Document


 
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
OR
ý
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
¨
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)
4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda

1


Telephone: (441) 298-2530
(Address and telephone number of principal executive offices)
Edith Robinson
4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda
Telephone: (441) 298-2533
Fax: (441) 292-3931
(Contact information for company contact person)
Securities registered, or to be registered, pursuant to Section 12(b) of the Act.
Title of each class
 
Name of each exchange on which registered
Common Units
 
New York Stock Exchange
Series A Preferred Units
 
New York Stock Exchange
Series B Preferred Units
 
New York Stock Exchange
6.00% Notes due 2019
 
New York Stock Exchange
Securities registered or to be registered, pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
___________________________________
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
147,514,113 Common Units
6,000,000 Series A Preferred Units
5,000,000 Series B Preferred Units
8,517,745 Series C-1 Preferred Units
4,000,000 Series D Preferred Units
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  ý
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ¨    No  ý
Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark if the registrant (1) has submitted electronically 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  ý    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  ¨                 Accelerated Filer  ý                Non-Accelerated Filer ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

2


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  ý
 

3


TEEKAY OFFSHORE PARTNERS L.P.
INDEX TO REPORT ON FORM 20-F
 
 
Page
 
 
Item 1.
Item 2.
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 4A.
Item 5.
 
 
 
 
 
 
 
 
 
 
 
 
Item 6.
 
 
 
 
 

2


 
 
 
 
 
Item 7.
 
 
Item 8.
 
 
 
 
 
Item 9.
Item 10.
 
 
 
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
 
 
Item 13.
Item 14.
Item 15.
 
Item 16A.
Item 16B.
Item 16C.
Item 16D.
Item 16E.
Item 16F.
Item 16G.
Item 16H.
 
 
 
 
 
Item 17.
Item 18.
Item 19.
 


3


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 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;
•
our future growth prospects, business strategy and other plans and objectives for future operations;
•
future capital expenditures and availability of capital resources to fund capital expenditures;
•
our liquidity needs and meeting our going concern requirements, including our working capital deficit, anticipated funds and sources of financing for liquidity needs and the sufficiency of cash flows, and our estimation that we will have sufficient liquidity for a one-year period;
•
our ability to refinance existing debt obligations, to raise additional debt and capital, to fund capital expenditures, negotiate extensions or redeployments of existing assets and the sale of partial interests of certain assets;
•
our ability to maintain and expand long-term relationships with major crude oil companies, including our ability to service fields until they no longer produce, and the negative impact of low oil prices on the likelihood of certain contract extensions;
•
the derivation of a substantial majority of revenue from a limited number of customers;
•
the outcome and cost of claims and potential claims against us, including claims and potential claims by Sevan Marine ASA (or Sevan), CeFront Technology AS (or CeFront) and COSCO (Nantong) Shipyard (or COSCO) relating to Logitel Offshore Holding AS (or Logitel) and cancellation of Units for Maintenance and Safety (or UMS) newbuildings, by Petroleo Brasileiro S.A. (or Petrobras) associated with the Piranema Spirit FPSO, by Royal Dutch Shell Plc (or Shell) associated with the Petrojarl Knarr FPSO and by Transocean Offshore International Ventures Limited (or Transocean) associated with the ALP Forward;
•
the outcome of discussions with Petrobras, the charterer on the Arendal Spirit UMS, including the timing and certainty of the unit returning to operation;
•
our ability to leverage to our advantage Teekay Corporation’s relationships and reputation in the shipping industry;
•
our continued ability to enter into fixed-rate time charters and FPSO contracts with customers;
•
results of operations and revenues and expenses;
•
maintaining a reduced level of vessel operating expenses, including services and spares and crewing costs;
•
offshore and tanker market fundamentals, including the balance of supply and demand in the offshore and tanker market and spot tanker charter rates;
•
our competitive advantage in the shuttle tanker market;
•
the expected lifespan of our vessels;
•
the estimated sales price or scrap value of vessels;
•
our expectations as to any impairment of our vessels;
•
future capital expenditures and availability of capital resources to fund capital expenditures;
•
offers of shuttle tankers, floating storage and off-take (or FSO) units, or floating production, storage and offloading (or FPSO) units and related contracts from Teekay Corporation and our accepting such offers;
•
acquisitions from third parties and obtaining offshore projects, that we or Teekay Corporation bid on or may be awarded;
•
certainty of completion, estimated delivery and completion dates, commencement of charter, intended financing and estimated costs for newbuildings, acquisitions, conversions and upgrades, including the towing and offshore installation vessel newbuildings, conversion of the Randgrid to an FSO unit to serve the Gina Krog oil and gas field, conversion of the Libra FPSO unit to serve the Libra field, the upgrade of the Petrojarl I FPSO unit and shuttle tanker newbuildings;
•
the timing of the new shuttle tanker contract of affreightment (or CoA) contracts and the number of shuttle tankers to serve these new CoAs;
•
expected employment and trading of older shuttle tankers;

4


•
payment of additional contingent consideration for our acquisitions of ALP Maritime Services B.V. (or ALP) and Logitel and the capabilities of the ALP vessels acquired;
•
the expectations as to the chartering of unchartered vessels, including towage newbuildings and the HiLoad DP unit;
•
our expectations regarding competition in the markets we serve;
•
our entering into joint ventures or partnerships with companies;
•
our ability to maximize the use of our vessels, including the re-deployment or disposition of vessels no longer under long-term time charter contracts;
•
the duration of dry dockings;
•
the future valuation of goodwill;
•
our compliance with covenants under our credit facilities;
•
timing of settlement of amounts due to and from affiliates;
•
the ability of the counterparties for our derivative contracts to fulfill their contractual obligations;
•
our hedging activities relating to foreign exchange, interest rate and spot market risks;
•
our exposure to foreign currency fluctuations, particularly in Norwegian Kroner;
•
increasing the efficiency of our business and redeploying vessels as charters expire or terminate;
•
the adequacy of our insurance coverage;
•
the expected impact of heightened environmental and quality concerns of insurance underwriters, regulators and charterers;
•
the expected cost of, and our ability to comply with, governmental regulations and maritime self-regulatory organization standards applicable to our business, including the expected cost to install ballast water treatment systems on our vessels in compliance with the International Marine Organization (or IMO) proposals;
•
the outcome of the investigation into allegations of improper payments by one of our subsidiaries to Brazilian agents;
•
anticipated taxation of our partnership and its subsidiaries and taxation of unitholders;
•
our intent to take the position that we are not a passive foreign investment company;
•
our general and administrative expenses as a public company and expenses under service agreements with other affiliates of Teekay Corporation and for reimbursements of fees and costs of Teekay Offshore GP L.L.C., our general partner; and
•
our ability to avoid labor disruptions and attract and retain highly skilled personnel.

Forward-looking statements are necessary estimates reflecting the judgment of senior management, involve known and unknown risks and are based upon a number of assumptions and estimates that are inherently subject to significant uncertainties and contingencies, many of which are beyond our control. Actual results may differ materially from those expressed or implied by such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to, those factors discussed below in Item 3 – Key Information: Risk Factors and other factors detailed from time to time in other reports we file with the U.S. Securities and Exchange Commission (or the SEC).

We do not intend to revise any forward-looking statements in order to reflect any change in our expectations or events or circumstances that may subsequently arise. You should carefully review and consider the various disclosures included in this Annual Report and in our other filings made with the SEC that attempt to advise interested parties of the risks and factors that may affect our business, prospects and results of operations.
Item 1.
Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2.
Offer Statistics and Expected Timetable
Not applicable.
Item 3.
Key Information
Selected Financial Data
Set forth below is selected consolidated financial and other data of Teekay Offshore Partners L.P. and its subsidiaries for the fiscal years 2012 through 2016, which have been derived from our audited consolidated financial statements.


5


The following tables should be read together with, and are qualified in their entirety by reference to, (a) Item 5. Operating and Financial Review and Prospects, included herein, and (b) the historical consolidated financial statements and the accompanying notes and the Report of Independent Registered Public Accounting Firm thereon (which are included herein), with respect to the consolidated financial statements as at December 31, 2016 and December 31, 2015 and for each of the fiscal years in the three-year period ended December 31, 2016.

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

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

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

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

6


 
 
 
 
Year Ended December 31,
 
 
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(in thousands of U.S. Dollars, except per unit, unit and fleet data)
Income Statement Data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
1,152,390

 
1,229,413

 
1,019,539

 
930,739

 
901,227

Income from vessel operations (1)
 
230,853

 
283,399

 
256,218

 
103,418

 
166,577

Interest expense
 
(140,611
)
 
(122,838
)
 
(88,381
)
 
(62,855
)
 
(47,508
)
Interest income
 
1,257

 
633

 
719

 
2,561

 
1,027

Realized and unrealized (loss) gain on derivative instruments
 
(20,313
)
 
(73,704
)
 
(143,703
)
 
34,820

 
(26,349
)
Equity income
 
17,933

 
7,672

 
10,341

 
6,731

 
—

Foreign currency exchange loss (2)
 
(14,805
)
 
(17,467
)
 
(16,140
)
 
(5,278
)
 
(315
)
Loss on bond repurchase
 
—

 
—

 
—

 
(1,759
)
 
—

Other (expense) income - net
 
(21,031
)
 
1,091

 
781

 
1,144

 
1,538

Income tax (expense) recovery
 
(8,808
)
 
21,357

 
(2,179
)
 
(2,225
)
 
10,477

Net income from continuing operations
 
44,475

 
100,143

 
17,656

 
76,557

 
105,447

Net (loss) income from discontinued operations
 
—

 
—

 
—

 
(4,642
)
 
17,568

Net income
 
44,475

 
100,143

 
17,656

 
71,915

 
123,015

Non-controlling and other interests in net income from continuing operations
 
57,427

 
68,938

 
37,036

 
62

 
12,885

Non-controlling and other interests in net (loss) income from discontinued operations
 
—

 
—

 
—

 
(452
)
 
(1,772
)
Limited partners’ interest:
 
 
 
 
 
 
 
 
 
 
Net income from continuing operations
 
(12,952
)
 
31,205

 
(19,380
)
 
76,495

 
92,562

Net income from continuing operations per common unit (basic and diluted) (3)
 
(0.25
)
 
0.32

 
(0.22
)
 
0.93

 
1.26

Net (loss) income from discontinued operations
 
—

 
—

 
—

 
(4,190
)
 
19,340

Net (loss) income from discontinued operations per common unit (basic and diluted) (3)
 
—

 
—

 
—

 
(0.05
)
 
0.26

Cash distributions declared per common unit 
 
0.44

 
2.18

 
2.15

 
2.11

 
2.04

Balance Sheet Data (at end of year):
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
227,378

 
258,473

 
252,138

 
219,126

 
206,339

Vessels and equipment (4)
 
4,716,933

 
4,743,619

 
3,183,465

 
3,089,582

 
2,454,623

Total assets
 
5,718,620

 
5,744,166

 
3,917,837

 
3,786,700

 
3,042,625

Total debt
 
3,182,894

 
3,363,874

 
2,408,596

 
2,349,590

 
1,758,866

Total equity
 
1,138,596

 
967,848

 
802,853

 
821,341

 
705,229

Common units outstanding
 
147,514,113

 
107,026,979

 
92,386,383

 
85,452,079

 
80,105,108

Preferred units outstanding (5)
 
23,517,745

 
21,438,413

 
6,000,000

 
6,000,000

 
—

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
Net revenues (6)
 
1,071,640

 
1,131,407

 
906,999

 
827,096

 
790,744

EBITDA (7)
 
492,648

 
475,590

 
306,050

 
338,082

 
330,815

Adjusted EBITDA (7)
 
587,781

 
631,190

 
467,868

 
397,445

 
405,243

Expenditures for vessels and equipment
 
294,581

 
664,667

 
172,169

 
455,578

 
87,408

Fleet data:
 
 
 
 
 
 
 
 
 
 
Average number of shuttle tankers (8)
 
32.5

 
33.8

 
34.7

 
33.8

 
35.5

Average number of FPSO units (8)
 
8.0

 
7.8

 
5.2

 
4.2

 
3.0

Average number of conventional tankers (8)
 
2.0

 
3.9

 
4.0

 
5.2

 
6.0

Average number of FSO units (8)
 
7.0

 
6.6

 
6.0

 
5.8

 
5.0

Average number of towing vessels (8)
 
6.3

 
4.3

 
—

 
—

 
—

Average number of units for maintenance and safety (8)
 
1.0

 
0.9

 
—

 
—

 
—


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

7


 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
(Write-down) and gain (loss) on sale of vessels
 
(40,079
)
 
(69,998
)
 
(1,638
)
 
(76,782
)
 
(24,542
)
Restructuring (charge) recovery
 
(4,649
)
 
(568
)
 
225

 
(2,607
)
 
(1,115
)
 
 
(44,728
)
 
(70,566
)
 
(1,413
)
 
(79,389
)
 
(25,657
)

(2)
The majority of these foreign currency exchange gains and losses were unrealized and not settled in cash. Under GAAP, all foreign currency-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, accounts payable, advances from affiliates, deferred income taxes and long-term debt are revalued and reported based on the prevailing exchange rate at the end of the period. Foreign currency exchange gains and losses also include realized and unrealized gains and losses on our cross currency swaps.
(3)
Please read Item 18 - Financial Statements: Note 16 - Total Capital and Net Income Per Common Unit.
Limited partners’ interest in net (loss) income per common unit – basic is determined by dividing net income, after deducting the amount of net income attributable to the Dropdown Predecessor, non-controlling interests, the general partner’s interest, the distributions on the Series A, B, C, C-1 and D Preferred Units, the periodic accretion of the Series D Preferred Units, the Inducement Premium and the Exchange Contribution from the Series C Preferred Units, by the weighted-average number of common units outstanding during the period.
The computation of limited partners’ interest in net income per common unit - diluted assumes the issuance of common units for all potential dilutive securities, consisting of restricted units, warrants and Series C, C-1 and D Preferred Units. Consequently, the net income attributable to limited partners’ interest is exclusive of any distributions on the Series C, C-1 and D Preferred Units, the periodic accretion of the Series D Preferred Units, the Inducement Premium and the Exchange Contribution from the series C Preferred Units. In addition, the weighted average number of common units outstanding has been increased assuming exercise of the restricted units and warrants using the treasury stock method and the Series C, C-1 and D are converted to common units using the if-converted method. The computation of limited partners’ interest in net income per common unit - diluted does not assume the issuance of common units pursuant to the restricted units, warrants and Series C, C-1 and D Preferred Units if the effect would be anti-dilutive. In periods where a loss is attributable to common unitholders all restricted units, warrants, the Series C, C-1 and D Preferred Units are anti-dilutive.
We allocate the limited partners' interest in net income, including both distributed and undistributed net income, between continuing operations and discontinued operations based on the proportion of net (loss) income from continuing and discontinuing operations to total net income.
(4)
Vessels and equipment consists of (a) vessels, at cost less accumulated depreciation and (b) advances on newbuilding contracts and conversion costs.
(5)
Preferred units outstanding includes the Series A preferred units in 2013 through 2016, the Series B and Series C preferred units in 2015 through 2016 and the Series C-1 and Series D preferred units in 2016.
(6)
Net revenues is a non-GAAP financial measure. Consistent with general practice in the shipping industry, we use “net revenues” (defined as revenues less voyage expenses, which comprises all expenses unique to a particular voyage, including bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions) as a measure of equating revenues generated from voyage charters to revenues generated from time charters, which assists us in making operating decisions about the deployment of vessels and their performance. Under time charters and bareboat charters, the charterer typically pays the voyage expenses, whereas under voyage charter contracts and contracts of affreightment the shipowner typically pays the voyage expenses. Some voyage expenses are fixed, and the remainder can be estimated. If we, as the shipowner, pay the voyage expenses, we typically pass the approximate amount of these expenses on to the customers by charging higher rates under the contract or billing the expenses to them. As a result, although revenues from different types of contracts may vary, the “net revenues” are comparable across the different types of contracts. We principally use net revenues 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. Net revenue should not be considered as an alternative to revenue or any other measure of financial performance in accordance with GAAP. Net revenue is adjusted for expenses that we classify as voyage expenses and, therefore, may not be comparable to similarly titled measures of other companies. The following table reconciles net revenues with revenues.
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
Revenues
 
1,152,390

 
1,229,413

 
1,019,539

 
930,739

 
901,227

Voyage expenses
 
(80,750
)
 
(98,006
)
 
(112,540
)
 
(103,643
)
 
(110,483
)
Net revenues
 
1,071,640

 
1,131,407

 
906,999

 
827,096

 
790,744


(7)
EBITDA and Adjusted EBITDA are non-GAAP measures. These measures are used as supplemental financial measures by management and by external users of our financial statements, such as investors, as discussed below.

8


•
Financial and operating performance. EBITDA and Adjusted EBITDA assist our management and investors by increasing the comparability of our fundamental performance from period to period and against the fundamental performance of other companies in our industry that provide EBITDA or Adjusted EBITDA-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 income between periods. We believe that including EBITDA and Adjusted EBITDA as financial and operating measures benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength and health in assessing whether to continue to hold our common and preferred units.
•
Liquidity. EBITDA and Adjusted EBITDA allow us to assess the ability of assets to generate cash sufficient to service debt, make distributions and undertake capital expenditures. By eliminating the cash flow effect resulting from our existing capitalization and other items such as dry-docking expenditures, deferred mobilization revenue and expenditure, working capital changes and foreign currency exchange gains and losses (which may vary significantly from period to period), EBITDA and Adjusted EBITDA provide consistent measures of our ability to generate cash over the long term. Management uses this information as a significant factor in determining (a) our proper capitalization structure (including assessing how much debt to incur and whether changes to the capitalization should be made) and (b) whether to undertake material capital expenditures and how to finance them, all in light of existing cash distribution commitments to common and preferred unitholders. Use of EBITDA and Adjusted EBITDA as liquidity measures also permits investors to assess our fundamental ability to generate cash sufficient to meet cash needs, including distributions on our common and preferred units.

Neither EBITDA nor Adjusted EBITDA, should be considered as an alternative to net income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA as presented in this Annual Report may not be comparable to similarly titled measures of other companies.

The following table reconciles our historical consolidated EBITDA and Adjusted EBITDA to net income, and our historical consolidated Adjusted EBITDA to net operating cash flow.

9


 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(in thousands of US Dollars)
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income”:
 
 
 
 
 
 
 
 
 
 
Net income from continuing operations
 
44,475

 
100,143

 
17,656

 
76,557

 
105,447

Depreciation and amortization
 
300,011

 
274,599

 
198,553

 
199,006

 
189,364

Interest expense, net of interest income
 
139,354

 
122,205

 
87,662

 
60,294

 
46,481

Income tax expense (recovery)
 
8,808

 
(21,357
)
 
2,179

 
2,225

 
(10,477
)
EBITDA
 
492,648

 
475,590

 
306,050

 
338,082

 
330,815

Write-down and loss (gain) of sale of vessels
 
40,079

 
69,998

 
1,638

 
76,782

 
24,542

Restructuring charge (recovery)
 
4,649

 
568

 
(225
)
 
2,607

 
1,115

Unrealized (gain) loss on derivative instruments
 
(86,467
)
 
51,072

 
180,156

 
(91,837
)
 
(39,538
)
Realized loss on interest rate swaps
 
52,819

 
71,617

 
55,588

 
94,848

 
58,596

Foreign exchange loss (gain)(i)
 
60,932

 
(44,267
)
 
(77,813
)
 
(33,318
)
 
11,015

Loss on bond repurchase
 
—

 
—

 
—

 
1,759

 
—

Amortization of in-process revenue contracts
 
(12,779
)
 
(12,745
)
 
(12,744
)
 
(12,704
)
 
(12,634
)
Cancellation of two UMS newbuildings(ii)
 
23,401

 
—

 
—

 
—

 
—

Adjustments relating to equity income(iii)
 
12,499

 
19,647

 
15,218

 
6,057

 
—

Adjustments relating to discontinued operations(iii)
 
—

 
—

 
—

 
15,169

 
31,332

Adjusted EBITDA
 
587,781

 
631,480

 
467,868

 
397,445

 
405,243

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
 
 
 
 
 
 
 
 
 
 
Net operating cash flow
 
353,814

 
371,221

 
160,186

 
255,387

 
267,494

Expenditures for dry docking
 
26,342

 
13,060

 
36,221

 
19,332

 
19,122

Interest expense, net of interest income
 
139,354

 
122,205

 
87,662

 
60,294

 
46,481

Current income tax expense (recovery)
 
3,954

 
1,650

 
1,290

 
75

 
(1,669
)
Realized loss on interest rate swaps
 
52,819

 
71,617

 
55,588

 
94,848

 
58,596

Equity income, net of dividends received
 
10,727

 
(171
)
 
(6,462
)
 
6,731

 
—

Change in working capital
 
(74,218
)
 
(25,903
)
 
111,484

 
(51,999
)
 
17,447

Restructuring charge (recovery)
 
4,649

 
568

 
(225
)
 
2,607

 
1,115

Loss on bond repurchase
 
—

 
—

 
—

 
1,759

 
—

Deferred mobilization revenue and costs
 
(7,053
)
 
38,938

 
10,905

 
5,051

 
—

Realized (gain) loss on cross currency swaps
 
53,497

 
10,140

 
1,992

 
(8,363
)
 
(2,992
)
Cancellation of two UMS newbuildings(ii)
 
23,401

 
—

 
—

 
—

 
—

Other, net
 
(12,004
)
 
8,508

 
(5,991
)
 
5,556

 
(1,173
)
Adjustments relating to equity income(iii)
 
12,499

 
19,647

 
15,218

 
6,057

 
—

Interest expense, net of interest income related to discontinued operations(iv)
 
—

 
—

 
—

 
110

 
822

Adjusted EBITDA
 
587,781

 
631,480

 
467,868

 
397,445

 
405,243

(i)
Foreign exchange loss (gain) excludes the unrealized gain of $46.1 million in 2016 (2015 - loss of $61.7 million, 2014 – loss of $94.0 million, 2013 – loss of $38.6 million and 2012 – gain of $10.7 million) on cross currency swaps, which is incorporated in unrealized (gain) loss on derivative instruments in the table.
(ii)
In June 2016, as part of our financing initiatives, we canceled the construction contracts for our two UMS newbuildings. As a result, we accrued for potential damages resulting from the cancellations and reversed contingent liabilities previously recorded that were relating to the delivery of the UMS newbuildings. This net loss provision of $23.4 million for the year ended December 31, 2016 is reported in Other (expense) income - net in our consolidated statements of income. The newbuilding contracts are held in our separate subsidiaries and obligations of these subsidiaries are non-recourse to us. For additional information, please read Item 18 - Financial Statements: Note 14c Commitments and Contingencies.
(iii)
Adjustments relating to equity income, which is a non-GAAP measure, should not be considered as an alternative to equity income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjustments relating to equity income exclude some, but not all, items that affect equity income and these measures may vary among other companies. Therefore, adjustments relating to equity income as presented in this Annual Report may not be comparable to similarly titled measures of other companies. When using Adjusted EBITDA as a measure of liquidity it should be noted that this

10


measure includes the Adjusted EBITDA from our equity accounted for investments. We do not have control over the operations, nor do we have any legal claim to the revenue and expenses of our equity accounted for investments. Consequently, the cash flow generated by our equity accounted for investments may not be available for use by us in the period generated. Adjustments relating to equity income from our equity accounted joint ventures are as follows:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
Depreciation and amortization
 
8,715

 
8,356

 
8,085

 
4,239

 
—

Interest expense, net of interest income
 
3,541

 
4,234

 
3,837

 
2,715

 
—

Income tax expense (recovery)
 
372

 
161

 
(33
)
 
(184
)
 
—

Unrealized (gain) loss on derivative instruments
 
(2,579
)
 
4,137

 
410

 
(2,302
)
 
—

Realized loss on interest rate swaps
 
1,774

 
2,469

 
2,919

 
1,589

 
—

Write-down and loss on sale of equipment
 
676

 
290

 
—

 
—

 
—

Adjustments relating to equity income
 
12,499

 
19,647

 
15,218

 
6,057

 
—

(iv)
Adjustments relating to discontinued operations, which is a non-GAAP measure, should not be considered as an alternative to net (loss) income from discontinued operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjustments relating to discontinued operations exclude some, but not all, items that affect net (loss) income from discontinued operations and these measures may vary among other companies. Therefore, adjustments relating to discontinued operations as presented in this Annual Report may not be comparable to similarly titled measures of other companies. When using Adjusted EBITDA as a measure of liquidity it should be noted that this measure includes the Adjusted EBITDA from discontinued operations. Adjustments relating to our discontinued operations are as follows:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
Net (loss) income from discontinued operations
 
—

 
—

 
—

 
(4,642
)
 
17,568

Depreciation and amortization
 
—

 
—

 
—

 
1,236

 
5,267

Interest expense, net of interest income
 
—

 
—

 
—

 
110

 
822

Write-down and loss on sale of vessels
 
—

 
—

 
—

 
18,465

 
7,675

Adjustments relating to discontinued operations
 
—

 
—

 
—

 
15,169

 
31,332


(8)
Average number of vessels consists of the average number of owned and chartered-in vessels that were in our possession during the period, including the Dropdown Predecessor and those in discontinued operations. For 2016, 2015 and 2014 this includes two FPSO units, and for 2013 one FPSO unit, in our equity accounted joint ventures, of which we have 50% ownership interests in, at 100%.
Risk Factors
Some of the following risks relate principally to the industry in which we operate and to our business in general. Other risks relate principally to the securities market and to the ownership of our 6.00% notes due 2019 (the Notes) and common, preferred and convertible preferred units and our warrants. The occurrence of any of the events described in this section could materially and adversely affect our business, financial condition, operating results and ability to pay interest, principal or distributions on, and the trading price of our Notes and common, preferred and convertible preferred units.
Our cash flow depends substantially on the ability of our subsidiaries to make distributions to us.
The source of our cash flow includes cash distributions from our subsidiaries. The amount of cash our subsidiaries can distribute to us principally depends upon the amount of cash they generate from their operations, which may fluctuate from quarter to quarter based on, among other things:

•
the rates they obtain from their charters, voyages and contracts of affreightment (whereby our subsidiaries carry an agreed quantity of cargo for a customer over a specified trade route within a given period of time);
•
the price and level of production of, and demand for, crude oil, particularly the level of production at the offshore oil fields our subsidiaries service under contracts of affreightment;
•
the operating performance of our FPSO units, whereby receipt of incentive-based revenue from our FPSO units is dependent upon the fulfillment of the applicable performance criteria;
•
the level of their operating costs, such as the cost of crews and repairs and maintenance;
•
the number of off-hire days for their vessels and the timing of, and number of days required for, dry docking of vessels;
•
the rates, if any, at which our subsidiaries may be able to redeploy shuttle tankers in the spot market as conventional oil tankers during any periods of reduced or terminated oil production at fields serviced by contracts of affreightment;
•
the rates, if any, at which our subsidiaries may be able to redeploy vessels, particularly FPSO units, after they complete their charters or contracts and are redelivered to us;

11


•
the ability of our subsidiaries to contract our newbuilding vessels, including our newbuilding towage vessels, and the rates thereon (if any);
•
delays in the delivery of any newbuildings or vessels undergoing conversion or upgrades and the beginning of payments under charters relating to those vessels;
•
prevailing global and regional economic and political conditions;
•
currency exchange rate fluctuations; and
•
the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of business.

The actual amount of cash our subsidiaries have available for distribution also depends on other factors such as:
 
•
the level of their capital expenditures, including for maintaining vessels or converting existing vessels for other uses and complying with regulations;
•
their debt service requirements and restrictions on distributions contained in their debt agreements;
•
fluctuations in their working capital needs;
•
their ability to make working capital borrowings; and
•
the amount of any cash reserves, including reserves for future maintenance capital expenditures, working capital and other matters, established by the board of directors of our general partner at its discretion.

The amount of cash our subsidiaries generate from operations may differ materially from their profit or loss for the period, which will be affected by non-cash items and the timing of debt service payments. As a result of this and the other factors mentioned above, our subsidiaries may make cash distributions during periods when they record losses and may not make cash distributions during periods when they record net income.
Our ability to pay distributions on our units, and the amount of distributions that we pay, largely depends upon the distributions that we receive from our subsidiaries, and we may not have sufficient cash from operations to enable us to maintain or increase distributions.
The source of our earnings and cash flow includes cash distributions from our subsidiaries. Therefore, the amount of distributions we are able to make to our unitholders will fluctuate based on the level of distributions made to us by our subsidiaries. Our subsidiaries may not make quarterly distributions at a level that will permit us to maintain or increase our quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our common unitholders if our subsidiaries increase or decrease distributions to us, the timing and amount of any such increased or decreased distributions will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by our subsidiaries to us.

Our ability to distribute to our unitholders any cash we may receive from our subsidiaries is or may be limited by a number of factors, including, among others:
 
•
interest expense and principal payments on any indebtedness we incur;
•
distributions on any preferred units or convertible preferred units we have issued or may issue;
•
capital expenditures related to committed projects;
•
changes in our cash flows from operations;
•
restrictions on distributions contained in any of our current or future debt agreements;
•
fees and expenses of us, our general partner, its affiliates or third parties we are required to reimburse or pay, including expenses we incur as a result of being a public company; 
•
failure to raise a cash amount from the issuance of equity that matches or exceeds cash distributions paid to third party common unitholders within six months following the payment of such distributions; and
•
reserves the board of directors of our general partner believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions, including reserves for future capital expenditures and for anticipated future credit needs.

Many of these factors reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we do make may not be at or above our current level of quarterly distribution. The actual amount of cash that is available for distribution to our unitholders depends on several factors, many of which are beyond the control of us or our general partner.
In 2016, we issued significant amounts of additional common units and other equity securities to finance vessel acquisitions and organic growth projects, to repay or refinance debt obligations and to fund capital expenditures and estimated funding gaps, and we expect to issue additional common units or other equity securities in the future. The issuance of additional common units and other equity securities may be dilutive to unitholders, and increases the risk that we will not have sufficient available cash to maintain

12


or increase cash distribution levels to our unitholders. As a result, we may not have sufficient cash from operations to enable us to pay the current level of distributions on our units or to maintain or increase distributions.
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. During 2016, we issued the following common units and equity securities:
 
•
21,978,022 common units as part of the financing initiatives completed during the second quarter of 2016;
•
4,000,000 Series D Preferred Units and warrants exercisable for up to 6,750,000 common units;
•
8,323,809 common units in consideration for the exchange and cancellation of 1,920,668 Series C Preferred Units; and
•
8,517,745 Series C-1 Preferred Units in consideration for the exchange and cancellation of the remaining 8,517,745 Series C Preferred Units.
Under the terms of the Series C-1 Preferred Units and the Series D Preferred Units, for the eight consecutive quarters ending March 31, 2018, we may, at our discretion, make distributions on such preferred units in cash, common units, or a combination of cash and common units. In June 2016, in connection with the completion of our financing initiatives, we agreed that, until we repay amounts outstanding under our Norwegian Kroner bonds maturing 2018, we will only pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units in common units, except that, at any time with respect of the Series C-1 Preferred Units, and at any time after June 29, 2018 with respect to the Series D Preferred Units, we may pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units, respectively, in cash, upon condition that the amount of such cash distributions are matched or exceeded by the proceeds of additional equity raised by us in advance of, or within six months following, payment of the cash distributions. In addition, we agreed that, during the same period, we will only pay distributions in cash to third party holders of our common units if the amount of such cash distributions is matched or exceeded by the proceeds raised through the issuance of additional equity in advance of, or within six months following, the payment of such distributions. Also in connection with completion of the financing initiatives, we agreed that, until our Norwegian Kroner bonds maturing in 2018 have been repaid, all cash distributions (other than with respect to distributions, if any, on incentive distribution rights) to be paid to Teekay Corporation or its affiliates, including our general partner, will instead be paid in common units. In connection with extending to January 2019 the maturity date of $200 million in obligations owing to Teekay Corporation, we modified the terms of the note to provide that one half of the 10.0% per annum interest will be paid in common units or in cash provided the amount of such cash interest payments is matched or exceeded by the proceeds raised through the issuance of additional equity in advance of, or within six months following, such interest payments.

See “Item 5. Operating and Financial Review and Prospects-Management’s Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Liquidity and Cash Needs” for a further description of the transactions described above.

These recent issuances of additional equity securities have resulted in unitholder dilution and increased the aggregate amount of cash required to maintain our quarterly distributions to unitholders, once we resume making distributions to all unitholders with cash. Issuing additional equity securities in the future may result in further unitholder dilution and further increase the aggregate amount of cash required to maintain quarterly distributions on our common units.
Our ability to grow and to meet our financial needs may be adversely affected by our cash distribution policy.
Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash (as defined in our partnership agreement) each quarter. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

In determining the amount of cash available for distribution, the board of directors of our general partner, in making the determination on our behalf, approves the amount of cash reserves to set aside, including reserves for future capital expenditures, anticipated future credit needs, working capital and other matters. We also rely upon external financing sources, including commercial borrowings and proceeds from debt and equity offerings, to fund our capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may significantly impair our ability to meet our financial needs or to grow.

Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, we believe it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, in December 2015, we reduced our quarterly cash distributions per common unit to $0.11 per common unit, and our near-to-medium-term business strategy is primarily focused on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects. Our distributions in 2016 were all paid at this reduced rate. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and are expected to grow as we take delivery of our various capital projects, supported by a large and well-diversified portfolio of fee-based contracts with high-quality counterparties.
Current market conditions limit our access to capital and our growth prospects.
We have relied primarily upon bank financing and debt and equity offerings to fund our growth. Current depressed market conditions in the energy sector and for master limited partnerships have significantly reduced our access to capital, particularly equity capital. Debt financing or refinancing may not be available on acceptable terms, if at all. Issuing significant additional common equity given current market conditions

13


would be highly dilutive and costly. Lack of access to debt or equity capital at reasonable rates will adversely affect our growth prospects and our ability to refinance debt, make payments on our Notes and make distributions to our unitholders.
Our ability to repay or refinance our debt obligations and to fund our capital expenditures and estimated funding gaps will depend on certain financial, business and other factors, many of which are beyond our control. To the extent we are able to finance these obligations and expenditures with cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished or our financial leverage may increase or our unitholders may be diluted. Our business may be adversely affected if we need to access other sources of funding.
To fund our existing and future debt obligations and capital expenditures, we will be required to use cash from operations, incur borrowings including securing debt financing on our under-levered and unmortgaged vessels, enter into sale-leaseback transactions, raise capital through the sale of assets or partial interests in certain assets or joint venture entities, debt or additional equity securities and/or seek to access other financing sources, including loans from our sponsor, Teekay Corporation. Our ability to draw on committed funding sources, potential funding sources and our future financial and operating performance will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control.

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

•restructuring our debt;
•seeking additional debt or equity capital;
•selling additional assets or equity interests in certain assets or joint ventures;
•further reducing cash distributions;
•reducing, delaying or cancelling our business activities, acquisitions, investments or capital expenditures; or
•seeking bankruptcy protection.

Such measures might not be successful, and additional debt or equity capital may not be available on acceptable terms or enable us to meet our debt, capital expenditure and other obligations. Some of such measures may adversely affect our business and reputation. In addition, our credit agreements may restrict our ability to implement some of these measures.

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

The sale of partial interests of certain assets will reduce cash from operations and the cash available for distribution to unitholders.

Primarily as a result of the working capital deficit and committed capital expenditures, over the one-year period following the issuance of our 2016 consolidated financial statements we will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet our minimum liquidity requirements under our financial covenants. These anticipated sources of financing include refinancing debt facilities that mature during the one-year period, raising additional capital through equity issuances, increasing amounts available under existing debt facilities and entering into new debt facilities, negotiating extensions or redeployments of existing assets and the sale of partial interests of assets. We are actively pursuing the funding alternatives described above, which we consider probable of completion based on our history of being able to raise equity, refinance loan facilities for similar types of vessels, and indicative offers received from potential investors for partial interests in certain assets. We are in various stages of completion on these matters.
We have limited current liquidity.
As at December 31, 2016, we had total liquidity of $260.7 million, consisting of $227.4 million of cash and cash equivalents and $33.3 million of undrawn long-term borrowings under our revolving credit facilities, subject to limitations in the credit facilities. As at December 31, 2016, we had a working capital deficit of $398.0 million. Our limited availability under existing credit facilities and our current working capital deficit could limit our ability to meet our financial obligations and growth prospects. We expect to manage our working capital deficit primarily with net operating cash flow, issuing equity securities, debt financing and refinancings, divesting assets and our existing liquidity. However, there can be no assurance that any such funding will be available to us on acceptable terms, if at all.

14


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

•
the cost of labor and materials;
•
customer requirements;
•
increases in fleet size or the cost of replacement vessels;
•
governmental regulations and maritime self-regulatory organization standards relating to safety, security or the environment; and
•
competitive standards.

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

Our partnership agreement requires our general partner to deduct our estimated, rather than actual, maintenance capital expenditures from operating surplus each quarter in an effort to reduce fluctuations in operating surplus (as defined in our partnership agreement). The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the Conflicts Committee of our general partner at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders is lower than if actual maintenance capital expenditures were deducted from operating surplus. If our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates.
We require substantial capital expenditures and generally are required to make significant installment payments for acquisitions of newbuilding vessels or for the conversion of existing vessels prior to their delivery and generation of revenue.
Currently, the total cost for an Aframax or Suezmax-size shuttle tanker is approximately $85 to $150 million, the cost of an FSO unit is approximately $50 to $250 million and the cost of an FPSO unit is approximately $200 million to $3 billion, although actual costs vary significantly depending on the market price charged by shipyards, the size and specifications of the vessel, governmental regulations and maritime self-regulatory organization standards. The cost of a newbuilding towing and offshore installation vessel is approximately $60 to $65 million.

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

We typically must pay between 10% to 20% of the purchase price of a shuttle tanker or towing and offshore installation vessel upon signing the purchase contract, even though delivery of the completed vessel will not occur until much later (approximately two to three years from the time the order is placed). During the construction period, we generally are required to make installment payments on newbuildings prior to their delivery, in addition to incurring financing, miscellaneous construction and project management costs. If we finance these acquisition costs by issuing debt or equity securities, we will increase the aggregate amount of interest or cash required to maintain our current level of quarterly distributions to unitholders prior to generating cash from the operation of the newbuilding.

Our substantial capital expenditures may reduce our cash available for payments on our Notes and distribution to our unitholders. Funding of any capital expenditures with debt may significantly increase our interest expense and financial leverage, and funding of capital expenditures through issuing additional equity securities may result in significant unitholder dilution. Our failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make payments on our Notes and cash distributions.

15


Our substantial debt levels may limit our flexibility in obtaining additional financing, refinancing credit facilities upon maturity, pursuing other business opportunities and paying distributions.
As at December 31, 2016, our total debt was approximately $3.2 billion and we had the ability to borrow an additional $33.3 million under our revolving credit facilities, subject to limitations in the credit facilities. We plan to increase our total debt relating to our towing, and shuttle tanker newbuildings and FPSO/FSO conversion projects. If we are awarded contracts for additional offshore projects or otherwise acquire additional vessels or businesses, our consolidated debt may significantly increase. We may incur additional debt under these or future credit facilities. Our level of debt could have important consequences to us, including:
 
•
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes, and our ability to refinance our credit facilities may be impaired or such financing may not be available on favorable terms;
•
we will need a substantial portion of our cash flow to make principal and interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
•
our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our industry or the economy generally; and
•
our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt depends upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as further reducing cash distributions, reducing, cancelling or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, seeking to restructure or refinance our debt, seeking additional debt or equity capital or seeking bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.
Financing agreements containing operating and financial restrictions may restrict our business and financing activities.
The operating and financial restrictions and covenants in our current financing arrangements and any future financing agreements could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, the arrangements may restrict the ability of us and our subsidiaries to:

•incur or guarantee indebtedness;
•change ownership or structure, including mergers, consolidations, liquidations and dissolutions;
•make dividends or distributions;
•make certain negative pledges and grant certain liens;
•sell, transfer, assign or convey assets;
•make certain investments; and
•enter into a new line of business.

Four of our revolving credit facilities are guaranteed by us and certain of our subsidiaries for all outstanding amounts and contain covenants that require us to maintain minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months of maturity) in an amount equal to the greater of $75.0 million and 5.0% of our total consolidated debt. One revolving credit facility is guaranteed by Teekay Corporation and contains a covenant that requires Teekay Corporation to maintain an amount equal to 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 21 of our vessels, together with other related security. The ability of Teekay Corporation or us to comply with covenants and restrictions contained in debt instruments may be affected by events beyond their or our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, compliance with these covenants may be impaired. If restrictions, covenants, ratios or tests in the financing agreements are breached, a significant portion or all of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. This could lead to cross-defaults under other financing agreements and result in obligations becoming due and commitments being terminated under such agreements. Neither Teekay Corporation nor we might have, or be able to obtain, sufficient funds to make these accelerated payments.

Obligations under our credit facilities are secured by certain vessels, and if we are unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. We have two revolving credit facilities and five term loans that require us to maintain vessel values to drawn principal balance ratio of a minimum range of 113% to 125%. As at December 31, 2016, these ratios ranged from 120% to 433% and were in compliance with the minimum ratios required. The vessel values used in these ratios are the appraised values prepared by us based on second-hand sale and purchase market data. Changes in the shuttle tanker, towing and offshore installation, UMS, FPSO or FSO markets could negatively affect these ratios.

Furthermore, the termination of any of our charter contracts by our customers could result in the repayment of the debt facilities for which the chartered vessels relate to.

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At December 31, 2016, we and Teekay Corporation were in compliance with all covenants in the credit facilities and long-term debt.
Restrictions in our debt agreements may prevent us or our subsidiaries from paying distributions.
The payment of principal and interest on our debt reduces cash available for distribution to us and on our units. In addition, our and our subsidiaries’ financing agreements prohibit the payment of distributions upon the occurrence of the following events, among others:

•failure to pay any principal, interest, fees, expenses or other amounts when due;
•failure to notify the lenders of any material oil spill or discharge of hazardous material, or of any action or claim related thereto;
•breach or lapse of any insurance with respect to vessels securing the facilities;
•breach of certain financial covenants;
•failure to observe any other agreement, security instrument, obligation or covenant beyond specified cure periods in certain cases;
•default under other indebtedness;
•bankruptcy or insolvency events;
•failure of any representation or warranty to be materially correct;
•a change of control, as defined in the applicable agreement; and
•a material adverse effect, as defined in the applicable agreement.
We derive a substantial majority of our revenues from a limited number of customers, and the loss of any such customers could result in a significant loss of revenues and cash flow.
We have derived, and we believe we will continue to derive, a substantial majority of revenues and cash flow from a limited number of customers. Royal Dutch Shell Plc (or Shell, formerly BG Group Plc), Petroleo Brasileiro S.A. (or Petrobras) and Premier Oil (formerly E.ON Ruhgras UK GP Limited or E.ON) accounted for approximately 30%, 19% and 10%, respectively, for our consolidated revenues from continuing operations during 2016. Shell, Petrobras, Statoil ASA (or Statoil) and E.ON accounted for approximately 26%, 18%, 11% and 11%, respectively, of our consolidated revenues from continuing operations during 2015. Petrobras, Statoil, E.ON and Repsol S.A. accounted for approximately 22%, 19%, 12% and 11%, respectively, of our consolidated revenues from continuing operations during 2014. No other customer accounted for 10% or more of revenues from continuing operations during any of these periods. Please read “Item 18 – Financial Statements: Note 5 – Segment Reporting.”

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

•
the customer fails to make payments because of its financial inability, disagreements with us or otherwise;
•
we agree to reduce the payments due to us under a contract because of the customer’s inability to continue making the original payments;
•
the customer exercises certain rights to terminate the contract; or
•
the customer terminates the contract because we fail to deliver the vessel within a fixed period of time, the vessel is lost or damaged beyond repair, there are serious deficiencies in the vessel or prolonged periods of off-hire, or we default under the contract.

In early-November 2016, the Arendal Spirit UMS experienced an operational incident relating to its dynamic positioning system. As a result of this operational incident, and a gangway incident that occurred in April 2016, the charterer, Petrobras, initiated an operational review. Until the results of the review are available, Petrobras has suspended its charter hire payments since November 2016. We have completed an investigation to identify the cause of such incidents and have implemented corrective actions. There is a risk that Petrobras may seek to cancel the charter contract resulting from their operational review. If this occurs, the term loan outstanding for the Arendal Spirit UMS, which as at December 31, 2016 had a balance of $127.5 million, could become payable within 180 days of a cancellation. We are working to address Petrobras' concerns to bring the unit back into operations as soon as possible. Should the contract be cancelled, it could result in a reclassification of $112.5 million of long-term debt to the current portion of long-term debt unless we are able to obtain an extension from the lenders. A cancellation of the charter contract or demand for repayment of the loan would adversely affect our result of operations, financial condition and liquidity.

If we lose a key customer, we may be unable to obtain replacement long-term charters or contracts of affreightment and may become subject, with respect to any shuttle tankers redeployed on conventional oil tanker trades, to the volatile spot market, which is highly competitive and subject to significant price fluctuations. If a customer exercises its right under some charters to purchase the vessel, or terminate the charter, we may be unable to acquire an adequate replacement vessel or charter. Any replacement newbuilding would not generate revenues during its construction and we may be unable to charter any replacement vessel on terms as favorable to us as those of the terminated charter.

The loss of any of our significant customers or a reduction in revenues from them could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

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Allegations of improper payments may harm our reputation and business
In May 2016, a former executive of Transpetro, the transportation and logistics subsidiary of Petrobras, alleged in a plea bargain that a subsidiary of ours, among a number of other shipping companies, purportedly made improper payments to local Brazilian agents. Such payments were alleged to have been made by the subsidiary between 2004 and 2006, prior to our initial public offering, in an aggregate amount of approximately 1.5 million Brazilian Reals (less than $0.5 million at the December 31, 2016 exchange rate). Although we believe we have robust anti-corruption programs in place, we have commenced an internal investigation to determine the veracity of these allegations. It is uncertain at this time how these allegations may affect us, if at all, including the possibility of penalties that could be assessed by the relevant authorities. In addition, any dispute with Petrobras in connection with this matter may adversely affect our relationship with Petrobras.

In January 2015, through the Libra joint venture, our 50/50 joint venture with Odebrecht Oil & Gas S.A. (or OOG), we finalized the contract with Petrobras to provide an FPSO unit for the Libra field located in the Santos Basin offshore Brazil. The contract will be serviced by a new FPSO unit converted from our 1995-built shuttle tanker, the Navion Norvegia, which was sold by us to the joint venture. The converted unit is scheduled to commence operations in mid-2017 under a 12-year firm period fixed-rate contract with Petrobras and its international partners. Senior Odebrecht S.A. personnel, including a former executive of OOG, have been implicated in corruption charges related to improper payments to Brazilian politicians and political parties. Any adverse effect of these charges against OOG may harm our growth prospects and results of operations operations and inhibit the near-term ability of our joint venture with OOG to drawdown on the existing loan facility to fund the remaining amount of the Libra FPSO conversion.
We depend on Teekay Corporation and certain joint venture partners to assist us in operating our businesses and competing in our markets.
We have entered into various services agreements with certain direct and indirect subsidiaries of Teekay Corporation pursuant to which those subsidiaries provide to us various services including, in the case of 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, and in the case of Teekay Offshore Partners L.P., various administrative services. Our operational success and ability to execute our growth strategy depend 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.

In addition, we have entered into, and expect to enter into additional, joint venture arrangements with third parties to expand our fleet and access growth opportunities. In particular, we rely on the expertise and relationships that our joint ventures and joint venture partners may have with current and potential customers to jointly pursue FPSO projects and provide assistance in competing in new markets.

Our ability to compete for offshore oil marine transportation, processing, offshore accommodation, support for maintenance and modification projects, towing and offshore installation and storage projects and to enter into new charters or contracts of affreightment and expand our customer relationships depends largely on our ability to leverage our relationship with Teekay Corporation or our joint venture partners and their reputation and relationships in the shipping and offshore industries. If Teekay Corporation or our joint venture partners suffer material damage to their reputation or relationships, it may harm the ability of us or other subsidiaries to:

•renew existing charters and contracts of affreightment upon their expiration;
•obtain new charters and contracts of affreightment;
•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.
A continuation of the significant declines in oil prices may adversely affect our growth prospects and results of operations.
Global crude oil prices have significantly declined since mid-2014. A continuation of lower oil prices or a further decline in oil prices may adversely affect our business, results of operations and financial condition and our ability to make cash distributions, as a result of, among other things:

•
a reduction in exploration for or development of new offshore oil fields, or the delay or cancelation of existing offshore projects as energy companies lower their capital expenditures budgets, which may reduce our growth opportunities;
•
a reduction in or termination of production of oil at certain fields we service, which may reduce our revenues under volume-based contracts of affreightment, production-based components of our FPSO unit contracts or life-of-field contracts;
•
lower demand for vessels of the types we own and operate, which may reduce available charter rates and revenue to us upon redeployment of our vessels, in particular FPSO units, following expiration or termination of existing contracts or upon the initial chartering of vessels, or which may result in extended periods of our vessels being idle between contracts;

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•
customers potentially seeking to renegotiate or terminate existing vessel contracts, failing to extend or renew contracts upon expiration, or seeking to negotiate cancelable contracts;
•
the inability or refusal of customers to make charter payments to us due to financial constraints or otherwise; or
•
declines in vessel values, which may result in losses to us upon vessel sales or impairment charges against our earnings.
Our growth depends on continued growth in demand for offshore oil transportation, processing and storage services, offshore accommodation, and towing and offshore installation services.
Our long-term growth strategy focuses on expansion in the shuttle tanker, FSO, FPSO and towing sectors. Accordingly, our growth depends on continued growth in world and regional demand for these offshore services, which could be negatively affected by a number of factors, such as:

•
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, offshore accommodation or towing and offshore installation services would have a material adverse effect on our future growth and could harm our business, results of operations and financial condition.
Because payments under our contracts of affreightment are based on the volume of oil transported and a portion of the payments under our FPSO units operations contracts are based on the volume of oil produced, utilization of our shuttle tanker fleet, the success of our shuttle tanker business and the revenue from our FPSO units depends upon continued production from existing or new oil fields, which is beyond our control and generally declines naturally over time.
A portion of our shuttle tankers operate under contracts of affreightment. Payments under these contracts of affreightment are based upon the volume of oil transported, which depends upon the level of oil production at the fields we service under the contracts. Payments made to us under FPSO operations contracts are partially based on an incentive component, which is determined by the volume of oil produced. Oil production levels are affected by several factors, all of which are beyond our control, including: geologic factors, including general declines in production that occur naturally over time; mechanical failure or operator error; the rate of technical developments in extracting oil and related infrastructure and implementation costs; the availability of necessary drilling and other governmental permits; the availability of qualified personnel and equipment; strikes, employee lockouts or other labor unrest; and regulatory changes. In addition, the volume of oil produced may be adversely affected by extended repairs to oil field installations or suspensions of field operations as a result of oil spills or otherwise.

The rate of oil production at fields we service may decline from existing levels. If such a reduction occurs, the spot market rates in the conventional oil tanker trades at which we may be able to redeploy the affected shuttle tankers may be lower than the rates previously earned by the vessels under the contracts of affreightment. We have an annual adjustment (within a specified range) to the daily base hire rate under the Voyageur Spirit FPSO operations contract based on our operating performance. Premier Oil may terminate the Voyageur Spirit operations contract if the Huntington field does not yield sufficient revenues, although there is a significant termination fee. Low spot market rates for the shuttle tankers or any idle time prior to the commencement of a new contract or our inability to redeploy any of our FPSO units at an acceptable rate may have an adverse effect on our business and operating results.
The duration of many of our shuttle tanker, FSO and FPSO contracts is the life of the relevant oil field or is subject to extension by the field operator or vessel charterer. If the oil field no longer produces oil or is abandoned or the contract term is not extended, we will no longer generate revenue under the related contract and will need to seek to redeploy affected vessels.
Many of our shuttle tanker contracts have a “life-of-field” duration, which means that the contract continues until oil production at the field ceases. If production terminates or the field is abandoned for any reason, we no longer will generate revenue under the related contract. Other shuttle tanker, FSO and FPSO contracts under which our vessels operate are subject to extensions beyond their initial term. The likelihood of these contracts being extended may be negatively affected by reductions in oil field reserves, low oil prices generally or other factors. If we are unable to promptly redeploy any affected vessels at rates at least equal to those under the contracts, if at all, our operating results will be harmed. Any potential redeployment may not be under long-term contracts, which may affect the stability of our cash flow and our ability to make payments on our Notes and cash distributions.
The redeployment risk of FPSO units is high given their lack of alternative uses and significant costs.
FPSO units are specialized vessels that have very limited alternative uses and high fixed costs. In addition, FPSO units typically require substantial capital investments prior to being redeployed to a new field and production service agreement. These factors increase the

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redeployment risk of FPSO units. Unless extended, two of our FPSO production service agreements will expire in 2018 and a further agreement will expire early 2019. Our clients may also terminate certain of our FPSO production service agreements prior to their expiration under specified circumstances. Any idle time prior to the commencement of a new contract or our inability to redeploy the vessels at acceptable rates may have an adverse effect on our business and operating results.
Future adverse economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.
Commencing in 2007 and 2008, the global economy experienced an economic downturn and crisis in the global financial markets that produced illiquidity in the capital markets, market volatility, and increased exposure to interest rate and credit risks and reduced access to capital markets. Additionally, more recently, global crude oil prices have significantly declined since mid-2014 and this has adversely affected energy and master limited partnership capital markets and available sources of financing. If there is continued economic instability in the future, we may continue to face restricted access to the capital markets or secured debt lenders, such as our revolving credit facilities. This decreased access to such resources could have a material adverse effect on our business, financial condition and results of operations.
Future adverse economic conditions or other developments may affect our customers’ ability to charter our vessels and pay for our services and may adversely affect our business and results of operations.
Future adverse economic conditions or other developments relating directly to our customers may lead to a decline in our customers’ operations or ability to pay for our services, which could result in decreased demand for our vessels and services. Our customers’ inability to pay for any reason could also result in their default on our current contracts and charters. The decline in the amount of services requested by our customers or their default on our contracts with them could have a material adverse effect on our business, financial condition and results of operations.
The results of our shuttle tanker operations in the North Sea are subject to seasonal fluctuations.
Due to harsh winter weather conditions, oil field operators in the North Sea typically schedule oil platform and other infrastructure repairs and maintenance during the summer months. Because the North Sea is one of our primary existing offshore oil markets, this seasonal repair and maintenance activity contributes to quarter-to-quarter volatility in our results of operations, as oil production typically is lower in the second and third quarters in this region compared with production in the first and fourth quarters. Because a portion of our North Sea shuttle tankers operate under contracts of affreightment, under which revenue is based on the volume of oil transported, the results of these shuttle tanker operations in the North Sea under these contracts generally reflect this seasonal production pattern. When we redeploy affected shuttle tankers as conventional oil tankers while platform maintenance and repairs are conducted, the overall financial results for the North Sea shuttle tanker operations may be negatively affected as the rates in the conventional oil tanker markets at times may be lower than contract of affreightment rates. In addition, we seek to coordinate some of the general dry-docking schedule of our fleet with this seasonality, which may result in lower revenues and increased dry-docking expenses during the summer months.
Our recontracting of existing vessels and our future growth depends on our ability to expand relationships with existing customers and obtain new customers, for which we will face substantial competition.
One of our principal objectives is to enter into additional long-term, fixed-rate time charters and contracts of affreightment, including the redeployment of our assets as their current charter contracts expire. The process of obtaining new long-term time charters and contracts of affreightment is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. Shuttle tanker, FSO, FPSO, towing and offshore installation vessel and UMS contracts are awarded based upon a variety of factors relating to the vessel operator, including:

•industry relationships and reputation for customer service and safety;
•experience and quality of ship operations;
•quality, experience and technical capability of the crew;
•relationships with shipyards and the ability to get suitable berths;
•
construction management experience, including the ability to obtain on-time delivery of new vessels or conversions according to customer specifications;
•willingness to accept operational risks pursuant to the charter, such as allowing termination of the charter for force majeure events; and
•competitiveness of the bid in terms of overall price.

