012, which was primarily comprised of leasing income from our VOC equipment and the unrealized gain / (loss) on the contingent consideration liability relating to the Scott Spirit shuttle tanker acquisition (please read Item 18. Financial Statements: Note 3a – Financial Instruments). The leasing income is decreasing as the VOC contracts near completion.

Income Tax (Expense) Recovery. Income tax expense was ($2.2) million for 2013, compared to a recovery of $10.5 million for 2012. The increase to income tax expense was primarily due to a write-off of a portion of our deferred tax asset in 2013 amounting to $2.3 million relating to lower future projected income for our Norwegian tax group for which we recognized a $8.6 million deferred tax recovery in 2012. This Norwegian tax structure was established in the fourth quarter of 2012 and allows the utilization of past losses carried forward against future projected income. The increase to income tax expense is also due to an income tax recovery of $2.8 million relating to the reversal of an uncertain tax position accrual in the second quarter of 2012, partially offset by a tax recovery of $0.5 million relating to the settlement of a claim for prior taxes paid in the fourth quarter of 2013.

Net (Loss) Income from Discontinued Operations. Net (loss) income from discontinued operations was ($4.6) million for 2013 compared to $17.6 million for 2012. In 2012, we sold the Hamane Spirit, Torben Spirit and Luzon Spirit. During the first quarter of 2013, we sold the Leyte Spirit, which was classified as held-for-sale at December 31, 2012. During the second and third quarters of 2013 we sold the Poul Spirit and the Gotland Spirit, respectively.

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

Net loss from discontinued operations increased for 2013 from 2012, primarily due to:

•

a decrease of $23.8 million in net revenues due to the sale of six conventional tankers since 2012;

•

an increase of $10.8 million from the higher write down and loss on sale of vessels in 2013 relative to 2012, mainly as the vessels sold in 2012 had been previously written down in 2011; and

•

a decrease of $3.4 million in termination fees received from Teekay Corporation, of which $11.3 million in termination fees were received in 2013 in relation to the early terminations of the time-charter contracts for the Poul Spirit and the Gotland Spirit, compared to a $14.7 million termination fee received in 2012 in relation to the early cancellation of the time-charter contract for the Hamane Spirit;

partially offset by

•

a decrease of $10.4 million in vessel operating expenses due to the sale of six conventional tankers since 2012;

•

a decrease of $4.0 million in depreciation and amortization due to the sale of the Leyte Spirit, the Luzon Spirit, the Poul Spirit and the Gotland Spirit;

•

a decrease of $0.7 million in general and administrative expenses due to the sale of six conventional tankers since 2012; and

•

a decrease of $0.7 million in interest expense due to the sale of six conventional tankers since 2012.

Year Ended December 31, 2012 versus Year Ended December 31, 2011

Shuttle Tanker Segment

As at December 31, 2012, our shuttle tanker fleet consisted of 34 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters. Of the 34 shuttle tankers, six were owned through 50% owned subsidiaries, three through a 67% owned subsidiary and four were chartered-in, with the remainder owned 100% by us. We also had four newbuilding shuttle tankers on order which delivered mid-to-late 2013. Subsequent to December 31, 2012, we sold a 1992-built owned shuttle tanker. This vessel was previously laid up in July 2011, following the maturity of its time-charter-out contract.

The following table presents our shuttle tanker segment’s operating results for 2012 and 2011, and compares its net revenues (which is a non-GAAP financial measure) for 2012 and 2011, 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,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2012		2011		% Change
Revenues		569,519		573,296		(0.7	)
Voyage expenses		104,394		95,864		8.9

Net revenues		465,125		477,432		(2.6	)
Vessel operating expenses		160,957		186,642		(13.8	)
Time-charter hire expense		56,989		74,478		(23.5	)
Depreciation and amortization		122,921		115,637		6.3
General and administrative⁽¹⁾		20,146		24,692		(18.4	)
Write-down and loss on sale of vessels		24,542		28,270		(13.2	)
Restructuring charge		647		1,227		(47.3	)

Income from vessel operations		78,923		46,486		69.8

Calendar-Ship-Days
Owned Vessels		11,530		11,308		2.0
Chartered-in Vessels		1,459		2,007		(27.3	)

Total		12,989		13,315		(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 2012 compared to 2011, primarily due to the purchase from Teekay Corporation of two new building shuttle tankers, the Peary Spirit and the Scott Spirit, in August 2011 and October 2011, respectively (or the 2011 Newbuilding Shuttle Tankers Acquisitions), partially offset by the sale of the Navion Fennia in July 2012 and the Navion Savonita in November 2012. Included in calendar-ship-days are two owned shuttle tankers which have been in lay-up since July 2011 and May 2012, respectively, following their redelivery to us upon maturity of their time-charter-out contracts in March 2011 and April 2012.

The average size of our chartered-in shuttle tanker fleet decreased in 2012 compared to 2011, primarily due to:

•

the redelivery of one bareboat-in vessel to its owner in October 2011;

•

decreased spot chartered-in vessels in 2012 compared to the same period last year; and

•

more off-hire days in 2012 compared to the same period last year.

Net Revenues. Net revenues decreased for 2012 from 2011, primarily due to:

•

a decrease of $11.6 million due to the lay-up of two of our vessels following their redelivery to us in July 2011 and May 2012, respectively, upon maturity of the time-charter-out contracts;

•

a decrease of $8.6 million due to less opportunities to trade excess capacity in the conventional spot tanker market and on short-term offshore projects due to decreased demand for conventional crude transportation; and

•

a decrease of $3.6 million due to more drydock and repair off-hire days in our time-chartered-out fleet in 2012 as compared to 2011;

partially offset by

•

a net increase of $11.0 million due to an increase in revenues in our contract of affreightment fleet, and an increase in revenues in our time-chartered-out fleet from entering into new contracts and an increase in rates as provided in certain contracts, partially offset by fewer revenue days from the redelivery of six vessels to us in July 2011, February 2012, March 2011, April 2012, and two in November 2012 as they completed their time-charter-out agreements.

Vessel Operating Expenses. Vessel operating expenses decreased for 2012 from 2011, primarily due to:

•

a decrease of $10.6 million relating to the lay-up of two of our shuttle tankers since July 2011 and May 2012 and the reduction in costs associated with the sale of two of our older shuttle tankers in July 2012 and November 2012;

•

a decrease of $7.1 million due to a decrease in costs related to services and spares and the number of vessels dry docked. Certain repair and maintenance items are more efficient to complete while a vessel is in dry dock. Consequently, repair and maintenance costs will typically increase in periods when there is an increase in the number of vessels dry docked;

•

a decrease of $5.9 million in crew and manning costs primarily from changes in crew compensation and reduced helicopter usage;

•

a decrease of $4.5 million relating to the redelivery of one bareboat-in vessel to its owner in October 2011; and

•

a decrease of $1.3 million relating to a decrease in start up costs associated with less short-term offshore projects;

partially offset by

•

an increase of $4.3 million due to the 2011 Newbuilding Shuttle Tanker Acquisitions.

Time-Charter Hire Expense. Time-charter hire expense decreased for 2012 from 2011, primarily due to:

•

a decrease of $8.7 million due to the redelivery of one bareboat-in vessel to their owner in October 2011; and

•

a decrease of $7.8 million due to decreased spot in-chartering during 2012.

Depreciation and Amortization. Depreciation and amortization expense increased for 2012 from 2011, primarily due the accelerated depreciation related to a change in the useful life for six older shuttle tankers and the 2011 Newbuilding Shuttle Tanker Acquisitions, partially offset by less depreciation relating to the impairment and write-down of two older shuttle tankers in 2011 to their estimated fair value and the sale of the two older shuttle tankers in 2012.

Write down and Loss on Sale of Vessels. Write down of vessels was $23.4 million for 2012, resulting from the impairment of four older shuttle tankers. We determined these vessels were impaired and wrote down the carrying values of these vessels to their estimated fair value, due to a change in operating plan for these vessels. Write down of vessels was $28.3 million for 2011, resulting from the impairment of three shuttle tankers, all of which were 20-years old in 2012. These vessels’ carrying values were written down to their estimated fair value. Loss on sale of vessels was $1.1 million for 2012 relating to the sale of two 1992-built shuttle tankers.

Restructuring Charge. Restructuring charges were $0.6 million for 2012, resulting from a reorganization of marine operations to create better alignment within the shuttle tanker business unit to create a reduced-cost organization going forward. Restructuring charges were $1.2 million for 2011, resulting from the termination of the time-charter-out contract for the Basker Spirit.

FPSO Segment

As at December 31, 2012, our FPSO fleet consisted of the Petrojarl Varg, the Rio das Ostras and the Piranema Spirit, all of which we own 100%.

The following table presents our FPSO segment’s operating results for 2012 and 2011, and also provides a summary of the calendar-ship-days for our FPSO segment:


	Year Ended December 31,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2012		2011		% Change
Revenues		231,688		173,836		33.3
Vessel operating expenses		111,855		82,434		35.7
Depreciation and amortization		50,905		37,496		35.8
General and administrative⁽¹⁾		11,208		9,756		14.9
Income from vessel operations		57,720		44,150		30.7
Calendar-Ship-Days
Owned Vessels		1,098		761		44.3

(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 number of our FPSO units for 2012 increased compared to last year due to the acquisition of the Piranema Spirit on November 30, 2011.

Revenues. Revenues increased for 2012 from 2011, primarily due to:

•

an increase of $55.6 million relating to the acquisition of the Piranema Spirit in November 2011;

•

an increase of $6.7 million due to the recovery of crew and manning costs. In 2011 these recoveries were reported on a net basis in vessel operating expenses; and

•

an increase of $5.6 million due to increased rates on the Petrojarl Varg and Rio das Ostras in accordance with the annual escalation of the charter component;

partially offset by

•

a decrease of $3.5 million relating to payments made to us during 2011 for services previously rendered to the charterer of the Rio das Ostras;

•

a decrease of $3.5 million due to decreased incentives and lower production on the Petrojarl Varg and partly due to a planned maintenance shutdown of that unit during the second quarter of 2012;

•

a decrease of $2.0 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner; and

•

a decrease of $1.2 million relating to a credit earned in 2011 for unused maintenance days in accordance under the service contract of the Rio das Ostras.

Vessel Operating Expenses. Vessel operating expenses increased for 2012 from 2011, primarily due to:

•

an increase of $28.5 million due to the acquisition of the Piranema Spirit in November 2011;

•

an increase of $5.1 million due to the recovery of certain crew and manning costs, where the recovery is reported in revenue in 2012. In 2011 these recoveries were reported on a net basis in vessel operating expenses;

•

an increase of $2.7 million due to higher maintenance costs relating to the Petrojarl Varg during the third quarter of 2012; and

•

an increase of $1.2 million due to an increase in our ship management costs on the Petrojarl Varg and Rio das Ostras;

partially offset by

•

a decrease of $4.0 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner compared to 2011;

•

a decrease of $3.4 million due to repairs on the Rio das Ostras while on yard stay and higher consumables and spares during the first quarter of 2011 and deployment to the field during the second quarter of 2011; and

•

a decrease of $1.4 million due to lower crew and manning costs relating to the Rio das Ostras due to its deployment to the field during the second quarter of 2011.

Depreciation and Amortization Expense. Depreciation and amortization expense increased for 2012 from 2011, primarily due to the acquisition of the Piranema Spirit in November 2011.

Conventional Tanker Segment

As at December 31, 2012, we owned 100% interests in five Aframax conventional crude oil tankers (four of which operate under fixed-rate time charters with Teekay Corporation, and one of which has been laid up indefinitely), and two vessels, which have additional equipment for lightering, which operated under fixed-rate bareboat charters with Skaugen PetroTrans, Teekay Corporation’s 50% owned joint venture.

The following table presents our conventional tanker segment’s operating results for 2012 and 2011, and compares net revenues (which is a non-GAAP financial measure) for 2012 and 2011, 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.

The table below only includes the results of two Aframax conventional crude oil tankers and the two vessels, which have additional equipment for lightering, as the other three Aframax conventional crude oil tankers are deemed discontinued operations given they were sold in 2013.


	Year Ended December 31,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2012		2011		% Change
Revenues		37,119		31,119		19.3
Voyage expenses		5,689		332		1,613.6
Net revenues		31,430		30,787		2.1
Vessel operating expenses		6,509		6,115		6.4
Depreciation and amortization		6,500		6,588		(1.3	)
General and administrative⁽¹⁾		1,389		1,205		15.3
Restructuring charge		468		—		100.0

Income from vessel operations		16,564		16,879		(1.9	)

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 increased for 2012 from 2011, primarily due to a net increase of $0.7 million due to higher reimbursed bunkers.

Restructuring Charges. Restructuring charges increased for 2012 primarily due to the reorganization of our conventional tanker marine operations to create better alignment with marine operations. We recorded restructuring charges of $0.5 million during 2012 since this plan began. The reorganization was completed in 2013.

FSO Segment

As at December 31, 2012 our FSO fleet consisted of five vessels that operate under fixed-rate time charters or fixed-rate bareboat charters. We have 100% ownership interests in these units.

The following table presents our FSO segment’s operating results for 2012 and 2011, and compares its net revenues (which is a non-GAAP financial measure) for 2012 and 2011, 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,				% Change
(in thousands of U.S. dollars, except calendar-ship-days and percentages)	2012		2011		% Change
Revenues		62,901		62,731		0.3
Voyage expenses		400		1,388		(71.2	)

Net revenues		62,501		61,343		1.9
Vessel operating expenses		38,255		32,769		16.7
Depreciation and amortization		9,038		12,009		(24.7	)
General and administrative⁽¹⁾		1,838		1,480		24.2
Write down and loss on sale of vessels		—		8,769		(100.0	)
Restructuring charge		—		2,697		(100.0	)

Income from vessel operations		13,370		3,619		269.4

Calendar-Ship-Days
Owned Vessels		1,830		1,901		(3.7	)

(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).

In March 2011, we sold one of our FSO units, the Karratha Spirit, for proceeds of $5.1 million, resulting in a loss of $0.2 million.

Net Revenues. Net revenues increased for 2012 from 2011, primarily due to:

•

an increase of $5.5 million from engineering studies completed in 2012 to support our FSO tenders; and

•

an increase of $1.2 million due to a higher charter rate on two FSO units, lower bunkers expense and one additional day in 2012 as compared to 2011;

partially offset by

•

a decrease of $3.2 million due to the sale of the Karratha Spirit in March 2011; and

•

a decrease of $2.3 million due to the drydocking of the Navion Saga during the third quarter of 2012.

Vessel Operating Expenses. Vessel operating expenses increased for 2012 from 2011, primarily due to an increase of $7.3 million due to expenditures on projects completed to support our direct FSO tenders, partially offset by a decrease of $1.8 million related to the sale of the Karratha Spirit in March 2011.

Depreciation and amortization. Depreciation and amortization expense decreased for 2012 from 2011, primarily due to a decrease of $2.1 million due to the write down of the carrying value of the Navion Saga to its estimated fair value in December 2011.

Write down and loss on sale of vessels. Write down and loss on sale of vessels was $8.8 million for 2011 as a result of the impairment on the Navion Saga mainly due to escalating dry-dock costs and increased operating costs. We wrote down the carrying value of the vessel to its estimated fair value.

Restructuring charge. Restructuring charges for 2011 were incurred in connection with the termination of employment for certain of the crew members of the Karratha Spirit following the sale of the vessel in March 2011.

Other Operating Results

General and Administrative Expenses. General and administrative expenses decreased to $34.6 million for 2012, from $37.1 million for 2011, mainly due to increases in business development costs supporting our direct tenders, an increase during 2012 in realized and unrealized gains on foreign currency forward contracts that have been designated as hedges for accounting purposes and a decrease in direct costs and general cost savings associated with the restructuring in 2012 of our conventional tanker business unit, partially offset by the acquisition of the Piranema Spirit FPSO unit in November 2011 and a success fee paid to Teekay Corporation relating to the acquisition of the Piranema Spirit in November 2011.

Interest Expense. Interest expense, which excludes realized and unrealized gains and losses from interest rate swaps, increased to $47.5 million for 2012, from $35.9 million for 2011, primarily due to:

•

an increase of $7.2 million from the issuance of the NOK 600 million senior unsecured bonds in January 2012;

•

an increase of $4.1 million related to the new $130 million debt facility secured by the Piranema Spirit FPSO unit in February 2012; and

•

an increase of $3.0 million due to increased interest rates during 2012, compared to 2011;

partially offset by

•

a decrease of $3.0 million related to scheduled repayments and prepayments of debt during 2012 and 2011.

Realized and Unrealized Losses on Derivatives. Net realized and unrealized losses on non-designated derivatives were $26.3 million for 2012, compared to $159.7 million for 2011.

During 2012 and 2011, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.6 billion with average fixed rates of approximately 4.3% for both years. Short-term variable benchmark interest rates during these periods were generally less than 1.2% and, as such, we incurred realized losses of $58.6 million and $58.5 million, respectively, during 2012 and 2011 under the interest rate swap agreements.

The net unrealized gain resulted from the transfer of $58.6 million of previously recognized unrealized losses to realized losses related to actual cash settlements, offset by an incremental $32.5 million of unrealized losses relating to further declines in long-term LIBOR benchmark interest rates relative to the prior year. Due to significant decreases in long-term benchmark interest rates in 2011, we recognized unrealized losses of $100.3 million in 2011. 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 gains (losses) on derivative instruments.

Foreign Currency Exchange (Losses) Gains. Foreign currency exchange losses were $0.3 million for 2012, compared to a $1.5 million gain for 2011. Our foreign currency exchange losses and gains, 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 2012, foreign currency exchange losses and gains include a realized gain of $3.0 million (2011 – $2.9 million) and an unrealized gain (loss) of $10.7 million (2011 – ($1.6) million) on the cross currency swap and an unrealized (loss) gain of ($13.9) million (2011 – $2.6 million) on the revaluation of the Norwegian Kroner denominated debt. There were additional realized and unrealized foreign exchange losses of $0.1 million (2011 – $2.4 million) on all other monetary assets and liabilities.

Other Income. Other income was $1.5 million for 2012, compared to $3.7 million for 2011, which was primarily comprised of leasing income from certain of our VOC equipment and the unrealized gain / (loss) on the contingent consideration liability relating to the Scott Spirit acquisition (please read Item 18. Financial Statements: Note 4a - Financial Instruments). The leasing income is decreasing as the contracts near completion.

Income Tax Recovery (Expense). Income tax recovery (expense) was $10.5 million for 2012, compared to ($6.7) million for 2011. The increase to income tax recovery was primarily due to a new Norwegian tax structure established in the fourth quarter of 2012 which resulted in a $8.6 million deferred tax recovery for our Norwegian tax group by being able utilize past losses carried forward against future projected income, whereas 2011 included a $5.0 million current tax expense for this tax group. In 2012 we also recognized a deferred income tax recovery of $3.1 million relating to the reversal of an uncertain tax position accrual during 2012.