We expect competition for providing services for potential offshore projects from other experienced companies, including state-sponsored entities. Our competitors may have greater financial resources than us. This increased competition may cause greater price competition for charters. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a profitable basis, if at all, which would have a material adverse effect on our business, results of operations and financial condition and our ability to make payments on our Notes and cash distributions to unitholders.
Delays in the operational start-up of FPSO units, deliveries of newbuilding vessels or of conversions or upgrades of existing vessels could harm our operating results.

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The operational start-up of FPSO units, the completion of final performance tests of FPSO units, or the deliveries of any newbuildings or vessel conversions or upgrades we may order or undertake could be delayed, which would delay our receipt of revenues under the charters or other contracts related to the units or vessels. In addition, under some charters we may enter into, if the operational start-up or our delivery of the newbuilding or converted vessel to our customer is delayed, we may be required to pay liquidated damages during the delay. For prolonged delays, the customer may terminate the charter and, in addition to the resulting loss of revenues, we may be responsible for substantial liquidated damages.

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

•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 payments on our Notes and cash distributions to unitholders.
Charter rates for towing and offshore installation vessels may fluctuate substantially over time and may be lower when we are attempting to charter our towing and offshore installation vessels, which could adversely affect operating results. Any changes in charter rates for shuttle tankers, FSO or FPSO units and UMS could also adversely affect redeployment opportunities for those vessels.
Our ability to charter our towing and offshore installation vessels will depend, among other things, on the state of the towage market. Towage contracts are highly competitive and are based on the level of projects undertaken by the customer base. There also exists some volatility in charter rates for shuttle tankers, FSO and FPSO units and UMS, which could affect our ability to charter or recharter these vessels at acceptable rates, if at all.
Over time, the value of our vessels may decline, which could adversely affect our operating results.
Values for shuttle tankers, FSO and FPSO units, towing and offshore installation vessels and UMS units can fluctuate substantially over time due to a number of different factors, including:

•
prevailing economic conditions in oil and energy markets;
•
a substantial or extended decline in demand for oil;
•
increases in the supply of vessel capacity;
•
competition from more technologically advanced vessels;
•
the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, or otherwise; and
•
a decrease in oil reserves in the fields in which our FPSO units or other vessels are or might be deployed.

Vessel values may decline from existing levels. If the operation of a vessel is not profitable, or if we cannot re-deploy a vessel at attractive rates upon termination of its contract, rather than continue to incur costs to maintain and finance the vessel, we may seek to dispose of it. Our inability to dispose of the vessel at a reasonable value could result in a loss on its sale and adversely affect our 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.

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

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

•fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
•be unable to hire, train or retain qualified shore and seafaring personnel to manage and operate our growing business and fleet;
•decrease our liquidity by using a significant portion of available cash or borrowing capacity to finance acquisitions;
•significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•incur or assume unanticipated liabilities, losses or costs associated with the business or vessels acquired; or
•incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

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

We may not be successful in our entry into new markets, which may have competitive dynamics that differ from markets in which we already participate, and we may be unsuccessful in gaining acceptance in these markets from customers or competing against other companies with more experience or larger fleets or resources in these markets. We also may not be successful in employing the HiLoad DP unit, which is currently in lay-up, on contracts sufficient to recover our investment in the unit.
Our and many of our customers’ substantial operations outside the United States expose us to political, governmental and economic instability, which could harm our operations.
Because our operations are primarily conducted outside of the United States, they may be affected by economic, political and governmental conditions in the countries where we engage in business, including Brazil, or where our vessels are registered. Any disruption caused by these factors could harm our business, including by reducing the levels of oil exploration, development and production activities in these areas. We derive some of our revenues from shipping oil from politically unstable regions, in particular, our operations in South America. Conflicts in these regions have included attacks on ships and other efforts to disrupt shipping. Hostilities or other political instability in regions where we operate or where we may operate could have a material adverse effect on the growth of our business, results of operations and financial condition and ability to make cash distributions. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in Southeast Asia, the Middle East or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could also harm our business 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.

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Marine transportation and oil production is inherently risky, particularly in the extreme conditions in which many of our vessels operate. An incident involving significant loss of product or environmental contamination by any of our vessels could harm our reputation and business.
Vessels and their cargoes and oil production facilities we service are at risk of being damaged or lost because of events such as:

•marine disasters;
•bad weather;
•mechanical failures;
•grounding, capsizing, fire, explosions and collisions;
•piracy;
•human error; and
•war and terrorism.

A portion of our shuttle tanker fleet and our towage fleet, an FSO unit, and the Voyageur Spirit and Petrojarl Knarr FPSO units operate in the North Sea. Harsh weather conditions in this region and other regions in which our vessels operate may increase the risk of collisions, oil spills, or mechanical failures.

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

•death or injury to persons, loss of property or damage to the environment and natural resources;
•delays in the delivery of cargo;
•loss of revenues from charters or contracts of affreightment;
•liabilities or costs to recover any spilled oil or other petroleum products and to restore the eco-system affected by the spill;
•governmental fines, penalties or restrictions on conducting business;
•higher insurance rates; and
•damage to our reputation and customer relationships generally.

Any of these results could have a material adverse effect on our business, financial condition and operating results. In addition, any damage to, or environmental contamination involving, oil production facilities serviced could suspend that service and result in loss of revenues.
Our insurance may not be sufficient to cover losses that may occur to our property or as a result of our operations.
The operation of shuttle tankers, conventional oil tankers, FSO and FPSO units, towing and offshore installation vessels and UMS, is inherently risky. All risks may not be adequately insured against, and any particular claim may not be paid by insurance. In addition, all but two of our vessels, the Petrojarl Knarr FPSO unit and Libra FPSO unit, are not insured against loss of revenues resulting from vessel off-hire time, based on the cost of this insurance compared to our off-hire experience. Any significant off-hire time of our vessels could harm our business, operating results and financial condition. Any claims relating to our operations covered by insurance would be subject to deductibles, and since it is possible that a large number of claims may be brought, the aggregate amount of these deductibles could be material. Certain insurance coverage is maintained through mutual protection and indemnity associations, and as a member of such associations we may be required to make additional payments over and above budgeted premiums if member claims exceed association reserves.

We may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, more stringent environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic oil spill or marine disaster or natural disaster could exceed the insurance coverage, which could harm our business, financial condition and operating results. Any uninsured or underinsured loss could harm our business and financial condition. In addition, the insurance may be voidable by the insurers as a result of certain actions, such as vessels failing to maintain certification with applicable maritime regulatory organizations.

Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult to obtain. In addition, the insurance that may be available may be significantly more expensive than existing coverage.
We may experience operational problems with vessels that reduce revenue and increase costs.
Shuttle tankers, FSO and FPSO units, towing and offshore installation vessels and UMS are complex and their operations are technically challenging. Marine transportation and oil production operations are subject to mechanical risks and problems as well as environmental risks. Operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and operating results.

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

In addition, oil facilities, shipyards, vessels, pipelines, oil fields or other infrastructure could be targets of future terrorist attacks or warlike operations and our vessels could be targets of pirates, hijackers, terrorists or warlike operations. Any such attacks could lead to, among other things, bodily injury or loss of life, vessel or other property damage, increased vessel operational costs, including insurance costs, and the inability to transport oil to or from certain locations. Terrorist attacks, war, piracy, hijacking or other events beyond our control that adversely affect the distribution, production or transportation of oil to be shipped by us could entitle customers to terminate the charters and impact the use of shuttle tankers under contracts of affreightment, towing and offshore installation vessels under voyage charters and FPSO units under FPSO contracts, which would harm our cash flow and business.
Acts of piracy on ocean-going vessels have continued to be a risk, which could adversely affect our business.
Acts of piracy have historically affected ocean-going vessels trading in regions of the world such as the South China Sea, Gulf of Guinea and the Indian Ocean off the coast of Somalia. While there continues to be a significant risk of piracy in the Gulf of Aden and Indian Ocean, recently there have been increases in the frequency and severity of piracy incidents off the coast of West Africa and a resurgent piracy risk in the Straits of Malacca and surrounding waters. If these piracy attacks result in regions in which our vessels are deployed being named on the Joint War Committee Listed Areas, war risk insurance premiums payable for such coverage can increase significantly and such insurance coverage may be more difficult to obtain. In addition, crew costs, including costs which may be incurred to the extent we employ on-board armed security guards and escort vessels, could increase in such circumstances. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition and 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, British Pound and Brazilian Real under some of our time charters and FPSO contracts. In addition, we have entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which those subsidiaries provide various services to us. 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.

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Many seafaring employees are covered by collective bargaining agreements and the failure to renew those agreements or any future labor agreements may disrupt operations and adversely affect our cash flows.
A significant portion of Teekay Corporation’s seafarers that crew certain of our vessels and Norwegian-based onshore operational staff that provide services to us are employed under collective bargaining agreements. Teekay Corporation may become subject to additional labor agreements in the future. Teekay Corporation may suffer labor disruptions if relationships deteriorate with the seafarers or the unions that represent them. The collective bargaining agreements may not prevent labor disruptions, particularly when the agreements are being renegotiated. Salaries are typically renegotiated annually or bi-annually for seafarers and annually for onshore operational staff and higher compensation levels will increase our costs of operations. Although these negotiations have not caused labor disruptions in the past, any future labor disruptions could harm our operations and could have a material adverse effect on our business, results of operations and financial condition.
Teekay Corporation and certain of our joint venture partners may be unable to attract and retain qualified, skilled employees or crew necessary to operate our business, or may have to pay substantially increased costs for its employees and crew.
Our success depends in large part on Teekay Corporation’s ability to attract and retain highly skilled and qualified personnel. In crewing our vessels, we require technically skilled employees with specialized training who can perform physically demanding work. Any inability we experience in the future to hire, train and retain a sufficient number of qualified employees could impair our ability to manage, maintain and grow our business.
Teekay Corporation and its affiliates may engage in competition with us.
Teekay Corporation and its affiliates may engage in competition with us. Pursuant to an omnibus agreement we entered into in connection with our initial public offering, Teekay Corporation, Teekay LNG Partners L.P. (NYSE: TGP) and their respective controlled affiliates (other than us and our subsidiaries) generally have agreed not to engage in, acquire or invest in any business that owns, operates or charters (a) dynamically-positioned shuttle tankers (other than those operating in the conventional oil tanker trade under contracts with a remaining duration of less than three years, excluding extension options), (b) FSO units or (c) FPSO units (collectively “Offshore Vessels”) without the consent of our general partner. The omnibus agreement, however, allows Teekay Corporation, Teekay LNG Partners L.P. and any of such controlled affiliates to:

•
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;
•
own, operate and charter Offshore Vessels and related time charters or contracts of affreightment acquired as part of a business or package of assets and operating or chartering those vessels if a majority of the value of the total assets or business acquired is not attributable to the Offshore Vessels and related contracts, as determined in good faith by Teekay Corporation’s Board of Directors or the conflicts committee of the Board of Directors of Teekay LNG Partners L.P.’s general partner, as applicable; however, if at any time Teekay Corporation or Teekay LNG Partners L.P. completes such an acquisition, it must, within 365 days of the closing of the transaction, offer to sell the Offshore Vessels and related contracts to us for their fair market value plus any additional tax or other similar costs to Teekay Corporation or Teekay LNG Partners L.P. that would be required to transfer the vessels and contracts to us separately from the acquired business or package of assets; or
•
own, operate and charter Offshore Vessels and related time charters and contracts of affreightment that relate to tenders, bids or awards for an offshore project that Teekay Corporation or any of its subsidiaries submits or receives; however, at least 365 days after the delivery date of any such Offshore Vessel, Teekay Corporation must offer to sell the vessel and related time charter or contract of affreightment to us, with the vessel valued (a) for newbuildings originally contracted by Teekay Corporation, at its “fully-built-up cost” (which represents the aggregate expenditures incurred (or to be incurred prior to delivery to us) by Teekay Corporation to acquire, construct and/or convert and bring such Offshore Vessel to the condition and location necessary for our intended use, plus project development costs for completed projects and projects that were not completed but, if completed, would have been subject to an offer to us) and (b) for any other vessels, Teekay Corporation’s cost to acquire a newbuilding from a third party or the fair market value of an existing vessel, as applicable, plus in each case any subsequent expenditures that would be included in the “fully-built-up cost” of converting the vessel prior to delivery to us.

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

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

•
acquire, operate and charter Offshore Vessels and related time charters and contracts of affreightment if our general partner has previously advised Teekay Corporation or Teekay LNG Partners L.P. that our general partner’s Board of Directors has elected, with the approval of its Conflicts Committee, not to cause us or our controlled affiliates to acquire or operate the vessels and related time charters and contracts of affreightment;
•
acquire up to a 9.9% equity ownership, voting or profit participation interest in any publicly-traded company that engages in, acquires or invests in any business that owns or operates or charters Offshore Vessels and related time charters and contracts of affreightment; or

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

If there is a change of control of Teekay Corporation or of the general partner of Teekay LNG Partners L.P., the non-competition provisions of the omnibus agreement may terminate, which termination could have a material adverse effect on our business, results of operations and financial condition and our ability to make payments on our Notes and cash distributions to unitholders.
Our general partner and its other affiliates own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to those of unitholders.
As at December 31, 2016, Teekay Corporation indirectly owns the 2.0% general partner interest, 27.5% of our common units, and 26.0% of the Series D Preferred Units and the Warrants 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 an officer of our general partner are directors or officer of affiliates of our general partner. Conflicts of interest may arise between Teekay Corporation and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

•
neither our partnership agreement nor any other agreement requires Teekay Corporation or its affiliates (other than our general partner) to pursue a business strategy that favors us or utilizes our assets, and Teekay Corporation’s officers and directors have a fiduciary duty to make decisions in the best interests of the stockholders of Teekay Corporation, which may be contrary to our interests;
•
Two directors of our general partner serve as officers, management or directors of Teekay Corporation and, for one of such individual, a director of the general partner of Teekay LNG Partners L.P.
•
our general partner is allowed to take into account the interests of parties other than us, such as Teekay Corporation, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
•
our general partner has limited its liability and reduced its fiduciary duties under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders and unitholders are treated as having agreed to the modified standard of fiduciary duties and to certain actions that may be taken by our general partner, all as set forth in our partnership agreement;
•
our general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
•
in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions (in each case to affiliates of Teekay Corporation);
•
our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
•
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities on our behalf;
•
our general partner intends to limit its liability regarding our contractual and other obligations;
•
our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80.0% of our common units;
•
our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
•
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
The fiduciary duties of the officers and directors of our general partner may conflict with those of the officers and directors of Teekay Corporation.
Our general partner’s officer and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. Our general partner has a Secretary but does not have a Chief Executive Officer, Chief Financial Officer or any other officers. However, the Secretary and all of the non-independent directors of our general partner also serve as officers, management or directors of Teekay Corporation and/or other affiliates of Teekay Corporation. Consequently, the officer and directors may encounter situations in which their fiduciary obligations to Teekay Corporation or its other affiliates, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders.
Tax Risks
In addition to the following risk factors, you should read Item 4E – Taxation of the Partnership, Item 10 – Additional Information – Material U.S. Federal Income Tax Considerations and Item 10 – Additional Information – Non-United States Tax Consequences for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our common units.

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

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

If the IRS were to determine that we are or have been a PFIC for any taxable year during which a U.S. Holder (as defined below under Item 10 – Additional Information – Material U.S. Federal Income Tax Considerations) held units, such U.S. Holder would face adverse tax consequences. For a more comprehensive discussion regarding the tax consequences to U.S. Holders if we are treated as a PFIC, please read Item 10 – Additional Information: Material U.S. Federal Income Tax Considerations –- United States Federal Income Taxation of U.S. Holders – Consequences of Possible PFIC Classification.
We may be subject to taxes, which reduces our Cash Available for Distribution to partners.
We or our subsidiaries are subject to tax in certain jurisdictions in which we or our subsidiaries are organized, own assets or have operations, which reduces the amount of our cash available for distribution. In computing our tax obligations in these jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions, the applicable authorities will agree with our positions. A successful challenge by a tax authority could result in additional tax imposed on us or our subsidiaries, further reducing the cash available for distribution. We have established reserves in our financial statements that we believe are adequate to cover our liability for any such additional taxes. We cannot assure you, however, that such reserves will be sufficient to cover any additional tax liability that may be imposed on our subsidiaries. In addition, changes in our operations or ownership could result in additional tax being imposed on us or on our subsidiaries in jurisdictions in which operations are conducted. For example, Teekay Corporation indirectly owns less than 50% of the value of our outstanding units and therefore we believe that we do not satisfy the requirements of the exemption from U.S. taxation under Section 883 of the Code and our U.S. source income is subject to taxation under Section 887 of the Code. The amount of such tax will depend upon the amount of income we earn from voyages into or out of the United States, which is not within our complete control.
Unitholders may be subject to income tax in one or more non-U.S. countries, including Canada, as a result of owning our units if, under the laws of any such country, we are considered to be carrying on business there. Such laws may require unitholders to file a tax return with, and pay taxes to, those countries. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for distribution to unitholders.
The unitholders will be subject to tax in one or more countries, including Canada, as a result of owning our units if, under the laws of any such country, we are considered to be carrying on business there. If unitholders are subject to tax in any such country, unitholders may be required to file a tax return with, and pay taxes to, that country based on their allocable share of our income. We may be required to reduce distributions to unitholders on account of any withholding obligations imposed upon us by that country in respect of such allocation to unitholders. The United States may not allow a tax credit for any foreign income taxes that unitholders directly or indirectly incur. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for unitholders.
Item 4.
Information on the Partnership
A.
Overview, History and Development
Overview and History
We are an international provider of marine transportation, oil production, storage, long-distance towing and offshore installation and maintenance and safety services to the offshore oil industry focusing on the deep-water offshore oil regions of the North Sea, Brazil and the

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East Coast of Canada. We were formed as a Marshall Islands limited partnership in August 2006 by Teekay Corporation (NYSE: TK), a portfolio manager and project developer in the marine midstream space. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and our controlled affiliates. As of December 31, 2016, Teekay Corporation, which owns and controls our general partner, owned 27.5% of our limited partner interests.

Please see Item 5. Operating and Financial Review and Prospects – Management Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments and Item 18 - Financial Statements: Note 18 - Acquisitions, for recent acquisitions and developments.

As of December 31, 2016, our fleet consisted of:

•
FPSO Units. Our FPSO fleet consisted of six units, in which we have 100% ownership interests in, four which are operating under FPSO contracts with major energy companies in the North Sea and Brazil, one which is currently undergoing upgrades at the Damen Shipyard in the Netherlands, and one currently in lay-up. We also have two FPSO units, in which we have 50% ownership interests in, one on charter with Petrobras in Brazil and the other which recently completed its conversion into an FPSO unit and is en route for operation in the Libra field in offshore Brazil. We use the FPSO units to provide production, processing and storage services to oil companies operating offshore oil field installations. The FPSO contracts, including the contracts relating to the two FPSO units currently undergoing an upgrade and a conversion, have an average remaining term of approximately 5.1 years. As of December 31, 2016, our FPSO units had a total production capacity of approximately 0.4 million barrels of oil per day, including the expected capacity of the two units currently undergoing an upgrade and a conversion.
•
Shuttle Tankers. Our shuttle tanker fleet consisted of 30 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, three shuttle tanker newbuildings, and the HiLoad DP unit, which is currently in lay-up. Of these 34 shuttle tankers, six are owned through 50%-owned subsidiaries and three were chartered-in. The remaining vessels are owned 100% by us. All of these shuttle tankers, with the exception of the HiLoad DP unit, provide transportation services to energy companies in the North Sea, Brazil and the East Coast of Canada under contracts of affreightment, time charters or bareboat charters. The average term of the contracts of affreightment, weighted based on vessel years, is 2.5 years. The time charters and bareboat charters have an average remaining contract term of approximately 4.7 years. As of December 31, 2016, our shuttle tanker fleet, including newbuildings, had a total cargo capacity of approximately 4.4 million deadweight tonnes (or dwt), representing approximately 39% of the total tonnage of the world shuttle tanker fleet.
•
FSO Units. Our FSO fleet consisted of six units, of which we have a 100% ownership interest and includes one vessel which is completing its conversion into an FSO unit, and one unit of which we have 89% ownership interest in. As of December 31, 2016, one of our FSO units was idle and was classified as held for sale. Our remaining FSO units operate under fixed-rate contracts, with an average remaining term of approximately 3.8 years. As of December 31, 2016, our FSO units had a total cargo capacity of approximately 0.8 million dwt, including the expected capacity of the unit currently undergoing conversion.
•
UMS: We have one UMS unit, the Arendal Spirit. The unit operates on a fixed-rate time-charter contract with a remaining term of approximately 1.4 years. We have 100% ownership interest in this UMS unit.
•
Towing and offshore installation vessels. Our long-distance towing and offshore installation fleet consisted of seven on-the-water vessels and three ultra-long distance towing and offshore installation vessel newbuildings, which are scheduled to deliver during 2017. We have 100% ownership interests in all our towing and offshore installation vessels. All of our delivered towing and offshore installation vessels operate on towage contracts.
•
Conventional Tankers. Our conventional tanker fleet consisted of two in-chartered conventional tankers, which are in-chartered until early-2019 with additional one-year extension options. One vessel is trading fixed on a time-charter-out contract that will expire in May 2018 and the other vessel was trading in the spot conventional tanker market. As of December 31, 2016, our conventional tankers had a total cargo capacity of approximately 0.2 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 offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530.
Potential Additional Shuttle Tanker, FSO and FPSO Projects
Please see Item 5. Operating and Financial Review and Prospects – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Potential Additional Shuttle Tanker, FSO and FPSO Projects for possible future vessel acquisitions.
B.
Business Overview
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

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inexpensive solution compared to the new construction of other floating production systems. A majority of the cost of an FPSO unit comes from its top-side production equipment and thus, FPSO units are expensive relative to conventional tankers. An FPSO unit carries on board all the necessary production and processing facilities normally associated with a fixed production platform. As the name suggests, FPSO units are not fixed permanently to the seabed but are designed to be moored at one location for long periods of time. In a typical FPSO unit installation, the untreated 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 the mix of oil, gas and water from the ocean floor to the vessel, which processes it on board. The resulting crude oil is stored in the hull of the vessel and subsequently transferred to tankers either via a buoy or tandem loading system for transport to shore.

Traditionally for large field developments, the major oil companies have owned and operated new, custom-built FPSO units. FPSO units for smaller fields have generally been provided by independent FPSO contractors under life-of-field production contracts, where the contract’s duration is for the useful life of the oil field. FPSO units have been used to develop offshore fields around the world since the late 1970s. As of December 31, 2016, there were approximately 191 FPSO units operating and 18 FPSO units on order in the world fleet. At December 31, 2016, we owned six FPSO units, of which we have 100% ownership interests in, one of which is currently undergoing upgrades at the Damen Shipyard in the Netherlands, and two FPSO units, of which we have 50% ownership interests in, one of which has completed its conversion into an FPSO unit and is en route for operation in the Libra field in offshore Brazil. Most independent FPSO contractors have backgrounds in marine energy transportation, oil field services or oil field engineering and construction. Other major independent FPSO contractors are SBM Offshore N.V., BW Offshore, MODEC, Bumi Armada and Bluewater.

The following table provides additional information about our FPSO units as of December 31, 2016:
Vessel
 
Production Capacity (bbl/day)
 
Built
 
Ownership
 
Field name and location
 
Charterer
 
Contract End Date
Petrojarl Knarr (1) (2)
 
63,000

 
2014
 
100
%
 
Knarr, Norway
 
Shell
 
March 2025
Libra EWT (3)
 
50,000

 
2017
 
50
%
 
Libra, Brazil
 
Petrobras
 
March 2029
Cidade de Itajai (1) (4)
 
80,000

 
2012
 
50
%
 
Bauna and Piracaba, Brazil
 
Petrobras
 
February 2022
Voyageur Spirit (1)
 
30,000

 
2008
 
100
%
 
Huntington, U.K.
 
Premier
 
April 2018
Petrojarl Cidade de Rio das Ostras (5)
 
25,000

 
2008
 
100
%
 
Tartaruga Verde, Brazil
 
Petrobras
 
Jan 2018
Piranema Spirit (1)
 
30,000

 
2007
 
100
%
 
Piranema, Brazil
 
Petrobras
 
February 2019
Petrojarl I (6)
 
46,000

 
1986
 
100
%
 
Atlanta, Brazil
 
QGEP
 
December 2022
Petrojarl Varg (7)
 
57,000

 
1998
 
100
%
 
 
 
 
 
 
Total capacity
 
381,000

 
 
 
 
 
 
 
 
 
 
(1)
The charterer has options to extend the service contract.
(2)
The charterer has the annual right to terminate the contract after March 2021 subject to payment of certain termination fees.
(3)
The vessel is currently undergoing conversion into an FPSO unit for employment on the Libra field. The original hull was built in 1995. The unit is expected to commence its 12-year firm-period fixed-rate contract in mid-2017.
(4)
The Cidade de Itajai was converted to an FPSO unit in 2012. The original hull was built in 1985.
(5)
The Petrojarl Cidade de Rio das Ostras was converted to an FPSO unit in 2008. The original hull was built in 1981.
(6)
The Petrojarl I is currently undergoing upgrades. The unit is scheduled to commence operations in late-2017 under a five-year fixed-rate charter contract.
(7)
The Petrojarl Varg is in lay-up in Stavanger, Norway harbour.

During 2016, approximately 46% of our consolidated net revenues from continuing operations were earned by our FPSO units, compared to approximately 47% in 2015 and 39% in 2014. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

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

Our shuttle tankers are primarily subject to long-term, fixed-rate time-charter contracts for a specific offshore oil field or under contracts of affreightment for various fields. The number of voyages performed under these contracts of affreightment normally depends upon the oil production of each field. Competition for charters is based primarily upon price, availability, the size, technical sophistication, age and condition of the vessel and the reputation of the vessel’s manager. Although the size of the world shuttle tanker fleet has been relatively unchanged in recent years, conventional tankers could be converted into shuttle tankers by adding specialized equipment to meet customer requirements. Shuttle tanker demand may also be affected by the possible substitution of sub-sea pipelines to transport oil from offshore production platforms. The shuttle tankers in our contract of affreightment fleet may operate in the conventional spot market during downtime or maintenance periods for oil field installations or otherwise, which provides greater capacity utilization for the fleet.

As of December 31, 2016, there were approximately 100 vessels in the world shuttle tanker fleet (including 12 newbuildings), the majority of which operate in the North Sea and Brazil. Shuttle tankers also operate off the East Coast of Canada and in the U.S. Gulf. As of December 31, 2016, we owned 31 shuttle tankers (including three vessels under construction and the HiLoad DP unit), in which our ownership interests ranged from 50% to 100%, and chartered-in an additional three shuttle tankers. Other shuttle tanker owners include Knutsen NYK Offshore Tankers AS, SCF Group, Viken Shipping and AET, which as of December 31, 2016 controlled fleets ranging from 4 to 29 shuttle tankers each. We believe that we have competitive advantages in the shuttle tanker market as a result of the quality, type and dimensions of our vessels combined with our market share in the North Sea, Brazil and the East Coast of Canada.

The following tables provide additional information about our shuttle tankers as of December 31, 2016:

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Vessel
Capacity (dwt)
 
Built
 
Ownership
 
Positioning System
 
Operating Region
 
Contract Type(1)
 
Charterer
 
Contract End Date
 
 
Scott Spirit
109,300
 
2011
 
100%
 
DP2
 
North Sea
 
CoA
 
Chevron, Hess, ENI, Draugen Transport, Aker BP, ConocoPhillips, Total, Talisman, Nexen, Dana Petroleum, Shell, Statoil, OMV, Maersk Oil, Wintershall, Idemitsu, Rwe-Dea, Det Norske Oljeselslcap, Lundin, PGING, Itacha, Enquest, Premier, Marathon, TAQA(6)
 
 
 
Amundsen Spirit
109,300
 
2010
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Grena Knutsen
148,600
 
2003
 
In-chartered (until September 2019)
 
DP2
 
North Sea
 
CoA
 
 
 
 
Stena Natalita
108,100
 
2001
 
50%(5)
 
DP2
 
North Sea
 
CoA
 
 
 
 
Navion Oslo
100,300
 
2001
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Navion Oceania
126,400
 
1999
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Navion Anglia
126,400
 
1999
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Navion Scandia
126,700
 
1998
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Navion Britannia(2)
124,200
 
1998
 
100%
 
DP2
 
North Sea
 
CoA
 
 
 
 
Samba Spirit
154,100
 
2013
 
100%
 
DP2
 
Brazil
 
TC
 
Shell
 
June 2023
 
Lambada Spirit
154,000
 
2013
 
100%
 
DP2
 
Brazil
 
TC
 
Shell
 
July 2023
 
Bossa Nova Spirit
155,000
 
2013
 
100%
 
DP2
 
Brazil
 
TC
 
Shell
 
November 2023
 
Sertanejo Spirit
155,000
 
2013
 
100%
 
DP2
 
Brazil
 
TC
 
Shell
 
January 2024
 
Peary Spirit
109,300
 
2011
 
100%
 
DP2
 
North Sea
 
TC
 
Statoil (7)
 
 
 
Nansen Spirit
109,300
 
2010
 
100%
 
DP2
 
North Sea
 
TC
 
Statoil (7)
 
 
 
Stena Sirita
126,900
 
1999
 
50%(5)
 
DP2
 
North Sea
 
TC
 
Esso
 
January 2019
 
Stena Alexita
127,000
 
1998
 
50%(5)
 
DP2
 
North Sea
 
TC
 
Statoil (7)
 
 
 
Jasmine Knutsen(3)
148,600
 
2005
 
In-chartered (until October 2017)
 
DP2
 
Canada
 
TC
 
ExxonMobil, Canada Hibernia, Chevron, Husky, Mosbacher, Murphy, Nalcor, Statoil, Suncor(6)
 
October 2017
 
Heather Knutsen(3)
148,600
 
2005
 
In-chartered (until December 2017)
 
DP2
 
Canada
 
TC
 
 
December 2017
 
Navion Hispania(3)
126,200
 
1999
 
100%
 
DP2
 
Canada
 
TC
 
 
April 2018
 
Beothuk Spirit(3)
155,000
 
2017
 
100%
 
DP2
 
Canada
 
NB
 
 
May 2030
 
Norse Spirit(3)
155,000
 
2017
 
100%
 
DP2
 
Canada
 
NB
 
 
May 2030
 
Dorset Spirit(3)
155,000
 
2018
 
100%
 
DP2
 
Canada
 
NB
 
 
May 2030
 
Navion Gothenburg
152,200
 
2006
 
50%(5)
 
DP2
 
Brazil
 
BB
 
Petrobras(8)
 
July 2020
 
Nordic Brasilia
151,300
 
2004
 
100%
 
DP
 
Brazil
 
BB
 
Petrobras(8)
 
July 2017
 
Nordic Rio
151,300
 
2004
 
50%(5)
 
DP
 
Brazil
 
BB
 
Petrobras(8)
 
July 2017
 
Navion Stavanger
148,700
 
2003
 
100%
 
DP2
 
Brazil
 
BB
 
Petrobras(8)
 
July 2019
 
Petroatlantic
93,000
 
2003
 
100%
 
DP2
 
North Sea
 
BB
 
Teekay Corporation
 
March 2017(9)
 
Petronordic
93,000
 
2002
 
100%
 
DP2
 
North Sea
 
BB
 
Teekay Corporation
 
March 2017(9)
 
Nordic Spirit
151,300
 
2001
 
100%
 
DP
 
Brazil
 
BB
 
Petrobras(8)
 
April 2018
 
Stena Spirit
151,300
 
2001
 
50%(5)
 
DP
 
Brazil
 
BB
 
Petrobras(8)
 
July 2018
 
Navion Bergen
105,600
 
2000
 
100%
 
DP2
 
Brazil
 
BB
 
Petrobras(8)
 
April 2020
 
Navion Marita
103,900
 
1999
 
100%
 
DP
 
Far-East
 
Spot
 
 
 
 
 
HiLoad DP Unit(4)
  n/a
 
2010
 
100%
 
DP
 
Canary Islands
 
Lay-up
 
 
 
 
 
Total capacity
4,359,900
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
“CoA” refers to contracts of affreightment, "TC" refers to time charters, "BB" refers to bareboat charters, "NB" refers to newbuilding.
(2)
The vessel is capable of loading from a submerged turret loading buoy.
(3)
The three newbuildings in the above table are expected to be delivered in the fourth quarter of 2017 through the first half of 2018. These newbuildings will replace the three existing vessels servicing the East Coast of Canada, including two third-party owned vessels chartered-in to us, and continue on the existing time-charter contracts until May 2030.
(4)
Self-propelled DP system that attaches to and keeps conventional tankers in position when loading from offshore installations.
(5)
Owned through a 50% owned subsidiary. The parties share in the profits and losses of the subsidiary in proportion to each party’s relative ownership.
(6)
Not all of the contracts of affreightment or time-charter customers utilize every ship in the contract of affreightment or time-charter fleet.
(7)
Under the terms of a master agreement with Statoil, the vessels are chartered under individual fixed-rate annually renewable time-charter contracts. The number of vessels may be adjusted annually based on the requirements of the fields serviced. It is expected that between one and three vessels will be required by Statoil annually. Statoil will require three vessels during 2017. The vessels currently on time-charter to Statoil may be replaced by vessels currently servicing contracts of affreightment or other time-charter contracts.
(8)
Charterer has the right to purchase the vessel at end of the bareboat charter.

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(9)
In the process of finalizing an agreement for a five-year time-charter contract with Teekay Corporation effective April 1, 2017.

On the Norwegian continental shelf, regulations have been imposed on the operators of offshore fields related to vaporized crude oil that is formed and emitted during loading operations and which is commonly referred to as Volatile Organic Compounds (or VOC). To assist the oil companies in their efforts to meet the regulations on VOC emissions from shuttle tankers, we and Teekay Corporation have played an active role in establishing and participating in a unique co-operation among 25 owners of offshore fields in the Norwegian sector. The purpose of the co-operation is to implement VOC reduction systems on selected shuttle tankers to reduce and report VOC emissions according to Norwegian authorities’ requirements. Currently, we own VOC systems on 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 2016, approximately 42% of our consolidated net revenues from continuing operations were earned by the vessels in the shuttle tanker segment, compared to approximately 41% in 2015 and 52% in 2014. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.

Historically, the utilization of shuttle tankers in the North Sea is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our vessels and to the offshore oil platforms. Downtime for repairs and maintenance generally reduces oil production and, thus, transportation requirements.
FSO Segment
FSO units provide on-site storage for oil field installations that have no storage facilities or that require supplemental storage. An FSO unit is generally used in combination with a jacked-up fixed production system, floating production systems that do not have sufficient storage facilities or as supplemental storage for fixed platform systems, which generally have some on-board storage capacity. An FSO unit is usually of similar design to a conventional tanker, but has specialized loading and off-take systems required by field operators or regulators. FSO units are moored to the seabed at a safe distance from a field installation and receive cargo from the production facility via a dedicated loading system. An FSO unit is also equipped with an export system that transfers cargo to shuttle or conventional tankers. Depending on the selected mooring arrangement and where they are located, FSO units may or may not have any propulsion systems. Conversions, which include installation of a loading and off-take system and hull refurbishment, can generally extend the lifespan of a vessel as an FSO unit by up to 20 years over the normal conventional tanker lifespan of 25 years.

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

As of December 31, 2016, there were approximately 94 FSO units operating and five FSO units on order in the world fleet, and we had seven FSO units in which our ownership interests ranged from 89% to 100%, including one vessel completing its conversion into an FSO unit. The major markets for FSO units are Asia, West Africa, Northern Europe, the Mediterranean and the Middle East. Our primary competitors in the FSO market are conventional tanker owners who have access to tankers available for conversion, and oil field services companies and oil field engineering and construction companies who compete in the floating production system market. Competition in the FSO market is primarily based on price, expertise in FSO operations, management of FSO conversions and relationships with shipyards, as well as the ability to access vessels for conversion that meet customer specifications.

The following table provides additional information about our FSO units as of December 31, 2016:
Vessel
 
Capacity (dwt)
 
Built
 
Ownership
 
Field name and location
 
Contract Type
 
Charterer
 
Contract End Date
Suksan Salamander (1)
 
78,200

 
1993
 
100%
 
Bualuang, Thailand
 
Bareboat
 
Teekay Corporation
 
August 2024
Pattani Spirit (1)
 
113,800

 
1988
 
100%
 
Platong, Thailand
 
Bareboat
 
Teekay Corporation
 
April 2019
Dampier Spirit (1)
 
106,700

 
1987
 
100%
 
Stag, Australia
 
Time charter
 
Apache Energy
 
October 2024
Falcon Spirit (1)
 
124,500

 
1986
 
100%
 
Al Rayyan, Qatar
 
Time charter
 
Occidental Qatar Energy
 
June 2017
Apollo Spirit (2)
 
129,000

 
1978
 
89%
 
Banff, U.K.
 
Bareboat
 
Teekay Corporation
 
July 2018
Gina Krog (1)(3)
 
124,500

 
1995
 
100%
 
Gina Krog, Norway
 
Conversion
 
Statoil
 
May 2020
Navion Saga (4)
 
149,000

 
1991
 
100%
 

 
Lay-up
 
 
 
 
Total capacity
 
825,700

 
 
 
 
 
 
 
 
 
 
 
 
(1)
Charterer has option to extend the time charter.
(2)
Charterer is required to charter the vessel for as long as Teekay Corporation’s Petrojarl Banff FPSO unit produces in the Banff field in the North Sea, which is expected to remain under contract until at least July 2018.
(3)
The vessel is completing its conversion into an FSO unit. The FSO unit is expected to commence its three-year time-charter contract plus 12 one-year extension options in mid-2017.
(4)
As at December 31, 2016 the vessel was in lay-up and was classified as held for sale.


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During 2016, approximately 5% of our consolidated net revenues from continuing operations were earned by the vessels in the FSO segment, compared to 5% in 2015 and 6% in 2014. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.
UMS Segment
Units for Maintenance and Safety are used primarily for offshore accommodation, storage and support for maintenance and modification projects on existing offshore installations, or during the installation and decommissioning of large floating exploration, production and storage units, including FPSO units, FLNG units and floating drill rigs. Our unit is available for world-wide operations, excluding operations within the Norwegian Continental Shelf, and include DP3 keeping systems that are capable of operating in deep water and harsh weather. As of December 31, 2016, there were approximately 43 DP UMS operating and 21 units on order in the world fleet.

The Arendal Spirit UMS, was delivered to us in February 2015 and commenced its three-year time-charter contract in June 2015. In early-November 2016, the Arendal Spirit UMS experienced an operational incident relating to its dynamic positioning system. As a result of this operational incident, and a gangway incident that occurred in April 2016, the charterer, Petrobras, initiated an operational review. Until the results of the review are available, Petrobras has suspended its charter hire payments from November 2016. We completed an investigation to identify the cause of such incidents and implemented corrective actions. There is a risk that Petrobras may seek to cancel the charter contract resulting from their operational review.

The following table provides additional information about our UMS as of December 31, 2016:
Vessel
 
Berths
 
Built
 
Ownership
 
Location
 
Contract type
 
Charterer
 
Contract End Date
Arendal Spirit
 
500

 
2015
 
100
%
 
Brazil
 
Time charter
 
Petrobras
 
June 2018
Total capacity
 
500

 
 
 
 
 
 
 
 
 
 
 
 

During the second quarter of 2016, we canceled the UMS construction contracts for two UMS newbuildings.

During 2016, approximately 3% of our consolidated net revenues from continuing operations were earned by the UMS segment compared to 3% in 2015 and $nil in 2014. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.
Towage Segment
Long-distance towing and offshore installation vessels are used for the towage, station-keeping, installation and decommissioning of large floating objects such as exploration, production and storage units, including FPSO units, floating liquefied natural gas (or FLNG) units and floating drill rigs. We operate with high-end vessels which can be defined as long-distance towing and offshore installation vessels with a bollard pull of greater than 190 tonnes and a fuel capacity of more than 2,000 metric tonnes. Our focus is on intercontinental towage requiring trans-ocean movements.

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

As of December 31, 2016, there were approximately 27 long-distance towing and offshore installation vessels with a bollard pull greater than 150 tonnes, which is the minimum specification for vessels in direct competition with us, operating and three long-distance towing and offshore installation vessels on order in the world fleet. At December 31, 2016, our towage fleet includes ten long-distance towing and offshore installation vessels (including three newbuildings, which are all scheduled to deliver during 2017), all of which we have 100% ownership interest in.

The following table provides additional information about our towing and offshore installation vessels as of December 31, 2016:
Vessel
 
Bollard Pull (tonnes)
 
Built
 
Ownership
 
Contract Type
ALP Striker
 
309

 
2016
 
100
%
 
Voyage-charter
ALP Centre
 
298

 
2010
 
100
%
 
Voyage-charter
ALP Guard
 
298

 
2009
 
100
%
 
Voyage-charter
ALP Forward
 
218

 
2007
 
100
%
 
Voyage-charter
ALP Winger
 
219

 
2007
 
100
%
 
Voyage-charter
ALP Ace
 
192

 
2006
 
100
%
 
Voyage-charter
ALP Ippon
 
207

 
2006
 
100
%
 
Voyage-charter
ALP Defender (1)
 
306

 
2017
 
100
%
 
 
ALP Sweeper (1)
 
306

 
2017
 
100
%
 
 
ALP Keeper (1)
 
306

 
2017
 
100
%
 
 
 
 
2,659

 
 
 
 
 
 
(1)
Newbuilding scheduled for delivery in 2017.

33



During 2016, approximately 2% of our consolidated net revenues from continuing operations were earned by the vessels in the towage segment compared to 2% in 2015 and $nil in 2014. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.
Conventional Tanker Segment
Conventional oil tankers are used primarily for transcontinental seaborne transportation of oil. As used in this discussion, “conventional” oil tankers exclude those vessels that can carry dry bulk and ore, tankers that currently are used for storage purposes and shuttle tankers.

In March 2016, we sold our two conventional tankers and subsequently chartered-in both vessels for three years each; both with additional one-year extension options. One vessel is fixed on a time-charter-out contract that expires in May 2018 and the other vessel is trading in the spot conventional tanker market.

The following table provides information about our conventional tankers as of December 31, 2016:
Vessel
 
Capacity (dwt)
 
Built
 
Ownership
 
Contract Type
 
Charterer
 
Contract End Date
Blue Pride (2)
 
115,000

 
2004
 
In-chartered (until March 2019)
 
Spot(1)
 
 
 
 
Blue Power (3)
 
106,400

 
2003
 
In-chartered (until March 2019)
 
Time charter
 
Ruhai Shipping
 
May 2018
Total capacity
 
221,400

 
 
 
 
 
 
 
 
 
 
(1)
“Spot” refers to spot conventional tanker market.
(2)
Blue Pride was formerly known as Kilimanjaro Spirit.
(3)
Blue Power was formerly known as Fuji Spirit.

During 2016, approximately 2% of our consolidated net revenues from continuing operations were earned by the vessels in the conventional tanker segment, compared to 2% in 2015 and 3% in 2014. All earnings from discontinued operations in 2012 and 2013 were from the conventional tanker segment. Please read Item 5 – Operating and Financial Review and Prospects: Results of Operations.
Business Strategies
Our primary business objective is to increase distributable cash flow per limited partner unit by executing the following strategies:

•
Project management and execution of our growth projects mostly secured on long-term contracts. We continue to focus on executing on our existing shuttle tanker, FPSO, FSO and towing and offshore installation growth projects delivering between now and 2018, to provide stable cash flows.
•
Extend contracts and redeploy existing assets on long-term contracts. Over the near-to-medium term, we intend to extend contracts and redeploy existing shuttle tankers and FPSO and FSO units on medium-to-long-term contracts, rather than ordering new vessels. We believe this approach reduces our financing requirements and provides our customers with a quick-to-market and lower cost offshore solution, which significantly lowers our customers’ break-even and lifting cost per barrel of oil production, compared to a new vessel. We believe we are well-positioned to extend contracts and redeploy existing assets by leveraging our engineering and operational expertise with our global marketing organization and extensive customer and shipyard relationships.
•
Provide superior customer service by maintaining high reliability, safety, environmental and quality standards, while implementing and maintaining various cost saving initiatives. Energy companies seek partners that have a reputation for high reliability, safety, environmental and quality standards. We intend to leverage our operational expertise and customer relationships to further expand a sustainable competitive advantage with consistent delivery of superior customer service, including working together with customers to reduce production costs and find efficiencies, while at the same time implementing and maintaining our own cost saving initiatives.
Customers
We provide marine transportation, production, storage, long-distance towing and offshore installation and maintenance and safety services to energy and oil service companies or their affiliates. Our largest customer measured by annual revenue is Shell, which is a global group of energy and petrochemical companies.

Shell, Petrobras and Premier Oil accounted for approximately 30%, 19% and 10%, respectively, of our consolidated revenues from continuing operations during 2016. Shell, Petrobras, Statoil and Premier Oil accounted for approximately 26%, 18%, 11% and 11%, respectively, of our consolidated revenues from continuing operations during 2015. Petrobras, Statoil, Premier Oil and Repsol S.A. accounted for approximately 22%, 19%, 12% and 11%, respectively, of our consolidated revenues from continuing operations during 2014. No other customer accounted for 10% or more of such consolidated revenues during 2016, 2015 or 2014.
Safety, Management of Vessel Operations and Administration

34


Safety and environmental compliance are our top operational priorities. We operate our vessels in a manner intended to protect the safety and health of our employees, the general public and the environment. We seek to manage the risks inherent in our business and are committed to eliminating incidents that threaten the safety and integrity of our vessels, such as groundings, fires, collisions and petroleum spills. Our Quality Assurance and Training Officers (or QATO) program focuses on conducting rigorous internal audits of our processes and provide our seafarers with on-board training. We have a behavior-based safety program called “Safety in Action” to improve the safety culture in our fleet. We are also committed to reducing our emissions and waste generation. Teekay Corporation's “Operational Leadership, The Journey” is delivered to all employees which sets out the operational expectations, individual responsibilities and commitment to working safely and living Teekay’s vision through a positive and responsible attitude.

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

We, through certain of our subsidiaries, assist our operating subsidiaries in managing their ship operations. All vessels are operated under our comprehensive and integrated Safety Management System that complies with the International Safety Management Code (or ISM Code), the International Standards Organization’s (or ISO) 9001 for Quality Assurance, ISO 14001 for Environment Management Systems, Occupational Health and Safety Assessment Series (or OHSAS) 18001 and the Maritime Labor Convention 2006 (or MLC 2006) that became effective in 2013. The management system is certified by DNV-GL. It has also been separately approved by the Australian flag administrations. Although certification is valid for five years, compliance with the above mentioned standards is confirmed on a yearly basis by a rigorous auditing procedure that includes both internal audits as well as external verification audits by DNV-GL and applicable flag states.

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

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

•
vessel maintenance (including repairs and dry docking) and certification;
•
crewing by competent seafarers;
•
procurement of stores, bunkers and spare parts;
•
management of emergencies and incidents;
•
supervision of shipyard and projects during new-building and conversions;
•
insurance; and
•
financial management services.

These functions are supported by on-board and on-shore systems for maintenance, inventory, purchasing and budget management.

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

We believe that the generally uniform design of some of our existing vessels and the adoption of common equipment standards provides operational efficiencies, including with respect to crew training and vessel management, equipment operation and repair, and spare parts ordering.
Risk of Loss, Insurance and Risk Management
The operation of any ocean-going vessel carries an inherent risk of catastrophic marine disasters, death or injury of persons and property losses caused by adverse weather conditions, mechanical failures, human error, war, terrorism, piracy and other circumstances or events. In addition, the transportation of crude oil and petroleum products is subject to the risk of spills and to business interruptions due to political circumstances in foreign countries, hostilities, labor strikes, sanctions and boycotts. The occurrence of any of these events may result in loss of revenues or increased costs.

We carry hull and machinery (marine and war risks) and protection and indemnity insurance coverage to protect against most of the accident-related risks involved in the conduct of our business. Hull and machinery insurance covers loss of or damage to a vessel due to marine perils such as collisions, grounding and weather. Protection and indemnity insurance indemnifies against other liabilities incurred while operating vessels, including injury to the crew, third parties, cargo loss and pollution. The current range of our coverage for third party liability and pollution is $500 million to $1 billion per vessel per incident. We also carry insurance policies covering war risks (including piracy and terrorism).

Under bareboat charters, the customer is responsible to insure the vessel. We believe that current insurance coverage is adequate to protect against most of the accident-related risks involved in the conduct of our business and that we maintain appropriate levels of environmental damage and pollution coverage. However, we cannot assure that all covered risks are adequately insured against, that any particular claim

35


will be paid or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future. More stringent environmental regulations at times in the past have resulted in increased costs for, and may result in the lack of availability of, insurance against the risks of environmental damage or pollution. All, but two of our vessels, the Petrojarl Knarr FPSO unit and the Libra FPSO unit, are not insured against loss of revenues resulting from vessel off-hire time, based on the cost of this insurance compared to our off-hire experience.

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

36


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

The applicable classification society certifies that the vessel’s design and build conforms to the applicable class rules and meets the requirements of the applicable rules and regulations of the country of registry of the vessel and the international conventions to which that country is a signatory. The classification society also verifies throughout the vessel’s life that it continues to be maintained in accordance with those rules. In order to validate this, the vessels are surveyed by the classification society in accordance with the classification society rules, which in the case of our vessels follows a comprehensive five-year special survey cycle, renewed every fifth year. During each five-year period the vessel undergoes annual and intermediate surveys, the scrutiny and intensity of which is primarily dictated by the age of the vessel. We have enhanced the resiliency of the underwater coatings of each vessel hull and marked the hull to facilitate underwater inspections by divers, their underwater areas are inspected in a dry dock at five year intervals. In-water inspection is carried out during the second or third annual inspection (i.e. during an intermediate survey).

In addition to Class surveys, the vessels’ flag state also verifies the condition of the vessel during annual flag state inspections, either independently or by additional authorization to Class. Also, Port State Authorities of a vessel’s port of call are authorized under international conventions to undertake regular and spot checks of vessels visiting their jurisdiction.

Processes followed on board are audited by either the flag state or the classification society acting on behalf of a flag state to ensure that they meet the requirements of the International Management Code for the Safe Operation of Ships and for Pollution Prevention (or ISM Code). DNV-GL typically carries out this task. We also follow an internal process of internal audits undertaken at each office and vessel annually.

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

•
our vessels and operations adhere to our operating standards;
•
the structural integrity of the vessel is being maintained;
•
machinery and equipment is being maintained to give reliable service;
•
we are optimizing performance in terms of speed and fuel consumption; and
•
the vessel’s appearance will support our brand and meet customer expectations.

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

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

Overall we believe that our well-maintained and high-quality vessels provide us with a competitive advantage in the current environment of increasing regulation and customer emphasis on quality of service.
Regulations
General
Our business and the operation of our vessels are significantly affected by international conventions and national, state and local laws and regulations in the jurisdictions in which our vessels operate, as well as in the country or countries of their registration. Because these conventions, laws and regulations change frequently, we cannot predict the ultimate cost of compliance or their impact on the resale price or useful life of our vessels. Additional conventions, laws, and regulations may be adopted that could limit our ability to do business or increase the cost of our doing business and that may materially affect our operations. We are required by various governmental and quasi-governmental agencies to obtain permits, licenses and certificates with respect to our operations. Subject to the discussion below and to the fact that the kinds of permits, licenses and certificates required for the operations of the vessels we own will depend on a number of factors, we believe that we will be able to continue to obtain all permits, licenses and certificates material to the conduct of our operations.
International Maritime Organization (or IMO)
The IMO is the United Nations’ agency for maritime safety and prevention of pollution. IMO regulations relating to pollution prevention for oil tankers have been adopted by many of the jurisdictions in which our tanker fleet operates. Under IMO regulations and subject to limited exceptions, a tanker must be of double-hull construction in accordance with the requirements set out in these regulations, or be of another approved design ensuring the same level of protection against oil pollution. All of our tankers are double-hulled.

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

IMO regulations also include the International Convention for Safety of Life at Sea (or SOLAS), including amendments to SOLAS implementing the International Ship and Port Facility Security Code (or ISPS), the ISM Code, and the International Convention on Load Lines of 1966. The IMO Marine Safety Committee has also published guidelines for vessels with dynamic positioning (or DP) systems, which would apply to shuttle tankers and DP-assisted FSO units and FPSO units. SOLAS provides rules for the construction of and the equipment required for commercial vessels and includes regulations for their safe operation. Flag states which have ratified the convention and the treaty generally employ the classification societies, which have incorporated SOLAS requirements into their class rules, to undertake surveys to confirm compliance.

SOLAS and other IMO regulations concerning safety, including those relating to treaties on training of shipboard personnel, lifesaving appliances, radio equipment and the global maritime distress and safety system, are applicable to our operations. Non-compliance with IMO regulations, including SOLAS, the ISM Code, ISPS and the specific requirements for shuttle tankers, FSO units and FPSO units under the NPD (Norway) and HSE (United Kingdom) regulations, may subject us to increased liability or penalties, may lead to decreases in available insurance coverage for affected vessels and may result in the denial of access to or detention in some ports. For example, the U.S. Coast Guard (or USCG) and European Union authorities have indicated that vessels not in compliance with the ISM Code will be prohibited from trading in U.S. and European Union ports.

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

With regard to offshore support vessels, such as UMS, SOLAS permits certain exemptions and equivalents to be allowed by the relevant vessel’s flag state. The International Code on Intact Stability, 2008 (adopted by IMO Resolution MSC. 267(85) of December 4, 2008) (or IS Code), which became mandatory on July 1, 2010, also applies mandatorily to offshore support vessels (with the exception of certain provisions thereof). In 2016 the IMO’s Maritime Safety Committee (or MSC) adopted amendments to the IS Code relating to ships engaged in anchor handling operations and to ships engaged in lifting and towing operations, including escort towing. These amendments are expected to enter into force on January 1, 2020. The IMO has also developed non-mandatory codes and guidelines which apply to various types or aspects of offshore support vessels. These include, amongst others, the Code of Safe Practice for the Carriage of Cargoes and Persons by Offshore Supply Vessels (the OSV Code) (IMO Resolution A.863(20) of November 27, 1997) as subsequently amended, the Guidelines for the Design and Construction of Offshore Supply Vessels, 2006 (the OSV Guidelines)(IMO Resolution MSC.235(82) of December 1, 2006) as subsequently amended, the Guidelines for the Transport and Handling of Limited Amounts of Hazardous and Noxious Liquid Substances in Bulk on Offshore Support Vessels (the LHNS Guidelines)(IMO Resolution A.673(16)) of October 19, 1989, as subsequently amended, the Code of Safety for Special Purpose Ships, 2008 (Resolution MSC.266(84) of May 13, 2008 as subsequently amended (including amendments adopted in 2016), the Code of Safety for Dynamically Supported Craft (IMO Resolution A.373(X)) of November 17, 1977) as subsequently amended, the Guidelines for Vessels with Dynamic Positioning Systems (MSC/Circ.645 of June 6, 1994) and the Guidelines for Dynamic Positioning System (DP) Operator Training (MSC/Circ.738/Rev. 1 of July 7, 2006).

In addition, the IMO’s MSC has adopted the International Code of Safety for Ships using Gases or other Low-flashpoint Fuels (the IGF Code), which is a mandatory code for ships fueled by gases or other low-flashpoint fuels. The IGF Code, which is applicable from January 1, 2017, sets out mandatory provisions for the arrangement, installation, control and monitoring of machinery, equipment and systems using low-flashpoint fuel, in order to minimize the risk to the ship, its crew and the environment taking into account the nature of these fuels.

Annex VI to the IMO’s International Convention for the Prevention of Pollution from Ships (MARPOL) (or Annex VI) sets limits on sulfur oxide and nitrogen oxide emissions from ship exhausts and prohibits emissions of ozone depleting substances, emissions of volatile compounds from cargo tanks and the incineration of specific substances. Annex VI also includes a world-wide cap on the sulfur content of fuel oil and allows for special "emission control areas" (or ECAs) to be established with more stringent controls on sulfur emissions.

Annex VI also provides for a three-tier reduction in nitrogen oxide (or NOx) emissions from marine diesel engines, with the final tier (‘‘Tier III’’) to apply to engines installed on vessels constructed on or after January 1, 2016 and which operate in the North American ECA or the U.S. Caribbean Sea ECA. The Tier III requirements will also apply to ECAs designated in the future by the IMO. In October 2016 the IMO’s MEPC approved the designation of the North Sea and the Baltic Sea as ECAs for NOx emissions. These two new NOx ECAs and the related amendments to Annex VI of MARPOL are expected to be formally adopted by IMO’s MEPC in 2017 and the two new ECAs are expected to enter into effect on January 1, 2021.

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

The IMO's Ballast Water Management Convention has been adopted by 54 countries, the combined merchant fleets of which represent 53.30% of the gross tonnage of the world’s merchant shipping, and will enter into force on September 8, 2017. The convention stipulates two

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standards for discharged ballast water. The D-1 standard covers ballast water exchange while the D-2 standard covers ballast water treatment. Once effective, the convention will require the implementation of either the D-1 or D-2 standard. There will be a transitional period from the entry into force to the International Oil Pollution Prevention (or IOPP) renewal survey in which ballast water exchange (reg. D-1) can be employed. After the first IOPP renewal survey, vessels will be required to meet the discharge standard D-2 by installing an approved Ballast Water Management System (or BWMS). Ships constructed after entry into force will be required to have a treatment system installed at delivery. Besides the IMO convention, ships sailing in U.S. waters are required to employ a type-approved BWMS which is compliant with USCG regulations. So far the USCG have issued Type Approval (or TA) for the following ballast water treatment systems (or BWTS):

•Alfa Laval;

•Ocean Saver; and

•Optimarin.

We expect the USCG will issue more TA's for BWTS in the future. Plans have been set for the decoupling of IOPP surveys with Harmonized System of Survey and Certification for vessels planning to dock in 2018 with approval from the Flag and Classification Society. We estimate that the installation of approved BWTS may cost between $2 million and $3 million per vessel.

The IMO has also developed and adopted an International Code for Ships Operating in Polar Waters (or Polar Code) which deals with matters regarding design, construction, equipment, operation, search and rescue and environmental protection in relation to ships operating in waters surrounding the two poles. The Polar Code includes both safety and environmental provisions and will be mandatory, with the safety provisions becoming part of SOLAS and the environmental provisions becoming part of MARPOL. In November 2014 the IMO’s MSC adopted the Polar Code and the related amendments to SOLAS in relation to safety, while in May 2015 the IMO’s Marine Environment Protection Committee (or MEPC) adopted the environmental provisions of the Polar Code and associated amendments to MARPOL. The Polar Code has become mandatory for new vessels built after January 1, 2017. For existing ships, this code will be applicable from the first intermediate or renewal survey beginning on or after January 1, 2018.

MARPOL Annex I also states that oil residue may be discharged directly from the sludge tank to the shore reception facility through standard discharge connections. They may also be discharged to the incinerator or to an auxiliary boiler suitable for burning the oil by means of a dedicated discharge pump. Oil residue tanks shall have no discharge connection to the engine room bilge system, bilge tank or OWS except in following cases:

•
the residue tank may be fitted with manually operated self-closing valves and arrangements for subsequent visual monitoring of the settled water that lead to an oily water holding tank or bilge well;

•
the sludge tank discharge piping and bilge water piping may be connected to a common line leading to the standard discharge connection, however the interconnection of line shall not allow for the transfer of sludge to the bilge system; and

•
a screw down non-return valve in lines connecting to the standard discharge connection, provides an acceptable means for not allowing for the transfer of sludge to the bilge system. Ship operators and managers should before the first IOPP renewal survey, ensure that such systems are compliant. In the event that modifications are required, system drawings will be subject to approval.

Annex I is applicable for existing vessels with a first renewal survey beginning on or after January 1, 2017. It is anticipated that most vessels constructed after December 31, 1991 already comply with Annex I as MARPOL has since provided a unified interpretation prohibiting interconnections between sludge and bilge systems.

MSC 91 adopted amendments to SOLAS Regulation II-2/10 to add a new paragraph 10.4, to clarify that a minimum of two-way portable radiotelephone apparatus for each fire party for fire-fighter's communication shall be carried on board. These radio devices shall be of explosion proof type or intrinsically safe type. All existing ships (Built before July 1, 2014) should comply with this requirement not later than the first safety Equipment survey after July 1, 2018. All new vessels constructed (keel laid) on or after July 1, 2014 must comply with this requirement at the time of delivery.

As per MSC. 338(91), Requirements have been highlighted for audio and visual indicators for breathing apparatus' which will alert the user before the volume of the air in the cylinder has been reduced to no less than 200 liters. This applies to ship’s constructed on or after July 1, 2014. Ships constructed before July 1, 2014 must comply no later than July 1, 2019.
European Union (or EU)
Like the IMO, the EU has adopted regulations phasing out single-hull tankers. All of our tankers are double-hulled.

The EU has also adopted legislation (Directive 2009/16/EC on Port State Control as subsequently amended) that: bans from European waters manifestly sub-standard vessels (defined as vessels that have been detained twice by EU port authorities, in the preceding two years); creates obligations on the part of EU member port states to inspect minimum percentages of vessels using these ports annually; provides for increased surveillance of vessels posing a high risk to maritime safety or the marine environment; and provides the EU with greater authority and control over classification societies, including the ability to seek to suspend or revoke the authority of negligent societies. The EU is also considering the adoption of criminal sanctions for certain pollution events, including improper cleaning of tanks (Directive 2009/15/EC as amended by Directive 2014/111/EU of December 17, 2014).

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The EU has adopted a Directive requiring the use of low sulfur fuel. Since January 1, 2015, vessels have been required to burn fuel with sulfur content not exceeding 0.1% while within EU member states’ territorial seas, exclusive economic zones and pollution control zones that are included in SOX Emission Control Areas. Other jurisdictions have also adopted regulations requiring the use of low sulfur fuel. Since January 1, 2014, the California Air Resources Board has also required vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles of California. China also has established emission control areas in the Pearl River Delta, the Yangtze River Delta and the Bohai Bay rim area with restrictions, commencing on January 1, 2016, in the maximum sulfur content of the fuel to be used by vessels within those areas and which limits become progressively stricter over time.

IMO regulations require that as of January 1, 2015, all vessels operating within ECAs worldwide recognized under MARPOL Annex VI must comply with 0.1% sulfur requirements. Currently, the only grade of fuel meeting 0.1% sulfur content requirement is low sulfur marine gas oil (or LSMGO). Since January 1, 2015, the applicable sulfur content limits in the North Sea, the Baltic Sea and the English Channel ECAs have been 0.1%. Other established ECAs under Annex VI to MARPOL are the North American ECA and the United States Caribbean Sea ECA. Certain modifications were necessary in order to optimize operation on LSMGO of equipment originally designed to operate on Heavy Fuel Oil (or HFO). In addition, LSMGO is more expensive than HFO and this will impact the costs of operations. However, for vessels employed on fixed term business, all fuel costs, including any increases, are borne by the charterer. Our exposure to increased cost is in our spot trading vessels, although our competitors bear a similar cost increase as this is a regulatory item applicable to all vessels. All required vessels in our fleet trading to and within regulated low sulfur areas are able to comply with fuel requirements. The global cap on the sulfur content of fuel oil is currently 3.5%, to be reduced to 0.5% by January 1, 2020. The reduced global cap of 0.5% as of January 1, 2020 was subject to a feasibility review, which was completed in 2016 and on the basis of which the IMO’s Marine Environment Protection Committee (or the MEPC) decided in October 2016 to implement the 0.5% global sulfur cap as of January 1, 2020.

The EU Ship Recycling Regulation (1257/2013) entered into force on December 30, 2013. It aims to prevent, reduce and minimize accidents, injuries and other negative effects on human health and the environment when ships are recycled and the hazardous waste they contain is removed. The legislation applies to all ships flying the flag of an EU country and to vessels with non-EU flags that call at an EU port or anchorage. It sets out responsibilities for ship owners and for recycling facilities both in the EU and in other countries. Each new ship has to have on board an inventory of the hazardous materials (such as asbestos, lead or mercury) it contains in either its structure or equipment. The use of certain hazardous materials is forbidden. Before a ship is recycled, its owner must provide the company carrying out the work with specific information about the vessel and prepare a ship recycling plan. Recycling may only take place at facilities listed on the EU ‘List of facilities’. In 2014, the Council Decision 2014/241/EU was adopted, authorizing EU countries having ships flying their flag or registered under their flag to ratify or to accede to the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships. The Regulation is to apply not later than December 31, 2018, although certain of its provisions are to apply at different stages, with some of them being applicable from December 31, 2020. Pursuant to this Regulation, the EU Commission has recently published the first version of a European List of approved ship recycling facilities meeting the requirements of the regulation, as well as four further implementing decisions dealing with certification and other administrative requirements set out in the Regulation.
North Sea, Canada and Brazil
Our shuttle tankers and FPSO units primarily operate in the North Sea and Brazil.

There is no international regime in force which deals with compensation for oil pollution from offshore craft, such as FPSOs. The issue whether the CLC and the International Convention on the Establishment of an International Fund for Compensation for Oil Pollution Damage 1971, as amended by the 1992 Protocol (or the Fund Convention), which deal with liability and compensation for oil pollution and the Convention on Limitation of Liability for Maritime Claims 1976, as amended by the 1996 Protocol to it (or the 1976 Limitation of Liability Convention), which deals with limitation of liability for maritime claims, apply to FPSOs is neither straightforward nor certain. The CLC and the Fund Convention were not drafted with FPSOs and offshore craft in mind and it is doubtful whether FPSOs and any claims for oil pollution caused by them fall within the ambit of the CLC and the Fund Convention. This is due to the definition of “ship” under these conventions and the requirement that oil is “carried” on board the relevant vessel. Nevertheless, the wording of the 1992 Protocol to the CLC leaves room for arguing that FPSOs and oil pollution caused by them can come under the ambit of these conventions for the purposes of liability and compensation. However, the application of these conventions also depends on their implementation by the relevant domestic laws of the countries which are parties to them.

UK’s Merchant Shipping Act 1995, as amended (or the MSA), implements the CLC but uses a wider definition of a “ship” than the one used in the CLC and in its 1992 Protocol but still refers to the criteria used by the CLC. It is therefore doubtful that FPSOs fall within its wording. However, the MSA also includes separate provisions for liability for oil pollution otherwise than under the CLC (section 154 of Chapter III of Part VI of the MSA). These apply to vessels which fall within a much wider definition and include non-seagoing vessels. It is arguable that the wording of these MSA provisions is wide enough to cover oil pollution caused by offshore crafts such as FPSOs. The liability regime under these MSA provisions is similar to that imposed under the CLC but limitation of liability is subject to the 1976 Limitation of Liability Convention regime (as implemented in the MSA),

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


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

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

The EU’s Directive 2004/35/CE on environmental liability with regard to the prevention and remedying of environmental damage (or the Environmental Liability Directive) deals with liability for environmental damage on the basis of the “polluter pays” principle. Environmental damage includes damage to protected species and natural habitats and damage to water and land. Under this Directive, operators whose activities caused the environmental damage or the imminent threat of such damage are to be held liable for the damage (subject to certain exceptions). With regard to environmental damage caused by specific activities listed in the Directive, operators are strictly liable, regardless of fault or negligence. This is without prejudice to their right to limit their liability in accordance with national legislation implementing the 1976 Limitation of Liability Convention. The Directive applies both to damage which has already occurred and where there is an imminent threat of damage. It also requires the relevant operator to take preventive action, to report an imminent threat and any environmental damage to the regulators and to perform remedial measures, such as clean-up. The Environmental Liability Directive has been implemented in the UK by the Environmental Damage (Prevention and Remediation) Regulations 2009.

In June 2013 the EU adopted Directive 2013/30/EU on safety of offshore oil and gas operations and amending Directive 2004/35/EC (or the Offshore Safety Directive). This Directive lays down minimum requirements for member states and the European Maritime Safety Agency for the purposes of reducing the occurrence of major accidents related to offshore oil and gas operations, thus increasing protection of the marine environment and coastal economies against pollution, establishing minimum conditions for safe offshore exploration and exploitation of oil and gas, and limiting disruptions to the EU’s energy production and improving responses to accidents. The Offshore Safety Directive sets out extensive requirements, such as preparation of a major hazard report with risk assessment, emergency response plan and safety and environmental management system applicable to the relevant oil and gas installation before the planned commencement of the operations, independent verification of safety and environmental critical elements identified in the risk assessment for the relevant oil and gas installation, and ensuring that factors such as the applicant’s safety and environmental performance and its financial capabilities or security to meet potential liabilities arising from the oil and gas operations are taken into account when considering granting a license. Under the Offshore Safety Directive, Member States are to ensure that the relevant licensee is financially liable for the prevention and remediation of environmental damage (as defined in the Environmental Liability Directive) caused by offshore oil and gas operations carried out by or on behalf of the licensee or the operator. Member States must lay down rules on penalties applicable to infringements of the legislation adopted pursuant to this Directive. Member States were required to bring into force laws, regulations and administrative provisions necessary to comply with this Directive by 19 July 2015. The Offshore Safety Directive has been implemented in the UK by a number of different UK Regulations, including the Environmental Damage (Prevention and Remediation) (England) Regulations 2015, as amended, (which revoked and replaced the Environmental Damage (Prevention and Remediation) Regulations 2009)) and the Offshore Installations (Offshore Safety Directive)(Safety Case etc.) Regulations 2015, both of which were effective from July 19, 2015.

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

In Norway, the Norwegian Pollution Control Authority requires the installation of Volatile Organic Compound (or VOC) emissions reduction units on most shuttle tankers serving the Norwegian continental shelf. Customers bear the cost to install and operate the VOC equipment on board the shuttle tankers.

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

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NL; and give first consideration to services provided from within NL and to goods manufactured in NL. These regulatory requirements may change as regulations and CNLOPB guidelines are amended or replaced from time to time.

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

Additional requirements and restrictions for the operation of offshore vessels and shuttle tankers are imposed by Law 9.432/97 and by the National Waterway Transport Agency (“ANTAQ”), instituted by Law 10.233/2001, by way of frequently updated administrative resolutions. The transit of vessels and permanence and operation of offshore units in Brazil are further regulated by the Maritime Authorities, through law and administrative Ordinances known as “NORMAM”. Under Brazil’s environmental laws, owners and operators of vessels are strictly liable for damages to the environment. Other penalties for non-compliance with environmental laws include fines, loss of tax incentives and suspension of activities. Operators such as Petrobras may impose additional requirements, such as compliance with specific health, safety and environmental standards or the use of local labor. Additional regulations and requirements may be adopted or imposed that could limit our ability to do business or further increase the cost of doing business in Brazil.
United States
The United States has enacted an extensive regulatory and liability regime for the protection and cleanup of the environment from oil spills, including discharges of oil cargoes, bunker fuels or lubricants, primarily through the Oil Pollution Act of 1990 (or OPA 90) and the Comprehensive Environmental Response, Compensation and Liability Act (or CERCLA). OPA 90 affects all owners, bareboat charterers, and operators whose vessels trade to the United States or its territories or possessions or whose vessels operate in United States waters, which include the U.S. territorial sea and 200-mile exclusive economic zone around the United States. CERCLA applies to the discharge of “hazardous substances” rather than “oil” and imposes strict joint and several liabilities upon the owners, operators or bareboat charterers of vessels for cleanup costs and damages arising from discharges of hazardous substances. We believe that petroleum products should not be considered hazardous substances under CERCLA, but additives to oil or lubricants used on vessels might fall within its scope.

Under OPA 90, vessel owners, operators and bareboat charterers are “responsible parties” and are jointly, severally and strictly liable (unless the oil spill results solely from the act or omission of a third party, an act of God or an act of war and the responsible party reports the incident and reasonably cooperates with the appropriate authorities) for all containment and cleanup costs and other damages arising from discharges or threatened discharges of oil from their vessels. These other damages are defined broadly to include:
 
•
natural resources damages and the related assessment costs;
•
real and personal property damages;
•
net loss of taxes, royalties, rents, fees and other lost revenues;
•
lost profits or impairment of earning capacity due to property or natural resources damage;
•
net cost of public services necessitated by a spill response, such as protection from fire, safety or health hazards; and
•
loss of subsistence use of natural resources.

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

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

OPA 90 also requires owners and operators of vessels to establish and maintain with the 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 ship owners or operators must have a net worth and working capital, measured in assets located in the United States against liabilities located anywhere in the world, that exceeds the applicable amount of financial

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responsibility. We have complied with the Coast Guard regulations by using self-insurance for certain vessels and obtaining financial guarantees from a third party for the remaining vessels. If other vessels in our fleet trade into the United States in the future, we expect to obtain guarantees from third-party insurers.

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

Owners or operators of vessels, including tankers operating in U.S. waters are required to file vessel response plans with the Coast Guard, and their tankers are required to operate in compliance with their Coast Guard approved plans. Such response plans must, among other things:
 
•
address a “worst case” scenario and identify and ensure, through contract or other approved means, the availability of necessary private response resources to respond to a “worst case discharge”;
•
describe crew training and drills; and
•
identify a qualified individual with full authority to implement removal actions.

We have filed vessel response plans with the Coast Guard and have received its approval of such plans. In addition, we conduct regular oil spill response drills in accordance with the guidelines set out in OPA 90. The Coast Guard has announced it intends to propose similar regulations requiring certain vessels to prepare response plans for the release of hazardous substances.

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

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

Our vessels that discharge certain effluents, including ballast water, in U.S. waters must obtain a Clean Water Act 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 dry docking after January 1, 2016. Vessels that are constructed after December 1, 2013 are subject to the ballast water numeric effluent limitations. Several U.S. states have added specific requirements to the Vessel General Permit and, in some cases, may require vessels to install ballast water treatment technology to meet biological performance standards.
Greenhouse Gas Regulation
In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change (or the Kyoto Protocol) was effective. Pursuant to the Kyoto Protocol, adopting countries are required to implement national programs to reduce emissions of greenhouse gases. In December 2009, more than 27 nations, including the United States, entered into the Copenhagen Accord. The Copenhagen Accord is non-binding, but is intended to pave the way for a comprehensive, international treaty on climate change. In December 2015 the Paris Agreement (or the Paris Agreement) was adopted by 195 countries at the 21st Session of the Conference of Parties (commonly known as COP 21, a conference of the countries which are parties to the United Nations Framework Convention on Climate Change; the COP is the highest decision-making authority of this organization). The Paris Agreement deals with greenhouse gas emission reduction measures and targets from 2020 in order to limit the global temperature increases above pre-industrial levels to not more than 1.5 degrees Celsius. Although shipping was ultimately not included in the Paris Agreement, it is expected that the adoption of the Paris Agreement may lead to regulatory changes in relation to curbing greenhouse gas emissions from shipping.

In July 2011, the IMO adopted regulations imposing technical and operational measures for the reduction of greenhouse gas emissions. These regulations formed a new chapter in Annex VI and became effective on January 1, 2013. The technical and operational measures imposed by new regulations include the “Energy Efficiency Design Index” (or the EEDI), which is mandatory for newbuilding vessels, and the “Ship Energy Efficiency Management Plan,” which is mandatory for all vessels. In October 2016, the IMO’s MEPC adopted updated guidelines for the calculation of the EEDI. In addition, the IMO is evaluating various mandatory measures to reduce greenhouse gas emissions from international shipping, which may include market-based instruments or a carbon tax. In October 2014, the IMO’s MEPC agreed in principle to develop a system of data collection regarding fuel consumption of ships. In October 2016, the IMO adopted a mandatory data collection system under which vessels of 5,000 gross tonnages and above are to collect fuel consumption and other data and to report the aggregated data so collected to their flag state at the end of each calendar year. The new requirements are expected to enter into force on March 1, 2018. The IMO also approved a roadmap for the development of a comprehensive IMO strategy on reduction of greenhouse gas emissions from ships with an initial strategy to be adopted in 2018 and a revised strategy to be adopted in 2023.

The EU also has indicated that it intends to propose an expansion of an existing EU emissions trading regime to include emissions of greenhouse gases from vessels, and individual countries in the EU may impose additional requirements. The EU has adopted Regulation (EU) 2015/757 on the monitoring, reporting and verification of CO2 emissions from vessels (or the MRV Regulation), which entered into force

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on July 1, 2015. The regulation aims to quantify and reduce CO2 emissions from shipping. It lists the requirements on monitoring, reporting and verification (MRV) of carbon dioxide emissions and requires ship owners and operators to annually monitor, report and verify CO2 emissions for vessels larger than 5,000 gross tonnage calling at any EU and EFTA (Norway and Iceland) port (with a few exceptions, such as fish-catching or fish-processing vessels). Data collection takes place on a per voyage basis and starts January 1, 2018. The reported CO2 emissions, together with additional data, such as cargo and energy efficiency parameters, are to be verified by independent verifiers and sent to a central database, managed by the European Maritime Safety Agency. To comply with the EU MRV regulation, Teekay Corporation has prepared an EU MRV monitoring plan and an EU MRV monitoring template in line with legislative requirement. The approved EU-MRV monitoring plan is expected to be placed on all our vessels by August 31, 2017. The EU is currently considering a proposal for the inclusion of shipping in the EU Emissions Trading System as from 2021 in the absence of a comparable system operating under the IMO.
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. Procedures are in place to inform the Maritime Security Council Horn of Africa (or MSCHOA ) whenever our vessels are calling in the Indian Ocean Region or West Coast of Africa (or WAC) high risk area. In order to mitigate the security risk, security arrangements are required for vessels which travel through Gulf of Aden and WAC region.


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

Please read Exhibit 8.1 to this Annual Report for a list of our significant subsidiaries as of December 31, 2016.
D.
Properties
Other than our vessels and VOC plants mentioned above, we do not have any material property.
E.
Taxation of the Partnership
United States Taxation
The following is a discussion of the expected material U.S. federal income tax considerations applicable to us. This discussion is based upon the provisions of the Code, legislative history, applicable U.S. Treasury Regulations (or Treasury Regulations), judicial authority and administrative interpretations, all as in effect on the date of this Annual Report, and which are subject to change, possibly with retroactive effect, or are subject to different interpretations. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

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

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

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

Based on our current operations, a substantial portion of our Transportation Income is from sources outside the United States and not subject to U.S. federal income tax. However, certain of our activities give rise to U.S. Source International Transportation Income. Unless the exemption from U.S. taxation under Section 883 of the Code (or the Section 883 Exemption) applies, our U.S. Source International Transportation Income generally is subject to U.S. federal income taxation under either the net basis and branch profits taxes or the 4% gross basis tax, each of which is discussed below.

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

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

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

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

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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.

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

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

The 4% Gross Basis Tax. If the Section 883 Exemption does not apply and we are not subject to the net basis and branch profits taxes described above, we would be subject to a 4% U.S. federal income tax on our gross U.S. Source International Transportation Income, without benefit of deductions. For 2017, we estimate that the U.S. federal income tax on such U.S. Source International Transportation Income will be approximately $260,000 based on the amount of U.S. Source International Transportation Income we earned for 2016. The amount of such tax for which we are liable in any year will depend upon the amount of income we earn from voyages into or out of the United States in such year, however, which is not within our complete control.
Marshall Islands Taxation
Because we and our controlled affiliates do not, and we do not expect that we and our controlled affiliates will, conduct business or operations in the Republic of The Marshall Islands, neither we nor our controlled affiliates are subject to income, capital gains, profits or other taxation under current Marshall Islands law, other than taxes or fees due to (i) the continued existence of legal entities registered in the Republic of the Marshall Islands, (ii) the incorporation or dissolution of legal entities registered in the Republic of the Marshall Islands, (iii) filing certificates (such as certificates of incumbency, merger, or redomiciliation) with the Marshall Islands registrar, (iv) obtaining certificates of goodstanding from, or certified copies of documents filed with, the Marshall Islands registrar, or (v) compliance with Marshall Islands law concerning vessel ownership, such as tonnage tax. As a result, distributions by controlled affiliates to us are not subject to Marshall Islands taxation.
Other Taxation
We and our subsidiaries are subject to taxation in certain non-U.S. jurisdictions because we or our subsidiaries are either organized, or conduct business or operations, in such jurisdictions, but we do not expect any such tax to be material. However, we cannot assure this result as tax laws in these or other jurisdictions may change or we may enter into new business transactions relating to such jurisdictions, which could affect our tax liability. Please read Item 18 – Financial Statements: Note 13 – Income Taxes.
Item 4A.
Unresolved Staff Comments
Not applicable.
Item 5.
Operating and Financial Review and Prospects
The following discussion should be read in conjunction with the financial statements and notes thereto appearing elsewhere in this report.
Management’s Discussion and Analysis of Financial Conditions and Results of Operations
OVERVIEW
We are an international provider of marine transportation, oil production, storage, long-distance towing and offshore installation and maintenance and safety services to the offshore oil industry focusing on the deep-water offshore oil regions of the North Sea, Brazil and the East Coast of Canada. We operate shuttle tankers, floating production, storage and off-loading (or FPSO) units, floating storage and off-take (or FSO) units, units for maintenance and safety (or UMS), long-distance towing and offshore installation vessels and conventional crude oil tankers. As at December 31, 2016, our fleet consisted of 31 shuttle tankers (including three chartered-in vessels and one HiLoad Dynamic Positioning (or DP) unit), six FPSO units, seven FSO units, seven long-distance towing and offshore installation vessels, one UMS and two chartered-in conventional oil tankers, in which our interests range from 50% to 100%. We also have two FPSO upgrades or conversions scheduled for delivery in 2017, three long-distance towing and offshore installation vessel newbuildings scheduled for delivery throughout 2017, and three newbuilding shuttle tankers scheduled for delivery in late-2017 through to mid-2018.

Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, we believe it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, in December 2015, we reduced our quarterly cash distributions to $0.11 per common unit, and our near-to-medium-term business strategy is primarily focused on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects.

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Our distributions paid for 2016 were all paid at this reduced rate. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and will grow as we take delivery of our various capital projects, supported by a large and well-diversified portfolio of fee-based contracts with high-quality counterparties.

In addition to its effect on the energy and capital markets, the decline in global crude oil prices may also result in our vessels being employed on customer contracts that are cancellable or the failure of customers to exercise charter extension options, potentially resulting in increased off-hire for affected vessels. Conversely, we expect that a continuation of lower oil prices will motivate charterers to use existing FPSO units on new projects, given their lower cost relative to a newbuilding unit. Our operational focus over the short-term is to increase the efficiency of our business to ensure we are a cost-effective supplier in the offshore sector, as well as focusing on the redeployment of our assets that are scheduled to come off charter over the next few years.

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

SIGNIFICANT DEVELOPMENTS
Financing Initiatives
During the second quarter of 2016, we completed a series of initiatives to manage our unfunded capital expenditures and upcoming debt maturities, including:

•
obtaining additional bank financing, including a $250 million debt facility for the three East Coast of Canada newbuilding shuttle tankers, a $40 million debt facility for six previously un-mortgaged vessels, and a new $35 million tranche added to an existing debt facility secured by two shuttle tankers;
•
extending $75 million of the outstanding principal amount of an existing revolving credit facility financing for the Petrojarl Varg FPSO unit until late-2017;
•
extending the majority of the principal maturity payments to late-2018 for two of our existing NOK senior unsecured bonds, previously due in January 2017 and January 2018, and agreeing to pay a portion of the outstanding principal amount of these bonds in October 2016, October 2017 and January 2018;
•
agreeing with Teekay Corporation to pay all distributions on our common units to Teekay Corporation, including distributions to our general partner, in common units, instead of cash, until our NOK bonds maturing in 2018 have been fully repaid;
•
agreeing that, until our NOK bonds maturing in 2018 have been repaid, we will only pay distributions in cash to third party holders of our common units if the amount of the cash distributions is matched or exceeded by the proceeds raised through the issuance of additional equity in advance of, or within six months following, the payment of such distributions;
•
extending to January 2019 the maturity date of $200 million in obligations owing to a subsidiary of Teekay Corporation under the terms of a subordinated promissory note, which bears interest at the rate of 10.0% per annum, one half of which will be paid in cash, and the other half of which will be paid in our common units or from the proceeds of the sale of equity securities;
•
issuing $200 million of equity, consisting of (i) $100 million of our 10.5% Series D Preferred Units (with a two-year option to pay quarterly distributions in common units rather than cash) plus 4.5 million warrants with an exercise price of $4.55 per common unit and 2.25 million warrants with an exercise price of $6.05 per common unit, and (ii) $100 million of common units at a price of $4.55 per unit;
•
cancelling, by our subsidiary Logitel, the shipbuilding contracts for the two remaining UMS newbuildings; and
•
amending the terms of certain interest rate swaps to defer the counterparties’ early termination options and extending and increasing the threshold of existing cross currency swaps related to our two NOK bonds that have been extended as part of these initiatives.
As part of completing the above financing initiatives, we agreed to convert $46 million of face value of the $250 million of Series C Preferred Units for approximately 8.3 million common units and the remaining approximately $204 million of outstanding Series C Preferred Units for approximately 8.5 million of our newly-issued 8.60% Series C-1 Preferred Units that also include a two-year option to pay quarterly distributions in the form of common units rather than cash. We agreed that, until we repay amounts outstanding under our NOK bonds maturing in 2018, we will only pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units in common units, except that, at any time with respect to the Series C-1 Preferred Units, and at any time after June 29, 2018 with respect to the Series D Preferred Units, we may pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units, respectively, in cash, if the amount of such cash distributions are matched or exceeded by the proceeds of additional equity raised by us in advance of, or within six months following, payment of the cash distributions. We also issued $31 million of common units during 2016 under our continuous offering program.


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For additional information about our Series C, C-1 and D Preferred Units and the Warrants, please read Item 18 - Financial Statements: Note 16.Total Capital and Net Income Per Common Unit.

New North Sea Shuttle Tanker Contracts

In January 2017, we received a letter of award for a new five-year shuttle tanker CoA, plus extension options, with a consortium of oil companies to service a development located in the UK Central North Sea. The CoA is expected to commence during the first quarter of 2018 and will be serviced by our existing CoA shuttle tanker fleet. The CoA will require the use of approximately 0.5 shuttle tanker equivalents per annum.

In September 2016, we were awarded a new three-year shuttle tanker CoA, plus extension options, with BP plc, Royal Dutch Shell and OMV Group, to service the new Glen Lyon FPSO unit located west of Shetland in the North Sea. This CoA is expected to commence in mid-2017 and require the use of approximately two shuttle tankers from our existing CoA shuttle tanker fleet.

UMS Construction Contract Cancellation

In June 2016, as part of our financing initiatives, we canceled the construction contracts for our two UMS newbuildings. As a result, we incurred a $43.7 million write-down related to these two UMS newbuildings, which is included in (write-down) and gain on sale of vessels in our consolidated statement of income. In addition, we accrued for potential damages resulting from the cancellations and reversed contingent liabilities previously recorded that were relating to the delivery of the UMS newbuildings. This net loss provision of $23.4 million for the year ended December 31, 2016 is reported in Other (expense) income - net in our consolidated statements of income. The newbuilding contracts are held in our separate subsidiaries and obligations of these subsidiaries are non-recourse to us. For additional information, please read Item 18 - Financial Statements: Note 14c Commitments and Contingencies.

Arendal Spirit UMS

In April 2016, during the process to lift off the gangway connecting the Arendal Spirit to an FPSO unit, the gangway of the Arendal Spirit suffered damage. The gangway was replaced and underwent extensive testing and the unit recommenced operations in early-July 2016. As a result of this incident, we reversed contingent liabilities previously recorded that were subject to material defects of the UMS.

In November 2016, the Arendal Spirit UMS experienced an operational incident relating to its dynamic-positioning system. As a result of this operational incident, and a gangway incident that occurred in April 2016, the charterer, Petrobras, initiated an operational review. Until the results of the review are available, Petrobras has suspended its charter hire payments from November 2016. We have completed an investigation to identify the cause of the incidents and have implemented corrective measures. We are working to address Petrobras' concerns to bring the unit back into operations as soon as possible.

Delivery of Newbuilding Towage Vessel

In September 2016, we took delivery of the ALP Striker, the first of four state-of-the-art SX-157 Ulstein Design ultra-long distance towing and offshore installation newbuildings being constructed by Niigata Shipbuilding & Repair in Japan. In connection with the delivery, we received cash compensation from the shipyard totaling approximately $7 million due to the delayed delivery of the vessel. In April 2017, we received additional delayed delivery cash compensation of $24.3 million for the remaining three towing and offshore installation newbuildings, which are scheduled to deliver during 2017.

Sale and In-Chartering of Two Conventional Tankers

In March 2016, we terminated an above-market time-charter contract of the Kilimanjaro Spirit conventional tanker with a subsidiary of Teekay Corporation and received an early termination fee of $4.0 million from Teekay Corporation. Subsequently, we sold the Kilimanjaro Spirit and the Fuji Spirit conventional tankers for net proceeds of approximately $50 million. Related to the sale of these vessels, we are chartering back both vessels for a period of three years with an additional one-year extension option. One vessel is fixed on a two-year time-charter-out contract that commenced during the second quarter of 2016, and the other vessel is trading in the spot conventional tanker market.

Sale of Navion Europa shuttle tanker

In November 2016, we sold a 1995-built shuttle tanker, the Navion Europa, for net proceeds of $14.4 million, for which we recorded a gain on sale of $6.8 million in a 67%-owned subsidiary.
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. However, our current near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects.

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

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required from the charterer. The purchase price for the Petrojarl Foinaven would be based on its fair market value. Teekay Corporation owns two additional FPSO units, the Hummingbird Spirit FPSO and the Petrojarl Banff FPSO, which may also be offered to us in the future pursuant to the omnibus agreement.

In May 2011, Teekay Corporation entered into a joint venture agreement with OOG to jointly pursue FPSO projects in Brazil. OOG is a Brazil-based company that operates in the engineering and construction, petrochemical, bioenergy, energy, oil and gas, real estate and environmental engineering sectors. Through the joint venture agreement, OOG is a 50 percent partner with us in the Cidade de Itajai (or Itajai) FPSO unit and the Libra FPSO project.
Our Contracts and Charters
We generate revenues by charging customers for the transportation and storage of their crude oil using our vessels. Historically, these services generally have been provided under the following basic types of contractual relationships:

•
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;
•
Time charters, whereby vessels which we operate and are responsible for crewing, are chartered to customers for a fixed period of time at rates that are generally fixed, but may contain a variable component based on inflation, interest rates or current market rates;
•
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
•
Voyage charters, which are charters for shorter intervals that are priced on a current, or “spot,” market rate.

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

Furthermore, we generate revenues by charging customers for offshore accommodation, storage and support for maintenance and modification projects on existing offshore installations, or during the installation and decommissioning of large floating exploration, production and storage units, including FPSO units, FLNG units and floating drill rigs. These services are typically provided under mid-term, fixed-rate time-charter contracts, which may contain a variable component for inflation.

In addition, we generate revenues by charging customers for the towage, station-keeping, installation and decommissioning of large floating objects, such as exploration, production and storage units, including FPSO units, FLNG units and floating drill rigs. These services are typically provided under project-based voyage-charter contracts.
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 U.S. generally accepted accounting principles (or GAAP).

Vessel Operating Expenses. Under all types of charters and contracts for our vessels, except for bareboat charters, we are responsible for vessel operating expenses, which include crewing, repairs and maintenance, ship management services, insurance, stores, lube oils and communication expenses. The two largest components of our vessel operating expenses are crew costs and repairs and maintenance. We are taking steps to maintain these expenses at a stable level, but expect an increase in line with inflation in respect of crew, material, and maintenance costs. The strengthening or weakening of the U.S. Dollar relative to foreign currencies may result in significant decreases or increases, respectively, in our vessel operating expenses, depending on the currencies in which some of such expenses are incurred.

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


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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, interest income, income taxes, realized and unrealized losses on non-designated derivative instruments, equity income, foreign currency exchange loss and other (expenses) income - net.

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

Depreciation and Amortization. Depreciation and amortization expense typically consists of:

•
charges related to the depreciation of the historical cost of our fleet (less an estimated residual value) over the estimated useful lives of the vessels or equipment;
•
charges related to the amortization of dry-docking expenditures over the estimated useful life of the dry docking; and
•
charges related to the amortization of the fair value of contracts of affreightment where amounts have been attributed to those items in acquisitions; these amounts are amortized over the period in which the asset is expected to contribute to future cash flows.

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

Calendar-Ship-Days. Calendar-ship-days are the total number of calendar days that our vessels were in our possession during a period. We use calendar-ship-days primarily to highlight changes in vessel operating expenses, time-charter hire expense and depreciation and amortization. Calendar-ship days are based on our owned and chartered-in fleet, including vessels owned by our 50%, 67% and 89% owned subsidiaries, but excluding vessels owned by our 50% owned subsidiaries accounted for under the equity method.
Items You Should Consider When Evaluating Our Results

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

•
Our financial results reflect the results of the interests in vessels acquired from Teekay Corporation for all periods the vessels were under common control. In July 2015, we acquired the Petrojarl Knarr FPSO unit. This transaction was deemed to be a business acquisition between entities under common control. Accordingly, we have accounted for this transaction in a manner similar to the pooling of interests method. Under this method of accounting, our financial statements prior to the date the interest in this vessel was actually acquired by us are retroactively adjusted to include the results of this acquired vessel. The period retroactively adjusted includes all periods that we and the acquired vessel were both under common control of Teekay Corporation and had begun operations. As a result, our applicable consolidated financial statements reflect this vessel and its results of operations, referred to herein as the Dropdown Predecessor, as if we had acquired it when the vessel began operations under the ownership of Teekay Corporation on March 9, 2015. Please read Item 18 – Financial Statements: Note 3 – Dropdown Predecessor.
•
The size of and types of vessels in our fleet continues to change. Our results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries and vessel dispositions. Please read “Results of Operations” below for further details about vessel dispositions and deliveries. Due to the nature of our business, we expect our fleet to continue to fluctuate in size and composition.
•
The decline in global crude oil prices has correlated with a reduction in our operating expenses. With cost-saving initiatives implemented across the offshore industry, we expect to see a maintained level of reduced operating expenses, in particular the cost of services and spares and crewing costs. There is a general understanding with our suppliers to focus on cost-saving initiatives to support the lower global crude oil prices and with labor unions that there will likely be minimal or no short-term salary increases in the near term.
•
Our financial results are affected by fluctuations in currency exchange rates. Under GAAP, all foreign currency-denominated monetary assets and liabilities (such as cash and cash equivalents, restricted cash, accounts receivable, accounts payable, due to and from affiliates, long-term debt and deferred income taxes) are revalued and reported based on the prevailing exchange rate at the end of the period. We have entered into services agreements with subsidiaries of Teekay Corporation whereby the subsidiaries provide various services to us. 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, British Pound, Euro, Australian Dollar or Brazilian Real relative to the U.S. Dollar, which may result in increased or decreased payments under the services agreements if the strength of the U.S. Dollar declines or increases, respectively, relative to the Norwegian Kroner, British Pound, Euro, Australian Dollar or Brazilian Real.
•
Our financial results are affected by fluctuations in the fair value of our derivatives instruments. The change in fair value of our interest rate swaps, cross currency swaps and foreign currency forward contracts are included in our net income as the majority of our derivative instruments are not designated as hedges for accounting purposes. Although we believe that these non-designated derivative

50


instruments are economic hedges, the changes in their fair value are included in our consolidated statements of income as unrealized gains or losses on derivatives for interest rate swaps and foreign currency forward contracts and as foreign exchange losses for cross currency swaps. The unrealized gains or losses relating to changes in fair value of our derivative instruments do not affect our consolidated cash flows, liquidity or cash distributions to our common unitholders, preferred unit holders or our general partner.
•
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. Three shuttle tankers are scheduled for dry docking in 2017. From time to time, unscheduled dry dockings may cause additional fluctuations in our financial results.

We manage our business and analyze and report our results of operations on the basis of our six business segments: the FPSO segment, the shuttle tanker segment, the FSO segment, the UMS segment, the towage segment, and the conventional tanker segment, each of which are discussed below:
Results of Operations
Year Ended December 31, 2016 versus Year Ended December 31, 2015

FPSO Segment

As at December 31, 2016, our FPSO fleet consisted of the Petrojarl Knarr, the Petrojarl Varg, the Cidade de Rio das Ostras (or Rio das Ostras), the Piranema Spirit, the Voyageur Spirit, and the Petrojarl I FPSO units, all of which we own 100%, and the Itajai and Libra FPSO units, of which we own 50%. One equity accounted FPSO unit, the Libra FPSO unit owned through our 50/50 joint venture with OOG has completed its conversion into an FPSO unit and is en route for the Libra field located in the Santos Basin offshore Brazil and is scheduled to commence operations in mid-2017. The Petrojarl I FPSO unit is currently undergoing upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard (or Damen) in the Netherlands and is scheduled to commence operations under a five-year fixed-rate charter contract with Queiroz Galvão Exploração e Produção SA (or QGEP) at the end of 2017. We acquired the Petrojarl Knarr FPSO unit from Teekay Corporation in July 2015.

In late-2015, we received a termination notice for the Petrojarl Varg FPSO charter contract from Repsol S.A. (or Repsol), based on a termination right that was specific to the Petrojarl Varg FPSO contract. In accordance with the termination provision of the charter contract, the charterer ceased paying the capital component of the charter hire six months prior to the redelivery date, which redelivery occurred at the end of July 2016.
FPSO units provide production, processing and storage services to oil companies operating offshore oil field installations. These services are typically provided under long-term, fixed-rate FPSO contracts, some of which also include certain incentive compensation or penalties based on the level of oil production and other operational measures. Historically, the utilization of FPSO units and other vessels in the North Sea, where the Voyageur Spirit and Petrojarl Knarr operate, is higher in the winter months, as favorable weather conditions in the summer months provide opportunities for repairs and maintenance to our vessels and the offshore oil platforms, which generally reduces oil production. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner, Brazilian Real, and British Pound may result in significant decreases or increases, respectively, in our revenues and vessel operating expenses.

The following table presents the FPSO segment’s operating results for 2016 and 2015, and also provides a summary of the calendar-ship-days for the FPSO segment. The table excludes the results of the Itajai and the Libra FPSO units, which are accounted for as equity investments.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
495,223

 
531,554

 
(6.8
)
Vessel operating expenses
 
(165,346
)
 
(189,900
)
 
(12.9
)
Depreciation and amortization
 
(149,198
)
 
(137,914
)
 
8.2

General and administrative (1)
 
(35,971
)
 
(38,588
)
 
(6.8
)
Restructuring charge
 
(4,444
)
 
—

 
100.0

Income from vessel operations
 
140,264

 
165,152

 
(15.1
)
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
2,196

 
2,009

 
9.3

(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). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $9.7 million to Teekay Corporation related to the acquisition of the Petrojarl Knarr FPSO unit.

The average number of our FPSO units increased in 2016 compared to 2015, due to the acquisition of the Petrojarl Knarr on July 1, 2015.


51


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

Revenues. Revenues decreased for 2016 compared to 2015, primarily due to:

•
a decrease of $65.3 million due to no longer receiving the capital portion of the charter hire for the Petrojarl Varg since February 1, 2016 and the unit being off hire since August 1, 2016 due to the termination of the charter contract by Repsol;
•
a decrease of $10.9 million on the Voyageur Spirit related to a lower production bonus earned in 2016 compared to 2015;
•
a decrease of $8.0 million in 2016 due to lower reimbursable expenses incurred on the Voyageur Spirit compared to 2015 (partially offset by lower operating expenses incurred, as indicated below);
•
a decrease of $5.4 million related to the Piranema Spirit due to a provision relating to a possible return of 2% of the charter hire to Petrobras S.A. (or Petrobras), the charterer, in place of an agency fee owing for the period from November 2011 up to December 31, 2016;
•
a decrease of $3.4 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Brazilian Real during 2016 compared to 2015 on revenues related to the Petrojarl Varg, Petrojarl Knarr and Piranema Spirit (however, these decreases are offset by similar foreign exchange related decreases in vessel operating expenses); and
•
a decrease of $1.9 million due to a bonus earned from the charterer of the unit for unused maintenance days under the service contract of the Piranema Spirit during 2015 that was not repeated in 2016;

partially offset by

•
an increase of $44.4 million mainly due to the Petrojarl Knarr FPSO unit commencing operations on March 9, 2015;
•
an increase of $6.9 million due to unscheduled off-hire of the Piranema Spirit for repairs during 2015;
•
an increase of $4.0 million relating to revenue received for offshore field studies associated with the Petrojarl Varg during 2016 compared to 2015 (this revenue is offset by operating expenses incurred, as indicated below); and
•
an increase of $3.0 million on the Rio das Ostras, primarily due to higher incentive compensation and a bonus earned from the charterer of the unit for unused maintenance days under the service contract during 2016.

Vessel Operating Expenses. Vessel operating expenses decreased for 2016 compared to 2015, primarily due to:

•
a decrease of $17.6 million due to lower costs as the Petrojarl Varg was decommissioned at the end of July 2016 and is now in lay up;
•
a decrease of $7.2 million due to lower repair and maintenance costs on the Voyageur Spirit during 2016, which are reimbursed by the charterer, compared to 2015;
•
a decrease of $5.6 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Brazilian Real and British Pound during 2016 compared to 2015;
•
a decrease of $3.1 million due to lower repair and maintenance costs on the Piranema Spirit due to unscheduled off-hire during 2015 and the timing of repair and maintenance costs; and
•
a decrease of $1.5 million due to lower crew costs mainly as a result of lower crew overtime during 2016 compared to 2015;

partially offset by

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

•
a net increase of $3.7 million due to the Petrojarl Knarr FPSO unit commencing operations on March 9, 2015, partially offset by lower crew costs as 2015 crew costs were higher in the first year of operations of the unit related to start-up as well as preparing the unit for the final performance test; and

•
an increase of $3.0 million due to a reversal of an agency fee accrual relating to the Piranema Spirit during 2015, which we did not consider payable at that time.

Depreciation and amortization. Depreciation and amortization expense increased for 2016 compared to 2015, primarily due to:

•
an increase of $12.3 million due to the Petrojarl Knarr commencing operations on March 9, 2015, partially offset by amortization of credits received from the ship yard during 2016 related to the construction of the unit;

partially offset by

•
a decrease of $1.1 million due to an increase in the expected useful life of the Petrojarl I FPSO.

52


Restructuring Charge. Restructuring charge for 2016 relates to the reorganization of our FPSO business to create better alignment with our offshore operations resulting in a lower cost organization going forward.

Shuttle Tanker Segment

As at December 31, 2016, our shuttle tanker fleet consisted of 30 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, three shuttle tanker newbuildings, and the HiLoad DP unit, which is currently in lay-up. Of these 34 shuttle tankers, six are owned through 50%-owned subsidiaries and three were chartered-in. The remaining vessels are owned 100% by us. In November 2016, we sold a 1995-built shuttle tanker, the Navion Europa. In January 2016, we sold a 1992-built shuttle tanker, the Navion Torinita, which was in lay-up and was classified as held for sale on our consolidated balance sheet as of December 31, 2015. In July 2016, we agreed to in-charter a shuttle tanker, the Grena Knutsen, on a three-year charter contract for our North Sea fleet commencing in September 2016. All of our operating shuttle tankers, with the exception of the HiLoad DP unit, provide transportation services to energy companies in the North Sea, Brazil and the East Coast of Canada. Our shuttle tankers occasionally service the conventional spot tanker market. We commenced the FSO conversion of the Randgrid shuttle tanker during the second quarter of 2015 and the vessel has been included in our FSO segment since June 9, 2015. During the first quarter of 2015, we sold the Navion Svenita. The strengthening or weakening of the U.S. Dollar relative to the Norwegian Kroner, Euro or Brazilian Real may result in significant decreases or increases, respectively, in our vessel operating expenses.

The following table presents the shuttle tanker segment’s operating results for 2016 and 2015, and compares its net revenues (which is a non-GAAP financial measure) for 2016 and 2015, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the shuttle tanker segment:
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
509,596

 
541,792

 
(5.9
)
Voyage expenses
 
(62,846
)
 
(82,777
)
 
(24.1
)
Net revenues
 
446,750


459,015

 
(2.7
)
Vessel operating expenses
 
(123,950
)
 
(128,156
)
 
(3.3
)
Time-charter hire expenses
 
(62,511
)
 
(51,088
)
 
22.4

Depreciation and amortization
 
(122,822
)
 
(106,190
)
 
15.7

General and administrative (1)
 
(10,160
)
 
(22,884
)
 
(55.6
)
Gain on sale and (write-down) of vessels
 
4,554

 
(65,101
)
 
(107.0
)
Restructuring charge
 
(205
)
 
(568
)
 
(63.9
)
Income from vessel operations
 
131,656


85,028

 
54.8

Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
10,599

 
11,191

 
(5.3
)
Chartered-in Vessels
 
1,314

 
1,128

 
16.5

Total
 
11,913


12,319

 
(3.3
)
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the shuttle tanker segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.


The average size of our owned shuttle tanker fleet decreased in 2016 compared to 2015, primarily due to the sale of the Navion Svenita, the Navion Torinita and the Navion Europa in March 2015, January 2016 and November 2016, respectively, and the commencement of the FSO conversion of the Randgrid in June 2015. Three shuttle tanker newbuildings have been excluded from calendar-ship-days until they are delivered to us.

The average size of our chartered-in shuttle tanker fleet increased in 2016 compared to 2015, primarily due to the in-chartering of two shuttle tankers, the Jasmine Knutsen and the Heather Knutsen, for the East Coast of Canada contract, which commenced in June 2015, the in-chartering of the Grena Knutsen for three years which commenced in September 2016 and increased spot in-chartering of shuttle tankers, partially offset by redelivery to their owners of the Grena Knutsen and Aberdeen in June 2015 and December 2016, respectively. The Grena Knutsen was subsequently rechartered in by us in September 2016.

Net revenues. Net revenues decreased for 2016 compared to 2015, primarily due to:

•
a decrease of $22.7 million due to the expiration in April 2015 of a long-term contract at the Heidrun field serviced by our contracts of affreightment fleet;
•
a decrease of $17.9 million due to the redelivery of two vessels to us in April 2015 and June 2016, respectively, as they completed their time-charter-out agreement;
•
a decrease of $9.7 million due to fewer opportunities to trade excess shuttle tanker capacity in the conventional tanker spot market; and

53


•
a decrease of $3.4 million due to the sale of the Navion Svenita in March 2015;

partially offset by

•
an increase of $21.0 million due to an increase in net revenues from the commencement of the East Coast of Canada contract in June 2015, partially offset by lower reimbursable expenses in relation to this contract;
•
an increase of $15.9 million due to an increase in rates as provided in certain contracts in our time-chartered-out fleet and an increase in revenues in our contract of affreightment fleet due to higher average rates and higher fleet utilization; and
•
an increase of $4.0 million due to the Navion Europa acting as a substitute vessel while the Apollo Spirit FSO unit was undergoing a dry dock in the third quarter of 2016.
Vessel operating expenses. Vessel operating expenses decreased for 2016 compared to 2015, primarily due to:

•
a decrease of $4.5 million due to lower fleet and onshore overhead mainly related to lower crew training costs in 2016;
•
a decrease of $2.7 million due to the commencement of the FSO conversion of the Randgrid in June 2015;
•
a decrease of $2.0 million due to the sale of the Navion Svenita and Navion Europa in March 2015 and November 2016, respectively; and
•
a decrease of $1.7 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Euro and Brazilian Real;

partially offset by

•
an increase of $4.2 million related to higher repair and maintenance activities on Navion Anglia to prepare the vessel to trade in our contract of affreightment fleet in the North Sea as the vessel was redelivered to us in June 2016 due to the completion of its time-charter-out agreement in Brazil; and
•
an increase of $3.0 million due to higher crew costs relating to a change in crew composition.

Time-charter hire expenses. Time-charter hire expense increased for 2016 compared to 2015, primarily due to:

•
an increase of $14.0 million due to the in-chartering of three shuttle tankers for the East Coast of Canada contract, which commenced in June 2015 (one of the three shuttle tankers, Mattea, was redelivered on August 31, 2015);
•
an increase of $5.2 million due to the in-chartering of the Grena Knutsen starting September 2016; and
•
an increase of $3.6 million due to increased spot in-chartering of shuttle tankers;

partially offset by

•
a decrease of $7.6 million due to the redeliveries by us of the Grena Knutsen and Aberdeen in June 2015 and December 2016, respectively; and
•
a decrease of $3.8 million due to the redelivery by us of the Mattea on August 31, 2015, which was replaced by our own shuttle tanker Navion Hispania.

Depreciation and amortization. Depreciation and amortization expense increased for 2016 compared to 2015, primarily due to:

•
an increase of $29.3 million due to the change in the estimated useful life of the shuttle component for all shuttle tankers from 25 to 20 years, as well as the accelerated amortization of the tanker component for eight older shuttle tankers commencing the first quarter of 2016;

partially offset by

•
a decrease of $7.7 million due to a write-down of the carrying values of seven shuttle tankers during 2015;
•
a decrease of $2.9 million due to the commencement of the FSO conversion of the Randgrid in June 2015; and
•a decrease of $1.4 million due to the Navion Europa being fully amortized during the second quarter of 2015.

Gain on sale and (write-down) of vessels. Gain on sale and (write-down) of vessels was $4.6 million for 2016, which consisted of gains on sales of vessels of $6.7 million partially offset by a write-down of a vessel of $2.1 million, compared to ($65.1) million for 2015, which consisted of a write-down of vessels of $66.7 million partially offset by a gain on the sale of a vessel of $1.6 million.