Net Income (Loss) from Discontinued Operations. Net income (loss) from discontinued operations was $17.6 million for 2012, compared to ($11.5) million for 2011. In 2011, we sold the Scotia Spirit. In 2012, we sold the Hamane Spirit, Torben Spirit and Luzon Spirit. During the first quarter of 2013, we sold the Leyte Spirit, which was classified as held-for-sale at December 31, 2012. During the second and third quarters of 2013 we sold the Poul Spirit and the Gotland Spirit, respectively.

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

Net income from discontinued operations increased for 2012 from 2011, primarily due to:

•

a decrease of $46.4 million from the write down and loss on sale of vessels as five conventional tankers were written down in 2011 compared to one in 2012;

•

a $14.7 million termination fee received from Teekay Corporation in 2012 in relation to the early cancellation of the time charter contract for the Hamane Spirit;

•

a decrease of $10.7 million in depreciation and amortization expense primarily due to the cessation of depreciation of two held-for-sale vessels effective December 31, 2011 (the Hamane Spirit and the Torben Spirit), the sale of the Scotia Spirit in 2011 and the write down of the Leyte Spirit and the Luzon Spirit to their estimated fair value in the fourth quarter of 2011;

•

a decrease of $3.3 million in vessel operating expenses due to the sale of the Scotia Spirit, the Hamane Spirit and the Torben Spirit; and

•

a decrease of $2.3 million in vessel operating expenses due to the lay ups of the Leyte Spirit and Luzon Spirit commencing in April 2012;

partially offset by

•

a decrease of $23.4 million in net revenues due to the Leyte Spirit and Luzon Spirit operating in the spot tanker market until April 2012 after which they were laid up indefinitely until their sale in 2012 and 2013, respectively, compared to 2011 when they were operating under fixed-rate time charters;

•

a decrease of $20.2 million in net revenues due to the sale of the Scotia Spirit, the Hamane Spirit and the Torben Spirit; and

•

a decrease of $4.4 million in net revenues due to lower reimbursed bunker expenses on the Poul Spirit and the Gotland Spirit.

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. The operating cash flow our vessels generate each quarter, excluding a reserve for maintenance capital expenditures, is generally paid out to our common unitholders within approximately 45 days after the end of each quarter. Our primary short-term liquidity needs are to pay quarterly distributions on our outstanding common and Series A preferred units, payment of operating expenses, dry docking expenditures, debt service costs and to fund general working capital requirements. We anticipate that our primary sources of funds for our short-term liquidity needs will be cash flows from operations. We believe that our existing cash and cash equivalents and undrawn long-term borrowings, in addition to all other sources of cash including cash from operations, will be sufficient to meet our existing liquidity needs for at least the next 12 months.

Our long-term liquidity needs primarily relate to expansion and maintenance capital expenditures and debt repayment. Expansion capital expenditures primarily represent the purchase or construction of vessels to the extent the expenditures increase the operating capacity or revenue generated by our fleet, while maintenance capital expenditures primarily consist of dry docking expenditures and expenditures to replace vessels in order to maintain the operating capacity or revenue generated by our fleet. Our primary sources of funds for our long-term liquidity needs are from cash from operations, long-term bank borrowings and other debt or equity financings, or a combination thereof. Consequently, our ability to continue to expand the size of our fleet is dependent upon our ability to obtain long-term bank borrowings and other debt, as well as raising equity.

Our revolving credit facilities and term loans are described in Item 1 – Financial Statements: Note 7 – 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 that requires us to maintain a vessel value to drawn principal balance ratio of a minimum of 105%. As at December 31, 2013, this ratio was 123%. The vessel value used in this ratio is the appraised value prepared by us based on second hand sale and purchase market data. A further delay in the recovery of the conventional tanker market could negatively affect this ratio. As at December 31, 2013, we and our affiliates were in compliance with all covenants relating to the revolving credit facilities and term loans.

As at December 31, 2013, our total cash and cash equivalents were $219.1 million, compared to $206.3 million at December 31, 2012. Our total liquidity, including cash, cash equivalents and undrawn long-term borrowings, was $331.0 million as at December 31, 2013, compared to $419.8 million as at December 31, 2012. The decrease in liquidity was primarily due to our acquisition from Teekay Corporation in May 2013 of its 100% interest in Voyageur LLC, which owns the Voyageur Spirit FPSO unit; our acquisition from Teekay Corporation in June 2013 of its 50% interest in the Itajai FPSO unit; our acquisition of the four BG Shuttle Tankers; a reduction in the amount available for drawdown of our revolving credit facilities; and the scheduled repayment and prepayment of outstanding term loans, partially offset by the proceeds from the issuance in January 2013 of NOK 1,300 million senior unsecured bonds, of which a portion was used to repurchase NOK 388.5 million of our NOK 600 million senior unsecured bond issue that matured in November 2013; the net proceeds from the issuance of common and preferred units, including net proceeds of $2.4 million from the issuance of common units under the COP through December 31, 2013, $54.4 million from a private placement of common units in December 2013, $61.2 million from a private placement of common units in April 2013, $144.8 million from the public offering of Series A preferred units in April 2013; and a $200 million refinancing of our revolving credit facility relating to the Petrojarl Varg FPSO unit in July 2013.

As at December 31, 2013, we had a working capital deficit of $720.6 million, compared to a working capital deficit of $67.7 million at December 31, 2012. As at December 31, 2013, the working capital deficit included $227.5 million of term loans, $570.5 million of revolving credit facilities, $46.7 million of interest rate swap liabilities and $106.7 million of net due to affiliates. The current portion of long-term debt increased mainly due to the drawdown of term facilities and scheduled repayments of our existing term facilities coming due in the current year, partially offset by prepayments on revolving credit facilities. In October 2014, we have $410.4 million of balloon payments due on two revolving credit facilities. Both of these revolving credit facilities bear interest at rates that are considered below market rates relative to the current market levels and as such, we intend to refinance these balloon payments by entering a new credit facility closer to the date of their maturities. In September 2014, we have a $15.7 million

balloon payment due on one of our revolving credit facilities, which we intend on refinancing with a new loan facility closer to the date this facility comes due. Our due to affiliates balance increased mainly due the timing of settlements made and due to our acquisition from Teekay Corporation of its 100% interest in Voyageur LLC, which owns the Voyageur Spirit FPSO unit and our acquisition from Teekay Corporation of its 50% interest in the Itajai FPSO unit. We expect to manage our working capital deficit primarily with new and existing undrawn revolving credit facilities and term loans, including the NOK 1,000 million senior unsecured bonds, that we issued in January 2014 for an aggregate principal amount equivalent to $162.2 million, and, to a lesser extent, net operating cash flow generated in 2014.

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)	2013			2012			2011
Net cash flow from operating activities		255,387			267,494			254,162
Net cash flow from (used for) financing activities		231,865			(206,007	)		35,318
Net cash flow used for investing activities		(474,465	)		(35,082	)		(276,029	)

Operating Cash Flows. Net cash flow from operating activities decreased to $255.4 million for 2013, from $267.5 million in 2012, due primarily to a $40.0 million increase in realized losses on non-designated derivative instruments, a $26.6 million increase in vessel operating expenses, a $15.7 million decrease in income from discontinued operations, a $12.8 million increase in net interest expense, a $10.3 million increase in general and administrative expenses, a $4.4 million increase in net deferred mobilization costs, a $1.8 million loss on bond repurchase, a $1.5 million increase in restructuring costs and a $1.5 million increase in current income taxes partially offset by a $69.4 million increase in changes in non-cash working capital items and a $33.7 million increase in net revenue.

The increase in non-cash working capital items for 2013 compared to 2012 is primarily due 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.

Net cash flow from operating activities increased to $267.5 million for 2012, from $254.2 million in 2011, due primarily to a decrease in time-charter hire expenses of $13.9 million, an increase in the current tax recovery of $8.7 million, a decrease in dry docking expenditures of $7.3 million, a decrease in restructuring costs of $2.8 million, and an increase in net revenues of $2.7 million, partially offset by an increase in net interest expense of $9.9 million, a net decrease in changes to non-cash working capital items of $6.2 million, an increase in general and administrative expenses of $2.4 million, a decrease in other income of $2.0 million and an increase in realized losses on non-designated derivative instruments of $1.9 million. Details of the changes for the majority of these items are described in the Results of Operations - Year Ended December 31, 2012 versus Year Ended December 31, 2011. In summary, we benefited from a full year of the Piranema Spirit FPSO unit, partially offset by vessel sales and the terminations of time-charter-out contracts within our shuttle and conventional fleets.

The $7.3 million decrease in dry docking costs for 2012 compared to 2011 is primarily due to a decrease in the number of vessel dry dockings for 2012 compared to 2011.

The $6.2 million net decrease in the change in working capital for 2012 compared to 2011 is primarily due to the timing of settlements with related parties, partially offset by the timing of payments made to vendors and the timing of payments received from customers.

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

Financing Cash Flows.

In order to partially finance new acquisitions, we periodically issue equity to the public and to institutional investors. We raised net proceeds (including our general partner’s 2% proportionate capital contribution) of $263.8 million in 2013, $257.2 million in 2012 and $419.9 million in 2011. We paid finance shipyard installments for the four BG shuttle tankers in 2013, 2012 and 2011. We repaid a portion of our outstanding debt under certain of our revolving credit facilities in 2013 and 2012. We purchased the Voyageur Spirit FPSO unit during 2013. We purchased the Piranema Spirit FPSO unit and acquired the remaining 49% interest in Teekay Offshore Operating L.P. in 2011. We repaid the remaining $60.0 million of the Teekay Corporation vendor financing related to the purchase of the Petrojarl Varg FPSO unit in 2011.

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 (outflow) from the issuance of long-term debt, net of debt issuance costs and prepayments of long-term debt were $658.7 million in 2013, ($131.4) million in 2012, and $331.3 million in 2011. In 2013, we issued long-term debt to finance a portion of the acquisition of the Voyageur Spirit FPSO unit, to partially finance the final installments for the four BG shuttle tankers and for repayments and prepayments of existing revolving debt facilities. Net proceeds from the issuance of long-term debt declined in 2012 as a result of less cash required for capital expenditures. In 2011, we issued long-term debt to finance a portion of the acquisition of the Falcon Spirit, Rio Das Ostras, Amundsen Spirit and the Nansen Spirit from Teekay Corporation.

We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments of long-term debt increased to $266.9 million in 2013, from $146.2 million in 2012, and $110.7 million in 2011.

Cash distributions paid by our subsidiaries to non-controlling interests totaled $7.8 million in 2013, $8.8 million in 2012 and $37.0 million in 2011. Cash distributions paid by us to our common and Series A preferred unitholders and our general partner totaled $192.1 million in 2013, $160.9 million in 2012 and $129.3 million in 2011. The decrease in distribution to non-controlling interests and increase in distributions to our unitholders were mainly attributed to our acquisition from Teekay Corporation of the remaining 49% interest in OPCO in early March 2011. The increase in distributions to our common unitholders was attributed to two increases in our cash distribution of $0.0125 per unit and $0.0128 per unit, respectively, or approximately 2.5%, commencing with the cash distribution paid in the second quarters of 2012 and 2013, respectively, and an increase in the number of common units resulting from the 9.7 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2012 and 3.7 million (including our general partner’s 2% proportionate capital contribution) common units issued during 2013. The increase in the 2012 cash distribution coincided with our acquisition of the Piranema Spirit FPSO unit. The increase in the 2013 cash distribution coincided with our acquisition of the Voyageur Spirit FPSO unit. Subsequent to December 31, 2013, cash distributions relating to the fourth quarter of 2013 were declared and paid on February 14, 2014 and totaled $50.9 million, which included a $0.0131 per unit, or approximately 2.5%, increase over the cash distribution for the third quarter of 2013, and included an increase in the number of common units resulting from the 1.8 million (including our general partner’s 2% proportionate capital contribution) common units issued during December 2013. In 2013, we started the issuance of distributions resulting from the issuance of 6.0 million Series A preferred units in April 2013. Subsequent to December 31, 2013, cash distributions for Series A preferred units relating to the fourth quarter of 2013 were declared and paid on February 14, 2014 and totaled $2.7 million.

Investing Cash Flows. 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 the $52.5 million acquisition from Teekay Corporation of its 50 percent 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.

During 2012, net cash flow used for investing activities was $35.1 million, primarily relating to expenditures for vessels and equipment, including additional installment payments of $78.1 million on the four newbuilding BG shuttle tankers and $9.3 million on various other vessel additions, partially offset by $35.2 million in proceeds from the sale of five vessels and scheduled lease payments of $17.1 million received from the leasing of certain of our volatile organic compound emissions equipment and direct financing lease assets.

During 2011, net cash flow used for investing activities was $276.0 million, primarily relating to the purchase of the Piranema Spirit, expenditures on vessels and equipment relating to the four newbuilding BG shuttle tankers, the Peary Spirit newbuilding and upgrades on the Rio das Ostras, partially offset by scheduled lease payments of $20.9 million received from the leasing of our volatile organic compound emissions equipment and direct financing lease assets and the proceeds of $13.4 million received on the sale of vessels and equipment relating to the Scotia Spirit and the Karratha Spirit.

Contractual Obligations and Contingencies

The following table summarizes our long-term contractual obligations as at December 31, 2013:


	Total		2014		2015 and 2016		2017 and 2018		Beyond 2018
	(in millions of U.S. Dollars)
U.S. Dollar-Denominated Obligations
Long-term debt⁽¹⁾		2,056.1		806.0		376.7		462.4		411.0
Chartered-in vessels (operating leases)		33.8		27.0		6.8		—		—
Conversion of FSO units⁽²⁾		281.2		67.6		175.6		38.0		—
Norwegian Kroner-Denominated Obligations
Long-term debt⁽³⁾		312.9		—		82.4		230.5		—

Total contractual obligations		2,684.0		900.6		641.5		730.9		411.0

(1)

Excludes expected interest payments of $38.5 million (2014), $54.8 million (2015 and 2016), $33.1 million (2017 and 2018) and $33.1 million (beyond 2018). Expected interest payments are based on LIBOR, plus margins which ranged between 0.30% and 3.25% as at December 31, 2013. The expected interest payments do not reflect the effect or related interest rate swaps that we have used as an economic hedge of certain of our variable rate debt.

(2)	Includes amounts reimbursable upon delivery of the units relating to installation and mobilization costs, and the cost of acquiring the remaining 33% ownership interest in the Randgrid shuttle tanker. Please read Item 18 – Financial Statements; Note 13(b) and (c) – Commitments and Contingencies.

(3)

Excludes expected interest payments of $20.4 million (2014), $36.7 million (2015 and 2016), and $9.8 million (2017 and 2018). Expected interest payments are based on NIBOR, plus margins which ranged between 4.00% and 5.75% as at December 31, 2013. The expected interest payments do not reflect the effect or related interest rate swaps and cross currency swaps that we have used as an economic hedge of certain of our variable rate debt. The table excludes the NOK bonds issued subsequent to December 31, 2013.

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 require us to make estimates in the application of our accounting policies based on our best assumptions, judgments and opinions. Management of our general partner reviews our accounting policies, assumptions, estimates and judgments on a regular basis 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 will 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. Revenues from FPSO service contracts are recognized as 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 exceeds 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, 2013. 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 an 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 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 an impairment in the future for those vessels may primarily depend upon our deciding 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 an 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	⁽³⁾		44,000		79,440
Shuttle Tanker Segment		2	⁽²⁾⁽⁴⁾		52,000		73,704
FSO Segment		1	⁽³⁾		6,000		15,716
FSO Segment		1	⁽⁴⁾		6,500		11,153

(1)

Market values are determined using reference to second-hand market comparable values or using a depreciated replacement cost approach as at December 31, 2013. 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 values for the FSO units in the table above were 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)	These shuttle tankers are less than 15 years old. We expect that these vessels will generate sufficient cash flow over their remaining useful lives to exceed the respective carrying value of these vessels.

(3)	Undiscounted cash flows are marginally greater than the carrying values.

(4)	Undiscounted cash flows are significantly greater than the 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. FSO units are depreciated over the term of the contract. 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 drydocking costs and our expectations of future inflation and operating requirements. Vessel residual values are a product of a vessel’s lightweight tonnage and an estimated scrap rate. 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. Effective January 1, 2012, we reduced the estimated useful life of six older shuttle tankers from 25 years to 20 years. As a result of the change in useful life, we increased the estimate of the residual value of these vessels to reflect the more recent average scrap prices.

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 and conventional oil tankers 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 and conventional oil tanker 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 being 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, 2013, the shuttle segment had goodwill attributable to it. As of the date of this filing, we do not believe that there is a reasonable possibility that the goodwill attributable to this reporting unit 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.”

Amortization expense of intangible assets for 2013 and 2012 was $5.1 million and $6.0 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, 2013 and 2012, the net book value of intangible assets was $10.4 million and $15.5 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 11 – Derivative Instruments for the effects on the change in fair value of our derivative instruments on our consolidated statements of income (loss).

Taxes

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

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

Effect if Actual Results Differ from Assumptions. If we determined that we were able to realize a net deferred tax asset in the future, in excess of the net recorded amount, an adjustment to the deferred tax assets would typically increase our net income (or decrease our loss) in the period such determination was made. Likewise, if we determined that we were not able to realize all or a part of our deferred tax asset in the future, an adjustment to the deferred tax assets would typically decrease our net income (or increase our loss) in the period such determination was made. As at December 31, 2013, we had a valuation allowance of $136.7 million (2012 - $135.1 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 are as of March 1, 2014.


Name	Age	Position
C. Sean Day	64	Chairman ⁽¹⁾
Peter Evensen	55	Chief Executive Officer, Chief Financial Officer and Director
Kenneth Hvid	45	Director
David L. Lemmon	71	Director ^{(1) (2)}
Carl Mikael L.L. von Mentzer	69	Director ^{(1) (2)}
John J. Peacock	70	Director ^{(1) (2)}
Michael Balaski	57	Vice President

(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 and as Chairman of Teekay GP L.L.C. since 2004. He served as Chairman of Teekay Tankers Ltd. from October 2007 until June 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, he 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. In April, 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 October 2007 until June 2013. He was appointed Executive Vice President and Chief Strategy Officer of Teekay Corporation in 2006. 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. and Chief Strategy Officer and Executive Vice President of Teekay Corporation since April 2011. He served as a Director of Teekay GP L.L.C. from April 2011 to September 2012, when he resigned from this position to allow the Board to maintain a majority of independent Directors. Mr. Hvid rejoined the Board as a Director of Teekay GP L.L.C. in February 2013. 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 25 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 also currently serves on the Board of Directors of Kirby Corporation, a position he has held since April 2006, and also serves on the Board of Deltic Timber Corporation, a position he has held since February 2007. Mr. Lemmon was President and Chief Executive Officer of Colonial Pipeline Company from 1997 until his retirement in March 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 30 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. Prior to this, 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. He also serves as Chair of the McGill University Health Centre Foundation.

Michael Balaski has served as Vice President of Teekay Offshore GP L.L.C. and Teekay GP L.L.C. since December 2011. In 2011, he retired as a partner in the Tax Services Group of PricewaterhouseCoopers LLP (or PwC) in Vancouver, Canada, where he was a member of the International Tax Group specializing in the international shipping sector. Mr. Balaski was a partner of PwC Canada for over ten years. During that time, Mr. Balaski worked closely with Teekay Corporation and its subsidiaries, spending much of his working time at Teekay Corporation’s office.