During 2016, we sold a 1992-built shuttle tanker, the Navion Torinita, for net proceeds of $5.0 million, which was the approximate carrying value of the vessel at the time of sale, and sold a 1995-built shuttle tanker, the Navion Europa, for net proceeds of $14.4 million, for which we recorded a gain on sale of $6.8 million in a 67%-owned subsidiary. During the fourth quarter of 2016, the carrying value of the Navion Marita was written down to its estimated fair value, using an appraised value, as a result of fewer opportunities to trade the vessel in the spot conventional tanker market resulting in a $2.1 million write-down related to this vessel.

54



During 2015, the carrying values of seven of our 1990s-built shuttle tankers were written down to their estimated fair values using appraised values. Of the seven vessels, two of the vessels were written down during the first quarter of 2015 as a result of the expected sale of a vessel and a change in the operating plan of a vessel. In the fourth quarter of 2015, the write-down of five shuttle tankers, which had an average age of 17.5 years, was the result of changes in our expectations of their future opportunities, primarily due to their age. In 2015, we sold a 1997-built shuttle tanker, the Navion Svenita, to a third party resulting in a gain on the sale of the vessel of $1.6 million.
FSO Segment
As at December 31, 2016, our FSO fleet consisted of five units that operate under fixed-rate time charters or fixed-rate bareboat charters, for which our ownership interests ranged from 89% to 100%, one shuttle tanker, the Randgrid, currently undergoing conversion into an FSO unit, for which our ownership interest increased from 67% to 100% during the third quarter of 2015 and one idle unit, the Navion Saga. We commenced the FSO conversion of the Randgrid during the second quarter of 2015 and the vessel has been included in our FSO segment since June 9, 2015. The Navion Saga FSO unit was held for sale as at December 31, 2016.

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

The following table presents the FSO segment’s operating results for 2016 and 2015, and compares its net revenues (which is a non-GAAP financial measure) for 2016 and 2015, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days for the FSO segment:
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
54,440

 
57,391

 
(5.1
)
Voyage expenses
 
(1,517
)
 
(851
)
 
78.3

Net revenues
 
52,923


56,540

 
(6.4
)
Vessel operating expenses
 
(23,167
)
 
(26,394
)
 
(12.2
)
Depreciation and amortization
 
(9,311
)
 
(11,775
)
 
(20.9
)
General and administrative (1)
 
(836
)
 
(1,372
)
 
(39.1
)
Write-down of vessel
 
(983
)
 
—

 
100.0

Income from vessel operations
 
18,626


16,999

 
9.6

Calendar-Ship-Days
 
 
 
 
 


Owned Vessels
 
2,562

 
2,395

 
7.0

(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FSO segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.

The average number of our FSO units increased for 2016 compared to 2015, due to the commencement of the FSO conversion of the Randgrid on June 9, 2015. No earnings are expected from the Randgrid until its conversion is completed in mid-2017, when the unit is scheduled to commence operations under a three-year time-charter contract with Statoil ASA, which includes 12 additional one-year extension options. Additionally, the Navion Saga was redelivered to us in October 2016 and was classified as held for sale as at December 31, 2016, resulting in a $1.0 million write-down of the unit.

Net revenues. Net revenues decreased for 2016 compared to 2015, primarily due to the redelivery of the Navion Saga in October 2016, following the completion of its time-charter-out contract.

Vessel operating expenses. Vessel operating expenses decreased for 2016 compared to 2015, primarily due to the redelivery of the Navion Saga in October 2016 following the completion of its time-charter-out contract and due to lower crew costs on the Navion Saga and the Dampier Spirit mainly due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Australian Dollar compared to 2015.

Depreciation and amortization. Depreciation and amortization expense decreased for 2016 compared to 2015, primarily due to drydock costs for the Navion Saga being fully depreciated during the fourth quarter of 2015.

Write-down of vessel. Write-down of vessels for 2016 related to the Navion Saga, which was redelivered to us in October 2016. The carrying value of the unit was written down to its estimated fair value, using an appraised value, as a result of the expected sale of the unit and the unit was classified as held for sale on our consolidated balance sheet as at December 31, 2016.

UMS Segment


55


As at December 31, 2016, our UMS fleet consisted of one unit, the Arendal Spirit, in which we own a 100% interest. During the second quarter of 2016, as part of our financing initiatives, we canceled the UMS construction contracts for our two UMS newbuildings, resulting in a write-down of the UMS newbuildings to $nil.

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

The following table presents the UMS segment’s operating results and calendar-ship-days for 2016 and 2015. The Arendal Spirit delivered to us on February 16, 2015 and began its three-year charter contract with Petrobras on June 7, 2015. In mid-April 2016, during the process of lifting off the gangway connecting the Arendal Spirit to an FPSO unit, the gangway of the Arendal Spirit suffered damage. During the gangway replacement, the Arendal Spirit was declared off-hire. The gangway was replaced in mid-June 2016 and the Arendal Spirit was declared on-hire in early-July 2016. In early November the unit experienced an operational incident relating to the dynamic positioning system and, as a result, Petrobras has suspended its charter hire payments since November 6, 2016 pending the completion of its operational review resulting from this incident. We are uncertain when Petrobras will finalize its operational review.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
34,433

 
28,334

 
21.5

Vessel operating expenses
 
(32,888
)
 
(13,876
)
 
137.0

Depreciation and amortization
 
(6,660
)
 
(3,775
)
 
76.4

General and administrative (1)
 
(5,495
)
 
(4,109
)
 
33.7

Write-down of vessels
 
(43,650
)
 
(1,000
)
 
4,265.0

(Loss) income from vessel operations
 
(54,260
)
 
5,574

 
(1,073.4
)
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
366

 
318

 
15.1

(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the UMS segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.0 million paid to Teekay Corporation related to the delivery of the Arendal Spirit UMS.

The calendar-ship-days increased for 2016 compared to 2015, due to the delivery of the Arendal Spirit in February 2015.

Revenues. Revenues increased for 2016 compared to 2015, mainly due to the commencement of the charter contract of the Arendal Spirit in June 2015 and due to increased charter rates in 2016 compared to 2015. This was partially offset by lower revenues due to the unit being off-hire from mid-April 2016 until early-July 2016 due to damage suffered to the gangway and the suspension of charter hire payments since early-November 2016 due to an operational review being conducted by the charterer.

Vessel operating expenses. Vessel operating expenses increased for 2016 compared to 2015, mainly due to the commencement of the charter contract of the Arendal Spirit in June 2015 and an increase in spare parts and consumables in 2016 due to these costs being covered under warranty during 2015.

Depreciation and amortization. Depreciation and amortization expense increased for 2016 compared to 2015, due to the commencement of the charter contract of the Arendal Spirit in June 2015.

Write-down of vessels. Write-down of vessels for 2016 consists of the write-downs relating to the cancellation of our two UMS newbuilding contracts. In addition, we accrued for potential damages resulting from the cancellations and reversed the contingent liabilities previously recorded that were subject to the delivery of the UMS newbuildings. This net loss provision of $23.4 million is reported in Other (expense) income - net in our consolidated statements of loss. See the discussion under "Other Operating Results" below.

Write-down of vessels for 2015 consists of the write-down of options to purchase two additional UMS units, which expired during 2015.
Towage Segment
As at December 31, 2016, our towage vessel fleet consisted of seven long-distance towing and offshore installation vessels and three long-distance towing and offshore installation vessel newbuildings, which are scheduled to deliver during 2017. We own a 100% interest in each of the vessels in our towage fleet.

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


56


The following table presents the towage segment’s operating results for 2016 and 2015, and compares its net revenues (which is a non-GAAP financial measure) for 2016 and 2015, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the towage segment.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
37,952
 
40,112

 
(5.4
)
Voyage expenses
 
(15,024)
 
(12,052
)
 
24.7

Net revenues
 
22,928

28,060

 
(18.3
)
Vessel operating expenses
 
(17,524)
 
(13,920
)
 
25.9

Time-charter hire expenses
 
—
 
(662
)
 
(100.0
)
Depreciation and amortization
 
(12,020)
 
(8,362
)
 
43.7

General and administrative (1)
 
(3,307)
 
(4,598
)
 
(28.1
)
(Loss) income from vessel operations
 
(9,923)

518

 
(2,015.6
)
Calendar-Ship-Days
 
 
 
 
 


Owned Vessels
 
2,307
 
1,587

 
45.4

Chartered-in Vessels
 
—
 
19

 
(100.0
)
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the towage segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.2 million to Teekay Corporation related to the acquisition of six towing and offshore installation vessels.

The average number of our towing and offshore installation vessels increased for 2016 compared to 2015, due to the acquisition of three vessels during the first quarter of 2015, two vessels during the second quarter of 2015, one vessel during the third quarter of 2015 and the delivery of our first towage newbuilding vessel in September 2016.

Net revenues. Net revenues decreased for 2016 compared to 2015, mainly due to a decrease in rates and utilization for the towage vessel fleet due to volatility in the offshore market, partially offset by an increase in the fleet size.

Vessel operating expenses. Vessel operating expenses increased for 2016 compared to 2015, mainly due to the acquisition of the six towing and offshore installation vessels during 2015, the delivery of the ALP Striker in September 2016, an increase in repairs and maintenance expenses due to engine overhauls on the ALP Winger and ALP Centre during the first quarter of 2016, and an increase in crew costs compared to 2015 due to higher crew levels, partially offset by a more cost-efficient crew composition in 2016.

Depreciation and amortization. Depreciation and amortization increased for 2016 compared to 2015, due to the acquisition of the six towing and offshore installation vessels during 2015 and the delivery of the ALP Striker in September 2016.
Conventional Tanker Segment
As at December 31, 2016, our conventional tanker fleet consisted of two in-chartered conventional tankers. In March 2016, we terminated the time-charter contract of the Kilimanjaro Spirit with a subsidiary of Teekay Corporation and received an early termination fee of $4.0 million from Teekay Corporation. Subsequently, we sold the Kilimanjaro Spirit and the Fuji Spirit conventional tankers. The Kilimanjaro Spirit was renamed Blue Pride and the Fuji Spirit was renamed Blue Power. As part of the sales, we are in-chartering these vessels for three years with additional one-year extension options. One vessel is trading on a fixed two-year time-charter-out contract that commenced during the second quarter of 2016 and the other vessel is trading in the spot conventional tanker market.

In December 2015, we sold our 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd.
The following table presents the conventional tanker segment’s operating results for 2016 and 2015, and compares its net revenues (which is a non-GAAP financial measure) for 2016 and 2015, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the conventional tanker segment.

57


 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2016
 
2015
 
% Change
Revenues
 
20,746

 
30,230

 
(31.4
)
Voyage expenses
 
(1,363
)
 
(2,326
)
 
(41.4
)
Net revenues
 
19,383

 
27,904

 
(30.5
)
Vessel operating expenses
 
(1,566
)
 
(6,234
)
 
(74.9
)
Time-charter hire expense
 
(12,974
)
 
—

 
100.0

Depreciation and amortization
 
—

 
(6,583
)
 
(100.0
)
General and administrative (1)
 
(353
)
 
(1,062
)
 
(66.8
)
Write-down of vessels
 
—

 
(3,897
)
 
(100.0
)
Income from vessel operations
 
4,490

 
10,128

 
(55.7
)
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
160

 
1,432

 
(88.8
)
Chartered-in Vessels
 
572

 
—

 
100.0

Total
 
732

 
1,432

 
(48.9
)
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the conventional tanker segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.

The average number of our owned conventional tankers decreased for 2016 compared to 2015, due to the sales of the Kilimanjaro Spirit and the Fuji Spirit conventional tankers in March 2016, and the sale of the SPT Explorer and the Navigator Spirit conventional tankers in December 2015.

The average number of our chartered-in conventional tankers increased in 2016 compared to 2015, due to the in-chartering of the Blue Pride and Blue Power conventional tankers from March 2016.

Net revenues. Net revenues decreased for 2016 compared to 2015, primarily due to:

•
a net decrease of $10.6 million due to the termination of the time-charter-out contracts of the Fuji Spirit and Kilimanjaro Spirit with a subsidiary of Teekay Corporation in December 2015 and March 2016, respectively, and a termination fee received from Teekay Corporation due to the early termination of the time-charter-out contract of the Fuji Spirit in December 2015, partially offset by revenue from earnings in a conventional tanker pool prior to the sale of the Fuji Spirit and revenue from earnings in the spot conventional tanker market and the time-charter-out of our in-chartered vessels, the Blue Pride and Blue Power, respectively, from March 2016; and
•
a decrease of $1.9 million due to the sale of the SPT Explorer and Navigator Spirit in December 2015, partially offset by termination fees paid to Teekay Corporation due to the early termination of the bareboat contracts of these vessels in December 2015;

partially offset by:

•
an increase of $4.0 million relating to a termination fee received from Teekay Corporation due to the early termination of the time-charter-out contract of the Kilimanjaro Spirit in March 2016.

Vessel operating expenses. Vessel operating expenses decreased for 2016 compared to 2015, mainly due to the sale of two conventional tankers in December 2015 and the sale of two additional conventional tankers in March 2016.

Time-charter hire expense. Time-charter hire expense increased for 2016 compared to 2015, due to the in-chartering of the Blue Pride and the Blue Power conventional tankers from March 2016.

Depreciation and amortization. Depreciation and amortization expense decreased for 2016 compared to 2015, due to the sale of the SPT Explorer and Navigator Spirit in December 2015, and the sale of the Kilimanjaro Spirit and Fuji Spirit in March 2016.

Write-down of vessels. During 2015, the carrying value of the Kilimanjaro Spirit and Fuji Spirit were written down to their estimated fair values using appraised values. The write-downs were the result of the expected sales of these two vessels and both vessels were classified as held for sale on our consolidated balance sheet as of December 31, 2015.
Other Operating Results
General and administrative. General and administrative expenses decreased to $56.1 million for 2016, compared to $72.6 million for 2015. The decrease was due to lower management fees relating to our shuttle tanker and FSO segments primarily from our cost saving initiatives, lower management fees due to a change in pension scheme obligations in 2016, an increase in capitalized expenses on our newbuilding projects, the absence of any business development fees to Teekay Corporation in 2016 compared to 2015 business development fees to Teekay Corporation of $9.7 million, $2.2 million and $2.0 million, respectively, in connection with the acquisition of the Petrojarl Knarr FPSO unit, six long-distance towing and offshore installation vessels and the Arendal Spirit UMS, respectively, the redelivery and lay up of the

58


Petrojarl Varg FPSO unit in 2016, and a decrease due to the strengthening of the U.S. Dollar compared to 2015. These decreases were partially offset by an increase in general and administrative costs due to the acquisition of the Petrojarl Knarr FPSO unit in July 2015, the commencement of the charter contract of the Arendal Spirit in June 2015, and an increase in services provided to us from Teekay Corporation related to our financing initiatives, the expansion of our fleet and the challenging energy markets.

Interest expense. Interest expense increased to $140.6 million for 2016, compared to $122.8 million for 2015, primarily due to:

•
an increase of $10.1 million due to the interest expense incurred on a $100.0 million, six-month loan issued by Teekay Corporation to us in January 2016, which was refinanced on July 1, 2016 as part of a $200.0 million subordinated promissory note to Teekay Corporation due January 1, 2019;
•
an increase of $9.2 million due to the acquisition of the Petrojarl Knarr FPSO unit in July 2015 and the assumption of a term loan associated with the unit;
•
an increase of $3.6 million due to a non-cash guarantee fee to Teekay Corporation associated with the long-term financing for the East Coast of Canada shuttle tanker newbuildings and certain of our interest rate swaps and cross currency swaps during 2016; and
•
an increase of $3.4 million due to interest expense relating to our second UMS newbuilding up until its construction contract cancellation in late-June 2016;

partially offset by

•
a decrease of $5.2 million due to an increase in capitalized interest on our newbuildings, conversion and upgrade projects; and

•
a decrease of $3.0 million due to the maturity of the NOK 500 million senior unsecured bonds in January 2016.

Realized and unrealized losses on derivative instruments. Net realized and unrealized losses on non-designated derivative instruments were $20.3 million for 2016 compared to $73.7 million for 2015.

During 2016 and 2015, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $2.1 billion and $1.8 billion, respectively, and average fixed rates of approximately 3.3% and 3.4%, respectively. Short-term variable benchmark interest rates during 2016 and 2015 were generally 1.3% or less and 0.8% or less, respectively, and as such, we incurred realized losses of $52.8 million and $60.7 million during 2016 and 2015, respectively, under the interest rate swap agreements.

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

During 2016 and 2015, we were committed to foreign currency forward contracts to hedge portions of our forecasted expenditures in Norwegian Kroner, Euro and the Singapore Dollar, which incurred realized losses of $7.2 million and $13.8 million during 2016 and 2015, respectively.

The $53.4 million decrease in net realized and unrealized losses on derivatives for 2016 compared to 2015, was primarily due to an $18.0 million increase in unrealized gains on interest rate swaps mainly relating to an increase in long-term LIBOR benchmark rates during 2016 compared to 2015, a $10.9 million realized loss due to the early termination of an interest rate swap during 2015, a $10.0 million increase in unrealized gains on foreign currency forward contracts mainly from the weakening of the U.S. Dollar against the Norwegian Kroner as at December 31, 2016 compared to December 31, 2015, a $7.9 million decrease in realized losses on interest rate swaps due to an increase in LIBOR during 2016 and a $6.6 million decrease in realized losses on foreign currency forward contracts due to a decrease in the transfer of previously unrealized losses to realized losses during 2016 related to actual cash settlements.

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

Equity income. Equity income was $17.9 million for 2016 compared to $7.7 million for 2015. The increase in equity income was primarily due to an increase in unrealized gains on derivative instruments relating to our investment in the Libra FPSO joint venture and the Itajai FPSO joint venture, lower repairs and maintenance expenses due to turbine repairs made during 2015 and an insurance claim received during 2016 relating to these turbine repairs for the Itajai FPSO unit.

Foreign currency exchange loss. Foreign currency exchange losses were $14.8 million for 2016, compared to $17.5 million for 2015. Our foreign currency exchange losses are due primarily to the relevant period-end revaluation of Norwegian Kroner-denominated monetary assets and liabilities for financial reporting purposes and the realized and unrealized gains and losses on our cross currency swaps. Gains on Norwegian Kroner-denominated net monetary liabilities reflect a stronger U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on Norwegian Kroner-denominated net monetary liabilities reflect a weaker U.S. Dollar against the Norwegian Kroner on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

For 2016, foreign currency exchange losses include realized losses of $53.5 million (2015 - losses of $10.1 million) and unrealized gains of $46.1 million (2015 - losses of $61.7 million) on the cross currency swaps, and unrealized losses of $39.9 million (2015 - gains of $61.2 million), on the revaluation of the Norwegian Kroner denominated debt. During 2016, NOK 500 million of our senior unsecured bonds matured and NOK 180 million of our senior unsecured bonds were repaid resulting in realized foreign currency exchange gains of $32.6 million and

59


$8.6 million, respectively, on the repayment of the bonds and $32.6 million and $8.6 million realized losses, respectively, on the maturity or partial maturity of the associated cross currency swaps. There were additional realized and unrealized foreign exchange losses of $8.8 million for 2016 (2015 - losses of $6.8 million) on all other monetary assets and liabilities.

Income tax (expense) recovery. Income tax (expense) recovery was $(8.8) million for 2016 compared to $21.4 million for 2015.

The income tax expense of $8.8 million for 2016 was mainly due to an increase in deferred tax expense due to changes in our redeployment assumptions given the sustained low oil price, an income tax accrual for the Voyageur Spirit FPSO unit during 2016 due to an expected taxable income as we fully utilized our U.K. losses carried forward and an estimated tax liability relating to our Singapore and towage entities.

The income tax recovery of $21.4 million for 2015 was mainly due to a decrease in deferred tax expense due to an expected increase in the utilization of Norwegian tax losses against anticipated earnings from the acquisition of the Petrojarl Knarr FPSO unit in July 2015, the commencement of the East Coast of Canada contract during 2015, and the expected commencement of the Gina Krog FSO unit contract in 2017.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
FPSO Segment
As at December 31, 2015, our FPSO fleet consisted of the Petrojarl Knarr, the Petrojarl Varg, the Rio das Ostras, the Piranema Spirit, the Voyageur Spirit, and the Petrojarl I FPSO units, all of which we own 100%, and the Itajai and Libra FPSO units, of which we own 50%.

The following table presents the FPSO segment’s operating results for 2015 and 2014, and also provides a summary of the calendar-ship-days for the FPSO segment. The table excludes the results of the Itajai and the Libra FPSO units, which are accounted for under the equity method.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
531,554

 
354,518

 
49.9
Vessel operating expenses
 
(189,900
)
 
(158,216
)
 
20.0
Depreciation and amortization
 
(137,914
)
 
(72,905
)
 
89.2
General and administrative (1)
 
(38,588
)
 
(27,406
)
 
40.8
Income from vessel operations
 
165,152

 
95,991

 
72.0
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
2,009

 
1,476

 
36.1
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FPSO segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. 2015 includes a business development fee of $9.7 million to Teekay Corporation related to the acquisition of the Petrojarl Knarr FPSO unit.

The average number of our FPSO units increased in 2015 compared to 2014, due to the acquisition of the Petrojarl Knarr on July 1, 2015 and the Petrojarl I on December 14, 2014.

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

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

•
an increase of $182.0 million due to the acquisition of the Petrojarl Knarr FPSO unit in 2015;
•
an increase of $13.5 million on the Voyageur Spirit, primarily due to the charterer’s final acceptance of the charter contract on February 22, 2014, a production bonus earned in 2015 and a production penalty in 2014;
•
an increase of $3.7 million on the Petrojarl Varg, due to an increase in crew hours reimbursed by the charterer during 2015;
•
an increase of $3.6 million relating to revenue received for offshore field studies associated with the Petrojarl Varg (this revenue is offset by operating expenditures incurred, as mentioned below); and
•
an increase of $2.4 million due to the commencement of operations of a water treatment plant on the Piranema Spirit in the second quarter of 2014;

partially offset by

•
a decrease of $11.0 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Brazilian Real compared to 2014 related to the Petrojarl Varg and the Piranema Spirit, respectively (however, these decreases are offset by similar foreign-exchange related decreases in vessel operating expenses);

60


•
a decrease of $7.8 million due to unscheduled off-hire of the Piranema Spirit for repairs during the third and fourth quarters of 2015;
•
a decrease of $4.7 million due to the settlement of reimbursable expenses for the Voyageur Spirit FPSO unit during 2014;
•
a decrease of $2.9 million due to decreases in incentive compensation from the Petrojarl Varg during 2015; and
•
a decrease of $2.0 million primarily due to a decrease in bonus earned from the charterer of the Rio das Ostras for unused maintenance days under the service contract in 2015 compared to 2014 and a retroactive increase in rates in accordance with the annual contractual escalation recorded in the fourth quarter of 2014.

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

Vessel operating expenses. Vessel operating expenses increased for 2015 compared to 2014, primarily due to:

•
an increase of $56.8 million due to the acquisition of the Petrojarl Knarr FPSO unit in 2015;
•
an increase of $7.7 million due to higher repair and maintenance costs on the Piranema Spirit due to unscheduled off-hire during the third and fourth quarters of 2015 and the timing of repair and maintenance costs; and
•
an increase of $4.0 million due to expenditures incurred on offshore field studies for the Petrojarl Varg during 2015;

partially offset by

•
a decrease of $27.2 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Brazilian Real and British Pound;
•
a decrease of $3.3 million due to the timing of costs related to repair and maintenance on the Voyageur Spirit, the Petrojarl Varg and the Rio das Ostras FPSO units;
•
a decrease of $3.0 million due to a reversal of an agency fee accrual relating to the Piranema Spirit during 2015, which we no longer considered payable at that time;
•
a decrease of $2.2 million due to lower ship management costs related to operating the FPSO units; and
•
a decrease of $1.6 million due to external consulting fees incurred during the first quarter of 2014 to achieve final acceptance for the Voyageur Spirit FPSO unit.

Depreciation and amortization. Depreciation and amortization expense increased for 2015 compared to 2014, primarily due to the acquisitions of the Petrojarl Knarr on July 1, 2015 and the Petrojarl I on December 15, 2014.
Shuttle Tanker Segment
As at December 31, 2015, our shuttle tanker fleet consisted of 31 vessels that operate under fixed-rate contracts of affreightment, time charters and bareboat charters, three shuttle tanker newbuildings, one shuttle tanked held for sale and one HiLoad DP unit, which is currently in lay-up. Of these 36 shuttle tankers, six were owned through 50%-owned subsidiaries, one through a 67%-owned subsidiary and three were chartered-in. The remaining vessels are owned 100% by us.

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

61


 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
541,792

 
577,064

 
(6.1
)
Voyage expenses
 
(82,777
)
 
(105,562
)
 
(21.6
)
Net revenues
 
459,015


471,502

 
(2.6
)
Vessel operating expenses
 
(128,156
)
 
(159,438
)
 
(19.6
)
Time-charter hire expenses
 
(51,088
)
 
(31,090
)
 
64.3

Depreciation and amortization
 
(106,190
)
 
(110,686
)
 
(4.1
)
General and administrative (1)
 
(22,884
)
 
(29,154
)
 
(21.5
)
(Write-down) and gain on sale of vessels
 
(65,101
)
 
(1,638
)
 
3,874.4

Restructuring (charge) recovery
 
(568
)
 
225

 
(352.4
)
Income from vessel operations
 
85,028


139,721

 
(39.1
)
Calendar-Ship-Days
 
 
 
 
 


Owned Vessels
 
11,191

 
11,870

 
(5.7
)
Chartered-in Vessels
 
1,128

 
802

 
40.6

Total
 
12,319


12,672

 
(2.8
)
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the shuttle tanker segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.

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

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

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

•
a decrease of $31.3 million relating to the expiration of a long-term contract at the Heidrun field serviced by our contracts of affreightment fleet;
•
a decrease of $18.4 million due to the redelivery of two vessels to us in February 2014 and April 2015 as they completed their time-charter-out agreements; and
•
a decrease of $14.1 million due to the sale of the Navion Svenita in March 2015;

partially offset by

•
an increase of $35.3 million due to an increase in net revenues from the commencement of the East Coast of Canada contract in June 2015;
•
an increase of $8.0 million in revenues from our contract of affreightment fleet due to higher average rates, an increase in rates as provided in certain contracts in our time-chartered-out fleet, and an increase in revenues from the commencement of new contracts in mid-2015;
•
an increase of $3.7 million due to higher average rates earned trading excess shuttle tanker capacity in the conventional tanker spot market, partially offset by fewer conventional tanker spot days;
•
an increase of $2.9 million due to fewer off-hire days in our time-chartered-out fleet; and
•
an increase of $1.7 million due to an increase in reimbursable bunker, crew and dry-docking expenses.

Vessel operating expenses. Vessel operating expenses decreased for 2015 compared to 2014, primarily due to:

•
a decrease of $14.3 million due to the strengthening of the U.S. Dollar against the Norwegian Kroner, Euro and Brazilian Real;
•
a decrease of $6.0 million due to the sales of the Navion Norvegia and the Navion Svenita in October 2014 and March 2015, respectively;
•
a decrease of $4.9 million relating to the HiLoad DP unit mainly due to mobilization expenses incurred in 2014;
•
a decrease of $3.7 million due to the commencement of the FSO conversion of the Randgrid in June 2015; and

62


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

Time-charter hire expenses. Time-charter hire expenses increased for 2015 compared to 2014, primarily due to:

•
an increase of $28.8 million due to the in-chartering of the three shuttle tankers for the East Coast of Canada contract, which commenced in June 2015 (one of the three shuttle tankers, the Mattea, was redelivered on August 31, 2015 and was replaced by one of our owned vessels); and
•
an increase of $2.4 million primarily due to the drydocking and offhire of the Sallie Knutsen during the first and second quarters of 2014 and the drydocking of the Aberdeen during the second quarter of 2014;

partially offset by

•
a decrease of $7.2 million due to the redelivery by us of the Karen Knutsen in January 2014 and the Grena Knutsen in June 2015;
•
a decrease of $2.5 million due to decreased spot in-chartering of shuttle tankers; and
•
a decrease of $1.3 million due to lower time-charter hire rates on the Aberdeen and an increase in off-hire during the third quarter of 2015.

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

•
a decrease of $5.0 million due to the commencement of the FSO conversion of the Randgrid in the June 2015;
•
a decrease of $2.1 million due to the Navion Europa being fully amortized during the second quarter of 2015;
•
a decrease of $2.0 million due to the sale of the Navion Norvegia and the Navion Svenita in October 2014 and March 2015, respectively; and
•
a decrease of $1.0 million due to lower vessel contract amortization expense;

partially offset by

•
an increase of $3.0 million due to the dry docking of eight shuttle tankers from mid-2014 to late-2015; and
•
an increase of $2.7 million due to the commencement of depreciation on the HiLoad DP unit in January 2015.

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

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

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

Restructuring recovery for 2014 was $0.2 million relating to a $0.8 million reimbursement received relating to the reorganization of our shuttle tanker marine operations, partially offset by a $0.6 million charge relating to the reflagging of one shuttle tanker.
FSO Segment
As at December 31, 2015, our FSO fleet consisted of six units that operated under fixed-rate time charters or fixed-rate bareboat charters, in which our ownership interests ranged from 89% to 100%, and one shuttle tanker, the Randgrid, currently undergoing conversion into an FSO unit, in which our ownership interest increased from 67% to 100% during 2015.


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The following table presents the FSO segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days for the FSO segment:
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
57,391

 
53,868

 
6.5

Voyage expenses
 
(851
)
 
(1,500
)
 
(43.3
)
Net revenues
 
56,540


52,368

 
8.0

Vessel operating expenses
 
(26,394
)
 
(28,649
)
 
(7.9
)
Depreciation and amortization
 
(11,775
)
 
(8,282
)
 
42.2

General and administrative (1)
 
(1,372
)
 
(3,870
)
 
(64.5
)
Income from vessel operations
 
16,999


11,567

 
47.0

Calendar-Ship-Days
 
 
 
 
 


Owned Vessels
 
2,395

 
2,190

 
9.4

(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FSO segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.

The average number of our FSO units increased for 2015 compared to 2014, due to the commencement of the FSO conversion of the Randgrid on June 9, 2015.

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

•
an increase of $5.5 million due to the commencement of the Suksan Salamander FSO on its bareboat charter in the third quarter of 2014;
•
an increase of $2.4 million due to the drydocking of the Navion Saga during the third quarter of 2014; and
•
an increase of $2.0 million primarily due to the drydocking of the Dampier Spirit during the second quarter of 2014;

partially offset by

•
a decrease of $3.7 million primarily due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Australian Dollar;
•
a decrease of $1.3 million due to a contract extension in April 2014 for the Pattani Spirit at a lower charter rate for an additional five years; and
•
a decrease of $0.8 million due to reduced rates on the Falcon Spirit.

Vessel operating expenses. Vessel operating expenses decreased for 2015 compared to 2014, primarily due to:

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

partially offset by

•
an increase of $1.0 million due to the amortization of mobilization costs on the Suksan Salamander FSO commencing in the third quarter of 2014; and
•
an increase of $0.5 million due to lower crew costs for the Navion Saga in 2014 mainly relating to a pension adjustment recorded in the first quarter of 2014.

Depreciation and amortization. Depreciation and amortization expense increased for 2015 compared to 2014, primarily due the delivery of the Suksan Salamander FSO in August 2014 and an increase in drydock depreciation for the Navion Saga due its drydocking in the third quarter of 2014.
UMS Segment
As at December 31, 2015, our UMS fleet consisted of one operational unit, the Arendal Spirit, in which we own a 100% interest.

The following table presents the UMS segment’s operating results and calendar-ship-days for 2015 and 2014. We had no operations during 2014 and therefore no revenues or expenditures incurred for the segment for 2014, with the exception of acquisition costs presented as general and administrative expenses.

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Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
28,334

 
-

 
100.0

Vessel operating expenses
 
(13,876
)
 
-

 
100.0

Depreciation and amortization
 
(3,775
)
 
-

 
100.0

General and administrative (1)
 
(4,109
)
 
(622
)
 
560.6

Write-down of vessel
 
(1,000
)
 
-

 
100.0

Income (loss) from vessel operations
 
5,574

 
(622
)
 
(996.1
)
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
318

 
-

 
100.0

(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the UMS segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.0 million paid to Teekay Corporation related to the delivery of the Arendal Spirit UMS.

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

Income from vessel operations. Income from vessel operations increased for 2015 compared to 2014, primarily due to the commencement of the charter contract of the Arendal Spirit in June 2015, partially offset by write-downs relating to two options to purchase two additional units, which expired during 2015.
Towage Segment
As at December 31, 2015, our towage vessel fleet consisted of six long-distance towing and offshore installation vessels and four ultra-long distance towing and offshore installation vessel newbuildings. We own a 100% interest in each of the vessels in our towage fleet.

The following table presents the towage segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned and chartered-in vessels for the towage segment. We did not operate any of these vessels during 2014 and our operating results for the segment in 2014 consisted mainly of general and administrative expenses of $4.3 million.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
40,112

 
523

 
7,569.6

Voyage expenses
 
(12,052
)
 
(105
)
 
11,378.1

Net revenues
 
28,060


418

 
6,612.9

Vessel operating expenses
 
(13,920
)
 
-

 
100.0

Time-charter hire expenses
 
(662
)
 
-

 
100.0

Depreciation and amortization
 
(8,362
)
 
-

 
100.0

General and administrative (1)
 
(4,598
)
 
(4,328
)
 
6.2

Income (loss) from vessel operations
 
518


(3,910
)
 
(113.2
)
Calendar-Ship-Days
 
 
 
 
 
 
Owned Vessels
 
1,587

 
-

 
100.0

Chartered-in Vessels
 
19

 
-

 
100.0

Total
 
1,606

 
-

 
100.0

(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the towage segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below. General and administrative expenses for the year ended December 31, 2015 includes a business development fee of $2.2 million to Teekay Corporation related to the acquisition of the six towing and offshore installation vessels. General and administrative expenses for the year ended December 31, 2014 includes business development fees of $2.6 million relating to the acquisition of ALP.

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

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

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Conventional Tanker Segment
As at December 31, 2015, we owned 100% interests in two Aframax conventional crude oil tankers, the Kilimanajro Spirit, which operated under a fixed-rate time charter with Teekay Corporation, and the Fuji Spirit, which operated in the spot conventional tanker market. Both of these vessels were classified as held for sale as at December 31, 2015.

The following table presents the conventional tanker segment’s operating results for 2015 and 2014, and compares its net revenues (which is a non-GAAP financial measure) for 2015 and 2014, to revenues, the most directly comparable GAAP financial measure, for the same years. The following table also provides a summary of the changes in calendar-ship-days by owned vessels for the conventional tanker segment.
 
 
Year Ended December 31,
 
 
(in thousands of U.S. Dollars, except calendar-ship-days and percentages)
 
2015
 
2014
 
% Change
Revenues
 
30,230

 
33,566

 
(9.9
)
Voyage expenses
 
(2,326
)
 
(5,373
)
 
(56.7
)
Net revenues
 
27,904


28,193

 
(1.0
)
Vessel operating expenses
 
(6,234
)
 
(5,906
)
 
5.6

Depreciation and amortization
 
(6,583
)
 
(6,680
)
 
(1.5
)
General and administrative(1)
 
(1,062
)
 
(2,136
)
 
(50.3
)
Write-down of vessels
 
(3,897
)
 
—

 
100.0

Income from vessel operations
 
10,128


13,471

 
(24.8
)
Calendar-Ship-Days
 
 
 
 
 


Owned Vessels
 
1,432

 
1,460

 
(1.9
)
(1)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the conventional tanker segment based on estimated use of corporate resources). See the discussion under “Other Operating Results” below.

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

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

•
a decrease of $1.8 million due to net termination fees paid to Teekay Corporation in relation to the early terminations of bareboat and time-charter contracts with a subsidiary of Teekay Corporation for the SPT Explorer, Navigator Spirit and Fuji Spirit in December 2015; and
•
a decrease of $0.4 million due to the sales of the SPT Explorer and Navigator Spirit in December 2015;

partially offset by:

•
an increase of $1.0 million due to a higher amount of reimbursed bunkers in 2015 compared to 2014; and
•
an increase of $0.9 million due to the scheduled drydocking of the Kilimanjaro Spirit during the third quarter of 2014.

Write-down of vessels. Write-down of vessels was $3.9 million for 2015. During 2015, the carrying values of the Kilimanjaro Spirit and Fuji Spirit were written down to their estimated fair values using appraised values. The write-downs were the result of the expected sales of these two vessels and both vessels were classified as held for sale on our consolidated balance sheet as of December 31, 2015.
Other Operating Results
General and administrative. General and administrative expenses increased to $72.6 million for 2015, from $67.5 million for 2014. The increase was due to business development fees to Teekay Corporation of $9.7 million, $2.2 million and $2.0 million, respectively, in connection with the acquisition of the Petrojarl Knarr FPSO unit, the six long-distance towing and offshore installation vessels, and the Arendal Spirit UMS recorded in the third quarter of 2015, the acquisition of the Petrojarl Knarr FPSO unit in July 2015, the acquisition of Logitel during the third quarter of 2014, the commencement of the charter contract of the Arendal Spirit in June 2015, the commencement of the East Coast of Canada contract in June 2015 and an increase in services provided to us from Teekay Corporation as a result of our growth, partially offset by a decrease due to the strengthening of the U.S. Dollar compared to the same periods in 2014, a $2.1 million business development fee paid to Teekay Corporation in relation to the acquisition of the Petrojarl I FPSO unit during the fourth quarter of 2014, a $1.6 million business development fee paid to Teekay Corporation in relation to the acquisition of ALP during the second quarter of 2014, a $1.0 million acquisition fee to a third party relating to the acquisition of ALP during the first quarter of 2014, a decrease in management fees relating to our FPSO fleet primarily from our focus on obtaining the final charter contract acceptance for the Voyageur Spirit FPSO unit in the first quarter of 2014 and a decrease in management fees relating to our shuttle tanker fleet primarily from cost saving initiatives.

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

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

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•
an increase of $17.0 million due to the borrowings and loan costs relating to the Suksan Salamander FSO unit (which commenced operations during the third quarter of 2014), the six towing vessels (which delivered throughout 2015), the Arendal Spirit UMS (which commenced operations during the second quarter of 2015) and $300 million of senior unsecured bonds issued in May 2014; and
•
an increase of $1.1 million due to the ineffective portion of unrealized losses incurred on interest rate swaps designated as cash flow hedges during 2015 for the towage newbuildings;

partially offset by

•
a decrease of $7.0 million relating to lower interest expense on our NOK bonds as a result of the depreciation of the NOK against the U.S. Dollar and a decrease in NIBOR; however, this decrease was offset by an increase in realized losses on cross currency swaps related to our NOK senior unsecured bonds, which losses are included in foreign currency exchange losses;
•
a decrease of $2.0 million due to an increase in capitalized interest on our newbuildings; and
•
a net decrease of $1.3 million due to lower debt balances, partially offset by higher interest rates on existing debt facilities compared to 2014.

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

During 2015 and 2014, we had interest rate swap agreements with aggregate average outstanding notional amounts of approximately $1.8 billion and $1.7 billion, respectively, and average fixed rates of approximately 3.4% and 3.6%, respectively. Short-term variable benchmark interest rates during these periods were generally 0.8% or less and, as such, we incurred realized losses of $60.7 million and $55.6 million during 2015 and 2014, respectively, under the interest rate swap agreements.

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

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

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

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

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

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

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

Income tax recovery (expense). Income tax recovery (expense) was $21.4 million for 2015 and ($2.2) million for 2014. The increase in deferred income tax recovery of $23.9 million for 2015 compared to 2014 was primarily due to the acquisition of the Petrojarl Knarr FPSO unit and the commencement of the East Coast of Canada contract during 2015, and the expected commencement of the Gina Krog FSO unit contract in

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mid-2017, from which we expect to utilize more of our Norwegian tax losses from the earnings anticipated from their contracts, as well as an expected increase in earnings from our existing fleet, which resulted in a decrease in our deferred tax asset valuation allowance and an increase in deferred income tax recovery.
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 terms between three to ten years. Prior to the fourth quarter of 2015, the operating cash flow our vessels generated each quarter, excluding a reserve for maintenance capital expenditures and distributions on our preferred units, was generally paid out to our common unitholders within approximately 45 days after the end of each quarter. Global crude oil prices have significantly declined since mid-2014 and this decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming equity capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with the uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, we believe that it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, in December 2015, we reduced our quarterly cash distributions per common unit to $0.11 per common unit, and our near-to-medium-term business strategy is primarily focused on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations rather than pursuing additional growth projects. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and growing, supported by a large and well-diversified portfolio of fee-based contracts with high quality counterparties.

In order to manage our unfunded capital expenditures and upcoming debt maturities, in addition to reducing our quarterly cash distributions to $0.11 per common unit, we completed the following series of initiatives during the second quarter of 2016:
•
obtaining additional bank financing, including a $250 million debt facility for the three East Coast of Canada newbuilding shuttle tankers, a $40 million debt facility for six previously un-mortgaged vessels, and a new $35 million tranche added to an existing debt facility secured by two shuttle tankers;
•
extending $75 million of the outstanding principal amount of an existing revolving credit facility financing for the Petrojarl Varg FPSO unit until late-2017;
•
extending the majority of the principal maturity payments to late-2018 for two of our existing NOK senior unsecured bonds, previously due in January 2017 and January 2018, and agreeing to pay a portion of the outstanding principal amount of these bonds in October 2016, October 2017 and January 2018;
•
agreeing with Teekay Corporation to pay all distributions on our common units to Teekay Corporation, including distributions to our general partner, in common units, instead of cash, until our NOK bonds maturing in 2018 have been fully repaid;
•
extending to January 2019 the maturity date of $200 million in obligations owing to a subsidiary of Teekay Corporation under the terms of a subordinated promissory note, which bears interest at the rate of 10.0% per annum, one half of which will be paid in cash, and the other half of which will be paid in our common units or from the proceeds of the sale of equity securities;
•
issuing $200 million of equity, consisting of (i) $100 million of our 10.5% Series D Preferred Units (with a two-year option to pay quarterly distributions in common units rather than cash) plus 4.5 million common unit warrants with an exercise price of $4.55 per common unit and 2.25 million common unit warrants with an exercise price of $6.05 per common unit, and (ii) $100 million of common units at a price of $4.55 per unit;
•
cancelling, by our subsidiary Logitel, the shipbuilding contracts for the two remaining UMS newbuildings; and
•
amending the terms of certain interest rate swaps to defer the counterparties’ early termination options and extending and increasing the threshold of existing cross currency swaps related to our two NOK bonds that have been extended as part of these initiatives.
As part of completing the above financing initiatives, we agreed to convert $46 million of face value of the $250 million of Series C Preferred Units for approximately 8.3 million common units and the remaining approximately $204 million of outstanding Series C Preferred Units for approximately 8.5 million of our newly-issued 8.60% Series C-1 Preferred Units that also include a two-year option to pay quarterly distributions in the form of common units rather than cash. We agreed that, until we repay amounts outstanding under our NOK bonds maturing in 2018, we will only pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units in common units, except that, at any time with respect to the Series C-1 Preferred Units, and at any time after June 29, 2018 with respect to the Series D Preferred Units, we may pay distributions to holders of Series C-1 Preferred Units and Series D Preferred Units, respectively, in cash, if the amount of such cash distributions are matched or exceeded by the proceeds of additional equity raised by us in advance of, or within six months following, payment of the cash distributions. We also issued $31 million of common units during 2016 under our continuous offering program.

As part of the financing initiatives, Teekay Corporation provided financial guarantees to us for liabilities associated with the long-term debt financing relating to the East Coast of Canada newbuilding shuttle tankers and for certain of our interest rate swap and cross currency swap liabilities. The guarantees cover liabilities totaling up to $495 million and have been provided at no additional cost to us.

As at December 31, 2016, our total cash and cash equivalents were $227.4 million, compared to $258.5 million as at December 31, 2015. Our total liquidity, defined as cash, cash equivalents and undrawn long-term borrowings, was $260.7 million as at December 31, 2016,

68


compared to $282.7 million as at December 31, 2015. The decrease in liquidity was primarily due to: the scheduled repayments or prepayments of outstanding term loans and NOK bonds; collateral posted on the Petrojarl I term loan; and payments for committed newbuildings and conversions (please read Item 18 - Financial Statements: Note 14. Commitments and Contingencies), partially offset by proceeds from the issuance and sale of Series D Preferred Units and common units as described above and as part of our continuous offering program; additional bank financings as described above; proceeds from the sale of the Navion Europa, Navion Torinita, Fuji Spirit and Kilimanjaro Spirit; and a decrease in collateral on cross currency swaps.

As at December 31, 2016, we had a working capital deficit of $398.0 million, compared to a working capital deficit of $504.5 million as at December 31, 2015. Accounts receivable decreased mainly due to the timing of collections. Vessels held for sale decreased due to the sale of the Navion Torinita, Fuji Spirit and Kilimanjaro Spirit during 2016 partially offset by the classification of the Navion Saga as held for sale as at December 31, 2016. Accrued liabilities increased mainly due to estimated potential damages relating to the cancellation of the two UMS newbuildings. The due to affiliates balance in current liabilities decreased mainly due to the refinancing of the $100 million convertible promissory note issued to Teekay Corporation in connection with the financing of the acquisition of the Petrojarl Knarr FPSO unit, and a $100 million six-month loan made by Teekay Corporation to us, with a $200 million long-term subordinated promissory note issued to a subsidiary of Teekay Corporation by us, which matures in 2019. The current portion of derivative instruments in current liabilities decreased due to the amendment of terms of certain interest rate swaps to defer the counterparties’ early termination options and extend and increase the collateral threshold of existing cross currency swaps related to two of our NOK bonds, as described above, and an increase in long-term LIBOR benchmark rates during 2016 compared to 2015. The current portion of long-term debt increased mainly due to reclassifying one term loan maturing in the first half of 2017 to the current portion of long-term debt as at December 31, 2016, an increase in the current portion of long-term debt of an existing term loan as at December 31, 2016 compared to December 31, 2015, related to the refinancing of the existing debt facility and a portion of a NOK bond due in October 2017, the drawdown of existing term loans and revolving debt facilities to finance the installment payments on the four towing and offshore installation newbuildings, one of which delivered during September 2016, the Petrojarl I FPSO unit upgrades and the reclassification of a portion of the term loan relating to the Gina Krog FSO conversion to current portion of long-term debt, partially offset by the repayment of NOK 680 million of NOK bonds which matured and were paid in 2016 and other debt repayments and prepayments during 2016.

Our primary liquidity needs for 2017 and 2018 are to pay existing, committed capital expenditures, to make scheduled repayments of debt, to pay debt service costs, quarterly distributions on outstanding common and preferred units, operating expenses and dry docking expenditures, to fund general working capital requirements, to settle claims and potential claims against us and manage our working capital deficit. We anticipate that our primary sources of funds for 2017 and 2018 will be cash flows from operations, bank debt, equity and bond issuances and proceeds from the sale of partial interests in certain assets. As at December 31, 2016, our total future contractual obligations for vessels and newbuildings and committed conversions, including our 50% interest in the Libra FPSO conversion, were estimated to be $671 million, consisting of $600.4 million (2017) and $70.6 million (2018). Of this $671 million of future contractual obligations, we have pre-arranged financing in place of $436.8 million and a further $60.0 million held in escrow as funding for the Petrojarl I FPSO project, with a remaining requirement of $174.2 million, which mainly relates to 2017. We expect to manage these funding requirements from existing and expected liquidity.

Primarily as a result of the working capital deficit and committed capital expenditures, over the one-year period following the issuance of our 2016 consolidated financial statements we will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet our minimum liquidity requirements under our financial covenants. These anticipated sources of financing include refinancing debt facilities that mature during the one-year period, raising additional capital through equity issuances, increasing amounts available under existing debt facilities and entering into new debt facilities, negotiating extensions or redeployments of existing assets and the sale of partial interests of assets. We are actively pursuing the funding alternatives described above, which we consider probable of completion based on our history of being able to raise equity, refinance loan facilities for similar types of vessels, and indicative offers received from potential investors for partial interests in certain assets. We are in various stages of completion on these matters. Please refer to Item 18 - Financial Statements: Note 14k - Commitments and Contingencies.

Our revolving credit facilities and term loans are described in Item 18 – Financial Statements: Note 8 – Long-Term Debt. They contain covenants and other restrictions typical of debt financing secured by vessels that restrict the ship-owning subsidiaries from incurring or guaranteeing indebtedness; changing ownership or structure, including mergers, consolidations, liquidations and dissolutions; making dividends or distributions if we are in default; making capital expenditures in excess of specified levels; making certain negative pledges and granting certain liens; selling, transferring, assigning or conveying assets; making certain loans and investments; or entering into a new line of business. Certain of our revolving credit facilities and term loans include financial covenants. Should we not meet these financial covenants, the lender may accelerate the repayment of the revolving credit facilities and term loans, thus having an impact on our short-term liquidity requirements. We have two revolving credit facilities and five term loans that require us to maintain vessel values to drawn principal balance ratios of a minimum range of 113% to 125%. Such requirement is assessed either on a semi-annual or annual basis, with reference to vessel valuations performed by one or more agreed upon third parties. Should the ratio drop below the required amount, the lender may request we either prepay a portion of the loan in the amount of the shortfall or provide additional collateral in the amount of the shortfall, at our option. As at December 31, 2016, these ratios were estimated to range from 120% to 433% and exceeded the minimum ratios required. The vessel values used in these ratios are the appraised values prepared by us based on second-hand sale and purchase market data. Changes in the shuttle tanker, towing and offshore installation, UMS, FPSO or FSO markets could negatively affect these ratios. In October 2016, December 2016, February 2017 and April 2017, the lenders for our loan relating to the Petrojarl I FPSO unit agreed to extend the availability date of the loan for successive periods of two months, as the loan was subject to a mandatory prepayment provision, initially in early October 2016, if the unit was not accepted at that time by the charterer. These interim extensions provide additional time for us to negotiate a revised schedule for the delivery of the unit and thereafter, amend the loan facility accordingly to reflect the revised delivery schedule. As at December 31, 2016, we had $60 million held in escrow to fund the final upgrade costs. As at December 31, 2016, we and our affiliates were in compliance with all covenants relating to the revolving credit facilities and term loans.


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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)
 
2016
 
2015
 
2014
Net cash flow from operating activities
 
353,814

 
371,221

 
160,186

Net cash flow (used for) from financing activities
 
(105,145
)
 
273,138

 
42,404

Net cash flow used for investing activities
 
(279,764
)
 
(638,024
)
 
(169,578
)
Operating Cash Flows.
Net cash flow from operating activities decreased to $353.8 million for 2016, from $371.2 million for 2015, primarily due to the redelivery of the Petrojarl Varg FPSO unit during 2016, two shuttle tankers in 2016 and 2015, respectively, and the Navion Saga FSO unit during late-2016, as they completed their time-charter-out agreements, lower production and unused maintenance day bonuses on certain of our FPSO units during 2016, increased repairs and maintenance expenses on our shuttle tanker fleet, the expiration of a long-term shuttle tanker contract during 2015, the sale of a shuttle tanker and two conventional tankers during 2015, and two shuttle tankers and two conventional tankers, which were subsequently chartered-in by us, during 2016, the commencement of the FSO conversion of the Randgrid shuttle tanker during 2015, off hire of the Arendal Spirit UMS during 2016, lower rates and utilization for our towage fleet and an increase in interest expense from intercompany borrowings, partially offset by the acquisition of the Petrojarl Knarr FPSO unit during 2015, the unscheduled off-hire of the Piranema Spirit FPSO unit during 2015, the commencement of the charter contract for the Arendal Spirit during 2015, the acquisition of six towage vessels during 2015 and delivery of one newbuilding towage vessel during 2016, lower crew costs for our FPSO units, our shuttle tanker fleet and our FSO units, the commencement of the East Coast of Canada shuttle tanker contract in 2015, higher average rates and higher utilization from our shuttle tanker fleet, a decrease in general and administrative expenses and a decrease in realized losses on derivative instruments.

The increase in non-cash working capital items for 2016 compared to 2015 is primarily due to the timing of payments made to vendors and received from customers.

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

Net cash flow from operating activities increased to $371.2 million for 2015, from $160.2 million for 2014, primarily due to the acquisition of the Petrojarl Knarr FPSO unit during 2015, the charterers final acceptance of the Voyageur Spirit FPSO unit during 2014 and a production bonus earned during 2015, whereas a production penalty was incurred on the unit during 2014, decreased repairs and maintenance expenses on certain of our FPSO units and our shuttle tanker fleet, the commencement of the East Coast of Canada shuttle tanker contract in 2015, higher average rates from our shuttle tanker fleet, lower operating expenses on the HiLoad DP unit due to mobilization expenses incurred during 2014, the redelivery of two in-chartered shuttle tankers in 2015 and 2014, respectively, the commencement of the bareboat charter contract for the Suksan Salamander FSO unit during 2014, the commencement of the charter contract for the Arendal Spirit during 2015, the acquisition of six towage vessels during 2015, and lower operating expenses due to the strengthening of the U.S. Dollar relative to the NOK, British Pound, Euro, Australian Dollar and Brazilian Real, partially offset by the unscheduled off-hire of the Piranema Spirit FPSO unit during 2015, the expiration of a long-term shuttle tanker contract during 2015, the redelivery of two shuttle tankers in 2015 and 2014, respectively, as they completed their time-charter-out agreements, the sale of a shuttle tanker and two conventional tankers during 2015, and one shuttle tanker during 2014, the commencement of the FSO conversion of the Randgrid shuttle tanker during 2015, an increase in general and administrative expenses, an increase in realized losses on derivative instruments and a decrease in dividends received from our investments in equity accounted joint ventures.

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

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

Financing Cash Flows

We use our revolving credit facilities to finance capital expenditures and for general partnership purposes. Occasionally we will do this until longer-term financing is obtained, at which time we typically use all or a portion of the proceeds from the longer-term financings to prepay outstanding amounts under the revolving credit facilities. Our proceeds from the issuance of long-term debt, net of debt issuance costs and prepayments of long-term debt were $246.8 million in 2016, $639.4 million in 2015 and $915.9 million in 2014.


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Net proceeds from the issuance of long-term debt decreased for 2016 from 2015, mainly due to the drawdown of five new debt facilities and one existing revolving credit facility and the issuance of $30 million senior bonds during 2015. We used the 2015 debt proceeds primarily to fund the final installment payment on the Arendal Spirit UMS, the delivery of six towing and offshore installation vessels, installment payments on the four towing and offshore installation newbuildings and upgrades on the Petrojarl I FPSO unit and the Gina Krog FSO unit conversion. The decrease was due to lower debt drawdowns in 2016 relating to one new term loan and three existing term loans, and a new $35 million tranche added to an existing debt facility secured by two shuttle tankers during 2016, and a prepayment on a revolving credit facility during 2015. We used the 2016 debt net proceeds primarily to fund the installment payments on the four towing and offshore installation newbuildings (including the final installment on the first towage newbuilding), three shuttle tanker newbuildings being constructed for the East Coast of Canada contract, upgrades on the Petrojarl I FPSO unit and the Gina Krog FSO unit conversion.