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 he spends on our partnership matters.

Michael Balaski is the Vice President of our general partner. His compensation is set and paid by our general partner, and we reimburse the general partner for time he spends on our partnership matters.

During 2013, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the officers of the general partner incurred on our behalf and long-term incentive plan awards issued directly by the Partnership was $1.2 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 2013, each non-employee director received compensation for attending meetings of the Board of Directors, as well as committee meetings. Non-management directors received a director fee of $50,000 for the year and common units with an aggregate maximum value of approximately $50,000 for the year. The Chair received an additional annual fee of $37,000 and common units with a value of approximately $87,500. In addition, members of the audit and conflicts committees each received a committee fee of $5,000 for the year, and the chairs of the audit committee, conflicts committee and governance committee received an additional fee of $10,000, $10,000, and $5,000 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 2013, the four non-employee directors received, in the aggregate, $282,500 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. For the year ended December 31, 2013, 8,307 common units, with an aggregate value of $0.3 million, were granted and issued to the non-employee directors of the General Partner as part of their annual compensation for 2013.

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. During March 2013, the General Partner granted 63,309 restricted units with a fair value of $1.8 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 equally over three years 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 “Partnership Governance Charters” in the About Us page of our web site at www.teekayoffshore.com. During 2013, the Board held five meetings. Each director attended all Board meetings. Each committee member attended all applicable committee meetings, except for one meeting where one director was absent.

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 unitholders. The Board is not obligated to seek approval of the Conflicts Committee on any matter, and may determine the resolution of any conflict of interest itself.

Corporate Governance Committee. The Corporate Governance Committee of our general partner is composed of at least two directors. This committee is currently 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, 2013, approximately 2,000 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, 2013, approximately 207 staff served on shore in technical, commercial and administrative roles in Norway, Philippines, Singapore and Brazil. 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. 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, 2013, 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 March 1, 2014 (60 days after December 31, 2013) 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)		236,585		0.28	%

(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 the Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and Chief Financial Officer of Teekay Offshore GP L.L.C., and a Director of Teekay Offshore GP L.L.C. and Teekay GP L.L.C. Kenneth Hvid is a Director of Teekay Offshore GP L.L.C. and Teekay GP L.L.C. Mr. Hvid is also Executive Vice President and Chief Strategy Officer of Teekay Corporation. 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 March 1, 2014, 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 April 30, 2014 (60 days after March 1, 2014) 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⁾		23,809,468		27.9	%
Neuberger Berman Group LLC and Neuberger Berman, LLC, as a group ⁽²⁾		7,211,796		8.4	%
Kayne Anderson Capital Advisors, LP, and Richard A. Kayne, as a group ⁽³⁾		4,830,933		5.7	%

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

(2)

Includes shared voting power as to 6,910,089 units and shared dispositive power as to 7,211,796 units. Both Neuberger Berman Group LLC and Neuberger Berman LLC have shared dispositive power. Neuberger Berman, LLC and Neuberger Berman Management LLC serve as a sub-advisor and investment manager, respectively, of Neuberger Berman Group LLC’s various registered mutual funds which hold such shares. The holdings belonging to clients of Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC and Neuberger Berman Fixed Income LLC, affiliates of Neuberger Berman LLC, are also aggregated to comprise the holdings. This information is based on the Schedule 13G/A filed by this group with the SEC on February 12, 2014.

(3)

Includes shared voting power and shared dispositive power as to 4,101,402 units. Kayne Anderson Capital Advisors, LP, and Richard A. Kayne both have shared voting and dispositive power. Kayne Anderson Capital Advisors, L.P. is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. This information is based on the Schedule 13G/A filed by this group with the SEC on February 5, 2014.

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 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. and Teekay Offshore GP L.L.C.

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

Michael Balaski is the Vice President of Teekay Offshore GP L.L.C. and Teekay GP L.L.C.

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. Because Mr. Balaski is an employee of our general partner, his compensation is set and paid by our general partner. Pursuant to our partnership agreement, we have agreed to reimburse our general partner for time spent by Mr. Balaski 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 “offshore vessels” (i.e. 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), FSOs and FPSOs). 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;

•

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; or

•

owning shares of Teekay Petrojarl.

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 Teekay Petrojarl, 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.

On October 1, 2010, we acquired from Teekay Corporation the Rio das Ostras FPSO unit, which is on a long-term charter to Petroleo Brasileiro SA (or Petrobras), for a purchase price of $157.7 million, plus working capital of $12.4 million. The purchase agreement provides that Teekay Corporation shall reimburse us for upgrade costs in excess of the upgrade estimate as of the closing date. During the year ended December 31, 2011, Teekay Corporation reimbursed us for $2.0 million of such upgrade costs, which is reflected as a capital contribution.

On March 8, 2011, we acquired Teekay Corporation’s 49% interest in OPCO for a combination of $175 million in cash (less $15 million in distributions made by OPCO to Teekay Corporation between December 31, 2010 and the date of acquisition) and the issuance of 7.6 million of our common units to Teekay Corporation and a 2% proportionate interest to the General Partner in a private placement. The acquisition increased our ownership of OPCO to 100%. The excess of the proceeds paid by us over Teekay Corporation’s historical book value of $128.0 million for the 49% interest in OPCO was accounted for as an equity distribution to Teekay Corporation of $258.3 million.

On August 2, 2011, we acquired from Teekay Corporation the Peary Spirit for a purchase price of $134.5 million. The purchase price was financed through the assumption of debt of $96.8 million and $37.7 million with cash. The excess of $5.5 million of the cash portion of the purchase price over the book value of the net assets of $32.2 million is accounted for as an equity distribution to Teekay Corporation. Immediately prior to the acquisition, $36.9 million of amounts due to Teekay Corporation by Peary Spirit LLC was converted to equity of the vessel entity. For the period October 1, 2010 to August 2, 2011, we consolidated Peary Spirit LLC on our financial statements as it was considered a variable interest entity and we were the primary beneficiary.

On October 1, 2011, we acquired from Teekay Corporation a newbuilding shuttle tanker, the Scott Spirit, for $116.0 million. The purchase price was subject to adjustment for up to an additional $12 million based upon incremental shuttle tanker revenues above projections used for the sales price valuation generated during the two years following the acquisition. On October 1, 2012, we repaid a portion of the liability, which at the repayment date was $5.9 million. As at December 31, 2012, the outstanding liability was $5.7 million, which was included in due to affiliates. The remaining liability was settled as of the year end of December 31, 2013. The purchase price was financed through the assumption of debt of $93.3 million and $23.0 million with cash. The excess of $35.6 of the purchase price (including the contingent consideration liability of $10.1 million on October 1, 2011) over the book value of the net liabilities of $2.6 million, which includes the fair value of an interest rate swap of ($34.6) million, was accounted for as an equity distribution to Teekay Corporation. Immediately prior to the acquisition, $34.5 million of amounts due to Teekay Corporation by Scott Spirit LLC was converted to equity.

On October 1, 2012, we acquired from Teekay Corporation the volatile organic compound equipment on board the Amundsen Spirit, the Nansen Spirit, the Peary Spirit and the Scott Spirit for $12.8 million. On December 31, 2012, we recognized this liability in due to affiliates. The purchase price was financed with cash. The excess of $2.8 million of the purchase price over the net carrying value of the equipment is accounted for as an equity distribution to Teekay Corporation.

On May 2, 2013, we acquired from Teekay Corporation its 100% interest in Voyageur LLC, 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 Ruhrgas UK GP Limited (or E.ON), for an original purchase price of $540.0 million. The purchase price was financed with the assumption of the $230.0 million debt facility secured by the unit, $270.0 million with cash, of which a partial prepayment of $150.0 million was made to Teekay Corporation in February 2013, and the non-cash issuance of 1.4 million common units to Teekay Corporation, which had a value of $40.0 million at the time Teekay Corporation offered to sell the unit to us.

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 and our sponsor, Teekay Corporation, had a specified time period to receive final acceptance from the charterer, at which point the unit would commence full operations under the contract with E.ON. 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. This resulted in $29.2 million of the charter rate being foregone for the year ended December 31, 2013, inclusive of both the Dropdown Predecessor period from April 13, 2013 to May 1, 2013 and the period owned by us from May 2, 2013 to August 26, 2013.

On August 27, 2013, repairs to the defective gas compressor on the Voyageur Spirit FPSO were completed and the unit achieved full production capacity. On September 30, 2013, we entered into an interim agreement with E.ON whereby we were compensated for production beginning August 27, 2013 through until the receipt of final acceptance by E.ON. Compensation was based on actual production relative to the operating capacity of the FPSO unit; however, any restrictions on production as a result of the charterer were included in this compensation. Teekay Corporation has indemnified us for a further $2.1 million for the production shortfall from August 27, 2013 to December 31, 2013. In addition, we have been indemnified for a further $3.6 million associated with unrecovered repair costs to address the compressor issues. Teekay Corporation’s indemnification us for loss of the charter rate under the charter agreement with E.ON and certain unrecovered vessel operating expenses from the date of first oil on April 13, 2013 until receipt of the certificate of final acceptance from E.ON, is subject to a maximum of $54 million.

On April 4, 2014, we received the certificate of final acceptance from the charterer, which declared the unit on hire retroactive to February 22, 2014.

Any amounts paid as indemnification from Teekay Corporation to us were effectively treated as a reduction in the purchase price paid by us for the FPSO unit. Any future compensation received by us from the charterer related to the indemnification period will reduce the amount of Teekay Corporation’s indemnification to us. As at December 31, 2013, the $540.0 million original purchase price of the Voyageur Spirit FPSO unit has effectively been reduced to $509.3 million ($279.3 million net of assumed debt of $230.0 million) to reflect the $34.9 million indemnification amount for the last three quarters of 2013, partially offset by the excess value of $4.3 million relating to the 1.4 million common units issued to Teekay Corporation on the date of closing of the transaction in May 2013 compared to the date Teekay Corporation offered to sell the unit to us. The excess of the purchase price (net of assumed debt) over the book value of the net assets of $201.8 million is accounted for as an equity distribution to Teekay Corporation of $77.6 million.

The Itajai FPSO unit achieved first oil in February 2013, at which time the unit commenced operations under a nine-year, fixed-rate time-charter contract with Petroleo Brasileiro S.A. (or Petrobras), with six additional one-year extension options exercisable by Petrobras. On June 10, 2013, we acquired Teekay Corporation’s 50% interest in OOG-TKP FPSO GmbH & Co KG, a joint venture with Odebrecht, which owns the Itajai FPSO unit, for a purchase price of $53.8 million. The joint venture is a borrower under a term loan which at the time Teekay Corporation offered to sell its interest in the joint venture, had an outstanding balance of $300.0 million. Prior to finalizing the purchase, the joint venture repaid $10.5 million of its originally drawn down debt and as a result, the joint venture’s outstanding debt was $289.5 million as of the purchase date. The purchase price was paid in cash. The excess of the purchase price over Teekay Corporation’s carrying value of its 50% interest in the Itajai FPSO has been accounted for as an equity distribution to Teekay Corporation of $6.6 million. Our 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, including certain outstanding contractual items. To the extent the resolution of the outstanding contractual items results in a change to the fully built-up cost, we will not be exposed to changes in the fully built-up cost.

In June 2011, we entered into a new long-term contract with a subsidiary of BG Group plc (or BG) to provide shuttle tanker services in Brazil. The contract with BG is serviced with four newbuilding shuttle tankers (or the BG Shuttle Tankers) under ten-year time charter contracts. We took delivery of the four BG Shuttle Tankers in the second half of 2013. We received shipbuilding and site supervision services from certain subsidiaries of Teekay Corporation relating to BG Shuttle Tankers. These costs were originally capitalized and included as part of advances on newbuilding contracts. Upon delivery of the vessels, these costs were reclassified to vessels and equipment. As at December 31, 2013 and December 31, 2012, shipbuilding and site supervision costs provided by Teekay Corporation subsidiaries totaled $14.2 million and $2.8 million, respectively.

During the year ended, December 31, 2013, two conventional tankers, two shuttle tankers and two FSO units of ours were employed on long-term time-charter-out contracts with subsidiaries of Teekay Corporation, and two conventional tankers of ours were employed on long-term time-charter-out contracts with a joint venture in which Teekay Corporation has a 50% interest. During the year ended December 31, 2013 and 2012, we terminated the long-term time-charter-out contracts employed by three of our conventional tankers with a subsidiary of Teekay Corporation. In 2013 and 2012, we received early termination fees from Teekay Corporation of $11.3 million and $14.7 million, respectively, which is recorded in net income (loss) from discontinued operations on the consolidated statements of income (loss). Teekay Corporation and its wholly owned subsidiaries provide substantially all of our commercial, technical, crew training, strategic, business development and administrative services needs. In addition, we reimburse the General Partner for expenses incurred by the General Partner that are necessary or appropriate for the conduct of our business. Revenues (expenses) from such related party transactions were as follows:


	Year Ended December 31,
	2013			2012			2011
	$			$			$
Revenues⁽¹⁾		71,905			64,166			62,233
Vessel operating expenses⁽²⁾		(39,820	)		(44,024	)		(38,760	)
General and administrative⁽³⁾⁽⁴⁾		(29,528	)		(21,184	)		(26,660	)
Interest income⁽⁵⁾		1,217			—			—
Interest expense⁽⁶⁾		(450	)		(392	)		(316	)
Realized and unrealized loss on derivative instruments⁽⁷⁾		—			—			(12,186	)
Other expense⁽⁸⁾		(319	)		(657	)		(812	)
Net income from related party transactions from discontinued operations⁽⁹⁾		19,255			59,872			106,483

(1)	Includes revenue from long-term time-charter-out contracts and short-term time-charter-out contracts with subsidiaries or affiliates of Teekay Corporation, including management fees from ship management services provided by us to a subsidiary of Teekay Corporation.

(2)

Includes ship management and crew training fees charged by Teekay Corporation. The cost of ship management services provided by Teekay Corporation of $34.9 million for the year ended December 31, 2013, have been presented as vessel operating expenses. Please read Item 18. – Financial Statements: Note 1 – Summary of Significant Accounting Policies. The amounts reclassified from general and administrative to vessel operating expenses in the comparative periods to conform to the presentation adopted in the current periods were $38.7 million and $33.5 million for the years ended December 31, 2012 and 2011, respectively.

(3)	Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and reimbursements to Teekay Corporation and our General Partner for costs incurred on our behalf.

(4)

Includes a $1.0 million and $1.7 million success fee to Teekay Corporation for assistance with the acquisition of the 2010-built HiLoad Dynamic Positioning unit from Remora AS during the year ended December 31, 2013 and the acquisition of the 2007-built Piranema Spirit from Sevan Marine ASA during the year ended December 31, 2011, respectively.

(5)

Includes interest income related to the interest received from Teekay Corporation on the $150 million prepayment for the Voyageur Spirit. We 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 we acquired the FPSO unit on May 2, 2013.

(6)	Guarantee fee related to the final bullet payment of the Piranema Spirit FPSO debt facility guaranteed by Teekay Corporation for 2011 through 2013 and interest allocated from Teekay Corporation as a result of the Dropdown Predecessor during the year ended December 31, 2011.

(7)	Realized and unrealized losses on interest rate swaps allocated from Teekay Corporation as a result of the Dropdown Predecessor.

(8)	Unrealized loss from the change in fair value of our contingent consideration liability relating to the acquisition of the Scott Spirit. Please read Item 18. – Financial Statements: Note 3a – Financial Instruments.

(9)

Related party transactions relating to seven 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 the early termination fee 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, 2013, due from affiliates totaled $15.2 million (December 31, 2012 - $29.7 million) and due to affiliates totaled $121.9 million (December 31, 2012 - $47.8 million). Due to and from affiliates are non-interest bearing and unsecured and are expected to be settled within the next fiscal year in the normal course of operations.

Item 8. Financial Information

A. 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

On November 13, 2006, one of our shuttle tankers, the Navion Hispania, collided with the Njord Bravo, an FSO unit, while preparing to load an oil cargo from the Njord Bravo. The Njord Bravo services the Njord field, which is operated by Statoil Petroleum AS (or Statoil) and is located off the Norwegian coast. At the time of the incident, Statoil was chartering the Navion Hispania from us. The Navion Hispania and the Njord Bravo both incurred damage as a result of the collision. In November 2007, Navion Offshore Loading AS (or NOL) and Teekay Navion Offshore Loading Pte Ltd. (or TNOL), subsidiaries of ours, and Teekay Shipping Norway AS (or TSN), a subsidiary of Teekay Corporation, were named as co-defendants in a legal action filed by Norwegian Hull Club (the hull and machinery insurers of the Njord Bravo), several other insurance underwriters and various licensees in the Njord field. The plaintiffs sought damages for vessel repairs, expenses for a replacement vessel and other amounts related to production stoppage on the field, totaling NOK 213,000,000 (approximately $35.1 million).

In December 2011, the Stavanger District Court ruling in the first instance found that NOL was liable for damages except for damages related to certain indirect or consequential losses. The court also found that Statoil ASA was liable to NOL for the same amount of damages to NOL. As a result of this ruling, as at December 31, 2012, we reported a liability in the total amount of NOK 76,000,000 (approximately $12.5 million) to the plaintiffs and a corresponding receivable from Statoil ASA recorded in other long-term liabilities and other assets, respectively.

The plaintiffs appealed the decision and the appellate court in June 2013 held that NOL, TNOL and TSN are jointly and severally responsible towards the Plaintiffs for all the losses as a result of the collision, plus interests accrued on the amount of damages. In addition, Statoil ASA was held not to be under an obligation to indemnify NOL, TNOL and TSN for the losses. NOL, TNOL and TSN were also held liable for legal costs associated with court proceedings. As a result of this judgment, in the second quarter of 2013, we recognized a liability in the amount of NOK 213,000,000 in respect of damages, NOK 66,000,000 in respect of interest and NOK 11,000,000 in respect of legal costs, totaling NOK 290,000,000 (approximately $47.8 million), to the Plaintiffs recorded in accrued liabilities. The receivable from Statoil ASA previously recorded in other assets was reversed in the second quarter of 2013. In the fourth quarter of 2013, we recognized an additional liability of NOK 4,000,000 in respect of interest, bringing the total liability to NOK 294,000,000 (approximately $48.4 million). The judgment rendered deals with liability only and the ultimate amount of damages may be reduced compared to the NOK 213,000,000 claimed by the plaintiffs.

We and Teekay Corporation maintain protection and indemnity insurance for damages to the Navion Hispania and insurance for collision-related costs and claims. These insurance policies are expected to cover the costs related to this incident, including any costs not indemnified by Statoil, and thus a receivable of NOK 294,000,000 (approximately $48.4 million) was concurrently recorded in accounts receivable, which equals the total cost of the claim. In addition, Teekay Corporation has agreed to indemnify us for any losses it may incur in connection with this incident.

In the fourth quarter of 2013, the insurer made payments directly to the Plaintiffs in full settlement of interest and partial settlement of legal costs and thus we, as at December 31, 2013, reduced our liability and related receivable to NOK 213,000,000 in respect of damages and approximately NOK 3,400,000 in respect of legal costs, totaling approximately NOK 216,400,000 (approximately $35.6 million).

In addition, from time to time we have been, and expect to continue to be, subject to legal proceedings and claims in the ordinary course of our business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. We are not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on us.

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders are better served by our distributing our cash available (as defined in our partnership agreement and after deducting expenses, including estimated maintenance capital expenditures and reserves) rather than our retaining it. Because we believe we will generally finance any expansion capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance capital expenditures and reserves).

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

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

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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.

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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.

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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.

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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.

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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 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 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 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 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% 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	%

B. Significant Changes

On March 8, 2011, we acquired Teekay Corporation’s remaining 49% limited partner interest in OPCO for a combination of $175 million in cash (less $15 million in distributions made by OPCO to Teekay Corporation between December 31, 2010 and the date of acquisition), and 7.6 million of common units (and associated General Partner interest) to Teekay Corporation.

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 closing sales prices for our common units on the NYSE for each of the periods indicated:


Year Ended	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
High	$	35.91	$	29.94	$	31.19	$	29.79	$	20.06
Low	$	26.86	$	24.75	$	22.70	$	17.79	$	9.75

Quarter Ended	Mar. 31, 2014		Dec. 31, 2013		Sept. 30, 2013		June 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sept. 30, 2012		June 30, 2012
High	$	32.92	$	34.75	$	35.91	$	33.44	$	30.19	$	28.21	$	29.60	$	29.47
Low	$	31.12	$	29.81	$	31.10	$	29.16	$	26.86	$	24.75	$	27.20	$	26.70

Month Ended	Mar 31, 2014		Feb 28, 2014		Jan. 31, 2014		Dec. 31, 2013		Nov. 30, 2013		Oct. 31, 2013
High	$	32.92	$	32.76	$	32.73	$	33.09	$	34.75	$	33.61
Low	$	31.12	$	31.17	$	31.27	$	29.81	$	32.14	$	32.68

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:

Agreement, dated June 26, 2003, for a U.S. $455,000,000 Revolving Credit Facility between Norsk Teekay Holdings Ltd., Den Norske Bank ASA and various other banks. This facility bears interest at LIBOR plus a margin of 0.625%. The amount available under the facility reduces semi-annually, with a bullet reduction of $131.0 million on maturity in October 2014. The credit facility may be used for acquisitions and for general partnership purposes. As at December 31, 2013, our obligations under the facility are secured by first-priority mortgages granted on seven shuttle tankers and one FSO unit, together with other related security.

Agreement, dated October 2, 2006, for a U.S. $940,000,000 Revolving Credit Facility between Teekay Offshore Operating L.P. (or OPCO), Den Norske Bank ASA and various other banks. This facility bears interest at LIBOR plus a margin of 0.625%. The amount available under the facility reduces semi-annually, with a bullet reduction of $279.4 million on maturity in October 2014. The credit facility may be used for acquisitions and for general partnership purposes. In addition, this facility allows OPCO to make working capital borrowings and loan the proceeds to us, which we could use to make distributions, provided that such amounts are paid down annually. As at December 31, 2013, our obligations under the facility are secured by first-priority mortgages granted on eight of our shuttle tankers and two of our conventional tankers, together with other related security.

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 November 25, 2010, for NOK 600,000,000 Senior Unsecured Bonds due November 2013, among us, Teekay Offshore Operating L.P. and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.75% per annum.

Agreement, dated March 8, 2011, between Teekay Holdings Limited and Teekay Offshore Partners L.P., relating to the purchase of limited partner interests of OPCO. Please read Item 7 – Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for a summary of certain contract terms.

Agreement, dated January 25, 2012, for NOK 600,000,000 Senior Unsecured Bonds due January 2017, among us and Norsk Tillitsman ASA. All payments are at NIBOR plus 5.75% per annum.

Agreement, dated February 23, 2012, for a U.S. $130,000,000 debt facility between Piranema L.L.C. and Den Norske Bank ASA. This facility bears interest at LIBOR plus a margin of 3%. The amount available under the facility reduces quarterly, with a bullet reduction of $65.0 million on maturity in February 2017.

Agreement, dated September 11, 2012, between Teekay Corporation and Teekay Offshore Partners L.P., relating to the purchase of the Voyageur Spirit.

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 $174,150,000 senior secured bonds due December 2013 between Teekay Shuttle Tanker Finance L.L.C. and Wells Fargo.

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 non-resident holders of our securities.

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 the 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 common 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:

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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 common 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 common 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 common units, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding our common units, you should consult your own tax advisor about the U.S. federal income tax consequences of owning and disposing the common 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 and other tax consequences of the ownership or disposition of our common units.

United States Federal Income Taxation of U.S. Holders

As used herein, the term U.S. Holder means a beneficial owner of our common units that is (i) a U.S. citizen or U.S. resident alien, (ii) a corporation or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or 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 U.S. 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 with respect to our common units 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, as determined under U.S. federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in its common units and thereafter as capital gain, which will be either long term or short term capital gain depending upon whether the U.S. Holder has held the shares 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 paid with respect to our common units generally will be treated as “passive category income”.

Dividends paid on our common units to 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: (i) our common units are readily tradable on an established securities market in the United States (such as the New York Stock Exchange on which our common units are traded); (ii) 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); (iii) the Non-Corporate U.S. Holder has owned the common units for more than 60 days in the 121-day period beginning 60 days before the date on which the common units become ex-dividend; (iv) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property; and (v) certain other conditions are met. There is no assurance that any dividends paid on our common units will be eligible for these preferential rates in the hands of a Non-Corporate U.S. Holder. Any dividends paid on our common 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. An extraordinary dividend is, generally, a dividend with respect to a share of common stock if the amount of the dividend is equal to or in excess of 10% of a common stockholder’s adjusted basis (or fair market value in certain circumstances) in such common 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. If we pay an “extraordinary dividend” on our common units that is treated as “qualified dividend income,” then any loss derived by a Non-Corporate U.S. Holder from the sale or exchange of such common units will be treated as long-term capital loss to the extent 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 common units.

Sale, Exchange or Other Disposition of Common Units

Subject to the discussion of PFICs below, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common 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 common units.

Consequences of Possible PFIC Classification

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be 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 75.0% of its gross income is “passive” income; or (ii) at least 50.0% of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income.

For purposes of these tests, “passive income” includes dividends, interest, and 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 Code. However, the Internal Revenue Service (or IRS) stated in an Action on Decision (AOD 2010-01) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the Tidewater decision, and in its discussion stated that the time charters at issue in Tidewater would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to Tidewater cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the Tidewater decision in interpreting the PFIC provisions of the Code. Nevertheless, based on our and our subsidiaries’ current assets and operations, we intend to take the position that we are not now and have never been a PFIC. No assurance can be given, however, that 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 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 common 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 pro rata share would not exceed the income allocable to dividends on our units, although ordinary earnings could be allocated to a unitholder in a taxable year before the dividend is paid. 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 the common units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in common units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our common units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with 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 common 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 common 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 common 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 common 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 common units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made for the first year a U.S. Holder holds or is deemed to hold our common 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 common units at the end of the taxable year over the U.S. Holder’s adjusted tax basis in the common units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common units over the fair market value thereof at the end of the taxable year 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 common units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our common units 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 common 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 holder held our common 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 common units exceeds the U.S. Holder’s adjusted tax basis in the common 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 common 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 common units), and (ii) any gain realized on the sale, exchange or other disposition of our common 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 common units;

•

the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income in the current 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 common units. In addition, if a Non-Electing Holder who is an individual dies while owning our common units, such Non-Electing Holder’s successor generally would not receive a step-up in tax basis with respect to such common 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. Investors 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 common 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 common 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 Common 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 common 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 common unit 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 or the proceeds of a disposition of common 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-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 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 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 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 Consequences. 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 common 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 laws and therefore not a taxable entity for Canadian 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 common 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 common 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 common units, provided that, for purposes of the Canada-U.S. Treaty, such common 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 and the activities and affairs of OPCO, a Marshall Island limited partnership in which we own a 100% limited partnership interest, are conducted in such a manner that both we and OPCO 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 common 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 OPCO 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 and OPCO carry on our respective 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 headquarters 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 table below provides information about financial instruments as at December 31, 2013 that are sensitive to changes in interest rates. For debt obligations, the table presents principal payments and related weighted-average interest rates by expected maturity dates. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected contractual maturity dates.


	Expected Maturity Date
	2014			2015			2016			2017			2018			There- after			Total			Fair Value Liability		Rate ⁽¹⁾
	(in millions of U.S. dollars, except percentages)
Long-Term Debt:
Variable Rate ($U.S.)⁽²⁾		806.0			149.8			226.9			245.5			216.9			411.0			2,056.1			2,009.4		2.1	%
Variable Rate (NOK)⁽³⁾		—			—			82.4			98.7			131.8			—			312.9			322.4		6.5	%

Interest Rate Swaps:
Contract Amount ⁽⁴⁾		361.4			286.4			156.9			128.9			137.7			662.9			1,734.2			141.1		3.6	%
Average Fixed Pay Rate⁽²⁾		3.5	%		3.7	%		3.2	%		1.2	%		1.1	%		4.7	%		3.6	%

(1)

Rate refers to the weighted-average effective interest rate for our debt, including the margin paid on our floating-rate debt and 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, 2013 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 three 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 11 – 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.

Foreign Currency Fluctuation Risk

Our functional currency is 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 and general and administrative expenses in foreign currencies, the most significant of which is the Norwegian Kroner and, to a lesser extent, Australian Dollars, Brazilian Reals, British Pounds, Euros and Singapore Dollars. For the years ended December 31, 2013 and 2012, approximately 51.1% and 49.9%, 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, 2013, we were committed to the following foreign currency forward contracts:

Contract Amount

Average

Expected Maturity

in Foreign Currency

Forward

2014

2015

(thousands)

Rate⁽¹⁾

(in thousands of U.S. Dollars)

Norwegian Kroner

333,000

6.02

49,563

5,764

(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; however 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 11 – Derivative Instruments.

As at December 31, 2013, we were committed to the following cross currency swaps:


Principal Amount NOK	Principal Amount USD										Fair Value /
											Asset
			Floating Rate Receivable								(Liability)
			Reference					Fixed Rate			(Thousands of			Remaining
(Thousands)			Rate		Margin			Payable			U.S. Dollars)			Term (years)
600,000		101,351		NIBOR		5.75	%		7.49	%		(5,503	)		3.1
500,000		89,710		NIBOR		4.00	%		4.80	%		(8,185	)		2.1
800,000		143,536		NIBOR		4.75	%		5.93	%		(11,745	)		4.1

												(25,433	)

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, 2013, 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, 2013.

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 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, 2013.

Our independent auditors, KPMG LLP, a 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, 2013.

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

Our general partner has adopted revised Standards of Business Conduct that include a Code of Ethics for all our employees and the employees and directors of our general partner. This document is available under “About Us—Partnership Governance” from the Home Page of our web site (www.teekayoffshore.com). We intend to disclose, under “About Us—Partnership Governance” in the About Us 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 2013 and 2012 was KPMG LLP, Chartered Accountants. The following table shows the fees we paid or accrued for audit services provided by KPMG LLP for 2013 and 2012.


	2013		2012
	(in thousands of U.S. dollars)
Audit Fees ⁽¹⁾	$	771	$	716
Audit-related Fees ⁽²⁾		10		17
Tax Fees ⁽³⁾		31		30

Total	$	812	$	763

(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.

(2)	For 2013, audit-related fees relate primarily to assistance with general accounting issues.

(3)	For 2013 and 2012, 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 2013.

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 (Loss)		F-3

Consolidated Statements of Comprehensive Income (Loss)		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		First 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 November 25, 2010, among Teekay Offshore Partners L.P., Teekay Offshore Operating L.P. and Norsk Tillitsman ASA for NOK 600,000,000 Senior Unsecured Bonds due 2013. (5)

2.2		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)

2.3		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. (8)

2.4		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. (8)

2.5		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. (9)

2.6		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.

4.1		Agreement, dated June 26, 2003, for a U.S $455,000,000 Revolving Credit Facility between Norsk Teekay Holdings Ltd., Den Norske Bank ASA and various other banks. (1)

4.2		Agreement, dated October 2, 2006, for a U.S $940,000,000 Revolving Credit Facility between Teekay Offshore Operating L.P., Den Norske Bank ASA and various other banks. (1)

4.3		Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. (1)

4.4		Amended and Restated Omnibus Agreement. (1)

4.5		Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Limited. (3)

4.6		Advisory, Technical and Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Limited. (3)

4.7		Administrative Services Agreement between Teekay Offshore Partners L.P. and Teekay Limited. (3)

4.8		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. (5)

4.9		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.(8)

4.10		Business Development Services Agreement between Teekay Offshore Holdings L.L.C. and Teekay Shipping Limited. (8)

4.11		Agreement, dated September 11, 2012, between Teekay Corporation and Teekay Offshore Partners L.P., relating to the purchase of the Voyageur Spirit. (7)

4.12		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.

8.1		List of Subsidiaries of Teekay Offshore Partners L.P.

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.

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 Appendix A to our Rule 424(b)(4) Prospectus filed with the SEC on December 14, 2006, and hereby incorporated by reference to such Prospectus.

(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.

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 29, 2014	By:	/s/ Peter Evensen
	Peter Evensen Chief Executive Officer and Chief Financial Officer (Principal Financial and Accounting 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, 2013 and 2012, and the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated April 29, 2014 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.


Vancouver, Canada				/s/ KPMG LLP
April 29, 2014				Chartered 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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) 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, 2013 based on the criteria established in Internal Control—Integrated Framework (1992) 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 at December 31, 2013 and 2012, and the related consolidated statements of income (loss), comprehensive income (loss), cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2013, and our report dated April 29, 2014, expressed an unqualified opinion on those consolidated financial statements.


Vancouver, Canada				/s/ KPMG LLP
April 29, 2014				Chartered Accountants

F - 2

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 2)

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(in thousands of U.S. dollars, except unit and per unit data)


	Year Ended December 31 2013 $			Year Ended December 31 2012 $			Year Ended December 31 2011 $
REVENUES (note 10)		930,739			901,227			840,982

OPERATING EXPENSES
Voyage expenses		103,643			110,483			97,584
Vessel operating expenses (notes 10 and 11)		344,128			317,576			307,960
Time-charter hire expense		56,682			56,989			74,478
Depreciation and amortization		199,006			189,364			171,730
General and administrative (notes 10, 11 and 16)		44,473			34,581			37,133
Write down and loss on sale of vessels (note 18)		76,782			24,542			37,039
Restructuring charge (note 9)		2,607			1,115			3,924

Total operating expenses		827,321			734,650			729,848

Income from vessel operations		103,418			166,577			111,134

OTHER ITEMS
Interest expense (notes 7 and 10)		(62,855	)		(47,508	)		(35,929	)
Interest income		2,561			1,027			659
Realized and unrealized gains (losses) on derivative instruments (note 11)		34,820			(26,349	)		(159,744	)
Equity income (note 19)		6,731			—			—
Foreign currency exchange (loss) gain (note 11)		(5,278	)		(315	)		1,500
Loss on bond repurchase (note 7)		(1,759	)		—			—
Other income – net		1,144			1,538			3,683

Total other items		(24,636	)		(71,607	)		(189,831	)

Income (loss) from continuing operations before income tax (expense) recovery		78,782			94,970			(78,697	)
Income tax (expense) recovery (note 12)		(2,225	)		10,477			(6,679	)

Net income (loss) from continuing operations		76,557			105,447			(85,376	)
Net (loss) income from discontinued operations (notes 10 and 18)		(4,642	)		17,568			(11,495	)

Net income (loss)		71,915			123,015			(96,871	)

Non-controlling interests in net income (loss) from continuing operations		(19,089	)		58			18,901
Non-controlling interests in net income (loss) from discontinued operations		—			—			3,553
Non-controlling interests in net income (loss)		(19,089	)		58			22,454
Dropdown Predecessor’s interest in net income (loss) (note 2)		(2,225	)		—			(15,075	)
Preferred unitholders’ interest in net income (loss) (note 15)		7,250			—			—
General Partner’s interest in net income (loss) from continuing operations		14,126			12,827			3,775
General Partner’s interest in net income (loss) from discontinued operations		(452	)		(1,772	)		621
General Partner’s interest in net income (loss)		13,674			11,055			4,396
Limited partners’ interest in net income (loss) from continuing operations		76,495			92,562			(92,977	)
Limited partners’ interest in net income (loss) from continuing operations per common unit - basic (note 15)		0.93			1.26			(1.49	)
Limited partners’ interest in net income (loss) from continuing operations per common unit - diluted (note 15)		0.93			1.26			(1.49	)
Limited partners’ interest in net income (loss) from discontinued operations		(4,190	)		19,340			(15,669	)
Limited partners’ interest in net income (loss) from discontinued operations per unit - basic (note 15)		(0.05	)		0.26			(0.25	)
Limited partners’ interest in net income (loss) from discontinued operations per unit -diluted (note 15)		(0.05	)		0.26			(0.25	)
Limited partners’ interest in net income (loss)		72,305			111,902			(108,646	)
Limited partners’ interest in net income (loss) per common unit - basic (note 15)		0.88			1.52			(1.74	)
Limited partners’ interest in net income (loss) per common unit - diluted (note 15)		0.88			1.52			(1.74	)

Weighted-average number of common units outstanding - basic		82,634,000			73,750,951			62,362,072
Weighted-average number of common units outstanding - diluted		82,659,179			73,750,951			62,362,072

Cash distributions declared per unit		2.11			2.04			1.98
Related party transactions (note 10)

The accompanying notes are an integral part of the consolidated financial statements

F - 3

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 2)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands of U.S. dollars)


	Year Ended December 31, 2013 $			Year Ended December 31, 2012 $			Year Ended December 31, 2011 $
Net income (loss)		71,915			123,015			(96,871	)

Other comprehensive income (loss):
Unrealized net gain on qualifying cash flow hedging instruments (note 11)		6			713			319
Realized net loss (gain) on qualifying cash flow hedging instruments (note 11)		52			(217	)		(2,345	)

Other comprehensive income (loss)		58			496			(2,026	)

Comprehensive income (loss)		71,973			123,511			(98,897	)

Non-controlling interest in comprehensive income (loss)		(19,089	)		58			22,889
Dropdown Predecessor’s interest in comprehensive income (loss) (note 2)		(2,225	)		—			(15,075	)
Preferred unitholders’ interest in comprehensive income (loss)		7,250			—			—
General and limited partners’ interest in comprehensive income (loss)		86,037			123,453			(106,711	)

The accompanying notes are an integral part of the consolidated financial statements.