Net proceeds from the issuance of long-term debt decreased for 2015 from 2014, mainly due to proceeds from the issuance of NOK 1,000 million and $300.0 million unsecured bonds during 2014, which were used for general partnership purposes, and long-term debt issued to finance conversion costs for the Suksan Salamander in 2014, partially offset by the drawdown of five new debt facilities and one existing revolving credit facility and the issuance of $30 million senior bonds during 2015.

We actively manage the maturity profile of our outstanding financing arrangements. Our scheduled repayments of long-term debt were $434.3 million in 2016, $341.8 million in 2015 and $804.7 million in 2014. The increase during 2016 compared to 2015 was mainly due to the maturity of a NOK 500 million tranche and partial repayment of NOK 180 million of our senior unsecured bonds in January 2016 and October 2016, respectively. The decrease during 2015 compared to 2014 was mainly due to the maturity of two revolving debt facilities during 2014.

We purchased the Petrojarl Knarr FPSO unit from Teekay Corporation on July 1, 2015, as described in Item 18 - Financial Statements: Note 3 Dropdown Predecessor, for a cash payment of $112.7 million, net of $14.2 million of cash acquired.

In order to partially finance new acquisitions, we have issued common or preferred units to the public and to institutional investors. We raised net proceeds (including our general partner’s 2% proportionate capital contribution) of $228.9 million in 2016, $380.2 million in 2015 and $186.1 million in 2014.

During 2016, we issued 5.5 million common units under our continuous offering program for net proceeds of approximately $31.0 million, including the general partner’s 2% proportionate capital contribution of $0.6 million and net of approximately $0.8 million of offering costs. The net proceeds from the issuance of these common units were used for general partnership purposes.

In June 2016, we issued 22.0 million common units in a private placement for net proceeds of approximately $99.5 million, including the general partner's 2% proportionate capital contribution. We used the proceeds for general partnership purposes including the funding of existing newbuilding installments and capital conversion projects.

In June 2016, we issued 4.0 million of our 10.50% Series D Preferred Units to a group of investors for net proceeds of approximately $97.2 million. We also issued to these investors 4.5 million warrants with an exercise price equal to the closing price of our common units on June 16, 2016, or $4.55 per unit, and 2.25 million warrants with an exercise price at a 33% premium to the closing price of our common units on June 16, 2016, or $6.05 per unit. We used the proceeds for general partnership purposes including the funding of existing newbuilding installments and capital conversion projects.

In July 2015, we completed a private placement of $250 million of our 8.60% Series C Preferred Units for net proceeds of approximately $249.8 million. We used the net proceeds from the issuance to partially fund the acquisition of the Petrojarl Knarr FPSO unit from Teekay Corporation and to fund installments for the three shuttle tanker newbuildings being constructed to service the East Coast of Canada contract.

In April 2015, we completed a public offering of $125 million of our 8.5% Series B Preferred Units, raising net proceeds of approximately $120.8 million. The net proceeds from the issuance were used for general partnership purposes, including the funding of newbuilding installments, capital conversion projects and vessel acquisitions.

In November 2014, we issued 6.7 million common units in a private placement for net proceeds of approximately $178.5 million, including the general partner's 2% proportionate capital contribution. We used the proceeds for general partnership purposes including the funding of vessel conversion projects and to finance the UMS and towage vessel newbuildings.

Cash distributions paid by our subsidiaries to non-controlling interests totaled $14.2 million in 2016, $23.6 million in 2015 and $27.9 million in 2014. Cash distributions paid by us to our common and preferred unitholders and our general partner totaled $78.6 million in 2016, $257.9 million in 2015 and $214.7 million in 2014. The decrease in distributions paid by our subsidiaries to non-controlling interests in 2016 from 2015 and in 2015 from 2014 was due to the timing of payments of cash distributions.

The decrease in distributions to our common and preferred unitholders and our general partner in 2016 from 2015 was attributed to a decrease in the quarterly distribution paid on our common units effective the fourth quarter of 2015 to $0.11 per common unit compared to $0.5384 per common unit paid during the first three quarters of 2015 and the issuance of 2.0 million common units for a total value of $10.2 million, as a payment-in-kind for the distributions on our Series C-1 and Series D Preferred Units and our common units and general partner interest held by subsidiaries of Teekay Corporation for the distribution made during the fourth quarter of 2016, partially offset by an increase in the number of preferred units resulting from the issuance of 5.0 million Series B Preferred Units in April 2015 and 10.4 million Series C Preferred Units issued in July 2015 until their conversion to Series C-1 preferred units or common units in June 2016.


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The increase in distributions to our common and preferred unitholders and our general partner in 2015 from 2014 was attributed to an increase of $0.0216 per unit in our cash distribution to common unitholders for our distributions relating to the third quarter of 2015, and an increase in the number of common units resulting from 14.6 million common units issued during 2015, 6.9 million common units issued during 2014 and an increase in the number of preferred units resulting from the issuance of 5.0 million Series B preferred units in April 2015 and the 10.4 million Series C convertible preferred units issued in July 2015. The increase in the 2015 cash distribution coincided with our acquisition of the Knarr FPSO unit.

Subsequent to December 31, 2016, distributions of $16.6 million on our outstanding common units and general partner interest related to the fourth quarter of 2016 were declared of which $11.8 million relating to common units held by the public were paid in cash and $4.8 million relating to common units and the general partner interest held by a subsidiary of Teekay Corporation were paid with our common units on February 10, 2017. Subsequent to December 31, 2016, cash distributions of $5.4 million for our Series A and Series B Preferred Units relating to the fourth quarter of 2016 were declared and were paid on February 15, 2017. Subsequent to December 31, 2016, distributions of $7.0 million for our Series C-1 and Series D Preferred Units relating to the fourth quarter of 2016 were declared and were settled in common units on February 15, 2017.

Investing Cash Flows

During 2016, net cash flow used for investing activities was $279.8 million, primarily relating to $294.6 million of expenditures for vessels and equipment (including conversion costs on the Gina Krog FSO conversion, upgrade costs on the Petrojarl I FPSO unit, installment payments on the newbuilding towing and offshore installation vessels, partially offset by credits received relating to the Petrojarl Knarr FPSO unit), $54.9 million of investments in our joint ventures (including $58.2 million of cash investments partially offset by a $3.3 million construction credit received) and $0.1 million net investments in direct financing lease assets (including $6.4 million of investments in direct financing lease assets partially offset by $6.3 million received from leasing our direct financing lease assets to third parties), partially offset by $69.8 million from the sale of the Navion Torinita and Navion Europa shuttle tankers and the Fuji Spirit and Kilimanjaro Spirit conventional tankers.

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

During 2014, net cash flow used for investing activities was $169.6 million, primarily relating to the expenditures for vessels and equipment (including installment payments on the four newbuilding towing and offshore installation vessels, conversion costs on the Gina Krog FSO conversion, installment payments on the UMS newbuildings and various other vessel additions), investments in our equity accounted joint ventures of $12.4 million, $5.2 million of advances to our joint ventures and a $2.3 million acquisition cost for 100% of the shares of ALP, partially offset by aggregate sales proceeds of $13.4 million from the sale of the Navion Norvegia shuttle tanker, scheduled lease payments of $5.1 million received from the leasing of our VOC emissions equipment and direct financing lease assets and a net cash inflow of $4.1 million due to $8.1 million cash received in connection with the acquisition of 100% of the shares of Logitel, offset by $4.0 million cash consideration paid.
Contractual Obligations and Contingencies
The following table summarizes our long-term contractual obligations as at December 31, 2016:
 

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Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Beyond
2021
 
 
(in millions of U.S. Dollars)
U.S. Dollar-Denominated Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bond repayments (1)
 
300.0

 
—

 
—

 
300.0

 
—

 
—

 
—

Secured debt - scheduled repayments(1)
 
1,993.7

 
348.2

 
412.0

 
332.7

 
243.1

 
220.0

 
437.7

Secured debt - repayments on maturity
 
687.1

 
219.7

 
154.1

 
25.0

 
40.0

 
14.9

 
233.4

Subordinated promissory note - repayment on maturity (2)
 
200.0

 
—

 
—

 
200.0

 
—

 
—

 
—

Chartered-in vessels (operating leases)
 
122.3

 
69.7

 
35.4

 
17.2

 
—

 
—

 
—

Acquisition of vessels and newbuildings and committed conversion costs (3)
 
671.0

 
600.4

 
70.6

 
—

 
—

 
—

 
—

Norwegian Kroner-Denominated Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bond repayments (4)
 
256.9

 
20.8

 
120.4

 
115.7

 
—

 
—

 
—

Total contractual obligations
 
4,231

 
1,258.8

 
792.5

 
990.6

 
283.1

 
234.9

 
671.1

(1)
Excludes expected interest for U.S. Dollar-Denominated debt of $93.3 million (2017), $75.3 million (2018), $53.2 million (2019), $32.5 million (2020), $24.7 million (2021) and $34.0 million (beyond 2021). Expected interest payments for secured debts are based on existing interest rates (fixed-rate loans) and LIBOR as at December 31,2016, plus margins which ranged between 0.30% and 4.00% (variable-rate loans) as at December 31, 2016. The expected interest payments do not reflect the effect of related interest rate swaps that we have used as an economic hedge of certain of our variable rate debt.
(2)
Consists of the repayment of the $200.0 million subordinated promissory note, issued to a subsidiary of Teekay Corporation effective July 1, 2016. The promissory note bears interest at an annual rate of 10.00% on the outstanding principal balance, one half of which will be paid in cash, and the other half of which will be paid in common units or from the proceeds of the sale of equity securities. Excludes maximum expected interest payments of $20.0 million (2017) and $20.0 million (2018).
(3)
Consists of the estimated remaining payments for the acquisition of three towing and offshore installation newbuildings, three shuttle tanker newbuildings, our 50% interest in an FPSO conversion for the Libra field, upgrades of the Petrojarl I FPSO unit and the FSO conversion for the Randgrid shuttle tanker. Please read Item 18 – Financial Statements: Note 14 (a), (b), (d), (e), and (f) – Commitments and Contingencies. We have pre-arranged financing of approximately $436.8 million relating to our capital expenditure commitments.
(4)
Norwegian Kroner-denominated bond repayments are based on the foreign exchange rate as at December 31, 2016 and exclude the impact of the cross-currency swaps. Excludes expected interest payments of $15.1 million (2017), $14.3 million (2018), and $0.5 million (2019). Expected interest payments are based on NIBOR as at December 31,2016, plus margins which ranged between 4.25% and 5.75% as at December 31, 2016. The expected interest payments do not reflect the effect of related interest rate swaps and cross currency swaps that we have used as an economic hedge of certain of our Norwegian Kroner-denominated obligations.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with GAAP, which requires us to make estimates in the application of our accounting policies based on our best assumptions, judgments and opinions. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates and such differences could be material. Accounting estimates and assumptions discussed in this section are those that we consider to be the most critical to an understanding of our financial statements, because they inherently involve significant judgments and uncertainties. For a further description of our material accounting policies, please read Item 18 - Financial Statements: Note 1 - Summary of Significant Accounting Policies.

Revenue Recognition

Description. A portion of our revenues are generated from voyages servicing contracts of affreightment and to a lesser extent, spot voyages. Within the shipping industry, the two methods used to account for revenues and expenses are the proportionate performance and the completed voyage methods. Most shipping companies, including us, use the proportionate performance method. For each method, voyages may be calculated on a load-to-discharge, load-to-load or discharge-to-discharge basis. In other words, revenues are recognized ratably either from the beginning of when product is loaded for one voyage to when it is loaded for another voyage, or from when product is discharged (unloaded) at the end of one voyage to when it is discharged after the next voyage. We recognize revenues from time charters and bareboat charters daily over the term of the charter as the applicable vessel operates under the charter. We recognize revenues from

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towage charters ratably in proportion to the stage of completion of a project, which is determined based on an assessment of the work performed. Revenues from FPSO service contracts are recognized as service is performed. Revenues from UMS contracts are recognized as the service is performed. We generally do not recognize revenues during days that a vessel is off hire.

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

Effect if Actual Results Differ from Assumptions. If actual results are not consistent with our estimates in applying the proportionate performance method, our revenues could be overstated or understated for any given period by the amount of such difference.
Vessel Lives and Impairment
Description. The carrying value of each of our vessels represents its original cost at the time of delivery or purchase less depreciation and impairment charges. We depreciate the original cost, less an estimated residual value, of our vessels on a straight-line basis over each vessel’s estimated useful life. The carrying values of our vessels may not represent their market value at any point in time because the market prices of second-hand vessels tend to fluctuate with changes in charter rates and the cost of newbuildings. Both charter rates and newbuilding costs tend to be cyclical in nature.

We review vessels and equipment for impairment whenever events or circumstances indicate the carrying value of an asset, including the carrying value of the charter contract, if any, under which the vessel is employed, may not be recoverable. This occurs when the asset’s carrying value is greater than the future undiscounted cash flows the asset is expected to generate over its remaining useful life. For a vessel under charter, the discounted cash flows from that vessel may exceed its market value, as market values may assume the vessel is not employed on an existing charter. If the estimated future undiscounted cash flows of an asset exceed the asset’s carrying value, no impairment is recognized even though the fair value of the asset may be lower than its carrying value. If the estimated future undiscounted cash flows of an asset is less than the asset’s carrying value and the fair value of the asset is less than its carrying value, the asset is written down to its fair value. Fair value is calculated as the net present value of estimated future cash flows, which, in certain circumstances, will approximate the estimated market value of the vessel.

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

The following table presents by segment, the aggregate market values and carrying values of certain of our vessels that we have determined have a market value that is less than their carrying value as of December 31, 2016. Specifically, the following table reflects all such vessels, except those operating on contracts where the remaining term is significant and the estimated future undiscounted cash flows relating to such contracts are sufficiently greater than the carrying value of the vessels such that we consider it unlikely impairment would be recognized in the following year. Consequently, the vessels included in the following table generally include those vessels employed on single-voyage, or spot charters, as well as those vessels near the end of existing charters or other operational contracts. While the market values of these vessels are below their carrying values, no impairment has been recognized on any of these vessels as the estimated future undiscounted cash flows relating to such vessels are greater than their carrying values.

We would consider the vessels reflected in the following table to be at a higher risk of future impairment. The table is disaggregated for vessels which have estimated future undiscounted cash flows that are marginally or significantly greater than their respective carrying values. Vessels with estimated future cash flows significantly greater than their respective carrying values would not necessarily represent vessels that would likely be impaired in the next 12 months. The recognition of impairment in the future for those vessels may primarily depend upon our decision to dispose of the vessel instead of continuing to operate it. In deciding whether to dispose of a vessel, we determine whether it is economically preferable to sell the vessel or continue to operate it. This assessment includes an estimate of the net proceeds expected to be received if the vessel is sold in its existing condition compared to the present value of the vessel’s estimated future revenue, net of operating costs. Such estimates are based on the terms of the existing charter, charter market outlook and estimated operating costs, given a vessel’s type, condition and age. In addition, we typically do not dispose of a vessel that is servicing an existing customer contract. The recognition of impairment in the future may be more likely for vessels that have estimated future undiscounted cash flow marginally greater than their respective carrying value.
(in thousands of U.S. Dollars, except number of vessels)
Reportable Segment
 
Number of
Vessels
 
Market Values(1)
$
 
Carrying Values
$
Shuttle Tanker Segment(2)
 
2
 
55,297

 
70,444

FSO Segment(2)
 
1
 
6,000

 
12,241

FPSO Segment(2)
 
1
 
244,000

 
244,188


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(1)
Market values are determined using reference to second-hand market comparable values or using a depreciated replacement cost approach as at December 31, 2016. Since vessel values can be volatile, our estimates of market value may not be indicative of the current or future prices we could obtain if we sold any of the vessels. In addition, the determination of estimated market values for our shuttle tankers, FSO and FPSO units may involve considerable judgment, given the illiquidity of the second-hand markets for these types of vessels.
The estimated market values for shuttle tankers was based on second-hand market comparable values for conventional tankers of similar age and size, adjusted for shuttle tanker specific functionality. The estimated market value for the HiLoad DP unit, included in the shuttle tanker segment, in the table above was based on the present value of expected future cash flows given that there are no market comparable values for this unit. The estimated market value for the FSO and FPSO unit in the table above was based on second-hand market comparable values for similar vessels. Given the advanced age of these vessels, the estimated market values substantially reflect the price of steel and amount of steel in the vessel.
(2)
Undiscounted cash flows for these vessels are marginally greater than their carrying values.

Judgments and Uncertainties. Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Shuttle and conventional tankers are depreciated using an estimated useful life of 20 to 25 years commencing the date the vessel is delivered from the shipyard, or a shorter period if regulations prevent us from operating the vessel for the estimated useful life. FPSO units are depreciated using an estimated useful life of 20 to 25 years commencing the date the unit arrives at the oil field and is in a condition that is ready to operate. Some of our FPSO units have oil field specific equipment which is depreciated over the expected life of the oil field. The estimated useful life of our FPSO units is reassessed subsequent to a major upgrade being completed. FSO units are depreciated over the term of the contract. UMS’ are depreciated over an estimated useful life of 35 years commencing the date the unit arrives at the oil field and is in a condition that is ready to operate. Towage vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. However, the actual life of a vessel may be different than the estimated useful life, with a shorter actual useful life resulting in an increase in the quarterly depreciation and potentially resulting in an impairment loss. The estimated useful life of our vessels takes into account design life, commercial considerations and regulatory restrictions. Our estimates of future cash flows involve assumptions about future charter rates, vessel utilization, operating expenses, dry-docking expenditures, vessel residual values and the remaining estimated life of our vessels. Our estimated charter rates are based on rates under existing vessel contracts and market rates at which we expect we can re-charter our vessels. Our estimates of vessel utilization, including estimated off-hire time and the estimated amount of time our shuttle tankers may spend operating in the spot tanker market when not being used in their capacity as shuttle tankers, are based on historical experience and our projections of the number of future shuttle tanker voyages. Our estimates of operating expenses and dry-docking expenditures are based on historical operating and dry-docking costs and our expectations of future inflation and operating requirements. Vessel residual values are a product of a vessel’s lightweight tonnage and estimated scrap rates. The remaining estimated lives of our vessels used in our estimates of future cash flows are consistent with those used in the calculation of depreciation.

Effective January 1, 2016, we changed the estimated useful lives of the unique shuttle tanker component of our shuttle tankers from 25 to 20 years based on the challenges that we have faced in utilizing this unique equipment during the current adverse market conditions in the energy sector and the other long-term factors associated with the global oil industry. In addition, for eight of our older shuttle tankers, we have changed the estimated useful life of the tanker component of the vessels from 25 to 20 years due to our outlook for the shuttle and conventional tanker market and based on our expected operating plans. Please read Item 18 - Financial Statements: Note 1 - Summary of Significant Accounting Policies.

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

Effect if Actual Results Differ from Assumptions. If we conclude that a vessel or equipment is impaired, we recognize a loss in an amount equal to the excess of the carrying value of the asset over its fair value at the date of impairment. The written-down amount becomes the new lower cost basis and will result in a lower annual depreciation expense than for periods before the vessel impairment.

Dry docking

Description. We dry dock each of our shuttle tankers, conventional oil tankers and towage vessels periodically for inspection, repairs and maintenance and for any modifications to comply with industry certification or governmental requirements. We may dry dock FSO units if we desire to qualify them for shipping classification. We capitalize a substantial portion of the costs we incur during dry docking and amortize those costs on a straight-line basis over the estimated useful life of the dry dock. We immediately expense costs for routine repairs and maintenance performed during dry docking that do not improve or extend the useful lives of the assets.

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

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

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

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

As of December 31, 2016, the shuttle segment and the towage segment had goodwill attributable to them. As of the date of this filing, we do not believe that there is a reasonable possibility that the goodwill attributable to these reporting units might be impaired within the next year. However, certain factors that impact this assessment are inherently difficult to forecast and as such we cannot provide any assurances that an impairment will or will not occur in the future. An assessment for impairment involves a number of assumptions and estimates that are based on factors that are beyond our control. These are discussed in more detail in the section entitled “Forward-Looking Statements.”

Valuation of Derivative Instruments

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

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

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

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

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

Effect if Actual Results Differ from Assumptions. Although we measure the fair value of our derivative instruments utilizing the inputs and assumptions described above, if we were to terminate the agreements at the reporting date, the amount we would pay or receive to terminate the derivative instruments may differ from our estimate of fair value. If the estimated fair value differs from the actual termination amount, an adjustment to the carrying amount of the applicable derivative asset or liability would be recognized in earnings for the current period. Such adjustments could be material. See Item 18 – Financial Statements: Note 12 – Derivative Instruments for the effects on the change in fair value of our derivative instruments on our consolidated statements of income.
Taxes
Description. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.

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

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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, 2016, we had a valuation allowance of $78.4 million (2015 - $86.9 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. Effective February 1, 2017, our general partner has a Secretary but does not have any other officers. Instead, the Partnership and its wholly-owned subsidiary, Teekay Offshore Holdings L.L.C. (or Holdco), have entered into a services agreement with Teekay Offshore Group Ltd. (or the Service Provider), a subsidiary of Holdco.

Employees of certain subsidiaries of Teekay Corporation provide various services to us including in the case of our operating subsidiaries, substantially all of their managerial, operational and administrative services and other technical and advisory services, and in the case of the Partnership, various administrative services. Please see Item 7- Major Unitholders and Related Party Transactions.

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. The various services agreements require the service providers to provide the services diligently and in a commercially reasonable manner.
Directors of Teekay Offshore GP L.L.C.
The following table provides information about the directors of our general partner, Teekay Offshore GP L.L.C., as at the date of this Annual Report. Directors are elected for one-year terms. The business address of each of our directors listed below is c/o 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Ages of the directors and officers are as of December 31, 2016.
 
Name
 
Age
 
Position
C. Sean Day
 
67
 
Chairman (1)(2)
Kenneth Hvid
 
48
 
Director
David L. Lemmon
 
74
 
Director (1) (3)
Carl Mikael L.L. von Mentzer
 
72
 
Director (1) (3)
John J. Peacock
 
73
 
Director (1) (3)
Bill Utt
 
59
 
Director-elect (2)
(1)
Member of Corporate Governance Committee.
(2)
Mr. Sean Day is retiring as Chairman on June 15, 2017. He will remain on the Board of Directors. Mr. William P. Utt will succeed Mr. Day as Chairman of the Board effective June 15, 2017.
(3)
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 director and 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. Effective June 15, 2017, Mr. Day will resign as Chairman of Teekay Offshore and Teekay Corporation, but he intends to continue to serve as a member of each of those boards. He served as Chairman of Teekay GP L.L.C. until 2015 and is currently a board member. He served as Chairman of Teekay Tankers from 2007 until 2013. From 1989 to 1999, Mr. Day was President and Chief Executive Officer of Navios Corporation, a large bulk shipping company based in Stamford, Connecticut. Prior to that, Mr. Day held a number of senior management positions in the shipping and finance industry. He is currently serving as a Director of Kirby Corporation and Chairman of Compass Diversified Holdings. Mr. Day is engaged as a consultant to Kattegat Limited, which owns Resolute Investments Ltd., Teekay Corporation’s largest shareholder, to oversee its investments, including that in the Teekay Corporation group of companies.


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Kenneth Hvid was appointed President and CEO of Teekay Corporation on February 1, 2017, director of Teekay Tankers Ltd. on February 22, 2017 and has served as a director of Teekay Offshore GP L.L.C., the general partner of Teekay Offshore Partners L.P., since 2011. He joined Teekay Corporation in 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 liquified 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 floating storage and offtake business and related offshore activities. Mr. Hvid served as Chief Strategy Officer and Executive Vice President of Teekay Corporation from 2011 to December 2015, as director of Teekay GP L.L.C. from 2011 to June 2015 and as President and CEO of Teekay Offshore Group Ltd., from May 2015 until January 31, 2017. Mr. Hvid has 28 years of global shipping experience, 12 of which were spent with A.P. Moller in Copenhagen, San Francisco and Hong Kong. In 2007, Mr. Hvid joined the board of Gard P.& I. (Bermuda) Ltd.

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

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

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

Bill Utt will be joining the Teekay Offshore GP LLC board as director and Chairman on June 15, 2017. He joined the Teekay Corporation board on December 9, 2015 and will assume the role of Chairman on June 15, 2017. Mr. Utt brings over 31 years of engineering and energy industry experience to our board. From 2006 until his retirement in 2014, he served as Chairman, President and Chief Executive Officer of KBR Inc., a global engineering, construction and services company. From 1995 to 2006, Mr. Utt served as the President and CEO of SUEZ Energy North America and President and CEO of Tractebel’s North American energy businesses. Prior to 1995, he held non-executive senior management positions with CRSS, Inc., which was a developer and operator of independent power and industrial energy facilities prior to its merger with Tractebel in 1995. Mr. Utt also currently serves as Chairman of the board of directors at Cobalt International Energy and is a member of the board of directors for Brand Energy & Infrastructure Services, a Clayton, Dubilier & Rice, LLC portfolio company.

Our Management

Our general partner has a Secretary but does not have any other officers. On February 1, 2017, the Partnership and its wholly-owned subsidiary, Holdco, entered into a service agreement with the Service Provider, a subsidiary of Holdco. The following table presents certain information regarding the senior management team that is principally responsible for our operations and their positions with the Service Provider as at the date of this Annual Report:

Name
 
Age
 
Position
Ingvild Sæther
 
48
 
President and Chief Executive Officer, Teekay Offshore Group Ltd. - effective February 1, 2017
David Wong
 
46
 
Chief Financial Officer, Teekay Offshore Group Ltd. - effective May 2015
Edith Robinson
 
52
 
Secretary, Teekay Offshore GP LLC

Ingvild Sæther was appointed President and CEO of Service Provider effective from February 1, 2017. Ms. Sæther was previously an Executive Committee Member and President of Teekay Offshore Logistics of Service Provider since March 2016. She joined Teekay in 2002 as a result of Teekay’s acquisition of Navion AS from Statoil ASA. Ms. Sæther held various management positions in Teekay’s conventional tanker business until 2007, when she assumed the commercial responsibility for Teekay’s shuttle tanker activities in the North Sea. Effective April 1, 2011, Ms. Sæther assumed the position of President, Teekay Offshore Logistics, responsible for our global shuttle tanker business as well as initiatives in the floating storage and off take business and related offshore activities. Ingvild Sæther has more than 25 years of experience from the shipping and offshore sector, and has been engaged in various boards and associations related to the industry.


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David Wong was appointed Chief Financial Officer of Service Provider in May 2015. He joined Teekay Corporation in 2009 and has served in a number of financial positions including MLP Controller and Vice President, Accounting. Mr. Wong also served from 2011 to 2014 on the board of Vancouver City Savings Credit Union. Prior to joining Teekay, Mr. Wong worked for 13 years at BC Hydro, Canada’s third largest electric utility, in various financial positions including Chief Accounting Officer and CFO and VP Finance of Powerex Corp., the energy trading and marketing subsidiary of BC Hydro. Mr. Wong is a Canadian Chartered Professional Accountant.
Edith Robinson was appointed as the Secretary of Teekay Offshore GP LLC, the general partner of Teekay Offshore Partners L.P., in September 2014 and also currently serves as an Associate General Counsel for Teekay Corporation. Ms. Robinson joined Teekay Corporation in 2014. She was appointed Secretary of Service Provider in May of 2015. Prior to joining Teekay Corporation, Ms. Robinson served as the General Counsel for a utility group in Bermuda. She has over twenty years of legal experience and is qualified to practice law in Bermuda, Ontario Canada, and England. Ms. Robinson has an MBA from Cornell University in addition to her legal qualifications.
B.
Compensation
Executive Compensation
During 2016, Peter Evensen, the then Chief Executive Officer and Chief Financial Officer of our general partner, was an employee of a subsidiary of Teekay Corporation. His compensation (other than any awards under the long-term incentive plan described below) was set by the Teekay Corporation subsidiary, and we reimburse the Teekay Corporation subsidiary for the time he spent on our partnership matters. Peter Evensen retired as an executive officer of our general partner effective January 31, 2017. Our general partner did not appoint any executive officers to replace Mr. Evensen. Instead, the Partnership entered into a service agreement pursuant to which the Service Provider (an indirect subsidiary of the Partnership) provides the Partnership and Holdco with the services of its CEO, Ingvild Saether and its CFO, David Wong.

During 2016, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the officers of the general partner incurred on our behalf excluding any long-term incentive plan awards issued directly by the Partnership as described below, was $3.8 million, which includes a one-time compensation cost associated with the retirement of the former Chief Executive Officer and Chief Financial Officer of our general partner. The amounts were paid primarily in U.S. Dollars or in Canadian Dollars, but are reported here in U.S. Dollars using an average exchange rate of 1.32 Canadian Dollars for each U.S. Dollar for 2016. Teekay Corporation’s annual bonus plan, in which each of the Officers participates, considers both company performance and team performance.
Compensation of Directors
Employees of a subsidiary of 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 2016, each non-employee director, other than the Chair, received a director fee of $50,000 for the year and an award of common units with an aggregate maximum value of approximately $70,000 for the year. The Chair received a director fee of $50,000 and an additional annual fee of $37,500 for the year and an award of common units with a value of approximately $87,500 for the year. In addition, members of the audit, conflicts and corporate governance committees each received an additional committee fee of $5,000 for the year, and the chairs of each committee received an additional fee of $12,000 for the year for serving in that role. In addition, each director was reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

During 2016, the four non-employee directors received, in the aggregate, $308,500 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. For the year ended December 31, 2016, an aggregate of 76,084 common units, with a grant date fair value of $0.3 million, based on our closing unit price on the grant date, were granted and issued to the non-employee directors of the general partner as part of their annual compensation for 2016.
2006 Long-Term Incentive Plan
Our general partner adopted the Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan for employees and directors of and consultants to our general partner and employees and directors of and consultants to its affiliates, who perform services for us. The plan provides for the award of restricted units, phantom units, unit options, unit appreciation rights and other unit or cash-based awards. In March 2016, our general partner awarded 601,368 restricted units to certain employees of its affiliates who provide services to our business with a grant date fair value of $2.4 million, based on our closing unit price on the grant date. Each restricted unit is equal in value to one unit of our common units plus reinvested distributions from the grant date to the vesting date. The restricted units vest evenly over a three year period from the grant date. Any portion of a restricted unit award that is not vested on the date of a recipient’s termination of service is cancelled, unless their termination arises as a result of the recipient’s retirement and in this case the restricted unit award will continue to vest in accordance with the vesting schedule. Upon vesting, the value of the restricted units is paid to each grantee in the form of common units or cash.
C.
Board Practices
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.


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As at December 31, 2016, our general partner’s Board of Directors (or the Board) consisted of six members. It currently consists of five directors, but William Utt will be joining the Teekay Offshore GP LLC board as director and Chairman on June 15, 2017, bringing the total number of directors back up to six. 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. The committee charters for the Audit Committee, the Conflicts Committee and the Corporate Governance Committee are available under “Investors – Teekay Offshore Partners L.P. - Governance” from the home page of our web site at www.teekay.com. During 2016, the Board held five meetings. Each director attended all Board meetings. The members of the Audit Committee, the Conflicts Committee and the Corporate Governance Committee attended all meetings.

Audit Committee. The Audit Committee of our general partner is composed of three or more directors, each of whom must meet the independence standards of the NYSE, the SEC and any other applicable laws and regulations governing independence from time to time. This committee is currently comprised of directors John J. Peacock (Chair), David L. Lemmon and Carl Mikael L.L. von Mentzer. All members of the committee are financially literate and the Board has determined that Mr. Peacock qualifies as an audit committee financial expert.

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

•
the integrity of our financial statements;
•
our compliance with legal and regulatory requirements;
•
the qualifications and independence of our independent auditor; and
•
the performance of our internal audit function and our independent auditor.

Conflicts Committee. The Conflicts Committee of our general partner is composed of the same directors constituting the Audit Committee, being David L. Lemmon (Chair), John J. Peacock, and Carl Mikael L.L. von Mentzer. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the heightened NYSE and SEC director independence standards applicable to audit committee membership and certain other requirements.

The Conflicts Committee:

•
reviews specific matters that the Board believes may involve conflicts of interest; and
•
determines if the resolution of the conflict of interest is fair and reasonable to us.

Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unit holders. The Board is not obligated to seek approval of the Conflicts Committee on any matter, and may determine the resolution of any conflict of interest itself.

Corporate Governance Committee. The Corporate Governance Committee of our general partner is composed of at least two directors. This committee is currently comprised of directors Carl Mikael L.L. von Mentzer (Chair), David L. Lemmon, John J. Peacock, and C. Sean Day.

The Corporate Governance Committee:

•
oversees the operation and effectiveness of the Board and its corporate governance;
•
develops, updates and recommends to the Board corporate governance principles and policies applicable to us and our general partner and monitors compliance with these principles and policies; and
•
oversees director compensation and the long-term incentive plan described above.
D.
Employees
Crewing and Staff
As of December 31, 2016, 1,328 seagoing staff served on our vessels, compared to approximately 1,400 seagoing staff as of December 31, 2015 and approximately 1,600 seagoing staff as of December 31, 2014. Certain subsidiaries of Teekay Corporation employ the crew, who serve on the vessels pursuant to agreements with the subsidiaries. As of December 31, 2016, approximately 156 staff served on shore in technical, commercial and administrative roles in Norway, Brazil and Singapore, compared to approximately 166 staff in Norway, Brazil and Singapore as of December 31, 2015 and approximately 149 staff in Norway, Brazil and Singapore as of December 31, 2014. Teekay Corporation subsidiaries also provide on-shore advisory, operational and administrative support to our operating subsidiaries pursuant to service agreements. Please see Item 7 – Major Unitholders and Related Party transactions – Certain Relationships and Related Party Transactions.


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

Teekay Corporation has entered into a Collective Bargaining Agreement with the Philippine Seafarers’ Union, an affiliate of the International Transport Workers’ Federation (or ITF), and a Special Agreement with ITF London, which covers substantially all of the officers and seamen that operate our Bahamian-flagged vessels. Substantially all officers and seamen for the Norway-flagged vessels are covered by a collective bargaining agreement with Norwegian unions (Norwegian Maritime Officers’ Association, Norwegian Union of Marine Engineers and the Norwegian Seafarers’ Union). Teekay Corporation has entered into a Collective Bargaining Agreement with Sindicato dos Trabalhadores Offshore do Brasil (or SINDITOB), which covers substantially all Brazilian resident offshore employees on board our FPSO units Rio das Ostras and Piranema Spirit. Teekay Corporation has entered into a Collective Bargaining Agreement with Norwegian offshore unions (SAFE, Industry Energi and DSO), through our membership in Norwegian Shipowners Association (or NSA). The agreement covers substantially all of the offshore employees on board our FPSOs on the Norwegian Continental Shelf. Teekay Corporation has entered into a Collective Bargaining Agreement with the Fish, Food and Allied Workers Union of Newfoundland and Labrador in Canada. The agreement covers substantially all of the offshore employees on board our shuttle tankers operating in the East Coast of Canada. We believe Teekay Corporation’s relationships with these local labor unions are good.

Our commitment to training is fundamental to the development of the highest caliber of seafarers for marine operations. Teekay Corporation’s cadet training approach is designed to balance academic learning with hands-on training at sea. Teekay Corporation has relationships with training institutions in Canada, Croatia, India, Norway, Philippines, Turkey and the United Kingdom. After receiving formal instruction at one of these institutions, cadet training continues on board vessels. Teekay Corporation also has a career development plan that was devised to ensure a continuous flow of qualified officers who are trained on its vessels and familiarized with its operational standards, systems and policies. We believe that high-quality crewing and training policies will play an increasingly important role in distinguishing larger independent shipping companies that have in-house or affiliate capabilities from smaller companies that must rely on outside ship managers and crewing agents on the basis of customer service and safety.
E.
Unit Ownership
The following table sets forth certain information regarding beneficial ownership, as of December 31, 2016, of our units by all the Partnership's current 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, 2017 (60 days after December 31, 2016) 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)
 
368,670

 
0.25
%
(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 Kenneth Hvid. Kenneth Hvid is President and Chief Executive Officer of Teekay Corporation and is a Director of Teekay Offshore GP L.L.C. Please read Item 7: Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for more detail.
(2)
Each director, executive officer and key employee beneficially owns less than 1% of the outstanding units.
(3)
Excludes the 2% general partner interest held by our general partner, a wholly owned subsidiary of Teekay Corporation.
Item 7.
Major Unitholders and Related Party Transactions
A.
Major Unitholders
The following table sets forth the beneficial ownership, as of December 31, 2016, of our units by each person we know to beneficially own more than 5% of the outstanding common units. The number of common units beneficially owned by each person is determined under SEC rules and the information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules a person beneficially owns any 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 March 1, 2017 (60 days after December 31, 2016) 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)
 
40,589,218
 
27.5%
Advisory Research Inc. (2)
 
18,539,198
 
12.6%
MTP Energy Fund Ltd. (3)
 
16,613,106
 
12.6%
FMR LLC (4)
 
13,278,697
 
9.0%

81


____________________________
(1)
Excludes the 2% general partner interest held by our general partner, a wholly owned subsidiary of Teekay Corporation.
(2)
Includes sole voting power of Advisory Research Inc. as to 18,511,813 units and sole dispositive power of Advisory Research as to 18,539,198 units, and shared voting power and shared dispositive power by Piper Jaffray Companies with respect to such same units. This information is based on the Schedule 13G filed by this group with the SEC on February 13, 2017.
(3)
Includes shared voting power and shared dispositive power of MTP Energy Management LLC, Magnetar Financial LLC, Magnetar Capital Partners LP, Supernova Management LLC and Alec N. Litowitz as to 16,613,106 units. This includes 633,498 units held for account of MTP EOF II IP LLC, 518,654 units held for the account of MTP Energy Opportunities Fund LLC, 3,812,098 units held for the account of MTP Energy Opportunities Fund II LLC and 11,648,856 units held for the accounts of MTP Energy Fund. This information is based on the Schedule 13G filed by this group with the SEC on February 14, 2017.
(4)
Includes sole dispositive power of FMR LLC as to 13,278,697 units. This information is based on the Schedule 13G filed by this entity with the SEC on February 14, 2017.

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
(a)
C. Sean Day is the Chairman of our general partner, Teekay Offshore GP L.L.C. He also is the Chairman of Teekay Corporation, and board member of Teekay GP L.L.C., the general partner of Teekay LNG. Mr. Day will be succeeded by Mr. William Utt mid-June 2017, who will take over the role of Chairman for both Teekay Offshore GP L.L.C. and Teekay Corporation. Mr. Day will remain as a board member for both entities.
Peter Evensen was the President and Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and Chief Financial Officer of Teekay Offshore GP L.L.C. and Teekay GP L.L.C., and a Director of Teekay Corporation, Teekay GP L.L.C., Teekay Offshore GP L.L.C. and Teekay Tankers Ltd. through January 31, 2017.

Because Mr. Evensen was an employee of a subsidiary of Teekay Corporation, his compensation (other than any awards under the long-term incentive plan) was 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 on our partnership matters.

Kenneth Hvid is a Director of Teekay Offshore GP L.L.C. Mr. Hvid was also Executive Vice President and Chief Strategy Officer of Teekay Corporation until December 2015. He was appointed President and Chief Executive Officer of Teekay Corporation effective on February 1, 2017.

On February 1, 2017, the Partnership and its wholly-owned subsidiary, Holdco, entered into a service agreement with the Service Provider, a management services company that is a subsidiary of Holdco. The Service Provider provides services using persons employed by various subsidiaries of Teekay Corporation, including the services of Ingvild Sæther, the President and CEO of Service Provider, and David Wong, the CFO of Service Provider. In addition, we have entered into various service agreements with certain direct and indirect subsidiaries of Teekay Corporation pursuant to which those subsidiaries provide to us various services including, in the case of 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, and in the case of Teekay Offshore Partners LP, various administrative services. Because Ms. Sæther and Mr. Wong and the other persons providing services to the Partnership and its subsidiaries are employees of various subsidiaries of Teekay Corporation, their compensation (other than any awards under the long-term incentive plan) is set and paid by the Teekay Corporation subsidiary that employs them. Pursuant to our agreements with Teekay Corporation and its subsidiaries, we have agreed to reimburse Teekay Corporation for time spent by such persons on providing services to the Partnership and our subsidiaries.

(b)
We have entered into an amended and restated omnibus agreement with our general partner, Teekay Corporation, Teekay LNG and related parties. The following discussion describes certain provisions of the omnibus agreement.
Noncompetition. Under the omnibus agreement, Teekay Corporation and Teekay LNG have agreed, and have caused their controlled affiliates (other than us) to agree, not to own, operate or charter certain “Offshore Vessels”. This restriction does not prevent Teekay Corporation, Teekay LNG or any of their other controlled affiliates from, among other things:

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

82


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

In addition, under the omnibus agreement we have agreed not to own, operate or charter crude oil tankers or liquefied natural gas (or LNG) carriers. This restriction does not apply to any of the Aframax tankers in our current fleet, and the ownership, operation or chartering of any oil tankers that replace any of those oil tankers in connection with certain events. In addition, the restriction does not prevent us from, among other things:

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

Rights of First Offer on Conventional Tankers, LNG Carriers and Offshore Vessels. Under the omnibus agreement, we have granted to Teekay Corporation and Teekay LNG a 30-day right of first offer on certain (a) sales, transfers or other dispositions of any Aframax tankers, in the case of Teekay Corporation, or certain LNG carriers in the case of Teekay LNG, or (b) re-charterings of any Aframax tankers or LNG carriers pursuant to a time charter or contract of affreightment with a term of at least three years if the existing charter expires or is terminated early. Likewise, each of Teekay Corporation and Teekay LNG has granted a similar right of first offer to us for any Offshore Vessels it might own that, at the time of the proposed offer, is subject to a time charter or contract of affreightment with a remaining term, excluding extension options, of at least three years. These rights of first offer do not apply to certain transactions.

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

Please read Item 18. – Financial Statements: Note 11 – Related Party Transactions for a description of our various related-party transactions.
Item 8.
Financial Information
Consolidated Financial Statements and Other Financial Information
Consolidated Financial Statements and Notes
Please see Item 18 below for additional information required to be disclosed under this Item.
Legal Proceedings
Occasionally we have been, and expect to continue to be, subject to legal proceedings and claims in the ordinary course of our business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources.

Please read Item 18. – Financial Statements: Note 14 – Commitments and Contingencies for a description of the claims made against us.
Cash Distribution Policy
Rationale for Our Cash Distribution Policy

83


Our general cash distribution policy reflects a basic judgment that our common unitholders are better served by our distributing our available cash (as defined in our partnership agreement and after deducting expenses, including estimated maintenance capital expenditures and reserves) rather than our retaining it. However, in December 2015, commencing with our distribution on common units relating to the fourth quarter of 2015, we reduced the amount of our quarterly cash distributions per common unit. Global crude oil prices have significantly declined since mid-2014. This decline, combined with other factors beyond our control, has adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, the board of directors of our general partner believes it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, we reduced our quarterly distributions on our common units. This reduction in the amount of common unit distributions to establish cash reserves for these purposes is consistent with our cash distribution policy, and the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance capital expenditures and reserves, including reserves for future capital expenditures and for anticipated future credit needs).
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

•
Our unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to our general partner’s broad discretion to establish reserves and other limitations.
•
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended with the approval of a majority of the outstanding common units.
•
Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by the board of directors of our general partner, taking into consideration the terms of our partnership agreement.
•
Under Section 51 of the Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders to the extent that at the time of the distribution, after giving effect to the distribution, all of our liabilities, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specified property of ours, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of that property exceeds that liability.
•
We may lack sufficient cash to pay distributions to our unitholders due to decreases in net revenues or increases in operating expenses, principal and interest payments on outstanding debt, tax expenses, working capital requirements, maintenance capital expenditures or anticipated cash needs.
•
Our distribution policy may be affected by restrictions on distributions under our credit facility agreements, which contain material financial tests and covenants that must be satisfied. Should we be unable to satisfy these restrictions included in the credit agreements or if we are otherwise in default under the credit agreements, we would be prohibited from making cash distributions, which would materially hinder our ability to make cash distributions to unitholders, notwithstanding our stated cash distribution policy.
•
If we make distributions out of capital surplus, as opposed to operating surplus (as such terms are defined in our partnership agreement), those distributions will constitute a return of capital and will result in a reduction in the minimum quarterly distribution and the target distribution levels under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from our operating surplus (as defined in our partnership agreement) after the minimum quarterly distribution to our common unitholders and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. Except for transfers of incentive distribution rights to an affiliate or another entity as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to such entity, the approval of a majority of our common units (excluding common units held by our general partner and its affiliates), voting separately as a class, generally is required for a transfer of the incentive distributions rights to a third party prior to December 31, 2016. After December 31, 2016, our general partner may transfer any or all of its incentive distribution rights without the approval of the common unitholders.

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the common unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the common unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the common unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests shown for our general partner include its 2.0% general partner interest and assumes the

84


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
%
 
2
%
First Target Distribution
 
Up to $0.4025
 
98
%
 
2
%
Second Target Distribution
 
Above $0.4025 up to $0.4375
 
85
%
 
15
%
Third Target Distribution
 
Above $0.4375 up to $0.525
 
75
%
 
25
%
Thereafter
 
Above $0.525
 
50
%
 
50
%

During 2016, and the fourth quarter of 2015, cash distributions were below $0.35 per common unit. Consequently, the increasing percentages were not used to calculate the general partner’s interest in net income for the purposes of the net income per common unit calculation for these periods.

Cash distributions exceeded $0.4025 per common unit for the first three quarters of 2015 and for 2014 and therefore, increasing percentages were used to calculate the general partner’s interest in net income for the purposes of the net income per common unit calculation for these periods.


Significant Changes

Not applicable.
Item 9.
The Offer and Listing
Our common units are traded on the NYSE under the symbol “TOO”. The following table sets forth the high and low sales prices for our common units on the NYSE for each of the periods indicated:

Year Ended
 
Dec. 31,
2016
 
Dec. 31,
2015
 
Dec. 31,
2014
 
Dec. 31,
2013
 
Dec. 31,
2012
 
 
 
 
 
 
 
 
High
 
$
7.25

 
$
26.73

 
$
37.46

 
$
36.09

 
$
30.14

 
 
 
 
 
 
 
 
Low
 
$
2.30

 
$
3.68

 
$
20.61

 
$
26.17

 
$
24.55

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarter Ended
 
Mar. 31,
2017
 
Dec. 31,
2016
 
Sep. 30,
2016
 
Jun. 30,
2016
 
Mar. 31,
2016
 
Dec. 31,
2015
 
Sep. 30,
2015
 
Jun. 30,
2015
 
Mar. 31,
2015
High
 
$
6.30

 
$
6.69

 
$
6.69

 
$
7.25

 
$
6.68

 
$
17.3

 
$
20.38

 
$
24.72

 
$
26.73

Low
 
$
4.70

 
$
4.74

 
$
4.95

 
$
4.06

 
$
2.30

 
$
3.68

 
$
13.74

 
$
19.21

 
$
18.91

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Month Ended
 
Mar. 31,
2017
 
Feb. 28,
2017
 
Jan. 31,
2017
 
Dec. 31,
2016
 
Nov. 30,
2016
 
Oct. 31,
2016
 
Sep. 30,
2016
 
 
 
 
High
 
$
5.39

 
$
6.16

 
$
6.30

 
$
5.64

 
$
6.12

 
$
6.69

 
$
6.69

 
 
 
 
Low
 
$
4.70

 
$
4.91

 
$
5.14

 
$
4.74

 
$
4.97

 
$
5.91

 
$
5.05

 
 
 
 

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


85


Year Ended
 
Dec. 31,
2016
 
Dec. 31,
2015
 
Dec. 31,
2014
 
Dec. 31,
2013(1)
 
 
 
 
 
 
 
 
 
 
High
 
$
21.48

 
$
24.00

 
$
26.83

 
$
26.46

 
 
 
 
 
 
 
 
 
 
Low
 
$
8.02

 
$
11.70

 
$
21.85

 
$
24.01

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarter Ended
 
Mar. 31,
2017
 
Dec. 31,
2016
 
Sep. 30,
2016
 
Jun. 30,
2016
 
Mar. 31,
2016
 
Dec. 31,
2015
 
Sep. 30,
2015
 
Jun. 30,
2015
 
Mar. 31,
2015
High
 
$
21.94

 
$
21.43

 
$
21.48

 
$
20.70

 
$
16.84

 
$
20.15

 
$
21.44

 
$
23.41

 
$
24.00

Low
 
$
18.52

 
$
17.00

 
$
19.36

 
$
14.88

 
$
8.02

 
$
11.70

 
$
15.68

 
$
20.12

 
$
22.07

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Month Ended
 
Mar. 31,
2017
 
Feb. 28,
2017
 
Jan. 31,
2017
 
Dec. 31,
2016
 
Nov. 30,
2016
 
Oct. 31,
2016
 
Sep. 30,
2016
 
 
 
 
High
 
$
20.64

 
$
21.20

 
$
21.94

 
$
20.29

 
$
21.25

 
$
21.43

 
$
21.48

 
 
 
 
Low
 
$
18.75

 
$
20.00

 
$
18.52

 
$
18.25

 
$
17.00

 
$
19.55

 
$
19.36

 
 
 
 

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

Our Series B Preferred Units are traded on the NYSE under the symbol “TOO-PB”. The following table sets forth the high and low sales prices for our Series B Preferred Units on the NYSE for each of the periods indicated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended
 
Dec. 31,
2016
 
Dec. 31,
2015(1)
 
 
 
 
 
 
 
 
 
 
 
 
High
 
$
23.09

 
$
25.05

 
 
 
 
 
 
 
 
 
 
 
 
Low
 
$
9.08

 
$
12.31

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarter Ended
 
Mar. 31,
2017
 
Dec. 31,
2016
 
Sep. 30,
2016
 
Jun. 30,
2016
 
Mar. 31,
2016
 
Dec. 31,
2015
 
Sep. 30,
2015
 
Jun. 30,
2015(2)
High
 
$
23.20

 
$
22.74

 
$
23.09

 
$
22.24

 
$
18.20

 
$
21.83

 
$
24.32

 
$
25.05

Low
 
$
20.05

 
$
18.97

 
$
20.75

 
$
16.12

 
$
9.08

 
$
12.31

 
$
17.02

 
$
22.82

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Month Ended
 
Mar. 31,
2017
 
Feb. 28,
2017
 
Jan. 31,
2017
 
Dec. 31,
2016
 
Nov. 30,
2016
 
Oct. 31,
2016
 
Sep. 30,
2016
 
 
High
 
$
22.59

 
$
23.20

 
$
23.01

 
$
21.18

 
$
22.44

 
$
22.74

 
$
22.83

 
 
Low
 
$
21.51

 
$
21.87

 
$
20.05

 
$
19.53

 
$
18.97

 
$
20.86

 
$
21.36

 
 
(1)
Period from April 14, 2015 through December 31, 2015.
(2)
Period from April 14, 2015 through June 30, 2015.

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

Year Ended
 
Dec. 31,
2016
 
Dec. 31,
2015
 
Dec. 31,
2014(1)
 
 
 
 
 
 
 
 
 
 
 
 
High
 
$
92.10

 
$
94.50

 
$
103.47

 
 
 
 
 
 
 
 
 
 
 
 
Low
 
$
39.60

 
$
50.50

 
$
88.75

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarter Ended
 
Mar. 31,
2017
 
Dec. 31,
2016
 
Sep. 30,
2016
 
Jun. 30,
2016
 
Mar. 31,
2016
 
Dec. 31,
2015
 
Sep. 30,
2015
 
Jun. 30,
2015
 
Mar. 31,
2015
High
 
$
96.10

 
$
92.10

 
$
87.11

 
$
85.87

 
$
69.85

 
$
87.14

 
$
93.00

 
$
93.99

 
$
94.50

Low
 
$
83.25

 
$
79.75

 
$
79.25

 
$
62.50

 
$
39.60

 
$
50.50

 
$
68.90

 
$
86.50

 
$
87.20

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Month Ended
 
Mar. 31,
2017
 
Feb. 28,
2017
 
Jan. 31,
2017
 
Dec. 31,
2016
 
Nov. 30,
2016
 
Oct. 31,
2016
 
Sep. 30,
2016
 
 
 
 
High
 
$
94.11

 
$
95.23

 
$
96.10

 
$
92.10

 
$
87.29

 
$
88.90

 
$
87.11

 
 
 
 
Low
 
$
83.25

 
$
88.91

 
$
83.43

 
$
81.50

 
$
79.75

 
$
80.00

 
$
79.83

 
 
 
 


86


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

Item 10.
Additional Information
Memorandum and Articles of Association
The information required to be disclosed under Item 10B is incorporated by reference to Amendment No.5 to our Registration Statement on Form 8-A/A filed with the SEC on July 29,2016.
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:

a)
Amended and Restated Omnibus Agreement, dated December 19, 2006, among us, our general partner, Teekay Corporation, Teekay LNG and related parties. Please read Item 7 – Major Unitholders and Related Party Transactions – Certain Relationships and Related Party Transactions for a summary of certain contract terms.
b)
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 administrative services to the Partnership and administrative, advisory, technical, strategic consulting services, business development and ship management services to operating subsidiaries 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.
c)
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.
d)
Agreement, dated July 31, 2015, for a U.S. $803,711,787 term loan due 2027, among OOGTK Libra GmbH & Co KG, ABN AMRO Bank N.V. and various other banks.
Exchange Controls and Other Limitations Affecting Unitholders
We are not aware of any governmental laws, decrees or regulations, including foreign exchange controls, in the Republic of The Marshall Islands that restrict the export or import of capital, or that affect the remittance of dividends, interest or other payments to holders of our securities that are non-resident and not citizens.

We are not aware of any limitations on the right of non-resident or foreign owners to hold or vote our securities imposed by the laws of the Republic of The Marshall Islands or our partnership agreement.
Material U.S. Federal Income Tax Considerations
The following is a discussion of certain material U.S. federal income tax considerations that may be relevant to unitholders. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (or the Code), legislative history, applicable U.S. Treasury Regulations (or Treasury Regulations), judicial authority and administrative interpretations, all as in effect on the date of this Annual Report, and which are subject to change, possibly with retroactive effect, or are subject to different interpretations. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Teekay Offshore Partners L.P.