F - 4

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 2)

CONSOLIDATED BALANCE SHEETS

(in thousands of U.S. dollars)


	As at		As at
	December 31		December 31
	2013		2012
	$		$
ASSETS
Current
Cash and cash equivalents		219,126		206,339
Accounts receivable, including non-trade of $40,043 (December 31, 2012 - $7,714) (notes 11 and 13a)		176,265		91,879
Vessel held for sale (note 3a)		—		13,250
Net investments in direct financing leases - current (note 8)		5,104		5,647
Prepaid expenses		31,675		29,384
Due from affiliates (note 10k)		15,202		29,682
Current portion of derivative instruments (note 11)		500		12,398
Other current assets		3,051		8

Total current assets		450,923		388,587

Vessels and equipment
At cost, less accumulated depreciation of $1,016,812 (December 31, 2012 - $1,080,558)		3,089,582		2,327,337
Advances on newbuilding contracts		—		127,286
Net investments in direct financing leases (note 8)		22,463		27,568
Investment in joint venture (note 19)		52,120		—
Derivative instruments (note 11)		10,323		2,913
Deferred tax asset (note 12)		7,854		8,948
Other assets		35,272		28,112
Intangible assets – net (note 5b)		10,436		15,527
Goodwill (note 5a)		127,113		127,113

Total assets		3,806,086		3,053,391

LIABILITIES AND EQUITY
Current
Accounts payable		15,753		15,220
Accrued liabilities (notes 6, 9, 11, 13a)		138,156		61,708
Deferred revenues		29,075		22,641
Due to affiliates (note 10k)		121,864		47,810
Current portion of derivative instruments (note 11)		47,944		47,748
Current portion of long-term debt (note 7)		806,009		248,385
Current portion of in-process revenue contracts (note 5c)		12,744		12,744

Total current liabilities		1,171,545		456,256

Long-term debt (note 7)		1,562,967		1,521,247
Derivative instruments (note 11)		121,135		213,731
In-process revenue contracts (note 5c)		88,550		101,294
Other long-term liabilities		23,984		26,819

Total liabilities		2,968,181		2,319,347

Commitments and contingencies (notes 7, 8, 11 and 13)
Redeemable non-controlling interest (note 13b)		16,564		28,815
Equity
Limited partners - common units (85.5 and 80.1 million units issued and outstanding at December 31, 2013 and December 31, 2012, respectively)		621,002		640,990
Limited partners - preferred units (6.0 and nil million units issued and outstanding at December 31, 2013 and December 31, 2012, respectively) (note 15)		144,800		—
General Partner		21,242		20,162
Accumulated other comprehensive loss		—		(58	)

Partners’ equity		787,044		661,094

Non-controlling interests		34,297		44,135

Total equity		821,341		705,229

Total liabilities and total equity		3,806,086		3,053,391

Subsequent events (note 20)

The accompanying notes are an integral part of the consolidated financial statements.

F - 5

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 2)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of U.S. dollars)


Cash and cash equivalents provided by (used for)	Year Ended December 31, 2013 $			Year Ended December 31, 2012 $			Year Ended December 31, 2011 $
OPERATING ACTIVITIES
Net income (loss)		71,915			123,015			(96,871	)
Non-cash items:
Unrealized (gain) loss on derivative instruments (note 11)		(91,837	)		(39,538	)		107,860
Equity income		(6,731	)		—			—
Depreciation and amortization		200,242			194,631			187,710
Write down and loss on sale of vessels (note 18)		95,247			32,217			91,108
Deferred income tax expense (recovery) (note 12)		2,150			(8,808	)		(614	)
Amortization of in-process revenue contracts		(12,744	)		(12,714	)		(1,148	)
Foreign currency exchange (gain) loss and other		(35,522	)		15,260			3,820
Change in non-cash working capital items related to operating activities		51,999			(17,447	)		(11,296	)
Expenditures for dry docking		(19,332	)		(19,122	)		(26,407	)

Net operating cash flow		255,387			267,494			254,162

FINANCING ACTIVITIES
Proceeds from long-term debt		1,140,237			318,645			457,530
Scheduled repayments of long-term debt		(266,874	)		(146,162	)		(110,694	)
Prepayments of long-term debt		(466,781	)		(445,698	)		(125,562	)
Debt issuance costs		(14,797	)		(4,361	)		(682	)
Purchase of 49% interest in Teekay Offshore Operating L.P. (note 10c)		—			—			(386,267	)
Purchase of vessels from Teekay Corporation (note 10g and 14e)		(234,125	)		—			(60,683	)
Purchase of VOC equipment from Teekay Corporation (note 10f)		—			(12,848	)		—
Proceeds from issuance of common units (note 15)		119,588			265,393			420,146
Proceeds from issuance of preferred units (note 15)		150,000			—			—
Expenses relating to equity offerings		(5,837	)		(8,164	)		(222	)
Cash distributions paid by the Partnership		(199,892	)		(169,692	)		(166,303	)
Other		10,346			(3,120	)		8,055

Net financing cash flow		231,865			(206,007	)		35,318

INVESTING ACTIVITIES
Expenditures for vessels and equipment		(455,578	)		(87,408	)		(148,480	)
Purchase of equity investment in Itajai FPSO joint venture (net of cash acquired of $1.3 million) (note 10h and 14e)		(52,520	)		—			—
Purchase of Piranema Spirit (note 17)		—			—			(161,851	)
Proceeds from sale of vessels and equipment		27,986			35,235			13,354
Direct financing lease payments received		5,647			17,091			20,948

Net investing cash flow		(474,465	)		(35,082	)		(276,029	)

Increase in cash and cash equivalents		12,787			26,405			13,451
Cash and cash equivalents, beginning of the year		206,339			179,934			166,483

Cash and cash equivalents, end of the year		219,126			206,339			179,934

Supplemental cash flow disclosure (note 14)

The accompanying notes are an integral part of the consolidated financial statements.

F - 6

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 2)

CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL EQUITY

(in thousands of U.S. dollars and units)


	PARTNERS’ EQUITY
				Limited Partners
	Dropdown Predecessor Equity			Common Units		Common Units and Additional Paid-in Capital			Preferred Units		Preferred Units			General Partner			Accumulated Other Comprehensive Income (Loss) (Note 11)			Non- controlling Interests			Total Equity			Redeemable Non- controlling Interest
	$			#		$			#		$			$			$			$			$			$
Balance as at December 31, 2010		—			55,238		540,355			—		—			16,473			745			170,876			728,449			41,725

Net loss		(15,075	)		—		(108,646	)		—		—			4,396			—			22,454			(96,871	)		—
Reclassification of redeemable non-controlling interest in net loss		—			—		—			—		—			—			—			(6,601	)		(6,601	)		6,601
Other comprehensive (loss) income		—			—		—			—		—			—			(2,461	)		435			(2,026	)		—
Cash distributions		—			—		(121,152	)		—		—			(8,171	)		—			(26,961	)		(156,284	)		(10,019	)
Contribution of capital by joint venture partner		—			—		—			—		—			—			—			3,750			3,750			—
Proceeds from equity offering, net of offering costs (note 15)		—			15,389		411,522			—		—			8,402			—			—			419,924			—
Contribution of capital from Teekay Corporation to Rio das Ostras (note 10b)		—			—		1,960			—		—			40			—			—			2,000			—
Purchase of 49% of Teekay Offshore Operating L.P. (note 10c)		—			—		(254,237	)		—		—			(5,189	)		1,162			(128,003	)		(386,267	)		—
Conversion of intercorporate debt to equity (note 10d)		—			—		—			—		—			—			—			36,905			36,905			—
Purchase of Peary Spirit LLC (note 10d)		—			—		(5,386	)		—		—			(110	)		—			(32,233	)		(37,729	)		—
Net change in Parent’s equity in Dropdown Predecessor(note 10e)		12,519			—		—			—		—			—			—			—			12,519			—
Purchase of Scott Spirit LLC (note 10e)		2,556			—		(34,880	)		—		—			(712	)		—			—			(33,036	)		—

Balance as at December 31, 2011		—			70,627		429,536			—		—			15,129			(554	)		40,622			484,733			38,307

Net income		—			—		111,902			—		—			11,055			—			58			123,015			—
Reclassification of redeemable non-controlling interest in net income		—			—		—			—		—			—			—			4,520			4,520			(4,520	)
Other comprehensive income		—			—		—			—		—			—			496			—			496			—
Cash distributions		—			—		(149,631	)		—		—			(11,274	)		—			(3,815	)		(164,720	)		(4,972	)
Contribution of capital by joint venture partner		—			—		—			—		—			—			—			2,750			2,750			—
Proceeds from equity offering, net of offering costs (note 15)		—			9,479		251,921			—		—			5,308			—			—			257,229			—
Purchase of VOC equipment from Teekay Corporation (note 10f)		—			—		(2,738	)		—		—			(56	)		—			—			(2,794	)		—

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			—			(19,089	)		71,915			—
Reclassification of redeemable non-controlling interest in net income		—			—		—			—		—			—			—			6,391			6,391			(6,391	)
Other comprehensive income		—			—		—			—		—			—			58			—			58			—
Cash distributions		—			—		(172,150	)		—		(5,891	)		(14,101	)		—			—			(192,142	)		—
Distribution of capital to joint venture partner		—			—		—			—		—			—			—			(1,890	)		(1,890	)		(5,860	)
Contribution of capital by joint venture partner		—			—		—			—		—			—			—			4,750			4,750			—
Equity based compensation		—			—		946			—		—			—			—			—			946			—
Proceeds from equity offering, net of offering costs (note 15)		—			3,900		115,762			6,000		144,800			3,189			—			—			263,751			—
Purchase of Voyageur LLC from Teekay Corporation (note 10g)		(201,752	)		—		(76,019	)		—		—			(1,551	)		—			—			(279,322	)		—
Net proceeds from equity offering to Teekay Corporation for purchase of Voyageur LLC (note 10g)		—			1,447		44,268			—		—			—			—			—			44,268			—
Net change in Teekay Corporation’s equity in Dropdown Predecessor (note 10g)		203,977			—		—			—		—			—			—			—			203,977			—
Distribution of capital to Teekay Corporation related to acquisition of equity investment in Itajai FPSO joint venture (note 10h)		—			—		(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

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 2). As discussed in note 18, the Partnership disposed of certain conventional tankers during 2013, 2012 and 2011. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations of these conventional tankers as discontinued operations.

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, in instances in which certain redemption features that are not solely within the control of the issuer are present, classification of non-controlling interests outside of permanent equity is required. 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 13b). 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 on the Partnership’s consolidated balance sheet.

In order to more closely align the Partnership’s presentation to many of its peers, the cost of ship management services of $34.9 million for the year ended December 31, 2013 have been presented in vessel operating expenses with effect from January 1, 2013 in the Partnership’s consolidated statements of income (loss). Prior to 2013, the Partnership included these amounts in general and administrative expenses. All such costs incurred in comparative periods have been reclassified from general and administrative expenses to vessel operating expenses to conform to the presentation adopted in the current period. The amounts reclassified for the year ended December 31, 2012 and 2011 were $38.7 million and $33.5 million, respectively.

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 (loss).

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 used 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.

Time Charters, Bareboat Charters and FPSO Contracts

Operating Leases - The Partnership recognizes revenues from the time charters, bareboat charters and floating, production, storage and offloading (or FPSO) contracts accounted for as operating leases 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 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 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.

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.

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)

Cash and cash equivalents

The Partnership classifies all highly liquid investments with an original 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 off against the allowance when the Partnership believes that the receivable will not be recovered.

Investment in joint venture

This investment in a joint venture is accounted for using the equity method of accounting. Under the equity method of accounting, the investment is stated at initial cost, is adjusted for subsequent additional investments and the Partnership’s proportionate share of earnings or losses and distributions. The Partnership evaluates its investment in the joint venture for impairment when events or circumstances indicate that the carrying value of such investment may have experienced an other-than-temporary decline in value below its carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the Partnership’s consolidated statements of income (loss).

Vessels and equipment

All pre-delivery costs incurred during the construction of newbuildings, 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 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 arrives at the oil field and is in a condition that is ready to operate. Floating storage and off take (or FSO) units are depreciated over the term of the contract. Depreciation of vessels and equipment from continuing operations (including depreciation attributable to the Dropdown Predecessor) for the years ended December 31, 2013, 2012, and 2011, totalled $171.4 million, $158.0 million, and $135.4 million, respectively. Depreciation and amortization includes depreciation on all owned vessels.

Interest costs capitalized to vessels and equipment for the years ended December 31, 2013, 2012, and 2011 totaled $19.6 million, $1.5 million and $5.9 million, respectively.

Generally, the Partnership dry docks each shuttle tanker and conventional oil tanker every two and a half to five years. 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. The Partnership includes in capitalized dry docking those costs incurred as part of the dry docking to meet regulatory requirements, or expenditures that either add economic life to the vessel, increase the vessel’s earning capacity or improve the vessel’s operating efficiency. The Partnership expenses costs related to routine repairs and maintenance performed during dry docking that do not improve operating efficiency or extend the useful lives of the assets.

Dry-docking activity for the three years ended December 31, 2013, 2012, and 2011 is summarized as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
Balance at beginning of the year		45,909			60,158			71,349
Cost incurred for dry docking		19,020			19,101			24,507
Dry-docking amortization relating to continuing operations		(22,559	)		(25,267	)		(29,276	)
Dry-docking amortization relating to discontinued operations		(360	)		(2,087	)		(5,190	)
Write down / sale of capitalized dry-dock expenditure		(475	)		(5,996	)		(1,232	)

Balance at end of the year		41,535			45,909			60,158

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)

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 Partnership employs a number of vessels on long-term time charters and assembles, installs, operates and leases equipment that reduces volatile organic compound emissions (or VOC equipment) during loading, transportation and storage of oil and oil products. The long-term time charters and the leasing of some VOC equipment are accounted for as direct financing leases, with lease payments received by the Partnership being allocated between the net investment in the lease and other income 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, including fees, commissions and legal expenses, are deferred and presented as other non-current assets 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.

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 and certain types of interest rate swaps that it may enter into the future (see note 11).

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 (loss). The ineffective portion of the change in fair value of the derivative financial instruments is immediately recognized in the consolidated statements of income (loss). If a cash flow hedge is terminated and the originally hedged items 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 (loss). If the hedged items are no longer possible of occurring, amounts recognized in equity are immediately transferred to the earnings line item in the consolidated statements of income (loss).

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 gains (losses) on derivative instruments in the consolidated statements of income (loss). Gains and losses from the Partnership’s non-designated cross currency swaps are recorded in foreign currency exchange gain (loss) in the consolidated statements of income (loss).

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)

Unit-based compensation

The Partnership grants restricted unit awards as incentive-based compensation to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership. 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 (loss).

Income taxes

The Partnership’s Norwegian, Australian and Brazilian subsidiaries are subject to income taxes. 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).

Accumulated other comprehensive income (loss)

The following table contains the changes in the balance of the Partnership’s only component of accumulated other comprehensive income (loss) for the periods presented:


	Qualifying Cash
	Flow Hedging
	Instruments
	$
Balance as at December 31, 2010		745
Other comprehensive loss		(2,461	)
Purchase of 49% of Teekay Offshore Operating L.P. (or OPCO) (note 10c)		1,162

Balance as at December 31, 2011		(554	)
Other comprehensive income		496

Balance as at December 31, 2012		(58	)
Other comprehensive income		58

Balance as at December 31, 2013		—

2.	Dropdown Predecessor

The Partnership has accounted for the acquisition of interests in vessels from Teekay Corporation as a transfer of a business 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, transfers of net assets between entities under common control are accounted for as if the transfer occurred from 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 (the Scott Spirit and the Voyageur Spirit, collectively referred to herein as the Dropdown Predecessor) during the periods they were under common control of Teekay Corporation.

On May 2, 2013, the Partnership acquired from Teekay Corporation its 100% interest in Voyageur LLC, which owns the Voyageur Spirit, a FPSO unit. The Partnership’s financial statements to account for the common control transfer of the Voyageur Spirit FPSO unit decreased the Partnership’s net income and comprehensive income by $2.2 million for the year ended December 31, 2013.

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)

On October 1, 2011, the Partnership acquired from Teekay Corporation a shuttle tanker unit, the Scott Spirit. The Partnership’s financial statements to account for the common control transfer of the Scott Spirit shuttle tanker increased the Partnership’s net loss and comprehensive loss by $15.1 million for the year ended December 31, 2011.

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. This cash and cash equivalents 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 gains (losses) on derivative instruments were not identifiable as relating solely to each specific vessel. Amounts have been allocated to the Dropdown Predecessor for interest expense and realized and unrealized gains (losses) on derivative instruments for the years ended December 31, 2013 and 2011, respectively (see notes 10e and g). Management believes these allocations reasonably present the interest expense and realized and unrealized gains (losses) 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.

3.	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 - The fair value of the Partnership’s cash and cash equivalents approximate their carrying amounts reported in the accompanying consolidated balance sheets due to the current nature of the amounts.

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.

In December 2012, the Partnership determined that a shuttle tanker, Navion Norvegia, was impaired and wrote down the carrying value of this vessel to its estimated fair value of $18.0 million, due to a change in operating plan for this vessel. The Partnership used a discounted cash flow approach to value the vessel. Such a technique used estimates of future operating life (2.2 years based on the estimated remaining trading life of this vessel), future revenues ($37.2 million based on field production forecasts and the availability of contracts of affreightments suitable for the vessel), operating and dry-dock expenditures ($20.5 million), a residual value ($6.5 million based on the vessel’s light weight tonnage and the price of steel), and a discount rate (7.9%) that approximates the weighted average cost of capital of a market participant.

Contingent consideration liability – On October 1, 2011, the Partnership acquired from Teekay Corporation a newbuilding shuttle tanker, the Scott Spirit, for $116.0 million (see note 10e). The purchase price was subject to an adjustment for up to an additional $12 million based upon incremental shuttle tanker revenues above projections used for the sales price valuation generated during the two years following the acquisition. The fair value of the liability was the estimated amount that the Partnership would pay Teekay Corporation on September 30, 2012 and 2013, taking into account the Partnership’s secured contracts, new projects, and forecasted revenues. The estimated amount was the present value of the remaining future cash flows.

Changes in fair value during the year ended December 31, 2013, 2012 and 2011, for the Partnership’s contingent consideration liability, relating to the acquisition of the Scott Spirit, that is measured at fair value on a recurring basis using significant unobservable inputs (Level 3) are as follows:


	Year Ended
	December 31, 2013			December 31, 2012			December 31, 2011
	$			$			$
Balance at beginning of period		(5,681	)		(10,894	)		—
Initial liability included in Partners’ Equity		—			—			(10,082	)
Settlement of liability		6,000			5,870			—
Unrealized loss included in Other income - net		(319	)		(657	)		(812	)

Balance at end of period		—			(5,681	)		(10,894	)

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)

The estimated fair value of the Partnership’s contingent consideration liability is based in part upon the Partnership’s projection of incremental revenue secured during the period from September 1, 2011 to October 1, 2013, based primarily on the estimated number of new ship days, the daily rate for those new ship days, pursuant to new contracts, and the change in rate on existing ship days. The estimated fair value of the consideration liability as of December 31, 2012 is based upon estimated new ship days of 219 days (787 days – December 31, 2011) at an average daily hire rate of $59,255 ($53,043 – December 31, 2011) and a net increase in the daily rate of $15,532 ($nil – December 31, 2011) for 365 (nil – December 31, 2011) existing ship days. In developing and evaluating these estimates, the Partnership has used the actual number of new ship days and corresponding daily hire rate for the period subsequent to September 30, 2011, but prior to the date of valuation, forecasts for future periods and probabilities of such results, as well as the minimum (zero) and maximum ($12.0 million) payout amount as provided for in the contingent consideration formula. A different number of days, average daily hire rates, or probability of achieving these days and average daily hire rate, would result in a lower fair value liability. On October 1, 2012, the Partnership repaid a portion of the liability, which at the repayment date was $5.9 million. On October 1, 2013, the Partnership repaid the remainder of the liability, which at the repayment date was $6.0 million.