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

•
dealers in securities or currencies,
•
traders in securities that have elected the mark-to-market method of accounting for their securities,
•
persons whose functional currency is not the U.S. dollar,
•
persons holding our units as part of a hedge, straddle, conversion or other “synthetic security” or integrated transaction,
•
certain U.S. expatriates,
•
financial institutions,
•
insurance companies,
•
persons subject to the alternative minimum tax,
•
persons that actually or under applicable constructive ownership rules own 10% or more of our units; and

87


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

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

This discussion does not address any U.S. estate tax considerations or tax considerations arising under the laws of any state, local or non-U.S. jurisdiction. Each unitholder is urged to consult its tax advisor regarding the U.S. federal, state, local, non-U.S. and other tax consequences of the ownership or disposition of our units.
United States Federal Income Taxation of U.S. Holders
As used herein, the term U.S. Holder means a beneficial owner of our units that is for U.S. federal income tax purposes: (i) a U.S. citizen or U.S. resident alien (or a U.S. Individual Holder), (ii) a corporation or other entity taxable as a corporation, that was created or organized under the laws of the United States, any state thereof or the District of Columbia, (iii) an estate whose income is subject to U.S. federal income taxation regardless of its source, or (iv) a trust that either is subject to the supervision of a court within the United States and has one or more U.S. persons with authority to control all of its substantial decisions or has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.
Distributions
We have elected to be taxed as a corporation for U.S. federal income tax purposes. Subject to the discussion of passive foreign investment companies (or PFICs) below, any distributions made by us to a U.S. Holder generally will constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current and accumulated earnings and profits allocated to the U.S. Holder’s units, as determined under U.S. federal income tax principles. Distributions in excess of our current and accumulated earnings and profits allocated to the U.S. Holder’s units will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in our units and thereafter as capital gain, which will be either long term or short term capital gain depending upon whether the U.S. Holder has held the units for more than one year. U.S. Holders that are corporations for U.S. federal income tax purposes generally will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. For purposes of computing allowable foreign tax credits for U.S. federal income tax purposes, dividends received with respect to our units will be treated as foreign source income and generally will be treated as “passive category income”.

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

Special rules may apply to any “extraordinary dividend” paid by us. Generally, an extraordinary dividend is a dividend with respect to a share of stock if the amount of the dividend is equal to or in excess of 10% of a common stockholder’s, or 5% of a preferred stockholder’s adjusted tax basis (or fair market value in certain circumstances) in such stock. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a stockholder’s adjusted tax basis (or fair market value in certain circumstances). If we pay an “extraordinary dividend” on our units that is treated as “qualified dividend income,” then any loss recognized by a Non-Corporate U.S. Holder from the sale or exchange of such units will be treated as long-term capital loss to the extent of the amount of such dividend.

Certain Non-Corporate U.S. Holders currently are subject to a 3.8% tax on certain investment income, including dividends. Non-Corporate U.S. Holders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our units.
Sale, Exchange or Other Disposition of Units
Subject to the discussion of PFICs below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of our units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s tax basis in such units. Subject to the discussion of extraordinary dividends above, such gain or loss generally will be treated as (a) long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition, or short-term capital gain or loss otherwise and (b) U.S.-source gain or loss, as applicable, for foreign tax credit purposes. Non-Corporate U.S. Holders may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.

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

88


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

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

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

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder generally would be subject to different taxation rules depending on whether the U.S. Holder makes a timely and effective election to treat us as a “Qualified Electing Fund” (a QEF election). As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our units, as discussed below.

Taxation of U.S. Holders Making a Timely QEF Election. A U.S. Holder who makes a timely QEF election (an Electing Holder), must report the Electing Holder’s pro rata share of our ordinary earnings and net capital gain, if any, for each taxable year for which we are a PFIC that ends with or within the Electing Holder’s taxable year, regardless of whether or not the Electing Holder received distributions from us in that year. Such income inclusions would not be eligible for the preferential tax rates applicable to qualified dividend income. The Electing Holder’s adjusted tax basis in our units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in our units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with the U.S. Holder’s timely filed U.S. federal income tax return (including extensions).

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

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

Taxation of U.S. Holders Making a “Mark-to-Market” Election. If we were to be treated as a PFIC for any taxable year and, as we anticipate, our units were treated as “marketable stock,” then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made for the first year a U.S. Holder holds or is deemed to hold our units and for which we are a PFIC, the U.S. Holder generally would include as ordinary income in each taxable year that we are a PFIC the excess, if any, of the fair market value of the U.S. Holder’s units at the end of the taxable year over the U.S. Holder’s adjusted tax basis in the units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the units over the fair market value thereof at the end of the taxable year that we are a PFIC, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder’s tax basis in our units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our units in taxable years that we are a PFIC would

89


be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the units in taxable years that we are a PFIC would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were also determined to be PFICs.

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

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election. If we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year (a Non-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (i) any excess distribution (i.e., the portion of any distribution received by the Non-Electing Holder on our units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years or, if shorter, the Non-Electing Holder’s holding period for our units), and (ii) any gain realized on the sale, exchange or other disposition of our units. Under these special rules:

•
the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for our units;
•
the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income in the current taxable year;
•
the amount allocated to each of the other taxable years would be subject to U.S. federal income tax at the highest rate of tax in effect for the applicable class of taxpayer for that year; and
•
an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

Additionally, for each year during which a U.S. Holder owns units, we are a PFIC, and the total value of all PFIC units that such U.S. Holder directly or indirectly exceeds certain thresholds, such U.S. Holder will be required to file IRS Form 8621 with its annual U.S. federal income tax return to report its ownership of our units. In addition, if a Non-Electing Holder who is an individual dies while owning our units, such Non-Electing Holder’s successor generally would not receive a step-up in tax basis with respect to such units.
U.S. Holders are urged to consult their tax advisors regarding the PFIC rules, including the PFIC annual reporting requirements as well as the applicability, availability and advisability of, and procedure for, making QEF, Mark-to-Market and other available elections with respect to us, and the U.S. federal income tax consequences of making such elections.
U.S. Return Disclosure Requirements for U.S. Individual Holders
U.S. Individual Holders who hold certain specified foreign financial assets, including stock in a foreign corporation that is not held in an account maintained by a financial institution, with an aggregate value in excess of $50,000, on the last day of a taxable year, or $75,000 at any time during that taxable year, may be required to report such assets on IRS Form 8938 with their U.S. federal income tax return for that taxable year. This reporting requirement does not apply to U.S. Individual Holders who report their ownership of our units under the PFIC annual reporting rules described above. Penalties apply for failure to properly complete and file Form 8938. U.S. Individual Holders are encouraged to consult with their tax advisors regarding the possible application of this disclosure requirement.
United States Federal Income Taxation of Non-U.S. Holders
A beneficial owner of our units (other than a partnership, including any entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is a Non-U.S. Holder.
Distributions
In general, a non-U.S. Holder will not be subject to U.S. federal income tax on distributions received from us with respect to our units unless the distributions are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment that the Non-U.S. Holder maintains in the United States). If a Non-U.S. Holder is engaged in a U.S. trade or business and the distributions are deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on those distributions in the same manner as if it were a U.S. Holder.
Sale, Exchange or Other Disposition of Units
In general, a non-U.S. Holder is not subject to U.S. federal income tax on any gain resulting from the disposition of our units unless (a) such gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment that the Non-U.S. Holder maintains in the United States) or (b) the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year in which such disposition occurs and

90


meets certain other requirements. If a Non-U.S. Holder is engaged in a U.S. trade or business and the disposition of our units is deemed to be effectively connected to that trade or business, the Non-U.S. Holder generally will be subject to U.S. federal income tax on the resulting gain in the same manner as if it were a U.S. Holder.
Information Reporting and Backup Withholding
In general, payments of distributions with respect to, or the proceeds of a disposition of our units to a Non-Corporate U.S. Holder will be subject to information reporting requirements. These payments to a Non-Corporate U.S. Holder also may be subject to backup withholding if the Non-Corporate U.S. Holder:

•
fails to timely provide an accurate taxpayer identification number;
•
is notified by the IRS that it has failed to report all interest or distributions required to be shown on its U.S. federal income tax returns; or
•
in certain circumstances, fails to comply with applicable certification requirements.

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

Backup withholding is not an additional tax. Rather, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by accurately completing and timely filing a U.S. federal income tax return with the IRS.
Non-United States Tax Consequences
Marshall Islands Tax Consequences. Because we and our subsidiaries do not, and we do not expect that we and our subsidiaries will, conduct business or operations in the Republic of The Marshall Islands, and because all documentation related to our initial public offering and follow-on offerings was executed outside of the Republic of The Marshall Islands, under current Marshall Islands law, no taxes or withholdings will be imposed by the Republic of the Marshall Islands on distributions, including upon a return of capital, made to unitholders, so long as such persons are not citizens of and do not reside in, maintain offices in, nor engage in business or transactions in the Republic of The Marshall Islands. Furthermore, no stamp, capital gains or other taxes will be imposed by the Republic of The Marshall Islands on the purchase, ownership or disposition by such persons of our common units.

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

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

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

We believe that the activities and affairs of Teekay Offshore Partners L.P. are conducted in such a manner that Teekay Offshore Partners L.P. is not carrying on business in Canada and that U.S. Resident Holders should not be considered to be carrying on business in Canada for purposes of the Canada Tax Act or the Canada-U.S. Treaty solely by reason of the acquisition, holding, disposition or redemption of our units. We intend that this is and continues to be the case, notwithstanding that Teekay Shipping Limited (a subsidiary of Teekay Corporation that is a non-resident of Canada) and Service Provider (an indirect subsidiary of Teekay Offshore Partners L.P. that is a non-resident of Canada) provide certain services to Teekay Offshore Partners L.P. and obtain some or all such services under subcontracts with Canadian service providers. If the arrangements we have entered into result in Teekay Offshore Partners L.P. 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 Teekay Offshore Partners L.P. 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.


91


Although we do not intend to do so, there can be no assurance that the manner in which we carry on our activities will not change from time to time as circumstances dictate or warrant in a manner that may cause U.S. Resident Holders to be carrying on business in Canada for purposes of the Canada Tax Act. Further, the relevant Canadian federal income tax law may change by legislation or judicial interpretation and the Canadian taxing authorities may take a different view than we have of the current law.
Documents on Display
Documents concerning us that are referred to herein may be inspected at our principal executive offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Those documents electronically filed via the SEC’s Electronic Data Gathering, Analysis, and Retrieval (or EDGAR) system may also be obtained from the SEC’s website at www.sec.gov, free of charge, or from the SEC’s Public Reference Section at 100 F Street, NE, Washington, D.C. 20549, at prescribed rates. Further information on the operation of the SEC public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330.
Item 11.
Quantitative and Qualitative Disclosures About Market Risk

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Interest Rate Risk
We are exposed to the impact of interest rate changes, primarily through our floating-rate borrowings that require us to make interest payments based on LIBOR or NIBOR. Significant increases in interest rates could adversely affect operating margins, results of operations and our ability to service our debt. From time to time, we use interest rate swaps to reduce our exposure to market risk from changes in interest rates. The principal objective of these contracts is to minimize the risks and costs associated with our floating-rate debt.

We are exposed to credit loss in the event of non-performance by the counterparties to the interest rate swap agreements. In order to minimize counterparty risk, we only enter into derivative transactions with counterparties that are rated A- or better by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

The tables below provide information about financial instruments as at December 31, 2016 that are sensitive to changes in interest rates. For long-term debt, the table presents principal payments and related weighted-average interest rates by expected contractual maturity dates. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected contractual maturity dates.

 
 
 
Expected Maturity Date
 
 
 
 
 
 
2017
 
2018
 
2019
 
2020
 
2021
 
There-
after
 
Total
 
Fair
Value
Liability
 
Rate (1)
 
 
(in millions of U.S. dollars, except percentages)
Long-Term Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Variable Rate ($U.S.)(2)
 
555.2

 
540.8

 
330.4

 
257.3

 
205.4

 
566.8

 
2,455.9

 
2,328.6

 
3.0
%
Variable Rate (NOK)(3)
 
20.8

 
120.4

 
115.7

 
—

 
—

 
—

 
256.9

 
228.1

 
6.1
%
Fixed Rate Debt ($U.S.)(4)
 
12.7

 
25.3

 
527.3

 
25.8

 
29.5

 
104.3

 
724.9

 
668.7

 
6.6
%
Interest Rate Swaps:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contract Amount (5)(6)
 
220.3

 
229.0

 
406.0

 
459.9

 
37.4

 
622.4

 
1,975.0

 
203.1

 
3.3
%
Average Fixed Pay Rate(2)
 
1.8
%
 
1.8
%
 
4.3
%
 
2.9
%
 
2.4
%
 
4.3
%
 
3.3
%
 
 
 
 
 __________________________
(1)
Rate relating to long-term debt refers to the weighted-average effective interest rate for our debt, including the margin paid on our floating-rate debt. Rate relating to interest rate swaps refers to the average fixed pay rate for interest rate swaps. The average fixed pay rate for interest rate swaps excludes the margin paid on the floating-rate debt, which as of December 31, 2016 ranged between 0.30% and 4.00% based on LIBOR and between 4.25% and 5.75% based on NIBOR.
(2)
Interest payments on U.S. Dollar-denominated debt and interest rate swaps are based on LIBOR.
(3)
Interest payments on NOK-denominated debt and interest rate swaps are based on NIBOR. Our NOK-denominated debt has been economically hedged with cross currency swaps, to swap all interest and principal payments at maturity into U.S. Dollars. Please see the table in the Foreign Currency Fluctuation Risk section below and read Item 18 – Financial Statements: Note 12 – Derivative Instruments.
(4)
Includes amounts related to a subordinated promissory note owing to a subsidiary of Teekay Corporation.
(5)
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.
(6)
Includes six interest rate swaps, which as at December 31, 2016, had a total notional amount of $759.5 million and a total fair value liability of $181.8 million. In the second quarter of 2016, the early termination provisions of these interest rate swaps were extended from the second half of 2016 through the second half of 2017 to early-to-mid-2019.
Foreign Currency Fluctuation Risk
Our functional currency is the U.S. Dollar because virtually all of our revenues and most of our operating costs are in U.S. Dollars. We incur certain vessel operating expenses, general and administrative expenses and a portion of our capital conversion and upgrade projects in foreign currencies, the most significant of which is the Norwegian Kroner and, to a lesser extent, Australian Dollar, Brazilian Real, British Pound, Euro and Singapore Dollar. For the years ended December 31, 2016 and 2015, approximately 38.3% and 37.8%, 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, 2016, we were committed to the following foreign currency forward contracts:

93


 
 
Contract Amount in Foreign Currency
(thousands)
 
Average Forward Rate(1)
 
Expected Maturity
 
Fair Value / Carrying Amount of Asset (Liability) (in thousands of U.S. Dollars) Non-hedge
 
 
 
2017
 
2018
 
 
 
 
(in thousands of U.S. Dollars)
 
Norwegian Kroner
 
390,000

 
8.35

 
38,859

 
7,829

 
(1,482
)
Euro
 
13,750

 
0.92

 
14,879

 
—

 
(304
)
 
 
 
 
 
 
53,738

 
7,829

 
(1,786
)
(1)
Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

We incur interest expense on our Norwegian Kroner-denominated bonds. We have entered into cross currency swaps to economically hedge the foreign exchange risk on the principal and interest for these bonds. Please read Item 18 – Financial Statements: Note 12 – Derivative Instruments.

As at December 31, 2016, we were committed to the following cross currency swaps:

Principal
Amount
NOK(thousands)
 
Principal
Amount
USD(thousands)
 
Floating Rate Receivable
 
Fixed Rate
Payable
 
Fair Value /
Asset
(Liability)
 
Remaining
Term (years)
Reference
Rate
 
Margin
 
420,000 (1)(2)

 
70,946

 
NIBOR
 
5.75
%
 
8.84
%
 
(25,821
)
 
1.9
800,000 (1)(3)

 
143,536

 
NIBOR
 
5.75
%
 
7.58
%
 
(56,272
)
 
2.0
1,000,000

 
162,200

 
NIBOR
 
4.25
%
 
7.45
%
 
(55,286
)
 
2.1
 
 
 
 
 
 
 
 
 
 
(137,379
)
 
 

(1)
Notional amount reduces equally with NOK bond repayments.
(2)
Excludes an economic hedge on the foreign currency exposure for a three percent premium upon maturity of the NOK bonds which exchanges NOK 7.2 million for $1.2 million.
(3)
Excludes an economic hedge on the foreign currency exposure for a three percent premium upon maturity of the NOK bonds which exchanges NOK 19.2 million for $3.4 million.

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, 2016, 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.


94


We conducted an evaluation of our disclosure controls and procedures under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of Service Provider. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer of Service Provider concluded that our disclosure controls and procedures are effective as of December 31, 2016.

The Chief Executive Officer and Chief Financial Officer of Service Provider do not expect that our disclosure controls or internal controls will prevent all errors and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within us have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining for us adequate internal 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 only in accordance with authorizations of management and the directors; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

We conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation.

Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements even when determined to be effective and can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. However, based on the evaluation, management has concluded that our internal controls over financial reporting were effective as of December 31, 2016.

Our independent auditors, KPMG LLP, an independent registered public accounting firm, has audited the accompanying consolidated financial statements and our internal control over financial reporting. Their attestation report on the effectiveness of our internal control over financial reporting can be found on page F-2 of this Annual Report.

During the year ended December 31, 2016, we completed the global implementation of an accounting system designed to improve the effectiveness and efficiency of our accounting and financial reporting processes. This accounting system was previously implemented in certain regions during 2012. Although this implementation changed certain specific activities within the accounting function, it did not significantly affect the overall controls and procedures followed by us in establishing internal controls over financial reporting. Other than this accounting system implementation, there have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) during the year ended December 31, 2016, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
Item 16A.
Audit Committee Financial Expert
The board of directors of our general partner has determined that director John J. Peacock qualifies as an audit committee financial expert and is independent under applicable NYSE and SEC standards.
Item 16B.
Code of Ethics
We have adopted a Standards of Business Conduct that applies to all our employees and the employees and directors of our general partner. This document is available under “Investors – Teekay Offshore Partners L.P. – Governance” from the home page of our web site (www.teekay.com). We intend to disclose, under “Investors – Teekay Offshore Partners L.P. – Governance” in the Investors section of our web site, any waivers to or amendments of the Code of Ethics for the benefit of any directors and executive officers of our general partner.

95


Item 16C.
Principal Accountant Fees and Services
Our principal accountant for 2016 and 2015 was KPMG LLP, Chartered Professional Accountants. The following table shows the fees we paid or accrued for audit services provided by KPMG LLP for 2016 and 2015.
 
 
2016
 
2015
 
 
(in thousands of U.S. Dollars)
Audit Fees (1)
 
$
1,136

 
$
1,033

Tax Fees (2)
 
23

 
23

Total
 
$
1,159

 
$
1,056

(1)
Audit fees represent fees for professional services provided in connection with the audit of our consolidated financial statements, review of our quarterly consolidated financial statements and audit services provided in connection with other statutory or regulatory filings, including professional services in connection with the review of our regulatory filings for our follow-on offering of common units and offerings of preferred units.
(2)
For 2016 and 2015, 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 2016.
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
As a foreign private issuer, we are not required to obtain unitholder approval prior to the adoption of equity compensation plans or certain equity issuances, including, among others, issuing 20% or more of our outstanding common units or voting power in a transaction.

There are no other 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:

96


 
Page
F- 1 , F-2
Consolidated Financial Statements
 
F- 3
F- 4
F- 5
F- 6
F- 7
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
Fifth 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 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 August 18, 2016, between Teekay Offshore Partners L.P. and Citigroup Global Markets Inc. to offer and sell common units having an aggregate offering price of up to $100,000,000 under the Continuous Offering Program. (16)
2.2
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. (7)
2.3
Agreement, dated January 30, 2014, for NOK 1,000,000,000 Senior Unsecured Bonds due January 2019, between Teekay Offshore Partners L.P. and Norsk Tillitsman ASA. All payments are at NIBOR plus 4.25% per annum. (10)
2.4
Indentures, dated May 30 2014, for U.S. $300,000,000 Senior Unsecured Bonds due July 2019 in the U.S. bond market, between Teekay Offshore Partners L.P. and The Bank of New York Mellon. (8)
2.5
First Supplemental Indenture, dated as of May 30, 2014, among Teekay Offshore Partners L.P., Teekay Offshore Finance Corp. and The Bank of New York Mellon, as trustee. (8)
2.6
Agreement, dated October 14, 2014, for a U.S. $330,000,000 Revolving Credit Facility between Teekay Offshore Partners L.P., Den Norske Bank Capital LLC and various other banks. (10)
2.7
Purchase Agreement, dated April 6, 2015 for Knarr L.L.C. and Teekay Knarr AS, between Teekay Corporation and Teekay Offshore Partners L.P. (11)
2.8
Agreement, dated February 2, 2015, among Logitel Offshore Rig I Pte.Ltd. and Citibank N.A., London Branch for a U.S. $150,000,000 term loan, of which U.S. $117,000,000 is due 2025 and U.S. $33,000,000 is due 2021. (13)
2.9
Agreement, dated February 6, 2015, among ALP Forward B.V., ALP Ace B.V., ALP Centre B.V., ALP Guard B.V., ALP Winger B.V. and ALP Ippon B.V. and Credit Suisse AG, for a U.S. $150,000,000 term loan due 2023. (13)
2.10
Agreement, dated June 29, 2015, among Petrojarl I L.L.C. and ABN AMRO CAPITAL USA LLC for a U.S. $180,000,000 term loan due 2021. (13)
2.11
Agreement, dated July 31, 2015, among OOGTK Libra GmbH & Co KG, ABN AMRO Bank N.V. and various other banks for a U.S. $803,711,786.92 term loan due 2027. (13)
2.12
Agreement, dated February 24, 2014 among Knarr L.L.C., Citibank, N.A. and others, for a U.S. $815,000,000 Secure Term Loan Facility Agreement, of which $614,944,162 is due through 2026, $120,000,000 is due through 2024 and $80,055,838 is due through 2020. (14)
4.1
Teekay Offshore Partners L.P. 2006 Long-Term Incentive Plan. (1)
4.2
Amended and Restated Omnibus Agreement. (1)
4.3
Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Shipping Limited. (3)
4.4
Advisory, Technical and Administrative Services Agreement between Teekay Offshore Operating Partners L.P. and Teekay Shipping Limited. (3)
4.5
Administrative Services Agreement between Teekay Offshore Partners L.P. and Teekay Shipping Limited. (3)

97


4.6
Agreement, dated March 8, 2011, between Teekay Holdings Limited and Teekay Offshore Partners L.P., relating to the purchase of limited partner interests of Teekay Offshore Operating L.P. (4)
4.7
Business Development Services Agreement between Teekay Offshore Holdings L.L.C. and Teekay Shipping Limited. (6)
4.8
Agreement, dated September 11, 2012, between Teekay Corporation and Teekay Offshore Partners L.P., relating to the purchase of the Voyageur Spirit. (5)
4.9
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. (7)
8.1
List of Subsidiaries of Teekay Offshore Partners L.P.
10.1
Common Unit Purchase Agreement, dated November 24, 2014, by and among Teekay Offshore Partners L.P. and the purchasers named therein. (9)
10.2
Series C Preferred Unit Purchase Agreement, dated June 30, 2015, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (12)
10.3
Registration Rights Agreement, dated July 1, 2015, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (1)
10.4
Amendment No. 1 to Knarr Purchase Agreement, dated June 29, 2015, by and among Teekay Offshore Partners L.P. and Teekay Corporation.(12)
10.5
Registration Rights Agreement, dated June 29, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers Named on Schedule A thereto. (15)
10.6
Warrant Agreement, dated June 29, 2016 by and among Teekay Offshore Partners L.P. and Computershare Inc. and Computershare Trust Company N.A.(15) 
10.7
Common Unit Purchase Agreement, dated June 16, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers named on Schedule A thereto(15)

10.8
Series D Preferred Unit Purchase Agreement, dated June 22, 2016, by and among Teekay Offshore Partners L.P. and the Purchasers named on Schedule A thereto(15)

12.1
Rule 13a-14(a)/15d-14(a) Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd.
12.2
Rule 13a-14(a)/15d-14(a) Certification of David Wong, Chief Financial Officer of Teekay Offshore Group Ltd.
13.1
Teekay Offshore Partners L.P. Certification of Ingvild Saether, President and Chief Executive Officer of Teekay Offshore Group Ltd. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2
Teekay Offshore Partners L.P. Certification of David Wong, Chief Financial Officer of Teekay Offshore Group Ltd.
 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1
Consent of KPMG LLP, as independent registered public accounting firm.
15.2
Consolidated Financial Statements of OOG TKP FPSO GmbH & Co KG and subsidiaries.
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
101.DEF
XBRL Taxonomy Extension Definition Linkbase
101.LAB
XBRL Taxonomy Extension Label Linkbase
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
(1)
Previously filed as an exhibit to our Registration Statement on Form F-1 (File No. 333-139116), filed with the SEC on December 4, 2006, and hereby incorporated by reference to such Registration Statement.
(2)
Previously filed as Exhibit 4.4 to our Report on Form 6-K filed on June 30, 2016 (File No. 1-33198), and hereby incorporated by reference to such Report.
(3)
Previously filed as an exhibit to our Amendment No. 1 to Registration Statement on Form F-1 (File No. 333-139116), filed with the SEC on December 8, 2006, and hereby incorporated by reference to such Registration Statement.
(4)
Previously filed as an exhibit to our Annual Report on Form 20-F (File No.1-33198), filed with the SEC on April 11, 2011, and hereby incorporated by reference to such Report.
(5)
Previously filed as an exhibit to our Report on Form 6-K (File No.1-33198), filed with the SEC on September 11, 2012, and hereby incorporated by reference to such Report.
(6)
Previously filed as an exhibit to our Annual Report on Form 20-F (File No. 33198), filed with the SEC on April 11, 2013, and hereby incorporated by reference to such Report.
(7)
Previously filed as an exhibit to our Report on Form 20-F (File No.1-33198), filed with the SEC on April 29, 2014, and hereby incorporated by reference to such Report.
(8)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on May 30, 2014, and hereby incorporated by reference to such Report.
(9)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 28, 2014, and hereby incorporated by reference to such Report.
(10)
Previously filed as an exhibit to our Report on Form 20-F (File No. 1-33198), filed with the SEC on April 2, 2015, and hereby incorporated by reference to such Report.

98


(11)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on April 13, 2015, and hereby incorporated by reference to such Report.
(12)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on July 6, 2015, and hereby incorporated by reference to such Report.
(13)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 17, 2015, and hereby incorporated by reference to such Report.
(14)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on November 19, 2015, and hereby incorporated by reference to such Report.
(15)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on June 30, 2016, and hereby incorporated by reference to such Report.
(16)
Previously filed as an exhibit to our Report on Form 6-K (File No. 1-33198), filed with the SEC on August 18, 2016, and hereby incorporated by reference to such Report.
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 12, 2017
 
 
 
By:
 
/s/ Edith Robinson
 
 
 
 
Edith Robinson
Secretary

99



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, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows and changes in total equity for each of the years in the three-year period ended December 31, 2016. 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, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, 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, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated April 12, 2017 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
Vancouver, Canada
 
 
 
/s/ KPMG LLP
April 12, 2017
 
 
 
Chartered Professional Accountants

F- 1



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Unitholders of
Teekay Offshore Partners L.P.
We have audited Teekay Offshore Partners L.P. and subsidiaries’ (the “Partnership”) internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting in the accompanying Form 20-F. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Partnership as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows and changes in total equity for each of the years in the three-year period ended December 31, 2016, and our report dated April 12, 2017 expressed an unqualified opinion on those consolidated financial statements.

Vancouver, Canada
 
 
 
/s/ KPMG LLP
April 12, 2017
 
 
 
Chartered Professional Accountants

F- 2



TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)
CONSOLIDATED STATEMENTS OF INCOME
(in thousands of U.S. Dollars, except unit and per unit data)
 
 
Year Ended
 
Year Ended
 
Year Ended
 
 
December 31,
 
December 31,
 
December 31,
 
 
2016
 
2015
 
2014
 
 
$
 
$
 
$
Revenues (note 11)
 
1,152,390

 
1,229,413

 
1,019,539

Voyage expenses
 
(80,750
)
 
(98,006
)
 
(112,540
)
Vessel operating expenses (note 11)
 
(364,441
)
 
(378,480
)
 
(352,209
)
Time-charter hire expenses
 
(75,485
)
 
(51,750
)
 
(31,090
)
Depreciation and amortization (note 1)
 
(300,011
)
 
(274,599
)
 
(198,553
)
General and administrative (notes 11 and 17)
 
(56,122
)
 
(72,613
)
 
(67,516
)
(Write-down) and gain on sale of vessels (note 19)
 
(40,079
)
 
(69,998
)
 
(1,638
)
Restructuring (charge) recovery (note 10)
 
(4,649
)
 
(568
)
 
225

Income from vessel operations
 
230,853

 
283,399

 
256,218


 


 


 


Interest expense (notes 8, 11 and 12)
 
(140,611
)
 
(122,838
)
 
(88,381
)
Interest income
 
1,257

 
633

 
719

Realized and unrealized losses on derivative instruments (note 12)
 
(20,313
)
 
(73,704
)
 
(143,703
)
Equity income
 
17,933

 
7,672

 
10,341

Foreign currency exchange loss (note 12)
 
(14,805
)
 
(17,467
)
 
(16,140
)
Other (expense) income - net (notes 4 and 14c)
 
(21,031
)
 
1,091

 
781

Income before income tax (expense) recovery
 
53,283

 
78,786

 
19,835

Income tax (expense) recovery (note 13)
 
(8,808
)
 
21,357

 
(2,179
)
Net income
 
44,475

 
100,143

 
17,656


 


 


 


Non-controlling interests in net income
 
11,858

 
13,911

 
10,503

Dropdown Predecessor's interest in net income (note 3)
 
—

 
10,101

 
—

Preferred unitholders interest in net income (note 16)
 
45,836

 
28,609

 
10,875

General Partner’s interest in net income
 
(267
)
 
16,317

 
15,658

Limited partners' interest in net income
 
(12,952
)
 
31,205

 
(19,380
)
Limited partners' interest in net income for basic net income per common unit (note 16)
 
(31,326
)
 
31,205

 
(19,380
)
Limited partner's interest in net income per common unit
 


 


 

- basic (note 16)
 
(0.25
)
 
0.32

 
(0.22
)
- diluted (note 16)
 
(0.25
)
 
0.32

 
(0.22
)
Weighted-average number of common units outstanding:
 


 


 


- basic
 
124,747,207

 
98,507,732

 
86,212,290

- diluted
 
124,747,207

 
98,602,412

 
86,212,290

Cash distributions declared per unit
 
0.4400

 
2.1752

 
2.1536


 
 
 
 
 
 
Related party transactions (note 11)
 
 
 
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.
 
 

F- 3


TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands of U.S. Dollars)
 
 
Year Ended
 
Year Ended
 
Year Ended
 
 
December 31,
 
December 31,
 
December 31,
 
 
2016
 
2015
 
2014
 
 
$
 
$
 
$
Net income
 
44,475

 
100,143

 
17,656

Other comprehensive income:
 


 


 


Other comprehensive income before reclassifications
 
 
 
 
 
 
Unrealized (loss) gain on qualifying cash flow hedging instruments (note 12)
 
(1,564
)
 
696

 
—

Amounts reclassified from accumulated other comprehensive income
 
 
 
 
 
 
To interest expense:
 
 
 
 
 
 
Realized loss on qualifying cash flow hedging instruments (note 12)
 
64

 
—

 
—

Other comprehensive (loss) income
 
(1,500
)
 
696

 
—

Comprehensive income
 
42,975

 
100,839

 
17,656

Non-controlling interests in comprehensive income
 
11,858

 
13,911

 
10,503

Dropdown Predecessor's interest in comprehensive income (note 3)
 
—

 
10,101

 
—

Preferred unitholders' interest in comprehensive income
 
45,836

 
28,609

 
10,875

General and limited partners' interest in comprehensive income
 
(14,719
)
 
48,218

 
(3,722
)
 
 
 
 
 
 
 
The accompanying notes are an integral part of the unaudited consolidated financial statements.




F- 4


TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)
CONSOLIDATED BALANCE SHEETS
(in thousands of U.S. Dollars)
 
 
As at
 
As at
 
 
December 31,
 
December 31,
 
 
2016
 
2015
 
 
$
 
$
ASSETS
 
 
 

Current
 
 
 

Cash and cash equivalents
 
227,378

 
258,473

Restricted cash (notes 8, 12 and 14e)
 
92,265

 
51,431

Accounts receivable, including non-trade of $13,032 (December 31, 2015 - $7,458)
 
114,576

 
153,662

Vessels held for sale (notes 4a and 19)
 
6,900

 
55,450

Net investments in direct financing leases - current (notes 4b and 9)
 
4,417

 
5,936

Prepaid expenses
 
25,187

 
34,027

Due from affiliates (note 11l)
 
77,811

 
81,271

Other current assets (note 12)
 
21,282

 
20,490

Total current assets
 
569,816

 
660,740

Restricted cash - long-term (note 12)
 
22,644

 
9,089

Vessels and equipment
 
 
 


At cost, less accumulated depreciation of $1,494,038 (December 31, 2015 - $1,230,868)
 
4,084,803

 
4,348,535

Advances on newbuilding contracts and conversion costs (notes 14a, 14b, 14e and 14f)
 
632,130

 
395,084

Net investments in direct financing leases (notes 4b and 9)
 
13,169

 
11,535

Investment in equity accounted joint ventures (notes 14d and 20)
 
141,819

 
77,647

Deferred tax asset (note 13)
 
24,659

 
30,050

Other assets (notes 1 and 12)
 
100,435

 
82,341

Goodwill (note 6a)
 
129,145

 
129,145

Total assets
 
5,718,620

 
5,744,166

LIABILITIES AND EQUITY
 
 
 


Current
 
 
 


Accounts payable
 
8,946

 
15,899

Accrued liabilities (notes 7, 10, 12, and 17)
 
150,281

 
91,065

Deferred revenues
 
57,373

 
54,378

Due to affiliates (note 11l)
 
96,555

 
304,583

Current portion of derivative instruments (note 12)
 
55,002

 
201,456

Current portion of long-term debt (note 8)
 
586,892

 
485,069

Current portion of in-process revenue contracts (note 6b)
 
12,744

 
12,779

Total current liabilities
 
967,793

 
1,165,229

Long-term debt (note 8)
 
2,596,002

 
2,878,805

Derivatives instruments (note 12)
 
282,138

 
221,329

Due to affiliates (notes 11i, 11k and 11l)
 
200,000

 
—

In-process revenue contracts (note 6b)
 
50,281

 
63,026

Other long-term liabilities (note 1)
 
211,611

 
192,258

Total liabilities
 
4,307,825

 
4,520,647

Commitments and contingencies (notes 8, 9, 12 and 14)
 


 


Redeemable non-controlling interest
 
962

 
3,173

Convertible Preferred Units (12.5 million and 10.4 million units issued and outstanding at December 31, 2016 and December 31, 2015, respectively) (note 16)
 
271,237

 
252,498

Equity
 
 
 


Limited partners - common units (147.5 million and 107.0 million units issued and outstanding at December 31, 2016 and December 31, 2015, respectively) (notes 16 and 17)
 
784,056

 
629,264

Limited partners - preferred units (11.0 million units issued and outstanding at December 31, 2016 and December 31, 2015, respectively) (note 16)
 
266,925

 
266,925

General Partner
 
20,658

 
17,608

Warrants (note 16)
 
13,797

 
—

Accumulated other comprehensive (loss) income
 
(804
)
 
696

Non-controlling interests
 
53,964

 
53,355

Total equity
 
1,138,596

 
967,848

Total liabilities and equity
 
5,718,620

 
5,744,166

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

F- 5


TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of U.S. Dollars)
 
 
Year Ended
 
Year Ended
 
Year Ended
 
 
December 31,
 
December 31,
 
December 31,
 
 
2016
 
2015
 
2014
 
 
$
 
$
 
$
Cash and cash equivalents provided by (used for)
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 
44,475

 
100,143

 
17,656

Non-cash items:
 


 


 


Unrealized (gain) loss on derivative instruments (note 12)
 
(86,467
)
 
51,072

 
180,156

Equity income, net of dividends received of $7,206 (2015 - $7,843, 2014 - $16,803)
 
(10,727
)
 
171

 
6,462

Depreciation and amortization
 
300,011

 
274,599

 
198,553

Write-down and (gain) on sale of vessels (note 19)
 
40,079

 
69,998

 
1,638

Deferred income tax expense (recovery) (note 13)
 
4,854

 
(23,007
)
 
889

Amortization of in-process revenue contracts (note 6b)
 
(12,779
)
 
(12,745
)
 
(12,744
)
Unrealized foreign currency exchange loss (gain) and other
 
26,492

 
(101,853
)
 
(84,719
)
Change in non-cash working capital items related to operating activities (note 15a)
 
74,218

 
25,903

 
(111,484
)
Expenditures for dry docking (note 1)
 
(26,342
)
 
(13,060
)
 
(36,221
)
Net operating cash flow
 
353,814

 
371,221

 
160,186

FINANCING ACTIVITIES
 


 


 


Proceeds from long-term debt (note 8)
 
456,697

 
785,577

 
1,350,096

Scheduled repayments of long-term debt (note 8)
 
(434,339
)
 
(341,837
)
 
(804,704
)
Prepayments of long-term debt (note 8)
 
(197,776
)
 
(123,606
)
 
(418,625
)
Debt issuance costs
 
(12,095
)
 
(22,587
)
 
(15,555
)
Equity contribution from joint venture partners
 
750

 
5,500

 
27,267

Proceeds from issuance of common units (notes 3 and 16)
 
135,246

 
9,674

 
186,353

Proceeds from issuance of preferred units and warrants (note 16)
 
100,000

 
375,000

 
—

Expenses relating to equity offerings
 
(6,395
)
 
(4,459
)
 
(228
)
Increase in restricted cash (notes 4, 12 and 14e)
 
(54,389
)
 
(13,760
)
 
(46,760
)
Cash distributions paid by the Partnership
 
(78,634
)
 
(257,900
)
 
(214,656
)
Cash distributions paid by subsidiaries to non-controlling interests
 
(14,210
)
 
(23,575
)
 
(27,939
)
Settlement of contingent consideration liability (note 4)
 
—

 
(3,303
)
 
—

Indemnification from purchase of Voyageur LLC from Teekay Corporation (notes 11c and 15e)
 
—

 
—

 
6,181

Purchase of Teekay Knarr AS and Knarr L.L.C from Teekay Corporation (net of cash acquired) (2015 - $14.2 million) (notes 3 and 15e)
 
—

 
(112,710
)
 
—

Other
 
—

 
1,124

 
974

Net financing cash flow
 
(105,145
)
 
273,138

 
42,404

INVESTING ACTIVITIES
 


 


 


Net payments for vessels and equipment, including advances on newbuilding contracts and conversion costs
 
(294,581
)
 
(664,667
)
 
(172,169
)
Proceeds from sale of vessels and equipment
 
69,805

 
8,918

 
13,364

Investments in equity accounted joint ventures
 
(54,873
)
 
(22,855
)
 
(12,413
)
Repayments (advances) from (to) joint ventures (note 20)
 
—

 
5,225

 
(5,225
)
Direct financing lease (investments) payments received
 
(115
)
 
4,987

 
5,097

Acquisition of ALP Maritime Services B.V. (net of cash acquired of $0.3 million) (note 18a)
 
—

 
—

 
(2,322
)
Acquisition of Logitel Offshore Holding AS (net of cash acquired of $8.1 million) (note 18b)
 
—

 
—

 
4,090

Proceeds from sale of SPT Explorer L.L.C. and Navigator Spirit L.L.C. (notes 11e and 19)
 
—

 
30,368

 
—

Net investing cash flow
 
(279,764
)
 
(638,024
)
 
(169,578
)
(Decrease) increase in cash and cash equivalents
 
(31,095
)
 
6,335

 
33,012

Cash and cash equivalents, beginning of the year
 
258,473

 
252,138

 
219,126

Cash and cash equivalents, end of the year
 
227,378

 
258,473

 
252,138

Supplemental cash flow disclosure (note 15)
 


 


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

F- 6


 TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES (notes 1 and 3)
CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL EQUITY
(in thousands of U.S. Dollars and units)
 
 
PARTNERS’ EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dropdown Predecessor
Equity
$
 
Common
Units
#
 
Common
Units and
Additional Paid-in 
Capital
$
 
Preferred
Units
#
 
Preferred
Units
$
 

Warrants
$
 
General
Partner
$
 
Accumulated Other Comprehensive Income
(Loss)
$
 
Non-
controlling
Interests
$
 
Total
Equity
$
 
Convertible Preferred Units
#
 
Convertible Preferred Units
$
 
Redeemable
Non-
controlling
Interest
$
Balance as at December 31, 2013
 
—

 
85,453

 
621,002

 
6,000

 
144,800

 
—

 
21,242

 
—

 
34,297

 
821,341

 
—

 
—

 
16,564

Net income
 
—

 
—

 
(19,380
)
 
—

 
10,875

 
—

 
15,658

 
—

 
2,726

 
9,879

 
—

 
—

 
7,777

Cash distributions
 
—

 
—

 
(184,286
)
 
—

 
(10,875
)
 
—

 
(19,495
)
 
—

 
—

 
(214,656
)
 
—

 
—

 
—

Distributions to non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(16,440
)
 
(16,440
)
 
—

 
—

 
(11,499
)
Contributions of capital from joint venture partner
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
27,267

 
27,267

 
—

 
—

 
—

Indemnification payment on Voyageur LLC from Teekay Corporation (note 11c)
 
—

 
—

 
6,057

 
—

 
—

 
—

 
124

 
—

 
—

 
6,181

 
—

 
—

 
—

Proceeds from equity offering, net of offering costs (note 16)
 
—

 
6,918

 
182,398

 
—

 
—

 
—

 
3,727

 
—

 
—

 
186,125

 
—

 
—

 
—

Distribution of capital to Teekay Corporation related to the equity Investment in Itajai FPSO joint venture (note 11d)
 
—

 
—

 
(6,082
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(6,082
)
 
—

 
—

 
—

Distribution of capital to Teekay Corporation related to the purchase of Petrojarl I FPSO unit (note 11f)
 
—

 
—

 
(12,166
)
 
—

 
—

 
—

 
(248
)
 
—

 
—

 
(12,414
)
 
—

 
—

 
—

Equity based compensation and other (notes 11e and 17)
 
—

 
15

 
1,622

 
—

 
—

 
—

 
30

 
—

 
—

 
1,652

 
—

 
—

 
—

Balance as at December 31, 2014
 
—

 
92,386

 
589,165

 
6,000

 
144,800

 
—

 
21,038

 
—

 
47,850

 
802,853

 
—

 
—

 
12,842

Net income
 
10,101

 
—

 
31,205

 
—

 
18,260

 
—

 
16,317

 
—

 
10,980

 
86,863

 
—

 
10,349

 
2,931

Other comprehensive income (note 12)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
696

 
—

 
696

 
—

 
—

 
—

Cash distributions
 
—

 
—

 
(209,177
)
 
—

 
(16,925
)
 
—

 
(24,197
)
 
—

 
—

 
(250,299
)
 
—

 
(7,601
)
 
—

Distribution to non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(10,975
)
 
(10,975
)
 
—

 
—

 
(12,600
)
Contribution of capital from joint venture partner
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
5,500

 
5,500

 
—

 
—

 
—

Proceeds from equity offering, net of offering costs (note 16)
 
—

 
211

 
3,485

 
5,000

 
120,790

 
—

 
71

 
—

 
—

 
124,346

 
10,438

 
249,750

 
—

Net proceeds from equity offering to Teekay Corporation for purchase of Knarr LLC and Teekay Knarr AS (notes 3 and 11g)
 
—

 
14,402

 
300,000

 
—

 
—

 
—

 
6,122

 
—

 
—

 
306,122

 
—

 
—

 
—

Purchase of Knarr LLC and Teekay Knarr AS from Teekay Corporation (notes 3 and 11g)
 
(426,117
)
 
—

 
(101,254
)
 
—

 
—

 
—

 
(2,066
)
 
—

 
—

 
(529,437
)
 
—

 
—

 
—

Net change in Teekay Corporation's equity in Dropdown Predecessor (notes 3 and 11g)
 
416,016

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
416,016

 
—

 
—

 
—

Contribution of capital from sale of SPT Explorer L.L.C. and Navigator Spirit L.L.C. (notes 11e and 19)
 
—

 
—

 
14,011

 
—

 
—

 
—

 
286

 
—

 
—

 
14,297

 
—

 
—

 
—

Equity based compensation and other (notes 11e and 17)
 
—

 
28

 
1,829

 
—

 
—

 
—

 
37

 
—

 
—

 
1,865

 
—

 
—

 
—

Balance as at December 31, 2015
 
—

 
107,027

 
629,264

 
11,000

 
266,925

 
—

 
17,608

 
696

 
53,355

 
967,848

 
10,438

 
252,498

 
3,173

Net income
 
—

 
—

 
(12,952
)
 
—

 
21,500

 
—

 
(267
)
 
—

 
9,469

 
17,750

 
—

 
24,336

 
2,389

Other comprehensive loss (note 12)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(1,500
)
 
—

 
(1,500
)
 
—

 
—

 
—

Cash distributions
 
—

 
—

 
(45,904
)
 
—

 
(21,500
)
 
—

 
(480
)
 
—

 
—

 
(67,884
)
 
—

 
(10,750
)
 
—

Payment-in-kind distributions (note 16)
 
—

 
4,558

 
15,869

 
—

 
—

 
—

 
(630
)
 
—

 
—

 
15,239

 
—

 
(12,739
)
 
—

Distributions to non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(9,610
)
 
(9,610
)
 
—

 
—

 
(4,600
)
Contributions of capital from joint venture partner
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
750

 
750

 
—

 
—

 
—

Contribution of capital from Teekay Corporation (note 11j)
 
—

 
—

 
3,592

 
—

 
—

 
—

 
73

 
—

 
—

 
3,665

 
—

 
—

 
—

Proceeds from equity offerings, net of offering costs (note 16)
 
—

 
27,504

 
127,957

 
—

 
—

 
13,797

 
3,058

 
—

 
—

 
144,812

 
4,000

 
83,453

 
—

Conversion of Convertible Preferred Units (note 16)
 
—

 
8,324

 
46,282

 
—

 
—

 
—

 
889

 
—

 
—

 
47,171

 
(1,921
)
 
(46,429
)
 
—

Exchange of Convertible Preferred Units (note 16)
 
—

 
—

 
20,231

 
—

 
—

 
—

 
413

 
—

 
—

 
20,644

 
—

 
(20,644
)
 
—

Equity based compensation and other (note 17)
 
—

 
101

 
(283
)
 
—

 
—

 
—

 
(6
)
 
—

 
—

 
(289
)
 
—

 
1,512

 
—

Balance as at December 31, 2016
 
—

 
147,514

 
784,056

 
11,000

 
266,925

 
13,797

 
20,658

 
(804
)
 
53,964

 
1,138,596

 
12,517

 
271,237

 
962

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

F- 7

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


1.
Summary of Significant Accounting Policies

Basis of presentation

The consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (or GAAP). These financial statements include the accounts of Teekay Offshore Partners L.P., which is a limited partnership organized under the laws of the Republic of The Marshall Islands, its wholly owned or controlled subsidiaries and the Dropdown Predecessor (see note 3) (collectively, the Partnership).

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.

The Partnership presents non-controlling ownership interests in subsidiaries in the consolidated financial statements within temporary equity, separate from equity. However, the holder of the non-controlling interest of one of the Partnership’s subsidiaries holds a put option which, if exercised, would obligate the Partnership to purchase the non-controlling interest. As a result, the non-controlling interest that is subject to this redemption feature is presented on the Partnership’s consolidated balance sheet as part of the temporary equity as redeemable non-controlling interest above the equity section but below the liabilities section.

The Partnership presents its Series C Cumulative Convertible Perpetual Preferred Units (the Series C Preferred Units), its Series C-1 Cumulative Convertible Perpetual Preferred Units (the Series C-1 Preferred Units) and its Series D Cumulative Perpetual Preferred Units (the Series D Preferred Units) in the consolidated financial statements within temporary equity, separate from equity within the Partnership’s consolidated balance sheet as temporary equity above the equity section but below the liabilities section (see note 16).

Foreign currency

The consolidated financial statements are stated in U.S. Dollars and the functional currency of the Partnership is the U.S. Dollar. Transactions involving other currencies during the year are converted into U.S. Dollars using the exchange rates in effect at the time of the transactions. At the balance sheet dates, monetary assets and liabilities that are denominated in currencies other than the U.S. Dollar are translated to reflect the year-end exchange rates. Resulting gains or losses are reflected separately in the accompanying consolidated statements of income.

Operating revenues and expenses

Contracts of Affreightment and Voyage Charters

Revenues from contracts of affreightment and voyage charters are recognized on a proportionate performance method. Shuttle tanker voyages servicing contracts of affreightment with offshore oil fields commence with tendering of notice of readiness at a field, within the agreed lifting range, and ends with tendering of notice of readiness at a field for the next lifting. The Partnership uses a discharge-to-discharge basis in determining proportionate performance for all voyage charters, whereby it recognizes revenue ratably from when product is discharged (unloaded) at the end of one voyage to when it is discharged after the next voyage. The Partnership does not begin recognizing revenue until a charter has been agreed to by the customer and the Partnership, even if the vessel has discharged its cargo and is sailing to the anticipated load port on its next voyage. Towing and offshore installation revenue is recognized ratably in proportion to the stage of completion of a project, which is determined based upon an assessment of the work performed.

Time Charters, Bareboat Charters, FPSO Contracts and UMS Contracts

Operating Leases - The Partnership recognizes revenues from time charters, bareboat charters, floating, production, storage and offloading (or FPSO) contracts and Units for Maintenance and Safety (or UMS) contracts accounted for as operating leases on a straight-line basis daily over the term of the charter as the applicable vessel operates under the charter. Receipt of incentive-based revenue from the Partnership’s FPSO units is dependent upon its operating performance and such revenue is recognized when earned by fulfillment of the applicable performance criteria. The Partnership does not recognize revenue during days that the vessel is off hire unless the contract provides for compensation while off hire.

Direct Financing Leases - Charter contracts that are accounted for as direct financing leases are reflected in the consolidated balance sheets as net investments in direct financing leases. The lease revenue is recognized using an effective interest rate method over the lease term and is included in revenues. Revenues from rendering of services are recognized as the service is performed. Revenues are not recognized during days that the vessel is off hire unless the contract provides for compensation while off hire.

The consolidated balance sheets reflect the deferred portion of revenues and expenses, which will be earned or incurred, respectively, in subsequent periods.


F- 8

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Operating Expenses

Voyage expenses are all expenses unique to a particular voyage, including bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions. Vessel operating expenses include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses. Voyage expenses and vessel operating expenses are recognized when incurred.

Cash and cash equivalents

The Partnership classifies all highly-liquid investments with a maturity date of three months or less when purchased as cash and cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in existing accounts receivable. The Partnership determines the allowance based on historical write-off experience and customer economic data. The Partnership reviews the allowance for doubtful accounts regularly and past due balances are reviewed for collectability. Account balances are charged against the allowance when the Partnership believes that the receivable will not be recovered.

Investment in equity accounted joint ventures

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

Vessels and equipment

All pre-delivery costs incurred during the construction of newbuildings and conversions, including interest, supervision and technical costs, are capitalized. The acquisition cost and all costs incurred to restore used vessels purchased by the Partnership to the standards required to properly service the Partnership’s customers are capitalized.

Vessel capital modifications include the addition of new equipment or can encompass various modifications to the vessel which are aimed at improving and/or increasing the operational efficiency and functionality of the asset. This type of expenditure is amortized over the estimated useful life of the modification. Expenditures covering recurring routine repairs or maintenance are expensed as incurred.

The Partnership considers its shuttle tankers to be comprised of two components: i) a conventional tanker (or the tanker component) and ii) specialized shuttle equipment (or the shuttle component). The Partnership differentiates these two components on the principle that a shuttle tanker can also operate as a conventional tanker without the use of the shuttle component. The economics of this alternate use depend on the supply and demand fundamentals in the two segments. Historically, the useful life of both components was assessed as 25 years commencing from the date the vessel is delivered from the shipyard. During 2016, the Partnership has considered factors related to the ongoing use of the shuttle component and has reassessed the useful life as being 20 years based on the challenges associated with adverse market conditions in the energy sector and other long term factors associated with the global oil industry. This change in estimate, commencing January 1, 2016, impacts the entire fleet of its shuttle tanker vessels. Separately, the Partnership has reviewed the depreciation of the tanker component for eight vessels in its fleet that are 17 years of age or older. Based on the Partnership’s expected operating plan for these vessels, the Partnership has reassessed the estimated useful life of the tanker component for these vessels as 20 years commencing January 1, 2016. As market conditions evolve, the Partnership will continue to monitor the useful life of the tanker component for other vessels within the shuttle tanker segment. The effect of these changes in estimates was an increase in depreciation and amortization expense and a decrease in net income by $29.3 million, or a decrease of $0.23 per basic and diluted common unit, for 2016.

Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Conventional tankers are depreciated using an estimated useful life of 20 to 25 years commencing the date the vessel is delivered from the shipyard, or for a shorter period if regulations prevent the Partnership from operating the vessel for the estimated useful life. FPSO units are depreciated using an estimated useful life of 20 to 25 years commencing the date the unit is installed at the oil field and is in a condition that is ready to operate. Some of the Partnership’s FPSO units have oil field specific equipment, which is depreciated over the expected life of the oil field. Floating storage and off take (or FSO) units are depreciated over the term of the contract. The UMS is depreciated over an estimated useful life of 35 years commencing the date it arrived at the oil field and was in a condition that is ready to operate. Towage vessels are depreciated over an estimated useful life of 25 years commencing the date the vessel is delivered from the shipyard. Depreciation of vessels and equipment from continuing operations (including depreciation attributable to the Dropdown Predecessor) for the years ended December 31, 2016, 2015 and 2014, totalled $281.2 million, $247.8 million, and $171.8 million, respectively. Depreciation and amortization includes depreciation on all owned vessels.

Interest costs capitalized to vessels and equipment for the years ended December 31, 2016, 2015 and 2014 totaled $27.1 million, $10.3 million and $2.3 million, respectively.

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)


Generally, the Partnership dry docks each shuttle tanker, conventional oil tanker and towage vessel every two and a half to five years. UMS, FSO and FPSO units are generally not dry docked. The Partnership capitalizes a portion of the costs incurred during dry docking and amortizes those costs on a straight-line basis from the completion of a dry docking over the estimated useful life of the dry dock. Included in capitalized dry docking are costs incurred as part of the dry docking to meet regulatory requirements, or expenditures that either add economic life to the vessel, increase the vessel’s earning capacity or improve the vessel’s operating efficiency. The Partnership expenses costs related to routine repairs and maintenance performed during dry docking that do not improve operating efficiency or extend the useful lives of the assets.

Dry-docking activity for the three years ended December 31, 2016, 2015 and 2014 is summarized as follows:

 
 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
 
Year Ended
December 31, 2014
$
Balance at beginning of the year
 
42,822

 
54,259

 
41,535

Cost incurred for dry docking
 
25,043

 
14,609

 
36,221

Dry-docking amortization
 
(18,627
)
 
(23,863
)
 
(22,682
)
Write-down / sale of capitalized dry-dock expenditure
 
—

 
(2,183
)
 
(815
)
Balance at end of the year
 
49,238

 
42,822

 
54,259


Vessels and equipment that are “held and used” are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. If the asset’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. The estimated fair value for the Partnership’s impaired vessels is determined using discounted cash flows or appraised values. In cases where an active second hand sale and purchase market does not exist, the Partnership uses a discounted cash flow approach to estimate the fair value of an impaired vessel. In cases where an active second hand sale and purchase market exists, an appraised value is used to estimate the fair value of an impaired vessel. An appraised value is generally the amount the Partnership would expect to receive if it were to sell the vessel. Such appraisal is normally completed by the Partnership.

Direct financing leases

The long-term time charter of one of the Partnerships vessels and of equipment that reduces volatile organic compound emissions (or 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 revenue using the effective interest method so as to produce a constant periodic rate of return over the lease term.