Long-term debt – The fair values of the Partnership’s variable-rate long-term debt are 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 and requires no collateral from these institutions. 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, 2013						December 31, 2012
	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		Level 1		219,126			219,126			206,339			206,339
Contingent consideration(note 10e)		Level 3		—			—			(5,681	)		(5,681	)
Derivative instruments (note 11)
Interest rate swap agreements		Level 2		(141,143	)		(141,143	)		(270,731	)		(270,731	)
Cross currency swap agreement		Level 2		(25,433	)		(25,433	)		13,435			13,435
Foreign currency forward contracts		Level 2		(842	)		(842	)		2,153			2,153
Non-Recurring:
Vessel held for sale		Level 2		—			—			13,250			13,250
Vessels and equipment (note 18)		Level 2		17,250			17,250			—			—
Vessels and equipment		Level 3		—			—			17,979			17,979
Other:
Long-term debt - public (note 7)		Level 1		(487,097	)		(496,609	)		(215,641	)		(221,086	)
Long-term debt - non-public (note 7)		Level 2		(1,881,879	)		(1,835,218	)		(1,553,991	)		(1,452,136	)

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:

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)

Credit Quality Indicator

Grade

Year Ended
December 31, 2013
$

Year Ended
December 31, 2012
$

Direct financing leases

Payment activity

Performing

27,567

33,215

4.	Segment Reporting

The Partnership is engaged in the international marine transportation of crude oil and in the offshore processing and storage of crude oil through the operation of its oil tankers, FSO units and FPSO units. The Partnership’s revenues are earned in international markets.

The Partnership has four reportable segments: its shuttle tanker segment; its FPSO segment; its conventional tanker segment; and its FSO 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 conventional tanker segment consists of conventional tankers operating on fixed-rate, time-charter contracts or bareboat charter contracts. The results below exclude seven conventional tankers as they are determined to be discontinued operations. The Partnership’s FSO segment consists of its FSO units subject to fixed-rate, time-charter contracts or bareboat charter contracts. 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.

(U.S. dollars in millions)

Year Ended
December 31,
2013

Year Ended
December 31,
2012

Year Ended
December 31,
2011

Petrobras Transporte S.A ⁽¹⁾

228.9 or 25

259.3 or 28

211.8 or 24

Statoil ASA ⁽²⁾

183.0 or 20

198.0 or 21

206.0 or 24

Talisman Energy Inc⁽³⁾

122.1 or 13

123.0 or 13

113.1 or 13

(1)

Shuttle tanker and FPSO segments

(2)

Shuttle tanker segment

(3)

FPSO segment

(4)

Shuttle tanker, conventional tanker and FSO segments

(5)

Excludes the results of seven conventional tankers as they have been determined to be discontinued operations.

The following tables include results for these segments for the periods presented in these consolidated financial statements.


Year ended December 31, 2013
	Shuttle Tanker Segment		FPSO Segment⁽²⁾		Conventional Tanker Segment		FSO Segment			Total
Revenues		552,019		284,932		34,772		59,016			930,739
Voyage expenses		99,543		—		4,532		(432	)		103,643
Vessel operating expenses		152,986		152,616		5,813		32,713			344,128
Time-charter hire expense		56,682		—		—		—			56,682
Depreciation and amortization		115,913		66,404		6,511		10,178			199,006
General and administrative ⁽¹⁾		21,821		17,742		2,357		2,553			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		15,121		14,004			103,418

Equity income		—		6,731		—		—			6,731
Investment in joint venture		—		52,120		—		—			52,120
Expenditures for vessels and equipment⁽³⁾		427,069		28,260		68		181			455,578
Expenditures for dry docking		17,487		—		1,533		—			19,020

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)


Year ended December 31, 2012
	Shuttle Tanker Segment		FPSO Segment		Conventional Tanker Segment		FSO Segment			Total
Revenues		569,519		231,688		37,119		62,901			901,227
Voyage expenses		104,394		—		5,689		400			110,483
Vessel operating expenses		160,957		111,855		6,509		38,255			317,576
Time-charter hire expense		56,989		—		—		—			56,989
Depreciation and amortization		122,921		50,905		6,500		9,038			189,364
General and administrative⁽¹⁾		20,146		11,208		1,389		1,838			34,581
Write down and loss on sale of vessels		24,542		—		—		—			24,542
Restructuring charge		647		—		468		—			1,115

Income from vessel operations		78,923		57,720		16,564		13,370			166,577

Equity income		—		—		—		—			—
Investment in joint venture		—		—		—		—			—
Expenditures for vessels and equipment		83,491		3,055		598		264			87,408
Expenditures for dry docking		14,977		—		70		4,054			19,101

Year ended December 31, 2011
	Shuttle Tanker		FPSO		Conventional Tanker		FSO
	Segment		Segment		Segment		Segment			Total
Revenues		573,296		173,836		31,119		62,731			840,982
Voyage expenses		95,864		—		332		1,388			97,584
Vessel operating expenses		186,642		82,434		6,115		32,769			307,960
Time-charter hire expense		74,478		—		—		—			74,478
Depreciation and amortization		115,637		37,496		6,588		12,009			171,730
General and administrative ⁽¹⁾		24,692		9,756		1,205		1,480			37,133
Write down and loss on sale of vessels		28,270		—		—		8,769			37,039
Restructuring charge		1,227		—		—		2,697			3,924

Income from vessel operations		46,486		44,150		16,879		3,619			111,134

Equity income		—		—		—		—			—
Investment in joint venture		—		—		—		—			—
Expenditures for vessels and equipment ⁽³⁾		130,363		16,038		2,313		(234	)		148,480
Expenditures for dry docking		16,892		—		670		6,945			24,507

(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)

Income from vessel operations for the year ended December 31, 2013 excludes $29.2 million, inclusive of the Dropdown Predecessor period, relating to the Voyageur Spirit FPSO. The unit had been declared off-hire retroactive to when it commenced production on April 13, 2013, given a delay in achieving final acceptance from the charterer, up until an interim agreement was reached with the charterer. Please read note 10g for more information. Income from vessel operations for the year ended December 31, 2013 also excludes a further $2.1 million from the Voyageur Spirit FPSO as relating to a production shortfall from August 27, 2013 to December 31, 2013. Under an interim agreement with the charterer, Teekay Corporation has indemnified the Partnership for these amounts which have effectively been treated as reductions to the purchase price of the Voyageur Spirit FPSO (see note 10g).

(3)

Excludes the purchase of the Voyageur Spirit (note 10g), the Itajai (note 10h), and the Piranema Spirit (note 17) FPSO units.

A reconciliation of total segment assets to total assets presented in the accompanying consolidated balance sheets is as follows:


	December 31, 2013		December 31, 2012
	$		$
Shuttle tanker segment		2,004,505		1,758,619
FPSO segment		1,303,229		752,835
Conventional tanker segment		144,723		178,172
FSO segment		102,452		79,629
Unallocated:
Cash and cash equivalents		219,126		206,339
Other assets		32,051		77,797

Consolidated total assets		3,806,086		3,053,391

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)

5.	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, 2013 and 2012. In 2013 and 2012, the Partnership conducted a goodwill impairment review of its shuttle tanker segment and concluded that no impairment had occurred.

Intangible Assets

As at December 31, 2013, intangible assets consisted of:


	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer contracts (shuttle tanker segment)		124,250		(114,204	)		10,046
Customer contracts (FPSO segment)		353		(353	)		—
Other intangible assets (FPSO segment)		390		—			390

		124,993		(114,557	)		10,436

As at December 31, 2012, intangible assets consisted of:


	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer contracts (shuttle tanker segment)		124,250		(109,153	)		15,097
Customer contracts (FPSO segment)		353		(313	)		40
Other intangible assets (FPSO segment)		390		—			390

		124,993		(109,466	)		15,527

Aggregate amortization expense of intangible assets for the year ended December 31, 2013 was $5.1 million (2012 - $6.0 million, 2011 - $7.1 million), included in depreciation and amortization on the consolidated statements of income (loss). Amortization of intangible assets for the five years subsequent to December 31, 2013 is expected to be $4.0 million (2014), $3.0 million (2015), $2.0 million (2016), $1.0 million (2017) and nil thereafter. Other intangible assets is a trade name which is not amortized.

In-Process Revenue Contracts

As part of the Partnership’s acquisition of the Piranema Spirit (see note 17) 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, 2013, 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, 2013 was $12.7 million (2012 - $12.7 million, 2011 - $1.1 million), which is included in revenues on the consolidated statements of income (loss). Amortization for the five years subsequent to December 31, 2013 is expected to be $12.7 million (2014), $12.7 million (2015), $12.8 million (2016), $12.7 million (2017), $9.1 million (2018) and $41.3 million (thereafter).

6.	Accrued Liabilities


	December 31, 2013 $		December 31, 2012 $
Voyage and vessel expenses		72,481		33,949
Audit, legal and other general expenses		37,473		2,134
Interest including interest rate swaps		20,185		14,713
Payroll and benefits		6,803		9,864
Income tax payable and other		1,214		1,048

		138,156		61,708

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)

7.	Long-Term Debt


	December 31, 2013 $		December 31, 2012 $
U.S. Dollar-denominated Revolving Credit Facilities due through 2018		743,494		812,509
Norwegian Kroner Bonds due through 2018		312,947		215,641
U.S. Dollar-denominated Term Loans due through 2018		188,854		213,993
U.S. Dollar-denominated Term Loans due through 2023		949,531		527,489
U.S. Dollar Bonds due through 2023		174,150		—

		2,368,976		1,769,632
Less current portion		806,009		248,385

Total		1,562,967		1,521,247

As at December 31, 2013, the Partnership had seven long-term revolving credit facilities, which, as at such date, provided for borrowings of up to $855.4 million, of which $111.9 million was undrawn. The total amount available under the revolving credit facilities reduces by $615.0 million (2014), $59.2 million (2015), $121.9 million (2016), $20.9 million (2017), and $38.4 million (2018). Five 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. Two revolving credit facilities are 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 24 of the Partnership’s vessels, together with other related security.

In January 2013, the Partnership issued in the Norwegian bond market NOK 1,300 million in senior unsecured bonds. The bonds were issued in two tranches maturing in January 2016 (NOK 500 million) and January 2018 (NOK 800 million). As at December 31, 2013, the carrying amount of the bonds was $214.1 million. The bonds are listed on the Oslo Stock Exchange. Interest payments on the tranche maturing in 2016 are 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 USD, with interest payments fixed at a rate of 4.80% on the tranche maturing in 2016 and 5.93% 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 maturing in 2016 and fixed at $143.5 million upon maturity in exchange for NOK 800 million on the tranche maturing in 2018 (see note 11).

The Partnership has NOK 600 million of senior unsecured bonds that mature in January 2017 in the Norwegian bond market. As at December 31, 2013, the carrying amount of the bonds was $98.8 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 USD, 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 11).

The Partnership had NOK 211.5 million in senior unsecured bonds that matured in November 2013 in the Norwegian bond market. The bonds were listed on the Oslo Stock Exchange. Interest payments on the bonds were based on NIBOR plus a margin of 4.75%. The Partnership entered into a cross currency swap to swap the interest payments from NIBOR plus a margin of 4.75% into LIBOR plus a margin of 5.04%, and lock in the transfer of the principal amount at $34.7 million upon maturity in exchange for NOK 211.5 million. The Partnership also entered into an interest rate swap to swap the interest payments from LIBOR to a fixed rate of 1.12%. The floating LIBOR rate receivable from the interest rate swap was capped at 3.5%, which effectively resulted in a fixed rate of 1.12% unless LIBOR exceeded 3.5%, in which case the Partnership’s related interest rate effectively floated at LIBOR, but reduced by 2.38%. In January 2013, the Partnership repurchased NOK 388.5 million of the original NOK 600 million bond issue maturing in November 2013 at a premium in connection with the issuance of NOK 1,300 million in senior unsecured bonds as described above. The Partnership recorded a $1.8 million loss on bond repurchase and $6.6 million of realized losses included in foreign currency exchange loss in its consolidated statement of income for the year ended December 31, 2013. In connection with this bond repurchase, the Partnership terminated a similar notional amount of the related cross currency swap and recorded $6.8 million of realized gains included in foreign currency exchange loss in its consolidated statement of income for the year ended December 31, 2013 (see note 11).

As at December 31, 2013, six of the Partnership’s 50% owned subsidiaries each had an outstanding term loan, which in the aggregate totaled $188.9 million. The 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 six shuttle tankers to which the loans relate, together with other related security. As at December 31, 2013, the Partnership had guaranteed $55.6 million of these term loans, which represents its 50% share of the outstanding term loans of five of these 50% owned subsidiaries. The other owner and Teekay Corporation have guaranteed $94.4 million and $38.9 million, respectively.

As at December 31, 2013, 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 and for the Rio das Ostras, the Piranema Spirit, and the Voyageur Spirit FPSO units, which in aggregate totaled $949.5 million. 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 Peary Spirit, the Scott Spirit, the Samba Spirit, the Lambada Spirit, the Rio das Ostras, the

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)

Piranema Spirit and the Voyageur Spirit term loans reduce over time with quarterly or semi-annual payments. These term loans have varying maturities through 2023 and are collateralized by first-priority mortgages on the vessels to which the loans relate, together with other related security. As at December 31, 2013, the Partnership had guaranteed $548.9 million of these term loans and Teekay Corporation had guaranteed $400.6 million.

In September 2013 and November 2013, the Partnership issued in a U.S. private placement a total of $174.2 million of ten-year senior secured bonds to finance the Bossa Nova Spirit and the Sertanejo Spirit shuttle tankers. The bonds mature in December 2023 and accrue interest at a fixed combined rate of 4.96%. As at December 31, 2013, the carrying amount of the bonds was $174.2 million. The bonds are collateralized by first-priority mortgages on the vessels to which the bonds relate, together with other related security.

Interest payments on the revolving credit facilities and the term loans are based on LIBOR plus a margin. At December 31, 2013, and December 31, 2012, 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, 2013 was 2.7% (December 31, 2012 – 2.0%). This rate does not include the effect of the Partnership’s interest rate swaps (see note 11).

The aggregate annual long-term debt principal repayments required to be made subsequent to December 31, 2013 are $806.0 million (2014), $149.8 million (2015), $309.3 million (2016), $344.2 million (2017), $348.7 million (2018) and $411.0 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 that requires the Partnership to maintain a vessel value to outstanding drawn principal balance ratio of a minimum of 105%. As at December 31, 2013, this ratio was 122.9%. The vessel value used in this ratio is the appraised values prepared by the Partnership based on second hand sale and purchase market data. A further delay in the recovery of the conventional tanker market could negatively affect this ratio.

As at December 31, 2013 the Partnership and Teekay Corporation were in compliance with all covenants in the credit facilities and long-term debt.

8.	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, 2013 were $3.5 billion, $0.8 billion and $2.7 billion, respectively. As at December 31, 2013, minimum scheduled future revenues under these time charters and bareboat charters to be received by the Partnership, then in place were approximately $3.6 billion, comprised of $652.0 million (2014), $607.6 million (2015), $517.8 million (2016), $523.2 million (2017), $344.9 million (2018) and $989.0 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, 2013, revenue from unexercised option periods of contracts that existed on December 31, 2013, or variable or contingent revenues. In addition, minimum scheduled future revenues presented in this paragraph have been reduced by estimated off-hire time for period maintenance. The amounts may vary given unscheduled future events such as vessel maintenance.

Direct Financing Lease

Leasing of certain VOC equipment is accounted for as direct financing leases. As at December 31, 2013, the minimum lease payments receivable under the direct financing leases approximated $1.0 million (2012 - $3.5 million), including unearned income of $nil (2012 - $0.2 million). As at December 31, 2013, future scheduled payments under the direct financing leases to be received by the Partnership, then in place were approximately $1.0 million, comprised of $1.0 million (2014).

Leasing of the Falcon Spirit FSO unit is accounted for as a direct financing lease. As at December 31, 2013, the minimum lease payments receivable under the direct financing lease approximated $29.9 million (2012 - $38.4 million), including unearned income of $11.8 million (2012 - $17.0 million). The estimated unguaranteed residual value of the leased vessel is $8.5 million. As at December 31, 2013, future scheduled payments under the direct financing lease to be received by the Partnership, were approximately $29.9 million, comprised of $8.6 million (2014), $8.7 million (2015), $8.8 million (2016) and $3.8 million (2017).

Charters-in

As at December 31, 2013, minimum commitments owing by the Partnership under vessel operating leases by which the Partnership charters-in vessels were approximately $33.8 million, comprised of $27.0 million (2014) and $6.8 million (2015). 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.

9.	Restructuring Charge

During the years ended December 31, 2013 and 2012, the Partnership recognized restructuring charges of $1.6 million and $0.6 million, respectively, relating to the reorganization of the Partnership’s shuttle tanker marine operations and restructuring charges of $0.4 million and $0.5 million, respectively, relating to the reorganization of the Partnership’s conventional tanker marine operations. The purpose of the

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)

restructuring is to create better alignment with its marine operations resulting in a lower cost organization going forward. Both reorganizations were completed in 2013. Under these plans, the Partnership recorded restructuring charges in total of $2.2 million and $0.9 million, respectively, since these plans began in 2012.

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.

During the year ended December 31, 2011, the Partnership incurred $3.9 million of restructuring charges related to the sale of the Karratha Spirit FSO unit and the termination of the time-charter-out contract for the Basker Spirit shuttle tanker. During the year ended December 31, 2011, the Partnership terminated the employment of certain seafarers for these two vessels.

As of December 31, 2013, 2012 and 2011, restructuring liabilities of $0.7 million, $0.3 million and $nil were recorded in accrued liabilities on the consolidated balance sheets.

10.

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, oil tankers, shuttle tankers, FSO units and FPSO units.

On October 1, 2010, the Partnership acquired from Teekay Corporation the Rio das Ostras FPSO unit, which is on a long-term charter to Petroleo Brasileiro SA (or Petrobras), for a purchase price of $157.7 million, plus working capital of $12.4 million. The purchase agreement provides that Teekay Corporation shall reimburse the Partnership for upgrade costs in excess of the upgrade estimate as of the closing date. During the year ended December 31, 2011, Teekay Corporation reimbursed the Partnership for $2.0 million of such upgrade costs, which is reflected as a capital contribution.

On March 8, 2011, the Partnership acquired Teekay Corporation’s 49% interest in OPCO for a combination of $175 million in cash (less $15 million in distributions made by OPCO to Teekay Corporation between December 31, 2010 and the date of acquisition) and the issuance of 7.6 million of the Partnership’s common units to Teekay Corporation and a 2% proportionate interest to the General Partner in a private placement (see note 15). The acquisition increased the Partnership’s ownership of OPCO to 100%. The excess of the proceeds paid by the Partnership over Teekay Corporation’s historical book value of $128.0 million for the 49% interest in OPCO was accounted for as an equity distribution to Teekay Corporation of $258.3 million.

On August 2, 2011, the Partnership acquired from Teekay Corporation the Peary Spirit for a purchase price of $134.5 million. The purchase price was financed through the assumption of debt of $96.8 million and $37.7 million with cash. The excess of $5.5 million of the cash portion of the purchase price over the book value of the net assets of $32.2 million is accounted for as an equity distribution to Teekay Corporation. Immediately prior to the acquisition, $36.9 million of amounts due to Teekay Corporation by Peary Spirit LLC was converted to equity of the vessel entity. For the period October 1, 2010 to August 2, 2011, the Partnership consolidated Peary Spirit LLC on its financial statements as it was considered a variable interest entity and the Partnership was the primary beneficiary.

On October 1, 2011, the Partnership acquired from Teekay Corporation a newbuilding shuttle tanker, the Scott Spirit, for $116.0 million. The purchase price was subject to an adjustment for up to an additional $12 million based upon incremental shuttle tanker revenues above projections used for the sales price valuation generated during the two years following the acquisition. On October 1, 2012, the Partnership repaid a portion of the liability, which at the repayment date was $5.9 million. As at December 31, 2012, the outstanding liability was $5.7 million, which was included in due to affiliates. The remaining liability was settled as of the year end of December 31, 2013. The purchase price was financed through the assumption of debt of $93.3 million and $23.0 million with cash. The excess of $35.6 million of the purchase price over the book value of the net liabilities of $2.6 million, which includes the fair value of an interest rate swap of ($34.6) million, was accounted for as an equity distribution to Teekay Corporation. Immediately prior to the acquisition, $34.5 million of amounts due to Teekay Corporation by Scott Spirit LLC was converted to equity.

The following costs attributable to the operations of the Scott Spirit were incurred by Teekay Corporation, and have been allocated to the Partnership as part of the results of the Dropdown Predecessor:

•

Vessel operating expenses (consisting primarily of vessel management fees) and general and administrative expenses of $0.1 million and $0.1 million, respectively, for the year ended December 31, 2011.

•

Interest expense incurred by Teekay Corporation on its credit facilities that were used to finance the acquisition of the Scott Spirit of $0.3 million for the year ended December 31, 2011.

•

Teekay Corporation entered into an interest rate swap to offset increases or decreases in the variable-rate interest payments of the credit facilities that were used to finance the acquisition of the Scott Spirit. The unrealized loss on this interest rate swap allocated to the Partnership is $12.2 million for the year ended December 31, 2011. This amount is reflected in realized and unrealized gain (loss) on derivative instruments.

On October 1, 2012, the Partnership acquired from Teekay Corporation the VOC equipment on board the Amundsen Spirit, the Nansen Spirit, the Peary Spirit and the Scott Spirit for $12.8 million. On December 31, 2012, the Partnership recognized this liability in due to affiliates. The purchase price was financed with cash. The excess of $2.8 million of the purchase price over the net carrying value of the equipment is accounted for as an equity distribution to Teekay Corporation.

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)

On May 2, 2013, the Partnership acquired from Teekay Corporation its 100% interest in Voyageur LLC, 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. The purchase price was financed with the assumption of the $230.0 million debt facility secured by the unit, $270.0 million with cash, of which a partial prepayment of $150.0 million was made to Teekay Corporation in February 2013, and the non-cash issuance of 1.4 million common units to Teekay Corporation, which had a value of $40.0 million at the time Teekay Corporation offered to sell the unit to the Partnership.

Interest expense incurred by Teekay Corporation on its credit facilities that were used to finance the acquisition of the Voyageur Spirit of $0.3 million for the year ended December 31, 2013 has been allocated to the Partnership as part of the results of the Dropdown Predecessor.

On April 13, 2013, the Voyageur Spirit FPSO unit began production and on May 2, 2013, the Partnership acquired the unit from Teekay Corporation. Upon commencing production, the Partnership and its sponsor, Teekay Corporation, had a specified time period to receive final acceptance from the charterer, at which point the unit would commence full operations under the contract with E.ON. 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. This resulted in $29.2 million of the charter rate being foregone for the year ended December 31, 2013, inclusive of both the Dropdown Predecessor period from April 13, 2013 to May 1, 2013 and the period owned by the Partnership from May 2, 2013 to August 26, 2013.

On August 27, 2013, repairs to the defective gas compressor on the Voyageur Spirit FPSO were completed and the unit achieved full production capacity. 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 through until the receipt of final acceptance by E.ON. Compensation was based on actual production relative to the operating capacity of the FPSO unit; however, any restrictions on production as a result of the charterer were included in this compensation. Teekay Corporation has indemnified the Partnership for a further $2.1 million for the production shortfall from August 27, 2013 to December 31, 2013. In addition, the Partnership has been indemnified for a further $3.6 million associated with unrecovered repair costs to address the compressor issues. Teekay Corporation’s indemnification to the Partnership for loss of the charter rate under the charter agreement with E.ON and certain unrecovered vessel operating expenses from the date of first oil on April 13, 2013 until receipt of the certificate of final acceptance from E.ON, is subject to a maximum of $54 million.

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.

Any 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. Any future compensation received by the Partnership from the charterer related to the indemnification period will reduce the amount of Teekay Corporation’s indemnification to the Partnership. As at December 31, 2013, the $540.0 million original purchase price of the Voyageur Spirit FPSO unit has effectively been reduced to $509.3 million ($279.3 million net of assumed debt of $230.0 million) to reflect the $34.9 million indemnification amount for the last three quarters of 2013, partially offset by the excess value of $4.3 million relating to the 1.4 million common units issued to Teekay Corporation on the date of closing of the transaction in May 2013 compared to the date Teekay Corporation offered to sell the 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 is accounted for as an equity distribution to Teekay Corporation of $77.6 million.

The Itajai FPSO unit achieved first oil in February 2013, at which time the unit commenced operations under a nine-year, fixed-rate time-charter contract with Petrobras, with six additional one-year extension options exercisable by Petrobras. On June 10, 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, for a purchase price of $53.8 million. The joint venture is a borrower under a term loan which at the time Teekay Corporation offered to sell its interest in the joint venture, had an outstanding balance of $300.0 million. Prior to finalizing the purchase, the joint venture repaid $10.5 million of its originally drawn down debt and as a result, the joint venture’s outstanding debt was $289.5 million as of the purchase date. The purchase price was paid in cash. The excess of the purchase price over Teekay Corporation’s carrying value of its 50% interest in the Itajai FPSO has been accounted for as an equity distribution to Teekay Corporation of $6.6 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, including certain outstanding contractual items. To the extent the resolution of the outstanding contractual items results in a change to the fully built-up cost, the Partnership will not be exposed to changes in the fully built-up cost.

In June 2011, the Partnership entered into a new long-term contract with a subsidiary of BG Group plc (or BG) to provide shuttle tanker services in Brazil. The contract with BG is serviced with four newbuilding shuttle tankers (or the BG Shuttle Tankers) under ten-year time charter contracts. The Partnership took delivery of the four BG Shuttle Tankers in the second half of 2013. The Partnership received shipbuilding and site supervision services from certain subsidiaries of Teekay Corporation relating to BG Shuttle Tankers. These costs were originally capitalized and included as part of advances on newbuilding contracts. Upon delivery of the vessels, these costs were reclassified to vessels and equipment. As at December 31, 2013 and December 31, 2012, shipbuilding and site supervision costs provided by Teekay Corporation subsidiaries totaled $14.2 million and $2.8 million, respectively.

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)

During the year ended, December 31, 2013, two conventional tankers, two shuttle tankers and two FSO units of the Partnership were employed on long-term time-charter-out contracts with subsidiaries of Teekay Corporation, and two conventional tankers of the Partnership were employed on long-term time-charter-out contracts with a joint venture in which Teekay Corporation has a 50% interest. During the years ended December 31, 2013 and 2012, the Partnership terminated the long-term time-charter-out contracts employed by three of its conventional tankers with a subsidiary of Teekay Corporation. In 2013 and 2012, the Partnership received early termination fees from Teekay Corporation of $11.3 million and $14.7 million, respectively, which is recorded in net income (loss) from discontinued operations on the consolidated statements of income (loss). Teekay Corporation and its wholly owned subsidiaries provide substantially all of the Partnership’s commercial, technical, crew training, strategic, business development and administrative services 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,
	2013			2012			2011
	$			$			$
Revenues⁽¹⁾		71,905			64,166			62,233
Vessel operating expenses⁽²⁾		(39,820	)		(44,024	)		(38,760	)
General and administrative⁽³⁾⁽⁴⁾		(29,528	)		(21,184	)		(26,660	)
Interest income⁽⁵⁾		1,217			—			—
Interest expense⁽⁶⁾		(450	)		(392	)		(316	)
Realized and unrealized loss on derivative instruments⁽⁷⁾		—			—			(12,186	)
Other expense⁽⁸⁾		(319	)		(657	)		(812	)
Net income from related party transactions from discontinued operations⁽⁹⁾		19,255			59,872			106,483

(1)

Includes revenue from long-term time-charter-out contracts and short-term time-charter-out 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.

(2)

Includes ship management and crew training services provided by Teekay Corporation. The cost of ship management services provided by Teekay Corporation of $34.9 million for the year ended December 31, 2013, have been presented as vessel operating expenses (see note 1). The amounts reclassified from general and administrative to vessel operating expenses in the comparative periods to conform to the presentation adopted in the current periods were $38.7 million and $33.5 million for the years ended December 31, 2012 and 2011, respectively.

(3)

Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and reimbursements to Teekay Corporation and our General Partner for costs incurred on the Partnership’s behalf.

(4)

(5)

Includes interest income related to the interest received from Teekay Corporation on the $150 million prepayment for the Voyageur Spirit. 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)

Guarantee fee related to the final bullet payment of the Piranema Spirit FPSO debt facility guaranteed by Teekay Corporation for 2011 through 2013 and interest allocated from Teekay Corporation as a result of the Dropdown Predecessor during the year ended December 31, 2011.

(7)

Realized and unrealized losses on interest rate swaps allocated from Teekay Corporation as a result of the Dropdown Predecessor.

(8)

Unrealized loss from the change in fair value of the Partnership’s contingent consideration liability relating to the acquisition of the Scott Spirit (see note 3a).

(9)

11.

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, these foreign currency forward contracts as cash flow hedges.

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)

As at December 31, 2013, 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

Average
Forward
Rate⁽¹⁾

Expected Maturity

2014

2015

(in thousands of U.S. Dollars)

Norwegian Kroner

333,000

(842)

6.02

49,563

5,764

(1)

Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

The Partnership enters into cross currency swaps and pursuant to these swaps the Partnership receives the principal amount in Norwegian Kroner (or 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 Norwegian Kroner Bonds due through 2018. In addition, the cross currency swaps due from 2016 through 2018 economically hedge the interest rate exposure on the Norwegian Kroner Bonds due in 2016 through 2018. The Partnership has not designated, for accounting purposes, these cross currency swaps as cash flow hedges of its Norwegian Kroner Bonds due through 2018. As at December 31, 2013, the Partnership was committed to the following cross currency swaps:


Principal Amount NOK	Principal Amount USD		Floating Rate Receivable								Fair Value / Asset (Liability)
			Reference Rate		Margin			Fixed Rate Payable						Remaining Term (years)
			Reference Rate		Margin			Fixed Rate Payable						Remaining Term (years)
600,000		101,351		NIBOR		5.75	%		7.49	%		(5,503	)		3.1
500,000		89,710		NIBOR		4.00	%		4.80	%		(8,185	)		2.1
800,000		143,536		NIBOR		4.75	%		5.93	%		(11,745	)		4.1

												(25,433	)

Interest Rate Risk

The Partnership enters into interest rate swaps, which exchange a receipt of floating interest for a payment of fixed interest to reduce the Partnership’s exposure to interest rate variability on its outstanding floating-rate debt. The Partnership has not designated, for accounting purposes, its interest rate swaps as cash flow hedges of its USD LIBOR denominated borrowings.

As at December 31, 2013, 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)		Fixed Interest Rate (%)⁽¹⁾
U.S. Dollar-denominated interest rate swaps⁽²⁾		LIBOR		800,000		(103,818	)		8.9		4.7
U.S. Dollar-denominated interest rate swaps⁽³⁾		LIBOR		934,189		(37,325	)		6.0		2.7

				1,734,189		(141,143	)

(1)

Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2013, ranged from 0.30% and 3.25%.

(2)

Notional amount remains constant over the term of the swap.

(3)

Notional amount reduces quarterly or semi-annually.

As at December 31, 2013, 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, 2013, these interest rate swaps and cross currency swaps had an aggregate fair value asset amount of $4.0 million and an aggregate fair value liability amount of $151.7 million.

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)

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.


	Accounts Receivable		Current portion of derivative assets		Derivative assets		Accrued liabilities			Current portion of derivative liabilities			Derivative liabilities
	$		$		$		$			$			$
As at December 31, 2013
Foreign currency contracts		—		213		4		—			(976	)		(83	)
Cross currency swap		12		287		—		—			(311	)		(25,421	)
Interest rate swaps		—		—		10,319		(9,174	)		(46,657	)		(95,631	)

		12		500		10,323		(9,174	)		(47,944	)		(121,135	)

As at December 31, 2012
Foreign currency contracts		—		2,160		—		—			(7	)		—
Cross currency swap		284		10,238		2,913		—			—			—
Interest rate swaps		—		—		—		(9,259	)		(47,741	)		(213,731	)

		284		12,398		2,913		(9,259	)		(47,748	)		(213,731	)

For the periods indicated, the following table presents the effective portion of gains (losses) on foreign currency forward contracts designated and qualifying as cash flow hedges that were (1) recognized in other comprehensive income (loss), (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) gains on derivative instruments designated and qualifying as cash flow hedges.


		Year Ended December 31, 2013								Year Ended December 31, 2012
Balance Sheet (AOCI)		Statement of Income						Balance Sheet (AOCI)		Statement of Income
	Effective Portion		Effective Portion		Ineffective Portion				Effective Portion		Effective Portion	Ineffective Portion
	$		$		$				$		$	$
	6		—		—		Vessel operating expenses		713		—	—		Vessel operating expenses
			(52	)	(59	)	General and administrative expenses				217	(440	)	General and administrative expenses

	6		(52	)	(59	)			713		217	(440	)


		Year Ended December 31, 2011
Balance Sheet (AOCI)		Statement of Loss
Effective Portion		Effective Portion		Ineffective Portion
$		$		$
	319		833		(300	)	Vessel operating expenses
			1,512		(6	)	General and administrative expenses

	319		2,345		(306	)

Realized and unrealized gains (losses) 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 gains (losses) on derivative instruments in

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)

the consolidated statements of income (loss). The effect of the gains (losses) on these derivatives on the consolidated statements of income (loss) for the years ended 2013, 2012, and 2011 is as follows:


	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
Realized (losses) gains relating to:
Interest rate swap termination		(31,798	)		—			—
Interest rate swaps		(63,050	)		(58,596	)		(58,475	)
Foreign currency forward contracts		(824	)		2,969			4,704

		(95,672	)		(55,627	)		(53,771	)

Unrealized gains (losses) relating to:
Interest rate swaps		133,488			26,100			(100,306	)
Foreign currency forward contracts		(2,996	)		3,178			(5,667	)

		130,492			29,278			(105,973	)

Total realized and unrealized gains (losses) on derivative instruments		34,820			(26,349	)		(159,744	)

Realized and unrealized (losses) gains of the cross currency swaps are recognized in earnings and reported, including the impact of the partial termination of a cross currency swap, in foreign currency exchange (loss) gain in the consolidated statements of income (loss). The effect of the (loss) gain on cross currency swaps on the consolidated statements of income (loss) for the years ended 2013, 2012, and 2011 is as follows:


	Year ended			Year ended		Year ended
	December 31,			December 31,		December 31,
	2013			2012		2011
	$			$		$
Realized gain on partial termination of cross- currency swap		6,800			—		—
Realized gains		1,563			2,992		2,881
Unrealized (losses) gains		(38,596	)		10,700		(1,581	)

Total realized and unrealized (losses) gains on cross currency swaps		(30,233	)		13,692		1,300

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)

12.

Income Taxes

The significant components of the Partnership’s deferred tax assets and liabilities are as follows:


	December 31, 2013			December 31, 2012
	$			$
Deferred tax assets:
Tax losses carried forward⁽¹⁾		182,085			197,912
Provisions		1,548			2,045
Other		5,748			8,129

Total deferred tax assets:		189,381			208,086

Deferred tax liabilities:
Vessels and equipment		19,555			26,503
Long-term debt		22,008			33,764
Other		3,234			3,792

Total deferred tax liabilities		44,797			64,059

Net deferred tax assets		144,584			144,027

Valuation allowance		(136,730	)		(135,079	)

Net deferred tax assets⁽²⁾		7,854			8,948

Disclosed in:

Deferred tax asset		7,854			8,948

(1)

The net operating losses carried forward of $689.1 million are available to offset future taxable income in the applicable jurisdictions, and can be carried forward indefinitely.

(2)

The change in the net deferred tax assets is related to the change in temporary differences and foreign exchange gains.

The components of the provision for income taxes are as follows:


	Year ended			Year ended		Year ended
	December 31,			December 31,		December 31,
	2013			2012		2011
	$			$		$
Current		(75	)		1,669		(7,293	)
Deferred		(2,150	)		8,808		614

Income tax (expense) recovery		(2,225	)		10,477		(6,679	)

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:

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)


	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
Net income (loss) before taxes		78,782			94,970			(78,697	)
Net income (loss) not subject to taxes		41,100			77,570			(102,756	)

Net income subject to taxes		37,682			17,400			24,059

At applicable statutory tax rates		2,559			(6,292	)		6,812
Permanent differences		(3,619	)		(12,245	)		(11,444	)
Adjustments related to currency differences		(14,231	)		6,476			(14,044	)
Temporary differences for which no deferred tax asset was recognized		1,758			23			705
Valuation allowance		15,758			1,600			24,673
Prior year current taxes accrued		—			(39	)		(23	)

Tax expense (recovery) related to current year		2,225			(10,477	)		6,679

The following is a tabular reconciliation of the Partnership’s total amount of unrecognized tax benefits at the beginning and end of 2013, 2012, and 2011:


	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
Balance of unrecognized tax benefits as at beginning of the year		3,692			6,231			5,929
Decreases for positions related to prior years		(336	)		(2,539	)		(122	)
Increases for positions related to the current year		—			—			424
Increase for positions attributable to the Dropdown Predecessor		3,681			—			—

Balance of unrecognized tax benefits as at end of the year		7,037			3,692			6,231

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 2009 through 2013 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.