Asset retirement obligation

The Partnership has an asset retirement obligation (or ARO) relating to the sub-sea mooring and riser system associated with the Gina Krog FSO unit expected to commence operations in the North Sea in mid-2017 (see note 14a). This obligation involves the costs associated with the restoration of the environment surrounding the facility and removal of all equipment, which are subsequently to be reimbursed by the charterer. This obligation is expected to be settled at the end of the contract under which the FSO unit is expected to operate, which is currently estimated to be May 2024.

The Partnership records the fair value of an ARO as a liability in the period when the obligation arises. The fair value of the ARO is measured using expected future cash outflows discounted at the Partnership’s credit-adjusted risk-free interest rate. When the liability is recorded, and as the ARO will be covered by contractual payments to be received from the charterer, the Partnership records a separate receivable concurrently with the ARO being created. Each period, the liability is increased for the change in its present value. Changes in the amount or timing of the estimated ARO are recorded as an adjustment to the related asset and liability. As at December 31, 2016, the ARO and associated receivable, which are recorded in other long-term liabilities and other non-current assets, respectively, were both $21.7 million.

Debt issuance costs

Debt issuance costs related to a recognized debt liability, including fees, commissions and legal expenses, are deferred and presented as a direct deduction from the carrying amount of that debt liability and amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included in interest expense. If the debt issuance costs are not attributable to a specific debt liability or the debt issuance costs exceed the carrying value of the related debt liability, the debt issuance costs are deferred and presented as other non-current assets and amortized on an effective interest rate method over the term of the relevant loan.

Goodwill

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

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)

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.

Derivative instruments

All derivative instruments are initially recorded at fair value as either assets or liabilities in the accompanying consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the derivative contract is designed to hedge a specific risk and also qualifies and is designated for hedge accounting. The Partnership does not apply hedge accounting to all its derivative instruments. Certain of the partnerships interest rate swaps are designated and accounted for as hedges in the consolidated financial statements or within our equity-accounted joint ventures (see note 12).

When a derivative is designated as a cash flow hedge, the Partnership formally documents the relationship between the derivative and the hedged item. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge. Any hedge ineffectiveness is recognized immediately in earnings, as are any gains and losses on the derivative that are excluded from the assessment of hedge effectiveness. The Partnership does not apply hedge accounting if it is determined that the hedge was not effective or will no longer be effective, the derivative was sold or exercised, or the hedged item was sold, repaid or is no longer possible of occurring.

For derivative financial instruments designated and qualifying as cash flow hedges, changes in the fair value of the effective portion of the derivative financial instruments are initially recorded as a component of accumulated other comprehensive income in equity. In the periods when the hedged items affect earnings, the associated fair value changes on the hedging derivatives are transferred from equity to the corresponding earnings line item in the consolidated statements of income. The ineffective portion of the change in fair value of the derivative financial instruments is immediately recognized in the interest expense line of the consolidated statements of income. A portion of the ineffectiveness of the fair value of derivative instruments is recognized in the equity accounted joint ventures line of the consolidated balance sheets. If a cash flow hedge is terminated and the originally hedged item is still considered possible of occurring, the gains and losses initially recognized in equity remain there until the hedged item impacts earnings, at which point they are transferred to the corresponding earnings line item in the consolidated statements of income. If the hedged item is no longer possible of occurring, amounts recognized in equity are immediately transferred to the earnings line item in the consolidated statements of income.

For derivative financial instruments that are not designated as accounting hedges, the changes in the fair value of the derivative financial instruments are recognized in earnings. Gains and losses from the Partnership’s non-designated foreign currency forward contracts and interest rate swaps are recorded in realized and unrealized losses on derivative instruments in the consolidated statements of income. Gains and losses from the Partnership’s non-designated cross currency swaps are recorded in foreign currency exchange loss in the consolidated statements of income.

Unit-based compensation

The Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership (see note 17). The Partnership measures the cost of such awards using an option pricing model to determine the grant date fair value of the award and recognizes that cost, net of estimated forfeitures, over the requisite service period. The requisite service period consists of the period from the grant date of the award to the earlier of the date of vesting or the date the recipient becomes eligible for retirement. For unit-based compensation awards subject to graded vesting, the Partnership calculates the value of the award as if it was one single award with one expected life and amortizes the calculated expense for the entire award on a straight-line basis over the requisite service period. For cash settled awards, the fair value of such awards is remeasured at each reporting date, based on the fair market value of the Partnership's common units at that date, with the change in fair value recognized as compensation expense. Unit-based compensation expenses are recorded under general and administrative expenses in the Partnership’s consolidated statements of income.

Income taxes

The Partnership is subject to income taxes relating to its subsidiaries in Norway, Australia, Brazil, the United Kingdom, Singapore, Qatar, Canada, Luxembourg and the Netherlands. The Partnership accounts for such taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Partnership’s assets and liabilities using the applicable jurisdictional tax rates. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

Recognition of uncertain tax positions is dependent upon whether it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax position meets the more-likely-than-not recognition threshold, it is measured to determine the amount of benefit to recognize in the consolidated financial statements based on guidance in the interpretation. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax (expense) recovery in the Partnership’s consolidated statements of income.

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)

2.
Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (or FASB) issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (or ASU 2014-09). ASU 2014-09 will require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update creates a five-step model that requires entities to exercise judgment when considering the terms of the contract(s) which include (i) identifying the contract(s) with the customer, (ii) identifying the separate performance obligations in the contract, (iii) determining the transaction price, (iv) allocating the transaction price to the separate performance obligations, and (v) recognizing revenue as each performance obligation is satisfied. ASU 2014-09 is effective for the Partnership January 1, 2018 and shall be applied, at the Partnership’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership expects that the adoption of ASU 2014-09 may result in a change in the method of recognizing revenue from contracts of affreightments whereby revenue will be recognized over the voyage until discharge is complete, instead of over the voyage until tendering notice for the next voyage. This will result in all revenue being fully recognized upon discharge of cargo whereas currently revenue recognition extends into the period the vessel returns to the oil field. This change may result in revenue being recognized earlier which may cause additional volatility in revenue and earnings between periods. In addition, the Partnership expects that the adoption of ASU 2014-09 may result in a change in the method of recognizing revenue for voyage charters, whereby the Partnership’s method of determining proportional performance will change from discharge-to-discharge to load-to-discharge. This will result in no revenue being recognized from discharge of the prior voyage to loading of the current voyage and all revenue being recognized from loading of the current voyage to discharge of the current voyage. This change will result in revenue being recognized later in the voyage which may cause additional volatility in revenue and earnings between periods. The Partnership is in the process of validating aspects of its preliminary assessment of ASU 2014-09, determining the transitional impact and completing other items required for the adoption of ASU 2014-09.

In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (or ASU 2016-02). ASU 2016-02 establishes a right-of-use model that requires a lessee to record a right of use asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Partnership expects to adopt ASU 2016-02 effective January 1, 2018. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership expects that the adoption of ASU 2016-02 will result in a change in accounting method for the lease portion of the daily charter hire for the Partnership's chartered-in vessels accounted for as operating leases with firm periods of greater than one year. Under ASU 2016-02, the Partnership will recognize a right of use asset and a lease liability on the balance sheet for these charters, whereas currently no right of use asset or lease liability is recognized. This will have the result of increasing the Partnership’s assets and liabilities. The pattern of expense recognition of chartered-in vessel is expected to remain substantially unchanged, unless the right of use asset becomes impaired. The Partnership is in the process of validating aspects of its preliminary assessment of ASU 2016-02, determining the transitional impact and completing other items required for the adoption of ASU 2016-02

In March 2016, the FASB issued Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (or ASU 2016-09). ASU 2016-09 simplifies aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 became effective for the Partnership January 1, 2017. The Partnership expects the impact of adopting this new accounting guidance will be a change in presentation of cash payments for tax withholdings on share settled equity awards from an operating cash outflow to a financing cash outflow on the Partnership's statement of cash flows.

In June 2016, the FASB issued Accounting Standards Update 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments (or ASU 2016-13). ASU 2016-13 replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for the Partnership January 1, 2020, with a modified-retrospective approach. The Partnership is currently evaluating the effect of adopting this new guidance.

In August 2016, the FASB issued Accounting Standards Update 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (or ASU 2016-15), which, among other things, provides guidance on two acceptable approaches of classifying distributions received from equity method investees in the statement of cash flows. ASU 2016-15 is effective for the Partnership January 1, 2018, with a retrospective approach. The Partnership is currently evaluating the effect of adopting this new guidance.
3.
Dropdown Predecessor

The Partnership has accounted for the acquisition of interests in vessels from Teekay Corporation as a transfer of net assets between entities under common control. The method of accounting for such transfers is similar to the pooling of interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. The excess of the proceeds paid, if any, by the Partnership over Teekay Corporation’s historical cost is accounted for as an equity distribution to Teekay Corporation. In addition, acquisition of vessels from Teekay Corporation that are businesses are accounted for as if the acquisition occurred on the date that the Partnership and the acquired vessels were both under the common control of Teekay Corporation and had begun operations. As a result, the Partnership’s financial statements prior to the date the interests in these vessels were actually acquired by the Partnership are retroactively adjusted to include the results of these vessels during the periods they were under common control of Teekay Corporation and had begun operations.


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)

Teekay Knarr AS and Knarr L.L.C. acquisition

On July 1, 2015, the Partnership acquired from Teekay Corporation, which controls the Partnership, Teekay Corporation's 100% interest in Teekay Knarr AS and Knarr L.L.C. (referred to herein as the Dropdown Predecessor). The purchase price of $529.4 million that the Partnership paid for the acquisition was based on the $1.26 billion fully built-up cost of the Petrojarl Knarr, an FPSO unit owned by the Dropdown Predecessor, and consisted of actual costs incurred for construction and mobilization of the unit less cash generated from operations between March 9, 2015 to July 1, 2015, plus $14.5 million of working capital of the Dropdown Predecessor less $745.1 million of assumed debt. The purchase price was primarily financed with a $492.0 million convertible promissory note issued to Teekay Corporation. The convertible promissory note was due in full on July 1, 2016, bearing interest at an annual rate of 6.5% on the outstanding principal balance; however, $100 million of the promissory note was refinanced on July 1, 2016, with a two-year promissory note to Teekay Corporation (see note 11j) which was subsequently assigned to a subsidiary of Teekay Corporation. The Partnership paid $35.0 million of the remaining $37.4 million of the purchase price in cash to Teekay Corporation upon the acquisition of the Dropdown Predecessor. During July 2015, $300.0 million of the convertible promissory note was converted into 14.4 million common units of the Partnership and the Partnership repaid an additional $92.0 million of the convertible promissory note. Concurrent with the conversion of the promissory note, Teekay Corporation contributed $6.1 million to the Partnership to maintain its 2% general partner interest. The Petrojarl Knarr operates on the Knarr oil and gas field in the North Sea under a six-year fixed-rate charter contract, plus extension options, with Royal Dutch Shell Plc, as the operator.

The $103.3 million excess of the purchase price over Teekay Corporation’s carrying value of the Dropdown Predecessor was accounted for as an equity distribution to Teekay Corporation. In addition, the acquisition of the Dropdown Predecessor has been accounted for as if the acquisition occurred on March 9, 2015, the date that the Partnership and the Petrojarl Knarr FPSO were both under the common control of Teekay Corporation and had begun operations.

As a result, the Partnership’s financial statements prior to the Partnership’s July 1, 2015 acquisition of the Dropdown Predecessor were retroactively adjusted to include the financial results of the Dropdown Predecessor as if the Partnership had acquired the FPSO on March 9, 2015. This had the effect of increasing the Partnership’s revenue by $69.5 million and net income by $10.1 million for the year ended December 31, 2015.

4.
Financial Instruments

a)
Fair value measurements

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

Cash and cash equivalents and restricted cash - The fair value of the Partnership’s cash and cash equivalents and restricted cash approximate their carrying amounts reported in the accompanying consolidated balance sheets.

Vessels and equipment and vessels held for sale – The estimated fair value of the Partnership’s vessels and equipment and vessels held for sale are determined based on discounted cash flows or appraised values. In cases where an active second hand sale and purchase market does not exist, the Partnership uses a discounted cash flow approach to estimate the fair value of an impaired vessel. In cases where an active second hand sale and purchase market exists, an appraised value is generally the amount the Partnership would expect to receive if it were to sell the vessel. Such appraisal is normally completed by the Partnership.

Contingent consideration liability

In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS (or Logitel), a Norway-based company focused on high-end UMS, from Cefront Technology AS (or Cefront) for $4.0 million. The Partnership paid the purchase price in cash at closing, plus a commitment to pay an additional amount of up to $27.6 million, depending on certain performance criteria. For a description of the performance criteria, please refer to the Partnership's Annual Report on Form 20-F for the year ended December 31, 2015.

During the second quarter of 2016, the Partnership canceled the UMS construction contracts for its two remaining UMS newbuildings. This is expected to eliminate any future purchase price contingent consideration payments. Consequently, the contingent liability was reversed in the second quarter of 2016. The gain associated with this reversal is included in Other (expense) income - net on the Partnership's consolidated statements of income for the year ended December 31, 2016.

Changes in the estimated fair value of the Partnership’s contingent consideration liability relating to the acquisition of Logitel, which is measured at fair value on a recurring basis using significant unobservable inputs (Level 3), during the years ended December 31, 2015 and 2014, is as follows:


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)

 
 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
 
Year Ended
December 31, 2014
$
Balance at beginning of period
 
(14,830
)
 
(21,448
)
 
—

Acquisition of Logitel
 
—

 
2,569

 
(21,170
)
Settlement of liability
 
—

 
3,540

 
—

Gain included in Other (expense) income - net
 
14,830

 
509

 
(278
)
Balance at end of period
 
—

 
(14,830
)
 
(21,448
)

Derivative instruments – The fair value of the Partnership’s derivative instruments is the estimated amount that the Partnership would receive or pay to terminate the agreements at the reporting date, taking into account current interest rates, foreign exchange rates and the current credit worthiness of both the Partnership and the derivative counterparties. The estimated amount is the present value of future cash flows. The Partnership transacts all of its derivative instruments through investment-grade rated financial institutions at the time of the transaction. The Partnership’s interest rate swap agreements and foreign currency forward contracts require no collateral from these institutions; however, collateral is required by these institutions on some of the Partnership’s cross currency swap agreements and as at December 31, 2016 the Partnership had $30.2 million held as collateral (2015 - $60.5 million), which has been recorded as restricted cash and restricted cash – long-term on the Partnerships consolidated balance sheets. Given the current volatility in the credit markets, it is reasonably possible that the amount recorded as a derivative liability could vary by a material amount in the near term.

Long-term debt – The fair value of the Partnership’s fixed-rate and variable-rate long-term debt is either based on quoted market prices or estimated using discounted cash flow analysis based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

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, 2016
 
December 31, 2015
 
 
Fair Value Hierarchy Level
 
Carrying Amount
Asset (Liability)
$
 
Fair Value Asset (Liability)
$
 
Carrying Amount
Asset (Liability)
$
 
Fair Value Asset (Liability)
$
Recurring:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents and restricted cash
 
Level 1
 
342,287


342,287


318,993


318,993

Logitel contingent consideration (see above)
 
Level 3
 
—


—


(14,830
)

(14,830
)
Derivatives instruments (note 12)
 
 
 
 
 
 
 
 
 
 
Interest rate swap agreements
 
Level 2
 
(203,106
)

(203,106
)

(235,998
)

(235,998
)
Cross currency swap agreement
 
Level 2
 
(137,379
)

(137,379
)

(183,327
)

(183,327
)
Foreign currency forward contracts
 
Level 2
 
(1,786
)

(1,786
)

(11,509
)

(11,509
)
 
 
 
 
 
 
 
 
 
 
 
Non-Recurring:
 
 
 
 
 
 
 
 
 
 
Vessels held for sale (note 19)
 
Level 2
 
6,900

 
6,900

 
55,450

 
55,450

Vessels and equipment (note 19)
 
Level 2
 
11,300

 
11,300

 
100,600

 
100,600

Other:
 
 
 
 
 
 
 
 
 
 
Long-term debt - public (note 8)
 
Level 1
 
(550,525
)

(480,710
)

(620,746
)

(473,729
)
Long-term debt - non-public (note 8)
 
Level 2
 
(2,632,369
)

(2,551,697
)

(2,743,128
)

(2,783,597
)
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- 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)

 
 
Credit Quality Indicator
 
Grade
 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
Direct financing leases
 
Payment activity
 
Performing
 
17,586

 
17,471

5.
Segment Reporting
The Partnership is engaged in the international marine transportation of crude oil, the offshore processing and storage of crude oil, long-distance ocean towage and offshore installation services, and maintenance and safety services through the operation of its shuttle and conventional tankers, FSO units, FPSO units, towage vessels and UMS. The Partnership’s revenues are earned in international markets.

The Partnership has six reportable segments: its FPSO segment; its shuttle tanker segment; its FSO segment; its UMS segment; its towage segment; and its conventional tanker segment. The Partnership’s FPSO segment consists of its FPSO units to service its FPSO contracts. The Partnership’s shuttle tanker segment consists of shuttle tankers operating primarily on fixed-rate contracts of affreightment, time-charter contracts or bareboat charter contracts. The Partnership’s FSO segment consists of its FSO units subject to fixed-rate, time-charter contracts or bareboat charter contracts. The Partnership’s UMS segment consists of one unit operating on a fixed-rate time-charter contract. The Partnership’s towage segment consists of long-distance towing and offshore installation vessels which operate on time-charter or towage contracts. The Partnership’s conventional tanker segment consists of two in-chartered conventional tankers, of which one vessel is operating on a time-charter-out contract and the other vessel is operating in the spot conventional tanker market. 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 31,2016
 
Year Ended
December 31, 2015
 
Year Ended
December 31, 2014
Royal Dutch Shell Plc (1)(2)
 
$349.0 or 30%
 
$315.3 or 26%
 
—  (6)
Petroleo Brasileiro S.A.(1)
 
$222.0 or 19%
 
$224.6 or 18%
 
$228.1 or 22%
Premier Oil (3)(4)
 
$113.5 or 10%
 
$129.2 or 11%
 
$120.2 or 12%
Statoil ASA (5)
 
—  (6)
 
$132.7 or 11%
 
$194.3 or 19%
Repsol S.A.(3)
 
—  (6)
 
—  (6)
 
$112.6 or 11%
(1)
Shuttle tanker and FPSO segments.
(2)
In February 2016, Royal Dutch Shell Plc acquired BG Group Plc, therefore the amount in the table for 2016 includes revenues from both Royal Dutch Shell Plc and BG Group Plc.
(3)
FPSO segment.
(4)
In April 2016, Premier Oil acquired E.ON's UK North Sea assets where the Voyageur Spirit FSPO operates. Revenues up to April 2016 are attributable to E.ON.
(5)
Shuttle tanker segment.
(6)
Percentage of consolidated revenue was less than 10%.

The following tables include results for the Partnership’s FPSO unit segment, shuttle tanker segment, FSO unit segment, UMS segment, towage segment and conventional tanker segment for the periods presented in these consolidated financial statements.

F- 15

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

Year ended December 31, 2016
 
FPSO Segment

Shuttle Tanker Segment

FSO Segment

UMS Segment

Towage Segment

Conventional Tanker Segment

Total
Revenues (1)
 
495,223


509,596


54,440


34,433


37,952


20,746


1,152,390

Voyage expenses
 
—


(62,846
)

(1,517
)

—


(15,024
)

(1,363
)

(80,750
)
Vessel operating expenses
 
(165,346
)

(123,950
)

(23,167
)

(32,888
)

(17,524
)

(1,566
)

(364,441
)
Time-charter hire expenses
 
—


(62,511
)

—


—


—


(12,974
)

(75,485
)
Depreciation and amortization
 
(149,198
)

(122,822
)

(9,311
)

(6,660
)

(12,020
)

—


(300,011
)
General and administrative (2)
 
(35,971
)

(10,160
)

(836
)

(5,495
)

(3,307
)

(353
)

(56,122
)
Gain on sale and (write-down) of vessels
 
—


4,554


(983
)

(43,650
)

—


—


(40,079
)
Restructuring charge
 
(4,444
)

(205
)

—


—


—


—


(4,649
)
Income (loss) from vessel operations
 
140,264


131,656


18,626


(54,260
)

(9,923
)

4,490


230,853

Equity income
 
17,933


—


—


—


—


—


17,933

Investment in joint ventures
 
141,819


—


—


—


—


—


141,819

Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs
 
66,234


40,584


101,347


9,742


76,674


—


294,581

Expenditures for dry docking
 
—


19,105


5,139


—


799


—

25,043

Year ended December 31, 2015
 
FPSO Segment

Shuttle Tanker Segment

FSO Segment

UMS Segment

Towage Segment

Conventional Tanker Segment
 
Total
Revenues (1)
 
531,554


541,792


57,391


28,334


40,112


30,230


1,229,413

Voyage expenses
 
—


(82,777
)

(851
)

—


(12,052
)

(2,326
)

(98,006
)
Vessel operating expenses
 
(189,900
)

(128,156
)

(26,394
)

(13,876
)

(13,920
)

(6,234
)

(378,480
)
Time-charter hire expenses
 
—


(51,088
)

—


—


(662
)

—


(51,750
)
Depreciation and amortization
 
(137,914
)

(106,190
)

(11,775
)

(3,775
)

(8,362
)

(6,583
)

(274,599
)
General and administrative (2)(3)
 
(38,588
)

(22,884
)

(1,372
)

(4,109
)

(4,598
)

(1,062
)

(72,613
)
(Write-down) and gain on sale of vessels
 
—


(65,101
)

—


(1,000
)

—


(3,897
)

(69,998
)
Restructuring charge
 
—


(568
)

—


—


—


—


(568
)
Income from vessel operations
 
165,152


85,028


16,999


5,574


518


10,128


283,399

Equity income
 
7,672


—


—


—


—


—


7,672

Investment in joint ventures
 
77,647


—


—


—


—


—


77,647

Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs (4)
 
116,473


26,980


94,317


183,364


243,436


97


664,667

Expenditures for dry docking
 
—


14,609


—


—


—


—


14,609


Year ended December 31, 2014
 
FPSO Segment

Shuttle Tanker Segment

FSO Segment

UMS Segment

Towage Segment

Conventional Tanker Segment

Total
Revenues
 
354,518


577,064


53,868


—


523


33,566


1,019,539

Voyage expenses
 
—


(105,562
)

(1,500
)

—


(105
)

(5,373
)

(112,540
)
Vessel operating expenses
 
(158,216
)

(159,438
)

(28,649
)

—


—


(5,906
)

(352,209
)
Time-charter hire expenses
 
—


(31,090
)

—


—


—


—


(31,090
)
Depreciation and amortization
 
(72,905
)

(110,686
)

(8,282
)

—


—


(6,680
)

(198,553
)
General and administrative (2)(3)
 
(27,406
)

(29,154
)

(3,870
)

(622
)

(4,328
)

(2,136
)

(67,516
)
(Write-down) and gain on sale of vessels
 
—


(1,638
)

—


—


—


—


(1,638
)
Restructuring recovery
 
—


225


—


—


—


—


225

Income (loss) from vessel operations (5)
 
95,991


139,721


11,567


(622
)

(3,910
)

13,471


256,218

Equity income
 
10,341


—


—


—


—


—


10,341

Investment in joint ventures
 
54,955


—


—


—


—


—


54,955

Expenditures for vessels and equipment, including advances on newbuilding contracts and conversion costs (6)
 
17,022


50,096


33,734


11,550


59,516


251


172,169

Expenditures for dry docking
 
—


22,552


11,560


—


—


2,109


36,221


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)

(1)
Revenues for the year ended December 31, 2016, includes a $4.0 million early termination fee received from Teekay Corporation during 2016, which is included in the Partnership's conventional tanker segment (see notes 11i and 19).
Revenues for the year ended December 31, 2015, includes $1.8 million net early termination fees paid to Teekay Corporation during 2015, which is included in the Partnership's conventional tanker segment (see notes 11i and 19).
(2)
Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to each segment based on estimated use of corporate resources).
(3)
General and administrative expenses for the year ended December 31, 2015 includes business development fees of $9.7 million, $2.2 million and $2.0 million to Teekay Corporation in connection with the acquisition of the Petrojarl Knarr FPSO unit in the FPSO segment, six long-distance towing and offshore installation vessels in the towage segment, and the Arendal Spirit UMS in the UMS segment, respectively (see notes 3 and 11l).
General and administrative expenses for the year ended December 31, 2014 includes a $1.0 million fee to a third party associated with the acquisition of ALP Maritime Services B.V. (or ALP), a $1.6 million business development fee to Teekay Corporation for assistance with the acquisition of ALP, both of which fees have been allocated to the Partnership’s towage segment, and also includes a $2.1 million fee to Teekay Corporation for assistance with securing a charter contract for the Petrojarl I FPSO unit (or Petrojarl I), which fee has been allocated to the Partnership’s FPSO segment (see notes 11l and 18a).
(4)
Excludes the purchase price of the Petrojarl Knarr FPSO unit (see note 3).
(5)
Income from vessel operations for the year ended December 31, 2014 excludes $3.1 million of the Voyageur Spirit FPSO unit indemnification payments received from Teekay Corporation relating to the production shortfall during the period from January 1, 2014 through February 21, 2014 and a further $0.4 million relating to unreimbursed vessel operating expenses incurred before the unit was declared on-hire as of February 22, 2014.
These indemnification payments received from Teekay Corporation have effectively been treated as a reduction to the purchase price of the Voyageur Spirit (see note 11c).
(6)
Excludes the vessel and equipment acquired in conjunction with the purchase of Logitel (note 18b) and the Petrojarl I (note 11f).

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

 
 
December 31, 2016
$
 
December 31, 2015
$
FPSO segment
 
2,672,100

 
2,717,193

Shuttle tanker segment
 
1,673,348

 
1,732,769

FSO segment
 
407,634

 
281,776

UMS segment
 
213,829

 
267,935

Towage segment
 
382,973

 
309,009

Conventional tanker segment
 
4,818

 
63,900

Unallocated:
 


 


Cash and cash equivalents and restricted cash
 
342,287

 
318,993

Other assets
 
21,631

 
52,591

Consolidated total assets
 
5,718,620


5,744,166

6.
Goodwill and In-Process Revenue Contracts

a)
Goodwill

The carrying amount of goodwill for the shuttle tanker segment was $127.1 million as at December 31, 2016 and 2015. In 2016, 2015 and 2014, the Partnership conducted its annual goodwill impairment review of its shuttle tanker segment and concluded that no impairment had occurred.

The carrying amount of goodwill for the towage segment was $2.0 million as at December 31, 2016 and 2015. In 2016, 2015 and 2014, the Partnership conducted its annual goodwill impairment review of its towage segment and concluded that no impairment had occurred.

b)
In-Process Revenue Contracts

As part of the Partnership’s acquisition of the Piranema Spirit 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, 2016, 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, 2016 was $12.8 million (2015 - $12.7 million, 2014 - $12.7 million), which is included in revenues on the consolidated statements of income. Amortization for the five years subsequent to December 31, 2016 is expected to be $12.7 million (2017), $9.1 million (2018), $7.8 million (2019), $7.9 million (2020), $7.9 million (2021), and $17.7 million (thereafter).


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)

7.
Accrued Liabilities
 
 
December 31, 2016
$
 
December 31, 2015
$
Voyage and vessel expenses
 
32,596

 
37,730

Audit, legal, contingency and other general expenses
 
81,999

 
17,058

Interest including interest rate swaps
 
22,414

 
23,185

Payroll and benefits
 
9,270

 
8,731

Income tax payable and other
 
4,002

 
4,361

 
 
150,281

 
91,065

8.Long-Term Debt
 
December 31, 2016
$
 
December 31, 2015
$
U.S. Dollar-denominated Revolving Credit Facilities due through 2019
291,764

 
429,279

Norwegian Kroner Bonds due through 2019
256,927

 
327,941

U.S. Dollar-denominated Term Loans due through 2018
112,406

 
129,133

U.S. Dollar-denominated Term Loans due through 2028
2,109,926

 
2,037,766

U.S. Dollar Non-Public Bonds due through 2024
166,680

 
202,449

U.S. Dollar Bonds due 2019
300,000

 
300,000

Total principal
3,237,703

 
3,426,568

Less debt issuance costs and other
(54,809
)
 
(62,694
)
Total debt
3,182,894

 
3,363,874

Less current portion
(586,892
)
 
(485,069
)
Long-term portion
2,596,002


2,878,805


As at December 31, 2016, the Partnership had five revolving credit facilities, which, as at such date, provided for borrowings of up to $325.1 million (2015 - $453.5 million), of which $33.3 million (2015 - $24.2 million) was undrawn. The total amount available under the revolving credit facilities reduces by $166.7 million (2017), $115.4 million (2018) and $43.0 million (2019). Four of the revolving credit facilities are guaranteed by the Partnership and certain of its subsidiaries for all outstanding amounts and contain covenants that require the Partnership to maintain a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) in an amount equal to the greater of $75.0 million and 5.0% of the Partnership’s total consolidated debt. One revolving credit facility is guaranteed by Teekay Corporation and contains a covenant that requires Teekay Corporation to maintain minimum liquidity (cash and cash equivalents) in an amount equal to the greater of $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 21 of the Partnership’s vessels, together with other related security. The Partnership has guaranteed $309.4 million of these revolvers, of which $276.1 million was drawn as at December 31, 2016, and Teekay Corporation has guaranteed $15.7 million which was fully drawn as at December 31, 2016.

As at December 31, 2016, the Partnership had Norwegian Kroner (or NOK) 1,000 million outstanding in senior unsecured bonds that mature in January 2019 in the Norwegian bond market. As of December 31, 2016, the carrying amount of the bonds was $115.7 million. The bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 4.25%. During the year ended December 31, 2016, the Partnership amended its existing cross currency rate swaps to swap all interest and principal payments into U.S. Dollars, with the interest payments at a fixed rate of 7.45%, and the transfer of the principal amount fixed at $162.2 million upon maturity in exchange for NOK 1,000 million (see note 12).

As at December 31, 2016, the Partnership had NOK 800 million outstanding in senior unsecured bonds in the Norwegian bond market. The bonds were originally issued in two tranches, of which one matured and was paid in January 2016 (NOK 500 million) and the remaining tranche which was originally scheduled to mature in January 2018 (NOK 800 million). In June 2016, the terms of the remaining tranche were amended such that NOK 160 million is now repayable in January 2018 with the remaining balance of NOK 640 million repayable in December 2018 at 103% of the amount outstanding. In addition, the Partnership was granted an option, exercisable at any time, to prepay the bonds in amounts ranging from 101% to 103% of the amount of bonds outstanding depending on the timing of settlement. The bonds are listed on the Oslo Stock Exchange. Interest payments previously were based on NIBOR plus a margin of 4.75%; however, under the June 2016 amended bond agreement, interest payments have increased to NIBOR plus a margin of 5.75%. As at December 31, 2016, the carrying amount of the bonds was $92.6 million. The Partnership also amended its existing cross currency rate swaps to swap all interest and principal payments into U.S. Dollars, with interest payments fixed at a rate of 7.58% and the transfer of the principal amount fixed at $28.7 million in exchange for NOK 160 million on the tranche maturing in January 2018 and $118.3 million in exchange for NOK 659 million on the tranche maturing in December 2018 (see note 12). The Partnership recorded a $32.6 million realized foreign currency exchange gain on the payment of the NOK 500 million tranche that matured in January 2016 and a corresponding $32.6 million realized loss on the maturing cross currency swap, both

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)

of which are included in foreign currency exchange loss on the Partnership’s consolidated statement of income for the year ended December 31, 2016.

As at December 31, 2016, the Partnership had NOK 420 million in senior unsecured bonds in the Norwegian bond market. These bonds were originally issued in a single tranche of NOK 600 million and were originally scheduled to mature in January 2017. In June 2016, the terms of these bonds were amended such that NOK 180 million was repaid in October 2016, NOK 180 million is repayable in October 2017 and NOK 240 million is repayable in November 2018 at 103% of the amount outstanding. In addition, the Partnership was granted an option, exercisable at any time, to prepay the bonds in amounts ranging from 101% to 103% of the amount of bonds outstanding depending on the timing of settlement. 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%. As at December 31, 2016, the carrying amount of the bonds was $48.6 million. The Partnership also amended its existing cross currency rate swap to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 8.84%. A portion of the swap related to the transfer of the principal amount fixed at $30.4 million in exchange for NOK 180 million on the tranche matured in October 2016, consistent with the terms of the amended debt. The remaining transfers of principal relate to the $30.4 million in exchange for NOK 180 million on the tranche maturing in October 2017 and $41.8 million in exchange for NOK 247 million on the tranche maturing in November 2018 (see note 12). The Partnership recorded a $8.6 million realized foreign currency exchange gain on the payment of the NOK 180 million tranche that matured in October 2016 and a corresponding $8.6 million realized loss on the maturing cross currency swap, both of which are included in foreign currency exchange loss on the Partnership’s consolidated statement of income for the year ended December 31, 2016.

As at December 31, 2016, three of the Partnership’s 50% owned subsidiaries each had an outstanding term loan, which in the aggregate totaled $112.4 million. These term loans reduce over time with quarterly and semi-annual payments and have varying maturities through 2018. These term loans are collateralized by first-priority mortgages on the three shuttle tankers to which the loans relate, together with other related security. As at December 31, 2016, the Partnership had guaranteed $25.8 million of these term loans, which represents its 50% share of the outstanding term loans of two of its 50%-owned subsidiaries. The other owner and Teekay Corporation have guaranteed $56.2 million and $30.4 million, respectively.

As at December 31, 2016, the Partnership had term loans outstanding for six shuttle tankers, for three East Coast of Canada shuttle tanker newbuildings, for the Suksan Salamander and Gina Krog FSO units, for four FPSO units, for ten towing and offshore installation vessels and vessel newbuildings, and for the Arendal Spirit UMS, which totaled $2.1 billion in the aggregate. For the term loan for two shuttle tankers, one tranche reduces in semi-annual payments while another tranche correspondingly is drawn up every six months with final bullet payments of $29.0 million due in 2022 and $29.1 million due in 2023, respectively. The other term loans reduce over time with quarterly or semi-annual payments. These term loans have varying maturities through 2028 and are collateralized by first-priority mortgages on the vessels to which the loans relate, together with other related security. As at December 31, 2016, the Partnership had guaranteed $1.8 billion of these term loans and Teekay Corporation had guaranteed $317.9 million.

In February 2015, the Partnership issued $30.0 million in senior bonds that mature in June 2024 in a U.S. private placement. As of December 31, 2016, the carrying amount of the bonds was $23.4 million. The interest payments on the bonds are fixed at a rate of 4.27%. The bonds are collateralized by first-priority mortgage on the Dampier Spirit FSO unit, together with other related security, and are guaranteed by the Partnership.

In September 2013 and November 2013, the Partnership issued, in a U.S. private placement, an aggregate of $174.2 million of ten-year senior bonds that mature in December 2023, to finance the Bossa Nova Spirit and the Sertanejo Spirit shuttle tankers. The bonds accrue interest at a fixed combined rate of 4.96%. The bonds are collateralized by first-priority mortgages on the two vessels to which the bonds relate, together with other related security. The Partnership makes semi-annual repayments on the bonds and as at December 31, 2016, the carrying amount of the bonds was $143.3 million.

In May 2014, the Partnership issued $300.0 million five-year senior unsecured bonds that mature in July 2019 in the U.S. bond market. As at December 31, 2016, the carrying amount of the bonds was $300.0 million. The bonds are listed on the New York Stock Exchange. The interest payments on the bonds are fixed at a rate of 6.00%.

Interest payments on the revolving credit facilities and the term loans are based on LIBOR plus margins, except for $58.3 million of one tranche of the term loan for the ALP newbuilding towing and offshore installation vessels, which is fixed at 2.93%. At December 31, 2016 and December 31, 2015, the margins ranged between 0.30% and 4.00%, and 0.30% and 3.25%, respectively. The weighted-average effective interest rate on the Partnership’s variable rate long-term debt as at December 31, 2016 was 3.3% (December 31, 2015 – 2.9%). This rate does not include the effect of the Partnership’s interest rate swaps (see note 12) or fixed rate facilities.

The aggregate annual long-term debt principal repayments required to be made subsequent to December 31, 2016, including the impact of the debt refinancing completed in March 2017, are $588.7 million (2017), $686.5 million (2018), $773.4 million (2019), $283.1 million (2020), $234.9 million (2021), and $671.1 million (thereafter).

As at December 31, 2016, the Partnership had $20 million held as security for a contractual requirement with the charterer of the Petrojarl Knarr FPSO unit. The amount is presented in Restricted cash on the consolidated balance sheets.

Obligations under the Partnership’s credit facilities are secured by certain vessels, and if the Partnership is unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets. The Partnership has two revolving credit facilities and five term loans that require the Partnership to maintain vessel values to drawn principal balance ratios of a minimum range of 113% to 125%. Such requirement is assessed either on a semi-annual or annual basis, with reference to vessel valuations performed by one or more agreed-upon third parties.

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)

Should the ratio drop below the required amount, the lender may request the Partnership to either prepay a portion of the loan in the amount of the shortfall or provide additional collateral in the amount of the shortfall, at the Partnership's option. As at December 31, 2016, these ratios were estimated to range from 120% to 433% and were in compliance with the minimum ratios required. The vessel values used in these ratios are the appraised values prepared by the Partnership based on second-hand sale and purchase market data. Changes in the shuttle tanker, towing and offshore installation, UMS, FPSO or FSO markets could negatively affect these ratios.

Please read Item 5. Operating and Financial Review and Prospects Management’s Discussion and Analysis of Financial Conditions and Results of Operations - Liquidity and Capital Resources - Liquidity and Capital Needs for a description of certain covenants contained in the Partnership’s credit facilities and loan agreements. As at December 31, 2016 the Partnership and Teekay Corporation were in compliance with all covenants in the credit facilities and long-term debt.
9.
Leases

Charters-out

The cost, accumulated depreciation and carrying amount of the Partnership's vessels with charter-out contracts accounted for as operating leases at December 31, 2016 were $4.3 billion, $1.0 billion and $3.3 billion, respectively. As at December 31, 2016, minimum scheduled future revenues under these then-in-place time charters and bareboat charters to be received by the Partnership, were approximately $4.2 billion, comprised of $810.5 million (2017), $754.7 million (2018), $608.9 million (2019), $541.4 million (2020), $341.8 million (2021), and $1.2 billion (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, 2016, revenue from unexercised option periods of contracts that existed on December 31, 2016, or variable or contingent revenues. 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, 2016, the minimum lease payments receivable under the direct financing leases approximated $8.4 million (2015 - $nil), including unearned income of $2.4 million. As at December 31, 2016, future scheduled payments under the direct financing leases to be received by the Partnership, were approximately $8.4 million comprised of $1.3 million (2017), $1.3 million (2018), $1.3 million (2019), $1.3 million (2020), $1.3 million (2021) and $1.9 million (thereafter).

Leasing of the Falcon Spirit FSO unit is accounted for as direct financing leases. As at December 31, 2016, the minimum lease payments receivable under the direct financing lease approximated $3.8 million (2015 - $12.6 million), including unearned income of $0.8 million (2015 - $3.6 million). The estimated unguaranteed residual value of the leased vessel is $8.5 million. As at December 31, 2016, the future scheduled payments under the direct financing lease to be received by the Partnership in 2017 were approximately $3.8 million.

Charters-in

As at December 31, 2016, minimum commitments owing by the Partnership under vessel operating leases by which the Partnership charters-in vessels were approximately $69.7 million (2017), $35.4 million (2018) and $17.2 million (2019). The Partnership recognizes the expense from these charters, which is included in time-charter hire expense, on a straight-line basis over the firm period of the charters.
10.
Restructuring Charge

During the year ended December 31, 2016, the Partnership recognized a restructuring charge of $4.6 million, mainly relating to the reorganization of the Partnership’s FPSO business to create better alignment with the Partnership’s offshore operations, resulting in a lower cost organization going forward. The Partnership expects to incur a total of $4.7 million of restructuring charges under this plan and the reorganization is expected to be completed in early-2017.

As at December 31, 2016, restructuring liabilities of $3.7 million were recorded in accrued liabilities on the consolidated balance sheet.
11.
Related Party Transactions and Balances

a)
The Partnership has entered into an omnibus agreement with Teekay Corporation, Teekay LNG Partners L.P., the general partner and others governing, among other things, when the Partnership, Teekay Corporation and Teekay LNG Partners L.P. may compete with each other and certain rights of first offering on liquefied natural gas carriers, conventional tankers, shuttle tankers, FSO units and FPSO units.

b)
In May 2013, the Partnership entered into an agreement with Statoil ASA (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 is being converted from the Randgrid shuttle tanker, which commenced its conversion during the second quarter of 2015. The Partnership has received project management and engineering services from certain subsidiaries of Teekay Corporation relating to this FSO unit conversion. These costs are capitalized and included as part of advances on newbuilding contracts and conversion costs and will be

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)

reclassified to vessels and equipment upon completion of the conversion in mid-2017. Project management and engineering costs paid to Teekay Corporation subsidiaries amounted to $13.8 million as of December 31, 2016.

c)
On May 2, 2013, the Partnership acquired from Teekay Corporation its 100% interest in Voyageur L.L.C., which owns the Voyageur Spirit FPSO unit. During 2014, Teekay Corporation indemnified the Partnership for $3.5 million for production shortfalls and unrecovered repair costs to address a defect on one of the unit's compressor, discovered upon acquisition of the unit and paid another $2.7 million in late-2014 relating to a final settlement of pre-acquisition capital expenditures for the Voyageur Spirit FPSO unit.

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.

d)
On June 10, 2013, the Partnership acquired Teekay Corporation’s 50% interest in OOG-TKP FPSO GmbH & Co KG, a joint venture with Odebrecht Oil & Gas S.A (or OOG), which owns the Cidade de Itajai (or Itajai) FPSO unit, for a cash purchase price of $53.8 million. The Partnership’s investment in the Itajai FPSO unit is accounted for using the equity method.

The purchase price was based on an estimate of the fully built-up cost of the Itajai FPSO unit, including certain outstanding contractual items. During 2014, the joint venture received in connection with the resolution of these contractual items an aggregate of $6.1 million in reimbursements from the charterer and insurer, which was originally deducted from the Partnership’s purchase price of the Itajai FPSO unit. Accordingly, the Partnership remitted this reimbursed amount to Teekay Corporation.

e)
In 2014, the long-term bareboat contracts relating to two of the Partnership’s former conventional tankers, the SPT Explorer and Navigator Spirit, with a joint venture in which Teekay Corporation had a 50% interest, were novated under the same terms to a subsidiary of Teekay Corporation in January 2014 and March 2014, respectively. The excess of the contractual rates over the market rates at the time of the novations were $0.9 million and $1.0 million for the years ended December 31, 2015 and 2014, respectively, and is accounted for as an equity contribution from Teekay Corporation.

In December 2015, the Partnership terminated the long-term bareboat contracts for these two conventional tankers (see notes 11i and 19). Immediately following the contract terminations, the Partnership sold its 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd.

f)
In December 2014, the Partnership entered into an agreement with a consortium led by Queiroz Galvão Exploração e Produção SA (or QGEP) to provide an FPSO unit for the Atlanta field located in the Santos Basin offshore Brazil. In connection with the contract with QGEP, the Partnership acquired the Petrojarl I FPSO from Teekay Corporation for a purchase price of $57 million (see note 14e). The purchase price was financed by means of an intercompany loan payable to a subsidiary of Teekay Corporation, which was repaid in July 2015. Interest payments on the loan were at a fixed rate of 6.5%. The excess of the purchase price over Teekay Corporation’s carrying value of the Petrojarl I FPSO unit has been accounted for as an equity distribution to Teekay Corporation of $12.4 million in 2014. The Partnership has received project management and engineering services from certain subsidiaries of Teekay Corporation relating to this FPSO unit upgrade. These costs are capitalized and included as part of advances on newbuilding contracts and conversion costs and will be reclassified to vessels and equipment upon completion of the upgrades in late-2017. Project management and engineering costs paid to Teekay Corporation subsidiaries amounted to $2.8 million as of December 31, 2016.

g)
In June 2015, the Partnership entered into 15-year contracts, plus extension options, with a group of oil companies to provide shuttle tanker services for oil production on the East Coast of Canada. The Partnership has entered into contracts to construct three Suezmax DP2 shuttle tanker newbuildings. These vessels will replace the existing vessels servicing the East Coast of Canada. The three newbuildings are expected to be delivered in late-2017 through the first half of 2018 (see note 14f). The Partnership has received project management and engineering services from certain subsidiaries of Teekay Corporation relating to the construction of these shuttle tankers. These costs are capitalized and included as part of advances on newbuilding contracts and conversion costs and will be reclassified to vessels and equipment upon delivery of the vessels in late-2017 through the first half of 2018. Project management and engineering costs paid to Teekay Corporation subsidiaries amounted to $2.2 million as of December 31, 2016.

h)
On July 1, 2015, the Partnership acquired from Teekay Corporation its 100% interest in the Dropdown Predecessor, which own the Petrojarl Knarr FPSO unit, which operates on the Knarr Field in the North Sea, for an equity purchase price of $529.4 million (see note 3).

i)
During 2016, one conventional tanker, two shuttle tankers and three FSO units of the Partnership were employed on long-term time-charter-out or bareboat contracts with subsidiaries of Teekay Corporation. In 2016, the Partnership terminated the long-term time-charter-out contract under which the one conventional tanker was employed with a subsidiary of Teekay Corporation. The Partnership concurrently received an early termination fee from Teekay Corporation of $4.0 million (see note 19), which is recorded in revenues on the consolidated statement of income for the year ended December 31, 2016.

In 2015, the Partnership terminated the long-term bareboat and time-charter-out contracts under which three conventional tankers were employed with a subsidiary of Teekay Corporation. The Partnership concurrently paid total net early termination fees to Teekay Corporation of $1.8 million (see note 19), which is recorded in revenues on the consolidated statements of income.

j)
Effective July 1, 2016, the Partnership issued a $200.0 million subordinated promissory note to a subsidiary of Teekay Corporation, to refinance the $100.0 million outstanding balance on the convertible promissory note in connection with the financing of the Dropdown Predecessor (see k(6) below) and the $100.0 million six-month loan issued by Teekay Corporation to the Partnership in January 2016

F- 21

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

(see k(7) below), both due July 1, 2016. The subordinated promissory note bears interest at an annual rate of 10.00% on the outstanding principal balance, which is payable quarterly and, of which (a) 5.00% is payable in cash and (b) 5.00% is payable in common units of the Partnership, or in cash, at the election of Teekay Corporation. If the Partnership pays cash for such second 5.00% of interest, the Partnership must raise at least an equal amount of cash proceeds from the issuance of common units in advance of or within six months following the applicable interest payment date. The outstanding principal balance of the subordinated promissory note, together with accrued interest, is payable in full on January 1, 2019. During the year ended December 31, 2016, the Partnership incurred $10.0 million of interest expense, of which $7.5 million was paid in cash and $2.5 million was settled through the issuance of 0.5 million common units of the Partnership under the terms of the subordinated promissory note.

k)
In June 2016, as part of various other financing initiatives, Teekay Corporation agreed to provide financial guarantees for the Partnership's liabilities associated with the long-term debt financing relating to the East Coast of Canada newbuilding shuttle tankers until their deliveries, which are expected to be in the third quarter of 2017 through the first half of 2018 (see note 14f), and for certain of the Partnerships interest rate swaps and cross currency swaps until early-2019. The guarantees cover liabilities totaling up to a maximum amount of $495.0 million. During the year ended December 31, 2016, a guarantee fee of $3.7 million was recognized in interest expense on the Partnership's consolidated statements of income, which represents the estimated fee a third party would charge to provide such financial guarantees. The guarantee fee was accounted for as an equity contribution by Teekay Corporation in the Partnership's consolidated statement of changes in total equity as Teekay Corporation has provided such financial guarantees at no cost to the Partnership.

l)
Teekay Corporation and its wholly-owned subsidiaries directly and indirectly provide substantially all of the Partnership’s commercial, technical, crew training, strategic, business development and administrative service needs. In addition, the Partnership reimburses the general partner for expenses incurred by the general partner that are necessary or appropriate for the conduct of the Partnership’s business. Such related party transactions were as follows for the periods indicated:
 
Year Ended December 31,
 
2016
$
 
2015
$
 
2014
$
Revenues (1)
49,228

 
68,734

 
68,172

Vessel operating expenses (2)
(34,629
)
 
(39,779
)
 
(39,237
)
General and administrative (3)(4)
(29,944
)
 
(52,257
)
 
(42,396
)
Interest expense (5)(6)(7)(8)
(22,400
)
 
(5,556
)
 
(933
)
(1)
Includes revenues from time-charter-out or bareboat contracts with subsidiaries or affiliates of Teekay Corporation, including management fees from ship management services provided by the Partnership to a subsidiary of Teekay Corporation, and net early termination fees paid or received by the Partnership to or from Teekay Corporation (see above and note 19).

(2)
Includes ship management and crew training services provided by Teekay Corporation.

(3)
Includes commercial, technical, strategic, business development and administrative management fees charged by Teekay Corporation and reimbursements to Teekay Corporation and the Partnership’s general partner for costs incurred on the Partnership’s behalf.

(4)
Includes business development fees of $9.7 million, $2.2 million and $2.0 million to Teekay Corporation in connection with the acquisition of the Petrojarl Knarr FPSO unit, six long-distance towing and offshore installation vessels, and the Arendal Spirit UMS, respectively, during the year ended December 31, 2015 and business development fees of $1.6 million and $2.1 million to Teekay Corporation in connection with the acquisition of ALP and the Petrojarl I FPSO unit, respectively, during the year ended December 31, 2014.

(5)
Includes a guarantee fee related to the final bullet payment of the Piranema Spirit FPSO debt facility and for the Partnership's liabilities associated with the long-term debt financing relating to the East Coast of Canada shuttle tanker newbuildings and certain of the Partnerships interest rate swaps and cross currency swaps (see note 11k).

(6)
Includes interest expense of $3.2 million for the year ended December 31, 2016, incurred on the convertible promissory note issued to Teekay Corporation in connection with the financing of the acquisition of the Dropdown Predecessor (see note 3) bearing interest at an annual rate of 6.50% on the outstanding principal balance.The outstanding principal balance of $100 million, together with accrued interest, was payable in full on July 1, 2016; however, this convertible promissory note was refinanced on July 1, 2016 (see note 11j). The outstanding principal balance of this convertible promissory note was $nil as at December 31, 2016.

(7)
Includes interest expense of $5.0 million for the year ended December 31, 2016, incurred on a $100.0 million six-month loan made by Teekay Corporation to the Partnership on January 1, 2016, bearing interest at an annual rate of 10.00% on the outstanding principal balance. The outstanding principal balance, together with accrued interest, was payable in full on July 1, 2016; however, this loan was refinanced on July 1, 2016 (see note 11j). The outstanding principal balance of this loan was $nil as at December 31, 2016.

(8)
Includes interest expense of $10.0 million for the year ended December 31, 2016, incurred on a $200.0 million subordinated promissory note issued to a subsidiary of Teekay Corporation effective July 1, 2016 (see note 11j). The subordinated promissory note bears interest at an annual rate of 10.00% on the outstanding principal balance, which as at December 31, 2016, was $200.0 million. The outstanding principal balance, together with accrued interest, is payable in full on January 1, 2019.

m)
At December 31, 2016, due from affiliates totaled $77.8 million (December 31, 2015 - $81.3 million) and due to affiliates totaled $296.6 million (December 31, 2015 - $304.6 million). Amounts due to and from affiliates, other than the $200.0 million promissory note issued to a subsidiary of Teekay Corporation (see 11j), are non-interest bearing and unsecured, and all current due to and from affiliates balances are expected to be settled within the next fiscal year in the normal course of operations or from financings.


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)






12.
Derivative Instruments

The Partnership uses derivatives to manage certain risks in accordance with its overall risk management policies.

Foreign Exchange Risk

The Partnership economically hedges portions of its forecasted expenditures denominated in foreign currencies with foreign currency forward contracts. The Partnership has not designated, for accounting purposes, any of the foreign currency forward contracts held during the years ended December 31, 2016 and 2015, as cash flow hedges.

As at December 31, 2016, 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
2017
 
2018
(in thousands of U.S. Dollars)
Norwegian Kroner
390,000

 
(1,482
)
 
8.35

 
38,859

 
7,829

Euro
13,750

 
(304
)
 
0.92

 
14,879

 
—

 
 
 
(1,786
)
 
 
 
53,738

 
7,829

(1)
Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy.

In connection with its issuance of NOK bonds, the Partnership has entered into cross currency swaps pursuant to which it receives the principal amount in NOK on the repayment and maturity dates, in exchange for payments of a fixed U.S. Dollar amounts. 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 repayments of principal at maturity of the Partnership’s NOK bonds due from 2018 to 2019 (see note 8). In addition, the cross currency swaps economically hedge the interest rate exposure on the NOK bonds. The Partnership has not designated, for accounting purposes, these cross currency swaps as cash flow hedges of its NOK bonds. As at December 31, 2016, the Partnership was committed to the following cross currency swaps:

Principal
Amount
NOK(thousands)
 
Principal
Amount
USD(thousands)
 
Floating Rate Receivable
 
Fixed Rate
Payable
 
Fair Value /
Asset
(Liability)
 
Remaining
Term (years)
Reference
Rate
 
Margin
 
420,000 (1)(2)

 
70,946

 
NIBOR
 
5.75
%
 
8.84
%
 
(25,821
)
 
1.9
800,000 (1)(3)

 
143,536

 
NIBOR
 
5.75
%
 
7.58
%
 
(56,272
)
 
2.0
1,000,000

 
162,200

 
NIBOR
 
4.25
%
 
7.45
%
 
(55,286
)
 
2.1
 
 
 
 
 
 
 
 
 
 
(137,379
)
 
 
(1)
Notional amount reduces equally with NOK bond repayments (see note 8).
(2)
Excludes an economic hedge on the foreign currency exposure for a three percent premium upon maturity of the NOK bonds which exchanges NOK 7.2 million for $1.2 million (see note 8).
(3)
Excludes an economic hedge on the foreign currency exposure for a three percent premium upon maturity of the NOK bonds which exchanges NOK 19.2 million for $3.4 million (see note 8).

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. Certain of these interest rate swaps are designated and accounted for as hedges in the consolidated financial statements or within our equity-accounted for investments.

As at December 31, 2016, the Partnership was committed to the following interest rate swap agreements:


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)

 
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
 
600,000

 
(151,049
)
 
7.9
 
5.0
%
U.S. Dollar-denominated interest rate swaps(3)
LIBOR
 
1,374,967

 
(52,057
)
 
4.9
 
2.6
%
 
 
 
1,974,967

 
(203,106
)
 
 
 
 
(1)
Excludes the margin the Partnership pays on its variable-rate debt, which as at December 31, 2016, ranged from 0.30% to 4.00%.
(2)
Notional amount remains constant over the term of the swap.
(3)
Principal amount reduces quarterly or semi-annually.

For the periods indicated, the following table presents the effective and ineffective portion of (losses) gains on interest rate swap agreements designated and qualifying as cash flow hedges. The following table excludes any interest rate swap agreements designated and qualifying as cash flow hedges in the Partnership's equity accounted joint ventures.