13.

Commitments and Contingencies

On November 13, 2006, one of the Partnership’s shuttle tankers, the Navion Hispania, collided with the Njord Bravo, an FSO unit, while preparing to load an oil cargo from the Njord Bravo. The Njord Bravo services the Njord field, which is operated by Statoil Petroleum AS (or Statoil) and is located off the Norwegian coast. At the time of the incident, Statoil was chartering the Navion Hispania from the Partnership. The Navion Hispania and the Njord Bravo both incurred damage as a result of the collision. In November 2007, Navion Offshore Loading AS (or NOL) and Teekay Navion Offshore Loading Pte Ltd. (or TNOL), subsidiaries of the Partnership, and Teekay Shipping Norway AS (or TSN), a subsidiary of Teekay Corporation, were named as co-defendants in a legal action filed by Norwegian Hull Club (the hull and machinery insurers of the Njord Bravo), several other insurance underwriters and various licensees in the Njord field. The Plaintiffs sought damages for vessel repairs, expenses for a replacement vessel and other amounts related to production stoppage on the field, totaling NOK 213,000,000 (approximately $35.1 million).

In December 2011, the Stavanger District Court ruling in the first instance found that NOL was liable for damages except for damages related to certain indirect or consequential losses. The court also found that Statoil ASA was liable to NOL for the same amount of damages to NOL. As a result of this ruling, as at December 31, 2012, the Partnership reported a liability in the total amount of NOK 76,000,000 (approximately $12.5 million) to the Plaintiffs and a corresponding receivable from Statoil ASA recorded in other long-term liabilities and other assets, respectively.

The Plaintiffs appealed the decision and the appellate court in June 2013 held that NOL, TNOL and TSN are jointly and severally responsible towards the Plaintiffs for all the losses as a result of the collision, plus interests accrued on the amount of damages. In addition, Statoil ASA was held not to be under an obligation to indemnify NOL, TNOL and TSN for the losses. NOL, TNOL and TSN were

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)

also held liable for legal costs associated with court proceedings. As a result of this judgment, in the second quarter of 2013, the Partnership recognized a liability in the amount of NOK 213,000,000 in respect of damages, NOK 66,000,000 in respect of interest and NOK 11,000,000 in respect of legal costs, totaling NOK 290,000,000 (approximately $47.8 million), to the Plaintiffs recorded in accrued liabilities. The receivable from Statoil ASA previously recorded in other assets was reversed in the second quarter of 2013. In the fourth quarter of 2013, the Partnership recognized an additional liability of NOK 4,000,000 in respect of interest, bringing the total liability to NOK 294,000,000 (approximately $48.4 million). The judgment rendered deals with liability only and the ultimate amount of damages may be reduced compared to the NOK 213,000,000 claimed by the Plaintiffs.

The Partnership and Teekay Corporation maintain protection and indemnity insurance for damages to the Navion Hispania and insurance for collision-related costs and claims. These insurance policies are expected to cover the costs related to this incident, including any costs not indemnified by Statoil, and thus a receivable of NOK 294,000,000 (approximately $48.4 million) was concurrently recorded in accounts receivable, which equals the total cost of the claim. In addition, Teekay Corporation has agreed to indemnify the Partnership for any losses it may incur in connection with this incident.

In the fourth quarter of 2013, the insurer made payments directly to the Plaintiffs in full settlement of interest and partial settlement of legal costs and thus the Partnership, as at December 31, 2013, reduced its liability and related receivable to NOK 213,000,000 in respect of damages and approximately NOK 3,400,000 in respect of legal costs, totaling approximately NOK 216,400,000 (approximately $35.6 million).

During 2010, an unrelated party contributed the Randgrid 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, 2013.

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 will be converted from the 1995-built shuttle tanker, the Randgrid, which the Partnership currently owns through a 67% owned subsidiary and will acquire full ownership of the vessel prior to its conversion. The FSO conversion project is expected to cost approximately $260 million, including amounts reimbursable upon delivery of the unit relating to installation and mobilization costs, and the cost of acquiring the remaining 33% ownership interest in the Randgrid shuttle tanker. Following scheduled completion 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 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 is converting its 1993-built shuttle tanker, the Navion Clipper, into an FSO unit for an estimated fully built-up cost of approximately $51 million. As at December 31, 2013, payments made towards this commitment totaled $21.1 million. The unit is expected to commence its charter contract with Salamander in the third quarter of 2014.

14.

Supplemental Cash Flow Information

The changes in non-cash working capital items related to operating activities for the years ended December 31, 2013, 2012, and 2011 are as follows:


	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
Accounts receivable		(59,003	)		(8,750	)		(13,788	)
Prepaid expenses and other assets		(2,884	)		6,075			(6,139	)
Accounts payable and accrued liabilities		46,266			35			(8,716	)
Advances from (to) affiliate		67,620			(14,807	)		17,347

		51,999			(17,447	)		(11,296	)

Cash interest paid (including interest paid by the Dropdown Predecessor and realized losses on interest rate swaps) during the years ended December 31, 2013, 2012, and 2011 totaled $146.0 million, $102.1 million, and $91.1 million, respectively.

Taxes paid (including taxes paid by the Dropdown Predecessor) during the years ended December 31, 2013, 2012, and 2011 totaled $0.6 million, $5.7 million and $4.8 million, respectively.

The Partnership’s consolidated statement of cash flows for the years ended December 31, 2013 and 2012 reflects the Dropdown Predecessor as if the Partnership had acquired the Dropdown Predecessor when the vessels began operations under the ownership of Teekay Corporation. For non-cash changes related to the Dropdown Predecessor, see note 10.

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)

The cash portion of the purchase price of vessels acquired from Teekay Corporation is as follows:


	Year ended			Year ended		Year ended
	December 31,			December 31,		December 31,
	2013			2012		2011
	$			$		$
Voyageur Spirit (net of cash acquired of $0.9 million)⁽¹⁾ (note 10g)		(234,125	)		—		—
Cidade de Itajai (net of cash acquired of $1.3 million) (note 10h)		(52,520	)		—		—
Peary Spirit (note 10d)		—			—		(37,729	)
Scott Spirit (note 10e)		—			—		(22,954	)

		(286,645	)		—		(60,683	)

(1)

As at December 31, 2013, the cash portion of the original purchase price of the Voyageur Spirit FPSO of $270.0 million was effectively reduced to reflect the $34.9 million indemnification from Teekay Corporation recorded during 2013 (see note 10g).

Contribution of capital from Teekay Corporation to the Dropdown Predecessor included in other financing activities on the consolidated statements of cash flows is as follows:


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2013		2012		2011
	$		$		$
Relating to Voyageur Spirit (note 10g)		5,596		—		—
Relating to Scott Spirit (note 10e)		—		—		2,305

		5,596		—		2,305

15.

Partners’ Equity and Net Income (Loss) Per Unit

At December 31, 2013, 72.1% 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 preferred units outstanding were held by the public.

Limited Partners’ Rights

Significant rights of the limited partners include the following:

•

Right to receive distribution of available cash 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 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 unitholders with respect to any quarter exceeds specified target levels shown below:


Quarterly Distribution Target Amount (per unit)	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 the year ended December 31, 2013, cash distributions exceeded $0.4025 per unit and, 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 unit calculation.

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TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data or unless otherwise indicated)

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the 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 (Loss) Per Unit

Limited partners’ interest in net income (loss) per common unit – basic is determined by dividing net income (loss), after deducting the amount of net loss attributable to the Dropdown Predecessor, the non-controlling interests and the General Partner’s interest and the distributions on the Series A preferred units, by the weighted-average number of common units outstanding during the period. The accumulated distributions on the preferred units for the year ended December 31, 2013 was $7.3 million. The computation of limited partners’ interest in net income (loss) per common unit – diluted assumes the exercise of all dilutive restricted units using the treasury stock method. The computation of limited partners’ interest in net loss per common unit – diluted does not assume such exercises as the effect would be anti-dilutive.

The General Partner’s and common unitholders’ interests in net income (loss) are calculated as if all net income (loss) was distributed according to the terms of the Partnership’s partnership agreement, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net income (loss); rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter less 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 and anticipated capital requirements and any accumulated distributions on the Series A Preferred Units (defined below). 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.

The Partnership allocates the limited partners’ interest in net income (loss), including both distributed and undistributed net income (loss), between continuing operations and discontinued operations based on the proportion of net income (loss) from continuing and discontinued operations to total net income (loss).

Preferred Units

In April 2013, the Partnership issued 6.0 million 7.25% Series A Cumulative Redeemable Preferred Units (or Series A Preferred Units) in a public offering for net proceeds of $144.8 million. The Partnership used a portion of the net proceeds from the public offering to prepay a portion of its outstanding debt on three of its revolving credit facilities and to partially finance the purchase of the Voyageur Spirit FPSO unit and the Partnership’s interest in the Itajai FPSO unit, and used the remainder for general partnership purposes.

Pursuant to the partnership agreement, distributions on the Series A Preferred units to preferred unitholders are cumulative from the date of original issue and will be 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.

Public and Private Offerings of Common Units

The following table summarizes the issuances of common units over the three years ending December 31, 2013:


Date	Offering Type		Number of Common Units Issued		Offering Price			Gross Proceeds ⁽ⁱ⁾		Net Proceeds		Teekay Corporation’s Ownership After the Offering⁽ⁱⁱ⁾			Use of Proceeds



								(in millions of U.S. Dollars)
March 2011		Private		7,562,814	$	29.32			226.3		226.3		36.90	%	Consideration for acquisition of remaining 49% in OPCO
July 2011		Private		713,266	$	28.04			20.4		20.4		36.51	%	Partially finance shipyard installments for
															four newbuilding shuttle tankers
November 2011		Private		7,112,974	$	23.90			173.5		173.2		33.03	%	Finance the purchase of the Piranema Spirit FPSO unit
July 2012		Private		1,700,022	$	26.47			45.9		45.8		32.30	%	Partially finance shipyard installments for four newbuilding shuttle tankers
September 2012		Public		7,778,832	$	27.65			219.5		211.4		29.36	%	Prepayment of revolving credit facilities
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
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 may include funding vessel conversion projects and future vessel acquisitions.

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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)

(i)

Including 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 up to a maximum aggregate amount of $100 million.

16.

Unit Based Compensation

For the year ended December 31, 2013, 8,307 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 2013.

During March 2013, the Partnership granted 63,309 restricted units with a fair value of $1.8 million, based on the Partnership’s closing unit price on the grant date. Each restricted unit is equal in value to one unit of the Partnership’s common units plus reinvested distributions from the grant date to the vesting date. The restricted units vest equally over three years 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. During the year ended December 31, 2013, the Partnership recorded a unit based compensation expense of $0.9 million in the Partnership’s consolidated statement of income (loss).

17.

Acquisition of Piranema Spirit

On November 30, 2011, the Partnership acquired a 100% of the shares of Piranema Production AS from Sevan Marine ASA for a total purchase price of $164.3 million. The purchase price was paid in cash and was financed through the concurrent issuance of 7.1 million common units. Piranema Production AS owns the 2007-built Piranema Spirit FPSO unit, which is operating under a long-term charter, with cost escalation clauses, to Petrobras on the Piranema field located offshore Brazil. The firm period of the charter expires in March 2018, however Petrobras has up to 11 one-year extension options.

The acquisition of the Piranema Spirit FPSO unit was accounted for using the purchase method of accounting, based upon estimates of fair value. The purchase price allocation adjustments were finalized in late 2012 and there were no changes to the preliminary fair values of the assets acquired and liabilities assumed by the Partnership. Operating results of the Piranema Spirit FPSO unit are reflected in these financial statements commencing November 30, 2011, the effective date of acquisition. During December 2011, the Partnership recognized $4.8 million of revenue and $1.5 million of net income resulting from its acquisition of the Piranema Spirit.

The following table summarizes the fair values of the assets acquired and liabilities assumed by the Partnership.


*(in thousands of U.S. dollars)*	As at November 30,
	2011
	$
ASSETS
Cash and cash equivalents		2,439
Other current assets		5,308
Vessels and equipment		292,242
Other assets - long-term		659

Total assets acquired		300,648

LIABILITIES
Current liabilities		8,458
In-process revenue contracts		127,900

Total liabilities assumed		136,358

Net assets acquired		164,290

Cash consideration		164,290

Net cash consideration		161,851

F - 30

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data or unless otherwise indicated)

The following table shows comparative summarized consolidated pro forma financial information for the Partnership for the year ended December 31, 2011, giving effect to the acquisition of a 100% interest in the Piranema Spirit FPSO unit as if it had taken place on January 1, 2010:


*(in thousands of U.S. dollars, except per unit data)*	Pro Forma Year ended December 31, 2011 (unaudited) $
Revenues		892,130
Net loss		(98,030	)
Limited partners’ interest in net loss per common unit- basic		(1.60	)
Limited partners’ interest in net loss per common unit- diluted		(1.60	)

18.

Write down and Loss on Sale of Vessels and Discontinued Operations

In 2013, the carrying value of six of the Partnership’s 1990s-built shuttle tankers were written down to their estimated fair value using appraised values. Of these 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 at lower rates than expected during the third quarter of 2013, the cancellation of a short-term contract which occurred 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 one in the North Sea. The Partnership’s consolidated statement of income for 2013 includes a $76.8 million write-down related to these vessels of which $37.2 million relates to two shuttle tankers which the Partnership owns through a 50%-owned subsidiary. In the fourth quarter of 2013, two shuttle tankers 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 write-down amounted to $19.3 million. These two vessels are owned through a 67%-owned subsidiary.

In 2012, the carrying value of five of the Partnership’s shuttle tankers were written down to their estimated fair value. In the third quarter of 2012, a 1993-built shuttle tanker was written down to its estimated fair value due to a change in the operating plan for the vessel. In the third and fourth quarters of 2012, two shuttle tankers, which were written down in 2011, were further written down to their estimated fair value upon sale in 2012. In the fourth quarter of 2012, a 1992-built shuttle tanker, which was written down in 2010, was further written down to its estimated fair value and classified as held-for-sale at December 31, 2012. The vessel was sold in 2013. In the fourth quarter of 2012, a 1995-built shuttle tanker was written down to its estimated fair value using discounted cash flows. The write-down was caused by the combination of the age of the vessel, the requirements of trading in the North Sea and Brazil and the weak tanker market. The estimated fair value for each of the other four vessels written down in 2012 was determined using appraised values.

In 2011, the carrying value of three of the Partnership’s older shuttle tankers were written down to their estimated fair value. The write-down was caused by the combination of the age of the vessels, the requirements of trading in the North Sea and Brazil and the weak tanker market. In 2011, two of the Partnership’s FSO units, were written down to their estimated fair value. The Karratha Spirit was sold and the Navion Saga was written down due to escalating dry-dock costs and increased operating costs. The estimated fair value of the Navion Saga was determined using discounted cash flows. The estimated fair value for each of the other four vessels written down in 2011 was determined using appraised values.

The operations of the Scotia Spirit, the Hamane Spirit, the Torben Spirit, the Luzon Spirit, the Leyte Spirit, the Poul Spirit and the Gotland Spirit prior to being considered discontinued operations, were reported within the conventional tanker segment. In 2011, the carrying value of five of the Partnership’s conventional crude oil tankers were written down to their estimated fair value. In 2011, the charter contract of the Scotia Spirit was terminated and the vessel was sold. Prior to the sale, the vessel was classified as held-for-sale. The Hamane Spirit, the Torben Spirit, the Luzon Spirit and the Leyte Spirit, vessels were sold in the second quarter of 2012, the fourth quarter of 2012, the fourth quarter of 2012, and the first quarter of 2013, respectively. 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.

In the second quarter and first quarter of 2013 and the second quarter of 2012, the Partnership terminated the long-term time-charter-out contracts employed by the Gotland Spirit, the Poul Spirit, and the Hamane Spirit, respectively, with a subsidiary of Teekay Corporation. The Partnership received early termination fees from Teekay Corporation of $4.5 million, $6.8 million and $14.7 million in the second quarter and first quarter of 2013 and the second quarter of 2012, respectively.

F - 31

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data or unless otherwise indicated)

The following table summarizes the net (loss) income from discontinued operations for the periods presented in the consolidated statements of income (loss):


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2013			2012			2011
	$			$			$
REVENUES		20,238			62,967			108,079

OPERATING EXPENSES
Voyage expenses		682			16,201			27,868
Vessel operating expenses		3,903			14,286			19,998
Depreciation and amortization		1,236			5,267			15,980
General and administrative		479			1,178			613
Write down and loss on sale of vessels		18,465			7,675			54,069

Total operating expenses		24,765			44,607			118,528

(Loss) income from vessel operations		(4,527	)		18,360			(10,449	)

OTHER ITEMS
Interest expense		(110	)		(822	)		(968	)
Foreign currency exchange (loss) gain		(4	)		2			—
Other (expense) income - net		(1	)		28			(78	)

Total other items		(115	)		(792	)		(1,046	)

Net (loss) income from discontinued operations		(4,642	)		17,568			(11,495	)

19.

Equity Method Investment

In June 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 (see note 10h).

As at December 31, 2013, the Partnership had an investment of $52.1 million in the joint venture. No indicators of impairment existed at December 31, 2013.

20.

Subsequent Events

In January 2014, the Partnership issued in the Norwegian bond market NOK 1,000 million in senior unsecured bonds, maturing in January 2019. The aggregate principal amount of the bonds was equivalent to $162.2 million and all interest and principal payments have been swapped into U.S. dollars at fixed rates of 6.28%. The net proceeds from the bond offerings are intended for general partnership purposes. The Partnership is applying to list the bonds on the Oslo Stock Exchange.

On March 14, 2014, the Partnership acquired 100% of the shares of ALP Maritime Services B.V. (or ALP), a Netherlands-based provider of long-haul ocean towage and offshore installation services to the global offshore oil and gas industry. Concurrent 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 2015 and 2016. The Partnership is committed to acquire these newbuildings for a total cost of approximately $258 million.

The Partnership acquired ALP for a purchase price of $6.1 million, of which $2.6 million was paid in cash on closing and a further $3.5 million representing the fair value of contingent consideration. The contingent consideration consists of $2.4 million which is contingently payable upon the delivery and employment of ALP’s four newbuildings. In addition, the contingent consideration includes a further amount of up to $2.6 million, based on ALP’s annual operating results from 2017 to 2021. The Partnership has the option to pay up to one half of the contingent consideration through the issuance of common units of the Partnership. The Partnership also incurred $1.0 million of acquisition-related costs which have been recognized in general and administrative expenses in March 2014. The Partnership financed the ALP acquisition and initial newbuilding payments through its existing liquidity and expects to secure long-term debt financing for the newbuildings prior to their deliveries.

This acquisition represents the Partnership’s entrance into the long-haul ocean towage and offshore installation services business. This acquisition allows the Partnership to combine its infrastructure and access to capital with ALP’s experienced management team to further grow this niche business that is in an adjacent sector to the Partnership’s FPSO and shuttle tanker businesses.

F - 32