Year Ended December 31, 2016
 
Year Ended December 31, 2015
Effective Portion Recognized in AOCI (1)
 
Effective Portion Reclassified from AOCI (2)
 
Ineffective Portion (3)
 
 
 
Effective Portion Recognized in AOCI (1)
  
Effective Portion Reclassified from AOCI (2)
 
Ineffective Portion (3)
 
101

 
(64
)
 
681

 
Interest expense
 
(65
)
  
—

  
(1,050
)
Interest expense
101

 
(64
)
 
681

 
 
 
(65
)
  
—

  
(1,050
)
 
Year Ended December 31, 2014
 
 
 
 
 
 
 
Effective Portion Recognized in AOCI (1)
 
Effective Portion Reclassified from AOCI (2)
 
Ineffective Portion (3)
 
 
 
 
 
 
 
 
 
—

 
—

 
—

 

 
 
 
 
 
 
 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
(1)
Effective portion of designated and qualifying cash flow hedges recognized in accumulated other comprehensive income (or AOCI).
(2)
Effective portion of designated and qualifying cash flow hedges recorded in AOCI during the term of the hedging relationship and reclassified to earnings.
(3)
Ineffective portion of designated and qualifying cash flow hedges.

As at December 31, 2016, the Partnership had multiple interest rate swaps, cross currency swaps and foreign currency forward contracts 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 derivative. The fair value of these derivatives are presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, 2016, these derivatives had an aggregate fair value asset amount of $0.1 million and an aggregate fair value liability amount of $216.7 million (December 31, 2015 - an aggregate fair value asset amount of $nil and an aggregate fair value liability amount of $360.6 million). As at December 31, 2016, the Partnership had $30.2 million on deposit with the relevant counterparties as security for cross currency swap liabilities under certain master agreements (December 31, 2015 - $60.5 million). The deposit is presented in Restricted cash and Restricted cash - long-term on the consolidated balance sheets.

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.


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)

 
Other
current
assets
$
 
Other
assets
$
 
Accrued
liabilities
$
 
Current
portion of
derivative
liabilities
$
 
Derivative
liabilities
$
As at December 31, 2016
 
 
 
 
 
 
 
 
 
Foreign currency contracts
119

 
—

 
—

 
(1,634
)
 
(271
)
Cross currency swaps
—

 
—

 
(2,375
)
 
(20,281
)
 
(114,723
)
Interest rate swaps
181

 
2,597

 
(5,653
)
 
(33,087
)
 
(167,144
)
 
300

 
2,597

 
(8,028
)
 
(55,002
)
 
(282,138
)
As at December 31, 2015
 
 
 
 
 
 
 
 
 
Foreign currency contracts
80

 
—

 
—

 
(10,266
)
 
(1,323
)
Cross currency swaps
—

 
—

 
(2,196
)
 
(42,878
)
 
(138,253
)
Interest rate swaps
—

 
1,894

 
(7,827
)
 
(148,312
)
 
(81,753
)
 
80

 
1,894

 
(10,023
)
 
(201,456
)
 
(221,329
)

Total realized and unrealized (losses) gains of interest rate swaps and foreign currency forward contracts that are not designated for accounting purposes as cash flow hedges are recognized in earnings and reported in realized and unrealized losses on derivative instruments in the consolidated statements of income. The effect of the (losses) gains on these derivatives in the consolidated statements of income for the years ended December 31, 2016, 2015 and 2014 are as follows:

 
Year Ended
December 31,
2016
$

Year Ended
December 31,
2015
$

Year Ended
December 31,
2014
$
Realized losses on derivative instruments
 
 
 
 
 
Interest rate swap termination
—

 
(10,876
)
 
—

Interest rate swaps
(52,819
)
 
(60,741
)
 
(55,588
)
Foreign currency forward contracts
(7,153
)
 
(13,799
)
 
(1,912
)
 
(59,972
)
 
(85,416
)
 
(57,500
)
Unrealized gains (losses) on derivative instruments
 
 
 
 
 
Interest rate swaps
29,937

 
11,952

 
(75,777
)
Foreign currency forward contracts
9,722

 
(240
)
 
(10,426
)
 
39,659

 
11,712

 
(86,203
)
Total realized and unrealized (losses) gains on derivative instruments
(20,313
)
 
(73,704
)
 
(143,703
)

Realized and unrealized (losses) gains of cross currency swaps are recognized in earnings and reported in foreign currency exchange loss in the consolidated statements of income. The effect of the (losses) gains on cross currency swaps in the consolidated statements of income for the years ended December 31, 2016, 2015 and 2014 are as follows:

 
Year Ended
December 31,
2016
$
 
Year Ended
December 31,
2015
$
 
Year Ended
December 31,
2014
$
Realized losses
(53,497
)
 
(10,140
)
 
(1,992
)
Unrealized gains (losses)
46,127

 
(61,734
)
 
(93,953
)
Total realized and unrealized losses on cross currency swaps
(7,370
)
 
(71,874
)
 
(95,945
)

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- 25

13.
Income Taxes

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

 
December 31, 2016
$
 
December 31, 2015
$
Deferred tax assets:
 
 
 
Tax losses carried forward (1)
109,013

 
128,523

Other
2,747

 
2,815

Total deferred tax assets
111,760

 
131,338

Deferred tax liabilities:
 
 
 
Vessels and equipment
5,974

 
10,577

Long-term debt
1,691

 
3,218

Other
1,933

 
1,204

Total deferred tax liabilities
9,598

 
14,999

Net deferred tax assets
102,162

 
116,339

Valuation allowance
(78,365
)
 
(86,906
)
Net deferred tax assets
23,797

 
29,433

Disclosed in:
 
 
 
Deferred tax asset
24,659

 
30,050

Other long-term liabilities
862

 
617

Net deferred tax assets
23,797

 
29,433

(1)
As at December 31, 2016, the income tax losses carried forward of $442.2 million ($506.5 million – December 31, 2015) are available to offset future taxable income in the applicable jurisdictions, and can be carried forward indefinitely.

Certain of the balances in the comparative columns above have been adjusted with no impact on the amount of the net deferred tax assets.

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

 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
 
Year Ended
December 31, 2014
$
Current
(3,954
)
 
(1,650
)
 
(1,290
)
Deferred
(4,854
)
 
23,007

 
(889
)
Income tax (expense) recovery
(8,808
)
 
21,357

 
(2,179
)

The Partnership operates in countries that have differing tax laws and rates. Consequently, a consolidated weighted average tax rate will vary from year to year according to the source of earnings or losses by country and the change in applicable tax rates. Reconciliations of the tax charge related to the current year at the applicable statutory income tax rates and the actual tax charge related to the current year are as follows:

 
Year ended
December 31,
2016
$
 
Year ended
December 31,
2015
$
 
Year ended
December 31,
2014
$
Net income before taxes
53,283

 
78,786

 
19,835

Net income not subject to taxes
(19,706
)
 
12,601

 
(72,469
)
Net income subject to taxes
72,989

 
66,185

 
92,304

At applicable statutory tax rates
12,972

 
14,527

 
12,484

Permanent differences
(13,277
)
 
387

 
(4,677
)
Adjustments related to currency differences
(1,869
)
 
(1,060
)
 
3,349

Valuation allowance
10,982

 
(35,211
)
 
(8,977
)
Tax expense (recovery) related to current year
8,808

 
(21,357
)
 
2,179




F- 26



The following is a tabular reconciliation of the Partnership’s total amount of unrecognized tax benefits at the beginning and end of 2016, 2015 and 2014:

 
Year ended
December 31,
2016
$
 
Year ended
December 31,
2015
$
 
Year ended
December 31,
2014
$
Balance of unrecognized tax benefits as at beginning of the year
4,047

 
6,779

 
7,037

Decreases for positions related to prior years
(3,376
)
 
(3,082
)
 
(258
)
Increases for positions related to the current year
1,503

 
350

 
—

Balance of unrecognized tax benefits as at end of the year
2,174

 
4,047

 
6,779


The Partnership does not presently anticipate such uncertain tax positions will significantly increase or decrease in the next 12 months; however, actual developments could differ from those currently expected. The tax years 2010 through 2016 remain open to examination by some of the taxing jurisdictions in which the Partnership is subject to tax.

The interest and penalties on unrecognized tax benefits included in the tabular reconciliation above are not material.
14.
Commitments and Contingencies

a)
In May 2013, the Partnership entered into an agreement with Statoil, on behalf of the field license partners, to provide an FSO unit for the Gina Krog oil and gas field located in the North Sea. The contract will be serviced by a new FSO unit that is being converted from the Randgrid shuttle tanker, which the Partnership purchased in August 2015 from a 67%-owned subsidiary. The FSO conversion project is expected to cost approximately $328 million, including amounts reimbursable upon delivery of the unit relating to installation and mobilization. As at December 31, 2016, payments made towards this commitment totaled $248.9 million and the remaining payments required to be made are $78.9 million (2017). Following scheduled completion of the conversion in mid-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. The Partnership secured a long-term debt facility providing total borrowings up to $230 million in December 2015, of which $33.5 million was undrawn as at December 31, 2016.

b)
In March 2014, the Partnership acquired 100% of the shares of ALP, a Netherlands-based provider of long-haul ocean towage and offshore installation services to the global offshore oil and gas industry. Concurrently with this transaction, the Partnership and ALP entered into an agreement with Niigata Shipbuilding & Repair of Japan for the construction of four state-of-the-art SX-157 Ulstein Design ultra-long distance towing and anchor handling vessel newbuildings. One vessel was delivered to the Partnership during September 2016 and the remaining three vessel newbuildings are scheduled for delivery throughout 2017. The total cost to acquire these newbuildings is approximately $217 million, net of amounts reimbursable by Niigata Shipbuilding & Repair of Japan upon the delivery of the vessels. The Partnership paid $17.1 million upon the delivery of the first newbuilding, ALP Striker, in September 2016, net of a reimbursement of $7.0 million from the yard resulting from the delay in delivery. As at December 31, 2016, payments made towards these commitments totaled $172.9 million and the remaining payments required to be made under these newbuilding contracts are $44.3 million (2017). The Partnership secured a long-term debt facility of approximately $185 million to finance the newbuilding installments, of which $68.3 million was undrawn as at December 31, 2016.

c)
In August 2014, the Partnership acquired 100% of the outstanding shares of Logitel Offshore Holding AS, a Norway-based company focused on high-end UMS. As part of this transaction, the Partnership assumed three UMS newbuildings ordered from COSCO (Nantong) Shipyard (COSCO) in China. The Partnership took delivery of one UMS, the Arendal Spirit, in February 2015.

In June 2016, the Partnership canceled the UMS construction contracts for the two remaining UMS newbuildings, the Stavanger Spirit and the Nantong Spirit. As a result of this cancellation, during the second quarter of 2016, the Partnership wrote-off $43.7 million of assets related to these newbuildings and reversed contingent liabilities of $14.5 million associated with the delivery of these assets (see notes 4 and 19). The estimate of potential damages for the cancellation of the Stavanger Spirit newbuilding contract is based on the amount due for the final yard installment of approximately $170 million less the estimated fair value of the Stavanger Spirit. Given the unique design of the vessel as well as the lack of recent sale and purchase transactions for this type of asset, the value of this vessel, and thus ultimately the amount of potential damages that may result from the cancellation, is uncertain. Pursuant to the Stavanger Spirit newbuilding contract and related agreements, COSCO only has recourse to the single purpose subsidiary that was a party to the Stavanger Spirit newbuilding contract and its immediate parent company, Logitel Offshore Pte. Ltd., for damages incurred.

The estimate of potential damages for the cancellation of the Nantong Spirit newbuilding contract is based upon estimates of a number of factors, including accumulated costs incurred by COSCO, sub-supplier contract cancellation costs, as well as how such costs are treated under the termination provisions in the contract. The Partnership estimates that the amount of potential damages related to the cancellation of the Nantong Spirit contract could range between $10 million and $40 million. Pursuant to the Nantong Spirit newbuilding contract, COSCO only has recourse to the single purpose subsidiary that was a party to the Nantong Spirit newbuilding contract.

F- 27


During September 2016, Sevan Marine ASA (or Sevan) commenced an action against Logitel, which the Partnership acquired in 2014, in the Oslo District Court. The action relates to the agreements between Sevan and CeFront Technology AS (or CeFront), related to the 2013 transfer to Logitel Offshore Pte. Ltd. or its wholly-owned subsidiaries (collectively Logitel Offshore) of two hulls to be converted into UMS, including a $60 million bond loan (of which $41 million was a vendor credit and $19 million was a cash loan) granted by a Sevan affiliate to Logitel (or the 2013 Transaction). The action also relates to agreements between Sevan and the Partnership entered into in connection with the Partnership's acquisition of Logitel from CeFront in 2014 (or the 2014 Transaction). Sevan has claimed that the $60 million bond loan to Logitel contravened certain provisions of the Norwegian Corporate Law and that, Sevan is entitled to the remaining payment of $50 million plus interest set at the court’s discretion. Logitel intends to dispute these claims. In addition, Sevan has presented the Partnership with a formal notice of claim and request for arbitration seeking $10 million for license and service fees, which Sevan claims is payable in connection with the delivery of the Arendal Spirit. The parties are in the process of selecting an arbitration tribunal and exchanging information on their respective calculations of the amount of license and service fees that may be due.

In addition, in September 2016, CeFront commenced an action against Logitel in the Oslo District Court, claiming that $2.8 million is due under a management agreement and an additional $3.6 million will fall due by May 2017 under that agreement. CeFront also claims that $3.3 million is due under the earn-out provisions of the contracts related to the Arendal Spirit and that $20.2 million is due or will become due related to the earn-out provisions of the contracts for the Stavanger Spirit and Nantong Spirit. The Partnership is defending these claims based on the interpretation of the agreement. The partnership is uncertain as to the ultimate resolution of these claims (see note 4).

As at December 31, 2016, the Partnership has accrued $61.9 million in the aggregate related to the above claims and potential claims related to Logitel from Sevan, COSCO and CeFront.

d)
In October 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to a 50/50 joint venture of the Partnership and Odebrecht Oil and Gas S.A. (or OOG) on behalf of its field license partners. The vessel is committed to a new FPSO conversion for the Libra field located in the Santos Basin offshore Brazil. The conversion project has been completed at Sembcorp Marine’s Jurong Shipyard in Singapore and the FPSO unit is scheduled to commence operations in mid-2017 under a 12-year fixed-rate contract with a consortium led by Petroleo Brasileiro S.A. (or Petrobras). The FPSO conversion is expected to cost approximately $1.0 billion. As at December 31, 2016, payments made by the joint venture towards these commitments totaled $700.6 million and the estimated remaining payments required to be made by the joint venture are $302.3 million (2017). The joint venture secured a long-term debt facility in 2015 providing total borrowings of up to $804 million for the FPSO conversion (see note 20), of which $266.7 million was undrawn as at December 31, 2016 (see note 20).

e)
In December 2014, the Partnership acquired the Petrojarl I FPSO unit from Teekay Corporation for $57 million. The Petrojarl I is undergoing upgrades at the Damen Shipyard Group’s DSR Schiedam Shipyard (or Damen) in the Netherlands with an estimated cost of approximately $350 million, which includes the cost of acquiring the Petrojarl I. The FPSO is scheduled to commence operations in late-2017 under a five-year charter contract with Queiroz Galvão Exploração e Produção SA (or QGEP). As at December 31, 2016, payments made towards these commitments, including the acquisition of the Petrojarl I FPSO unit from Teekay Corporation, totaled $252.5 million and the remaining payments required estimated to be made are $97.5 million (2017). The Partnership is currently in negotiations with the yard regarding the valuation of certain variation orders relating to the upgrades. The outcome of these negotiations may impact the total estimated cost of the Petrojarl I FPSO unit. The Partnership has financed $171.2 million of the Petrojarl I FPSO upgrade cost through a fully-drawn long-term loan. Due to project delays in the delivery of the unit resulting from shipyard delays, an increased scope of work relating to field-specific requirements and the age of the unit, the Partnership is currently in discussions with QGEP, Damen and its lenders in the Petrojarl I loan facility to agree on revised delivery and charterer acceptance dates for the unit and other terms associated with the charter, shipyard contract and loan facility. In October 2016, December 2016, February 2017, and April 2017 the lenders agreed to extend the availability date of the loan for successive periods of two months, as the loan was subject to a mandatory prepayment provision, initially in early October 2016, if the unit was not accepted at that time by QGEP. These interim extensions provide additional time for the Partnership to negotiate a revised schedule for the delivery of the unit and thereafter, amend the loan facility to reflect the revised delivery schedule. As at December 31, 2016, the Partnership had $60 million held in escrow to fund the final upgrade costs (December 31, 2015 - $nil). This amount is presented in Restricted cash on the consolidated balance sheet.

f)
In June 2015, the Partnership entered into 15-year contracts, plus extension options, with a group of oil companies to provide shuttle tanker services for oil production on the East Coast of Canada. These contracts were initially being serviced by three third party-owned shuttle tankers operating on the East Coast of Canada, which were chartered-in to the Partnership. One of these vessels was replaced by one of the Partnership’s existing shuttle tankers, the Navion Hispania, during the third quarter of 2015. The Partnership has entered into contracts to construct three Suezmax DP2 shuttle tanker newbuildings for an aggregate fully built-up cost of approximately $372 million. These vessels will replace the existing vessels servicing the East Coast of Canada. The three newbuildings are expected to be delivered in late-2017 through the first half of 2018. As at December 31, 2016, payments made towards these commitments totaled $73.1 million and the remaining payments required to be made under these newbuilding contracts were $228.6 million (2017), and $70.6 million (2018). The Partnership secured long-term debt financing of $250 million to finance the newbuilding installments, of which $201.6 million was undrawn as at December 31, 2016.

g)
In March 2016, Petrobras claimed that the Partnership’s November 2011 cessation of paying certain agency fees with respect to the Piranema Spirit FPSO unit’s charter contract should have resulted in a corresponding 2% rate reduction on the FPSO contract with Petrobras. The Partnership has estimated the maximum amount of the claim at $7.5 million, consisting of $5.4 million (which is the

F- 28

amount accrued by the Partnership as at December 31, 2016) from a return of 2% of the charter hire previously paid by Petrobras to the Partnership for the period from November 2011 up to December 31, 2016, and $2.1 million from a 2% reduction of future charter hire to the end of the term of the FPSO contract with Petrobras.

h)
In October 2016, the Partnership received a claim from Royal Dutch Shell Plc (or Shell) for liquidated damages of $23.6 million. This claim is based on Shell's allegation that the Petrojarl Knarr FPSO did not meet the conditions for achieving the Offshore Completion milestone on time. Shell is also claiming that the inability of the Partnership to meet the Offshore Completion milestone date in excess of the grace period has in effect resulted in a 20% reduction in the purchase price for which Shell may purchase the Petrojarl Knarr FPSO from the Partnership pursuant to an option granted in the Purchase Option Agreement. In the counterclaim, the Partnership has alleged that Offshore Completion was achieved after the milestone but within the grace period and that Shell had caused delays due to certain defaults in Shell’s specifications, as well as other events. It is the Partnership’s position that, due to delays caused by Shell, the Partnership is entitled to the daily lease rate for the unit for a period of time prior to when Shell actually started paying such rate and that Shell is not entitled to a reduction in the Purchase Option Price. The duration of any such period that the Partnership claims to be entitled to receive additional daily lease payments is in dispute. However, this Partnership expects that the amount of its claim relating to the counterclaim will exceed Shell's claim of liquidated damages. Nevertheless, uncertainty exists as to the resolution of the claims.

i)
In early-November 2016, the Arendal Spirit UMS experienced an operational incident relating to its dynamic positioning system. As a result of this operational incident, and a gangway incident that occurred in April 2016, the charterer, Petrobras, initiated an operational review. Until the results of the review are available, Petrobras has suspended its charter hire payments since November 2016. The Partnership has completed an investigation to identify the cause of such incidents and has implemented corrective actions. There is a risk that Petrobras may seek to cancel the charter contract resulting from their operational review. If this occurs, the term loan outstanding for the Arendal Spirit UMS, which as at December 31, 2016 had a balance of $127.5 million, could become payable within 180 days of a cancellation. The Partnership is working to address Petrobras' concerns to bring the unit back into operations as soon as possible. Should the contract be cancelled, it could result in a reclassification of $112.5 million of long-term debt to the current portion of long-term debt unless the Partnership is able to obtain an extension from the lenders. A cancellation of the charter contract or demand for repayment of the loan would adversely affect the Partnership’s results of operations, financial condition and liquidity.
j)
In February 2017, the Partnership received a notice from Transocean Offshore International Ventures Limited (or Transocean) that it intends to file a claim against the Partnership arising from the towage of the Transocean Winner oil rig by one of the Partnerships towage vessels, the ALP Forward. Transocean intends to file a claim to recover losses it claims to have incurred relating to the grounding of the Transocean Winner in August 2016, including the costs associated with the salvage and replacement tow and other costs payable by Transocean as a result of this incident. The Partnership intends to dispute these claims, and also believes that any such claims would be covered by insurance. As of December 31, 2016, the Partnership had not accrued for any potential liability relating to these claims. An estimate of the possible loss or range of loss cannot be made at this time.
k)
As of December 31, 2016, the Partnership adopted the new accounting standard ASC-205-40, Presentation of Financial Statements - Going Concern, which requires management to assess if the Partnership will have sufficient liquidity to continue as a going concern for the one-year period following the issuance of its financial statements. Despite generating $44 million of net income and $354 million of cash flows from operating activities during 2016, the Partnership ended the year with a working capital deficit of $398 million. This working capital deficit is driven primarily from scheduled 2017 maturities and repayments of outstanding debt of $587 million which were classified as current liabilities as at December 31, 2016. In addition to these obligations, the Partnership also anticipates making payments related to commitments to fund vessels under construction or undergoing conversions/upgrades during 2017 and early 2018 of approximately $671 million, of which $437 million is expected to be funded from pre-arranged financing and a further $60 million is held in escrow as funding for the Petrojarl I FPSO project.

Based on these factors, over the one-year period following the issuance of its financial statements, the Partnership will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet its minimum liquidity requirements under its financial covenants. These anticipated sources of financing include refinancing debt facilities that mature during the one-year period, raising additional capital through equity issuances, increasing amounts available under existing debt facilities and entering into new debt facilities, negotiating extensions or redeployments of existing assets and the sale of partial interests of assets.

The Partnership is actively pursuing the funding alternatives described above, which it considers probable of completion based on the Partnership’s history of being able to raise equity, refinance loan facilities for similar types of vessels, and indicative offers received from potential investors for partial interests in certain assets. The Partnership is in various stages of completion on these matters.

Based on the Partnership’s liquidity at the date these consolidated financial statements were issued, the liquidity it expects to generate from operations over the following year, and by incorporating the Partnership’s plans to raise additional liquidity that it considers probable of completion, the Partnership estimates that it will have sufficient liquidity to enable the Partnership to continue as a going concern for at least the one-year period following the issuance of these consolidated financial statements.
15.
Supplemental Cash Flow Information
a)
The changes in non-cash working capital items related to operating activities for the years ended December 31, 2016, 2015 and 2014 are as follows:


F- 29

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)

 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
 
Year Ended
December 31, 2014
$
Accounts receivable
34,669

 
(24,285
)
 
73,020

Prepaid expenses and other assets
5,983

 
804

 
1,899

Accounts payable and accrued liabilities
38,627

 
(23,745
)
 
(87,597
)
Advances (to) from affiliate
(5,061
)
 
73,129

 
(98,806
)
 
74,218

 
25,903

 
(111,484
)

b)
Cash interest paid (including interest paid by the Dropdown Predecessor and Knarr Companies and realized losses on interest rate swaps) during the years ended December 31, 2016, 2015 and 2014 totaled $180.9 million, $179.5 million, and $135.4 million, respectively.
c)
Income taxes paid (including taxes paid by the Dropdown Predecessor and Knarr Companies) during the years ended December 31, 2016, 2015 and 2014 totaled $1.5 million, $0.8 million and $2.1 million, respectively.
d)
The Partnership’s consolidated statement of cash flows for the years ended December 31, 2015 reflects the Knarr Companies and the Dropdown Predecessor as if the Partnership had acquired Knarr Companies and the Dropdown Predecessor when the vessels began operations under the ownership of Teekay Corporation. For non-cash charges related to Knarr Companies and the Dropdown Predecessor (see note 3).
e)
The cash portion of the purchase price of vessels acquired from Teekay Corporation is as follows:
 
Year ended
December 31,
2016
$
 
Year ended
December 31,
2015
$
 
Year ended
December 31,
2014
$
Petrojarl Knarr (net of cash aquired of $14.2 million)(1) (note 3)
—

 
(112,710
)
 
—

Voyageur Spirit (note 11c)
—

 
—

 
6,181

 
—

 
(112,710
)
 
6,181

(1)
As at December 31, 2015, the cash portion of the purchase price does not include the conversion of $300.0 million of the convertible promissory note into 14.4 million common units of the Partnership issued to Teekay Corporation (see note 3).
16.
Total Capital and Net Income Per Common Unit

At December 31, 2016, a total of 72.5% of the Partnership’s common units outstanding were held by the public. The remaining common units, as well as the 2% general partner interest, were held by a subsidiary of Teekay Corporation. All of the Partnership’s outstanding Series A Cumulative Redeemable Preferred Units (the Series A Preferred Units), Series B Cumulative Redeemable Preferred Units (the Series B Preferred Units), Series C-1 Cumulative Convertible Perpetual Preferred Units (the Series C-1 Preferred Units), and 74.0% of the 10.5% Series D Cumulative Convertible Perpetual Preferred Units (the Series D Preferred Units) are held by entities other than Teekay Corporation and its affiliates. A total of 26.0% of the Series D Preferred Units are held by Teekay Corporation.

Limited Partners’ Rights

Significant rights of the limited partners include the following:

•
Right of common unitholders to receive distributions of Available Cash (after deducting expenses, including estimated maintenance capital expenditures and reserves, including reserves for future capital expenditures and for anticipated future credit needs of the Partnership) within approximately 45 days after the end of each quarter.

•
No limited partner shall have any management power over the Partnership’s business and affairs; the general partner shall conduct, direct and manage our activities.

•
The general partner may be removed if such removal is approved by common unitholders holding at least 66.66% of the outstanding units voting as a single class, including units held by the general partner and its affiliates.

Incentive Distribution Rights

The general partner is entitled to incentive distributions if the amount the Partnership distributes to common unitholders with respect to any quarter exceeds specified target levels shown below:


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)

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 2016, cash distributions were below $0.35 per common unit. Consequently, the increasing percentages were not used to calculate the general partner’s interest in net income for the purposes of the net income per common unit calculation for the year ended December 31, 2016.

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities and liquidation amounts on the Series A, Series B, Series C-1 and Series D Preferred Units will be distributed to the common unitholders and the general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation in accordance with the partnership agreement.

Series B Preferred Units, Series C Preferred Units and Series C-1 Preferred Units

In April 2015, the Partnership issued 5.0 million 8.50% Series B Preferred Units in a public offering with and aggregate redemption amount of $125.0 million, for net proceeds of $120.8 million. Pursuant to the partnership agreement, distributions on the Series B Preferred Units to preferred unitholders are cumulative from the date of original issue and are payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. At any time on or after April 20, 2020, the Series B Preferred Units may be redeemed by the Partnership at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to the date of redemption. These units are listed on the New York Stock Exchange.

In July 2015, the Partnership issued 10.4 million 8.60% Series C Preferred Units Series C Cumulative Convertible Perpetual Preferred Units (the Series C Preferred Units) in a private placement for net proceeds of approximately $249.8 million. The terms of this original agreement provided that at any time after the 18 months anniversary of the closing date, at the election of each holder, the Series C Preferred Units may be converted on a one-for-one basis into common units of the Partnership. In addition, if after the three-year anniversary of the closing date, the volume weighted average price of the common units exceeded $35.925, the Partnership had the option to convert the Series C Preferred Units into common units. Distributions on the Series C Preferred Units were cumulative from the date of original issue and payable quarterly in arrears, when, as and if declared by the board of directors of the general partner. The Series C Preferred Units could be redeemed in cash if a change of control occurred in the Partnership. As a result, the Series C Preferred Units that were subject to this redemption feature were not included on the Partnership's consolidated balance sheet as part of total equity and were presented as temporary equity above the equity section but below the liabilities section. A summary description of the Series C Preferred Units is included in the Partnership’s Report on Form 6-K filed with the SEC on July 6, 2015. As a result of the exchange described below, no series C Preferred Units were outstanding as of December 31, 2016.

In June 2016, the Partnership and the holders of the Series C Preferred Units exchanged approximately 1.9 million of the Series C Preferred Units for approximately 8.3 million common units of the Partnership. The number of common units issued consists of the approximately 1.9 million common units that would have been issuable under the original conversion terms of the Series C Preferred Units plus an additional approximately 6.4 million common units to induce the exchange (the Inducement Premium). The value of the Inducement Premium 6.4 million common units on the date of conversion was approximately $37.7 million and has been charged to the limited partner - common units and the general partner.

In June 2016, the Partnership and the holders of the Series C Preferred Units also exchanged the remaining approximately 8.5 million Series C Preferred Units for approximately 8.5 million Series C-1 Preferred Units. The terms of the Series C-1 Preferred Units are equivalent to the terms of the Series C Preferred Units, with the exception that at any time after the 18 months anniversary of the original Series C Preferred Units closing date, at the election of each holder, each Series C-1 Preferred Unit is convertible into 1.474 common units of the Partnership. In addition, if a unitholder of the Series C-1 Preferred Units elects to convert their Series C-1 Preferred Units into common units of the Partnership, the Partnership now has the option to redeem these Series C-1 Preferred Units for cash instead of common units based on the closing market price of the common units of the Partnership at the time of the redemption. Furthermore, if after the three-year anniversary of the closing date, the volume weighted average price of the common units exceeds 150% of $16.25 per unit, the Partnership has the option to convert the Series C-1 Preferred Units into common units. In addition, unlike the Series C Preferred Units, for which distributions were to be paid in cash, quarterly distributions on the Series C-1 Preferred Units for the eight consecutive quarters ending March 31, 2018 may be paid, in the Partnership's sole discretion, in cash, common units (at a discount of 2% to the ten days trading volume weighted average price ending on the distribution declaration date) or a combination of cash and common units (at the same discount), and thereafter, the distributions will be paid in cash. Consistent with the terms of the Series C Preferred Units, the Series C-1 Preferred Units may be redeemed in cash if a change of control occurs in the Partnership. As a result, the Series C-1 Preferred Units are not included on the Partnership's consolidated balance sheet as part of total equity and are presented as temporary equity above the equity section but below the liabilities section. A summary description of the Series C-1 Preferred Units is included in the Partnership’s Report on Form 6-K filed with the SEC on June 30, 2016. The exchange of the Series C Preferred Units for Series C-1 Preferred Units has been accounted for as an extinguishment of the Series C Preferred Units and the issuance of the Series C-1 Preferred Units. As a result, the excess of the carrying value of the Series C Preferred Units over

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 fair value of Series C-1 Preferred Units of $20.6 million was accounted for as an increase to the limited partner - common units and the general partner (the Exchange Contribution).

Series D Preferred Units and Detachable Warrants

On June 29, 2016, the Partnership issued a total of 4.0 million of its 10.5% Series D Preferred Units to a group of investors and subsidiaries of Teekay Corporation. These investors and Teekay Corporation also received an aggregate of 4,500,000 warrants with an exercise price equal to the closing price of the Partnership’s common units on June 16, 2016, or $4.55 per unit (the $4.55 Warrants) and an aggregate of 2,250,000 warrants with an exercise price at a 33% premium to the closing price of the Partnership’s common units on June 16, 2016, or $6.05 per unit (the $6.05 Warrants). The gross proceeds from the sale of these securities was $100.0 million (approximately $97.2 million net of offering costs).

The Partnership pays to holders of the Series D Preferred Units a cumulative, quarterly cash distribution in arrears at an annual rate of 10.5%. However, the Partnership may elect to pay the quarterly distributions for the first eight consecutive quarters following issuance, in the Partnership's sole discretion, in cash, common units (at a discount of 4% discount to the ten days trading volume weighted average price ending on the distribution declaration date) or a combination of cash and common units (at the same discount), and thereafter, the distributions will be paid in cash. The Series D Preferred Units have a liquidation value of $25.00 per unit plus an amount equal to any accrued but unpaid distributions to the date fixed for payment. The Series D Preferred Units have no mandatory redemption date, but they are redeemable at the Partnership’s option after June 29, 2021 for a 10% premium to the liquidation value and for a 5% premium to the liquidation value any time after June 29, 2022. The Series D Preferred Units are exchangeable into common units of the Partnership at the option of the holder at any time after June 29, 2021, based on the greater of the ten days trading volume weighted average price at the time of the notice of exchange or $4.00. A change of control event involving the purchase of at least 90% of the Partnership's common units would result in the Series D Preferred Units being redeemable for cash. The change of control premium to the liquidation preference on the redemption is initially 25% until June 29, 2017, scaling down five percentage points per anniversary thereof to five from June 29, 2021. Other change of control events may result in the holders of the Series D Preferred Units retaining their interest in the Series D Preferred Units, receiving from the surviving corporation a mirror security to the Series D Preferred Units or the Series D Preferred Units being redeemed for cash and/or common units. The Series D Preferred Units rank senior to all common units, pari passu with the Series A, B and C-1 Preferred Units and junior with respect to any senior securities, with respect to distribution rights and liquidation preference. The holders of Series D Preferred Units generally only have voting rights in proposed transactions that would result in a change of control, the creation or issuance of any senior securities and the issuance of any parity securities if distributions payable on any of the Partnership's Preferred Units are in arrears. The Partnership has filed a registration statement with respect to the Series D Preferred Units and the common units issuable upon exercise of the Warrants, which was declared effective August 31, 2016 and has agreed to use commercially reasonable efforts to cause a registration statement with respect to the common units underlying the Series D Preferred Units to be declared effective within 60 days prior to June 29, 2021. In addition, the Partnership has agreed to pay liquidated damages in the event it fails to do so; however, this is not considered probable of occurring.

The Partnership issued warrants which allow the holders to acquire up to 4,500,000 common units for a price of $4.55 per common unit and 2,250,000 common units for a price of $6.05 per common unit (the Warrants). The Warrants have a seven-year term and are exercisable any time after six months following their issuance date. The Warrants will be net settled in either cash or common units at the Partnership’s option. In the event of a change in control in which the Partnership is not the surviving entity, the Partnership will use commercially reasonable efforts to deliver or cause to be delivered one or more warrants in the surviving entity that has substantially similar rights, preferences and privileges as the Series D Preferred Units. The Partnership filed a registration statement with respect to the common units issuable upon exercise of the Warrants and to be declared effective by the six months anniversary of the issuance date of the Warrants, which was declared effective August 31, 2016.

Net cash proceeds of approximately $97.2 million (which is net of approximately $2.8 million of issuance costs), were allocated on a relative fair value basis to the Series D Preferred Units (approximately $83.5 million), to the $4.55 Warrants (approximately $9.5 million) and to the $6.05 Warrants (approximately $4.3 million). The Warrants qualify as freestanding financial instruments and are accounted for separately from the Series D Preferred Units. The Series D Preferred Units are presented as temporary equity as they are not mandatorily redeemable and the prospect of a forced redemption paid with cash due to a change of control event is not presently probable. The Warrants are recorded as permanent equity in the Partnership's consolidated balance sheets with 6,750,000 Warrants outstanding at December 31, 2016 (December 31, 2015 - nil). The $16.5 million difference between the amount of net proceeds allocated to the Series D Preferred Units based on relative fair values and the redemption value of the Series D Preferred Units is subject to periodic accretion over the five-year period until they become redeemable. As a result, for year ended December 31, 2016, $1.7 million was accounted for as a charge to the limited partners - common units and the general partner.

Net Income Per Common Unit


F- 32

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, 2016
 
December 31, 2015
 
December 31, 2014
 
$
 
$
 
$
Limited partners' interest in net income
(12,952
)
 
31,205

 
(19,380
)
Preferred units - periodic accretion
(1,644
)
 
—

 
—

Additional consideration for induced conversion of Series C Preferred Units
(36,961
)
 
—

 
—

Deemed contribution on exchange of Series C Preferred Units
20,231

 
—

 
—

Limited partners' interest in net income for basic net income per common unit
(31,326
)
 
31,205

 
(19,380
)
Weighted average number of common units
124,747,207

 
98,507,732

 
86,212,290

Dilutive effect of unit based compensation
—

 
94,680

 
—

Common units and common unit equivalents
124,747,207

 
98,602,412

 
86,212,290

 
 
 
 
 
 
Limited partner's interest in net income per common unit
 
 
 
 
 
 - basic
(0.25
)
 
0.32

 
(0.22
)
 - diluted
(0.25
)
 
0.32

 
(0.22
)

Limited partners’ interest in net income per common unit – basic is determined by dividing net income, after deducting the amount of net income attributable to the non-controlling interests, the general partner’s interest and the distributions on the Series A, B, C, C-1 and D Preferred Units, the periodic accretion of the Series D Preferred Units, the Inducement Premium and the Exchange Contribution, by the weighted-average number of common units outstanding during the period. The distributions payable and paid on the preferred units for the year ended December 31, 2016 were $45.8 million (2015 - $28.6 million, 2014 - $10.9 million).

The computation of limited partners’ interest in net income per common unit - diluted assumes the issuance of common units for all potentially dilutive securities, consisting of restricted units (see note 17), the Warrants and Series C, C-1 and D Preferred Units. Consequently, the net income attributable to limited partners’ interest is exclusive of any distributions on the Series C, C-1 and D Preferred Units, the periodic accretion of the Series D Preferred Units, the Inducement Premium and the Exchange Contribution. In addition, the weighted average number of common units outstanding has been increased assuming exercise of the restricted units and Warrants using the treasury stock method and assuming the Series C, C-1 and D are converted to common units using the if-converted method. The computation of limited partners’ interest in net income per common unit - diluted does not assume the issuance of common units pursuant to the restricted units, Warrants and Series C, C-1 and D Preferred Units if the effect would be anti-dilutive. In periods where a loss is attributable to common unitholders, all restricted units, Warrants, the Series C, C-1 and D Preferred Units are anti-dilutive.

Therefore, for the year ended December 31, 2016, 40.6 million common unit equivalent Series C, C-1 and D Preferred Units and 7.1 million restricted units and common unit equivalent Warrants, respectively, were excluded from the computation of limited partners’ interest in net income per common unit - diluted, as their effect was anti-dilutive. For the years ended December 31, 2015 and December 31, 2014, 5.1 million Series C Preferred Units and 0.1 million restricted units, respectively, were excluded from the computation of limited partners' interest in net income per unit - diluted, as their effect was anti-dilutive.

The general partner’s and common unitholders’ interests in net income are calculated as if all net income was distributed according to the terms of the Partnership’s partnership agreement, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter less, among other things, the amount of cash reserves established by the general partner’s board of directors to provide for the proper conduct of the Partnership’s business including reserves for maintenance and replacement capital expenditure, anticipated capital requirements and any accumulated distributions on, or redemptions of, the Series A Preferred Units, Series B Preferred Units, Series C-1 Preferred Units and Series D Preferred Units. Unlike available cash, net income is affected by non-cash items such as depreciation and amortization, unrealized gains and losses on derivative instruments and unrealized foreign currency translation gains and losses.

Pursuant to the partnership agreement, allocations to partners are made on a quarterly basis.

F- 33

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)

Public and Private Offerings of Common Units
The following table summarizes the issuances of common units over the three years ending December 31, 2016:
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)
 
 
During 2014
 
COP
 
213,350

 
(iii) 
 
7.8

 
7.6

 
(iii) 
 
General partnership purposes
November 2014
 
Private
 
6,704,888

 
$
26.10

 
178.6

 
178.5

 
27.26
%
 
For general partnership purposes, which included funding vessel conversion projects and finance newbuilding UMS and towage vessels.
During 2015
 
COP
 
211,077

 
(iii) 
 
3.6

 
3.5

 
(iii) 
 
General partnership purposes
July 2015
 
Private
 
14,402,304

 
$
20.83

 
306.1

 
306.1

 
37.06
%
 
Partially finance the acquisition of the Knarr companies.
During 2016
 
COP
 
5,525,310

 
 (iv)  
 
31.8

 
31.0

 
(iv) 
 
General partnership purposes
June 2016
 
Private
 
21,978,022

 
$
4.55

 
102.0

 
99.5

 
29.25
%
 
For general partnership purposes, which included funding existing newbuilding installments and capital conversion projects.
During 2016
 
PIK
 
4,558,624

 
 (v) 
 
0.5

 
0.5

 
(v) 
 
(v) 
June 2016
 
Series C Conversion
 
8,323,809

 
(vi) 
 
0.9

 
0.7

 
(vi) 
 
(vi) 
(i)
Including the General Partner’s 2% proportionate capital contribution.
(ii)
Including Teekay Corporation’s indirect 2% general partner interest.
(iii)
In May 2013, the Partnership implemented a continuous offering program (or COP), under which the Partnership may issue new common units, representing limited partner interests, at market prices from time to time up to a maximum aggregate amount of $100 million.
(iv)
In June 2016, the Partnership implemented a replacement $100 million COP.
(v)
Common units issued or issuable as a payment-in-kind for the distributions on the Partnership's Series C-1 and D Preferred Units and on the Partnership's common units and general partner interest held by subsidiaries of Teekay Corporation and payment-in-kind for interest on a subordinated promissory note to Teekay Corporation (see note 11j). In June 2016, the Partnership agreed with Teekay Corporation that, until the Partnership's Norwegian Kroner bonds maturing in 2018 have been repaid, all distributions to be paid by the Partnership to Teekay Corporation or its affiliates, including the Partnership's general partner, related to common and preferred units held by Teekay Corporation or its affiliates (other than with respect to incentive distribution rights) will be paid in the form of common units.
(vi)
In June 2016, the Partnership and the holders of the Series C Preferred Units exchanged approximately 1.9 million of the Series C Preferred Units for approximately 8.3 million common units of the Partnership. The number of common units issued consists of the approximately 1.9 million common units that would have been issuable under the original conversion terms of the Series C Preferred Units plus an additional approximately 6.4 million common units to induce the exchange (the Inducement Premium).

17.
Unit Based Compensation

During the year ended December 31, 2016, a total of 76,084 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 2016.

The Partnership grants restricted unit-based compensation awards as incentive-based compensation to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership. During March 2016, 2015 and 2014, the Partnership granted restricted unit-based compensation awards with respect to 601,368, 102,834 and 67,569 units, respectively, with aggregate grant date fair values of $2.4 million, $2.1 million and $2.1 million, respectively for 2016, 2015 and 2014, based on the Partnership’s closing unit price on the grant dates. Each restricted unit is equal in value to one of the Partnership’s common units. Each award represents the specified number of the Partnership’s common units plus reinvested distributions from the grant date to the vesting date. The awards vest equally over three years

F- 34

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)

from the grant date. Any portion of an award that is not vested on the date of a recipient’s termination of service is canceled, unless their termination arises as a result of the recipient’s retirement and, in this case, the award will continue to vest in accordance with the vesting schedule. Upon vesting, the awards are paid to each grantee in the form of common units or cash.

During the year ended December 31, 2016, restricted unit-based awards with respect to a total of 76,637 common units with a fair value of $2.0 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 25,286 common units and by paying $0.2 million in cash.

During the year ended December 31, 2015, restricted unit-based awards with respect to a total of 48,488 common units with a fair value of $1.5 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 12,612 common units and by paying $0.5 million in cash.

During the year ended December 31, 2014, restricted unit-based awards with respect to a total of 20,988 common units with a fair value of $0.6 million, based on the Partnership’s closing unit price on the grant date, vested and the amount paid to the grantees was made by issuing 6,584 common units and by paying $0.3 million in cash.

The Partnership recorded unit-based compensation expense of $1.9 million, $0.9 million and $1.9 million, during the years ended December 31, 2016, 2015 and 2014, respectively, in general and administrative expenses in the Partnership’s consolidated statements of income.

As of December 31, 2016 and December 31, 2015, liabilities relating to cash settled restricted unit-based compensation awards of $1.1 million and $0.4 million, respectively, were recorded in accrued liabilities on the Partnership’s consolidated balance sheets. As at December 31, 2016, the Partnership had $1.6 million of non-vested awards not yet recognized, which the Partnership expects to recognize over a weighted average period of 1.2 years.

18.
Acquisitions

a)
Acquisition of ALP Maritime Services B.V.

On March 14, 2014, the Partnership acquired 100% of the shares of ALP. Concurrently with this transaction, the Partnership and ALP entered into an agreement with Niigata Shipbuilding & Repair of Japan for the construction of four state-of-the-art SX-157 Ulstein Design ultra-long distance towing and anchor handling vessel newbuildings (see note 14b).

The Partnership acquired ALP for a purchase price of $2.6 million, which was paid in cash, and also entered into an arrangement to pay additional compensation to three former shareholders of ALP if certain requirements are satisfied. This contingent compensation consists of $2.4 million, which is payable upon the delivery and employment of ALP’s four newbuildings and a further amount of up to $2.6 million, which is payable if ALP’s annual operating results from 2017 to 2021 meet certain targets. The Partnership has the option to pay up to 50% of this compensation through the issuance of common units of the Partnership. Each of the contingent compensation amounts are payable only if the three shareholders are employed by ALP at the time performance conditions are met. For the year ended December 31, 2016, compensation cost was $0.7 million and was recorded in general and administrative expenses in the Partnership’s consolidated statements of income (December 31, 2015 - $0.7 million, December 31, 2014 - $0.5 million). The Partnership also incurred a $1.0 million fee to a third party associated with the acquisition of ALP in 2014 and a $1.6 million business development fee to Teekay Corporation in 2014 (see note 11l) for assistance with the acquisition, which have been recognized in general and administrative expenses during 2014.

The acquisition of ALP was accounted for using the purchase method of accounting, based upon finalized estimates of fair value.

The following table summarizes the finalized fair values of the ALP assets acquired and liabilities assumed by the Partnership on the acquisition date.
 
(in thousands of U.S. Dollars)
As at March 14, 2014
$
 
 
ASSETS
 
 
Cash and cash equivalents
294

 
Other current assets
404

 
Advances on newbuilding contracts
164

 
Other assets - long-term
395

 
Goodwill (towage segment)
2,032

 
Total assets acquired
3,289

 
LIABILITIES
 
 
Current liabilities
387

 
Other long-term liabilities
286

 
Total liabilities assumed
673

 
Net assets acquired
2,616

 
Consideration
2,616


F- 35

TEEKAY OFFSHORE PARTNERS L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)


The goodwill recognized in connection with the ALP acquisition is attributable primarily to the assembled workforce of ALP, including their experience, skills and abilities. Operating results of ALP are reflected in the Partnership’s financial statements commencing March 14, 2014, the effective date of the acquisition. For the year ended December 31, 2014, the Partnership recognized $0.5 million of revenue and $2.3 million of net loss resulting from this acquisition. The following table shows summarized consolidated pro forma financial information for the Partnership for the year ended December 31, 2014, giving effect to the Partnership’s acquisition of ALP as if it had taken place on January 1, 2014:
(in thousands of U.S. Dollars, except per unit data)
Pro Forma Year Ended December 31, 2014
Revenues
1,019,674

Net income from continuing operations
17,495

Limited partners' interest in net income from continuing operations per common unit:
 
   - Basic
(0.23
)
   - Diluted
(0.23
)
b)
Acquisition of Logitel Offshore Holding AS
On August 11, 2014, the Partnership acquired 100% of the outstanding shares of Logitel. The purchase price for the shares of Logitel consisted of $4.0 million in cash paid at closing and a potential additional cash amount of $27.6 million, subject to reductions of some or all of this potential additional amount if certain performance criteria were not met, primarily relating to the construction of the three UMS ordered (see note 4a).

Prior to the acquisition, Logitel secured a three-year fixed-rate charter contract with Petrobras in Brazil for the first UMS, the Arendal Spirit, which delivered in February 2015 and commenced its contract with Petrobras in June 2015. During 2016, the Partnership canceled the UMS construction contracts for its two remaining UMS newbuildings (see notes 4a and 14c).

The acquisition of Logitel was accounted for using the acquisition method of accounting, based upon finalized estimates of fair value.

The following table summarizes the preliminary and final valuations of the Logitel assets and liabilities on the acquisition date. The estimates of fair values of the Logitel assets acquired and liabilities assumed by the Partnership were finalized during the second quarter of 2015.
(in thousands of U.S. Dollars)
Preliminary Valuation
August 11, 2014
$
 
Adjustments
$
 
Final Valuation
August 11, 2014
$
 
 
ASSETS
 
 
 
 
 
Cash and cash equivalents
8,089

 
—

 
8,089

Prepaid expenses
640

 
—

 
640

Advances on newbuilding contracts
46,809

 
(2,239
)
 
44,570

Intangible assets
—

 
1,000

 
1,000

Total assets acquired
55,538

 
(1,239
)
 
54,299

LIABILITIES
 
 
 
 
 
Accrued liabilities
4,098

 
—

 
4,098

Long-term debt
26,270

 
1,330

 
27,600

Total liabilities assumed
30,368

 
1,330

 
31,698

Net assets acquired
25,170

 
(2,569
)
 
22,601

Cash consideration
4,000

 
—

 
4,000

Contingent consideration
21,170

 
(2,569
)
 
18,601


Operating results of Logitel are reflected in the Partnership’s financial statements commencing August 11, 2014, the effective date of acquisition. For the year ended December 31, 2014, the Partnership recognized $nil revenue and $1 million of net loss resulting from this acquisition. The following table shows summarized consolidated pro forma financial information for the Partnership for the year ended December 31, 2014, giving effect to the Partnership’s acquisition of Logitel as if it had taken place on January 1, 2014:

F- 36

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 thousands of U.S. Dollars, except per unit data)
Pro Forma Year Ended December 31, 2014
Revenues
1,019,539

Net income from continuing operations
16,717

Limited partners' interest in net income from continuing operations per common unit:
 
   - Basic
(0.24
)
   - Diluted
(0.24
)

19.
(Write-down) and Gain (Loss) on Sale of Vessels, Conventional Tankers Dispositions and Discontinued Operations

(Write-down) and Gain (Loss) on Sale of Vessels

In 2016, the Partnership sold a 1992-built shuttle tanker, the Navion Torinita, for net proceeds of $5.0 million, which was the approximate carrying value of the vessel at the time of sale, and sold a 1995-built shuttle tanker, the Navion Europa, for net proceeds of $14.4 million, for which the Partnership recorded a gain on sale of $6.8 million in the Partnership's shuttle tanker segment, in a 67%-owned subsidiary of the Partnership. The gain on sale of $6.8 million recorded includes both the Partnership's interest and the non-controlling interest. The Navion Torinita had previously been written down to its estimated fair value, using an appraised value as a result of the expected sale of the vessel and the vessel was classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015. The Partnership’s consolidated statement of income for the year ended December 31, 2015 includes a $1.7 million write-down related to this vessel. The write-down is included in the Partnership’s shuttle tanker segment.

During the fourth quarter of 2016, the carrying value of the Navion Marita was written down to its estimated fair value, using an appraised value, as a result of fewer opportunities to trade the vessel in the conventional tanker market. The Partnership’s consolidated statement of income for the year ended December 31, 2016, includes a $2.1 million write-down related to this vessel. The write-down is included in the Partnership’s shuttle tanker segment. In 2016, the carrying value of one of the Partnerships FSO units, the Navion Saga, was written down to its estimated fair value, using an appraised value, as a result of the expected sale of the unit and the unit was classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2016. The Partnership’s consolidated statement of income for the year ended December 31, 2016, includes a $1.0 million write-down related to this FSO unit. The write-down is included in the Partnership's FSO segment. In 2016, the Partnership canceled the UMS construction contracts for its two UMS newbuildings. As a result, the carrying values of these two UMS newbuildings were written down to $nil. The Partnership's consolidated statements for the year ended December 31, 2016 includes a $43.7 million write-down related to these two UMS newbuildings (see notes 4 and 14c). The write-down is included in the Partnership’s UMS segment.

In 2015, the carrying values of two of the Partnership’s 2000s-built conventional tankers and seven of the Partnership’s 1990s-built shuttle tankers were written down to their estimated fair value, using appraised values. The write-down of the two conventional tankers was the result of the expected sale of the vessels and the vessels were classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015 (see below). The Partnership’s consolidated statement of income for the year ended December 31, 2015, includes a $3.9 million write-down related to these two conventional tankers. The write-down is included in the Partnership’s conventional tanker segment. Of the seven shuttle tankers, during the first quarter of 2015, one shuttle tanker was written down as a result of the expected sale of the vessel and the vessel was classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015. An additional shuttle tanker was written down during the first quarter of 2015 as a result of a change in the operating plan of the vessel. In the fourth quarter of 2015, the write-down of five shuttle tankers, which have an average age of 17.5 years, was the result of changes in our expectations of their future opportunities, primarily due to their advanced age. The Partnership’s consolidated statement of income for the year ended December 31, 2015, includes total write-downs of $66.7 million related to these seven shuttle tankers. The write-downs are included in the Partnership’s shuttle tanker segment. In 2015, the Partnership sold a 1997-built shuttle tanker, the Navion Svenita, for net proceeds of $8.6 million. The Partnership’s consolidated statement of income for the year ended December 31, 2015 includes a $1.6 million gain related to the sale of this vessel. The gain on sale is included in the Partnership’s shuttle tanker segment.

In 2014, the carrying value of one of the Partnership’s 1990s-built shuttle tankers was written down to its estimated fair value, using an appraised value. The write-down was the result of the vessel charter contract expiring in early-2015. The Partnership’s consolidated statement of income for the year ended December 31, 2014, includes a $4.8 million write-down related to this vessel. The write-down is included in the Partnership’s shuttle tanker segment. In the fourth quarter of 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to a joint venture between the Partnership and a joint venture partner (see note 20). The Partnership’s consolidated statement of income for the year ended December 31, 2014, includes a $3.1 million gain related to the sale of this vessel. The gain on sale of vessel is included in the Partnership’s shuttle tanker segment.

Conventional Tankers Dispositions

In March 2016, the time-charter contract with a subsidiary of Teekay Corporation for a 2004-built conventional tanker, the Kilimanjaro Spirit, was terminated by the Partnership. The Partnership concurrently received an early termination fee of $4.0 million from Teekay Corporation. Immediately following the charter termination, the Partnership sold the Kilimanjaro Spirit for net proceeds of $26.7 million and also sold a 2003-built conventional tanker, the Fuji Spirit, for net proceeds of $23.7 million, which were the approximate carrying values of the vessels at the time of sale. The two vessels were classified as held for sale on the Partnership’s consolidated balance sheet as at December 31, 2015. As part of the sale of these vessels, the Partnership is in-chartering these vessels for a period of 3 years each, both with an additional 1-year

F- 37

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)

extension option. One vessel is fixed on a two-year time-charter-out contract which commenced during the second quarter of 2016, and the other vessel is currently trading in the spot conventional tanker market.

In December 2015, bareboat and time-charter contracts with a subsidiary of Teekay Corporation for the SPT Explorer, Navigator Spirit and Fuji Spirit were terminated by the Partnership. The Partnership concurrently paid total net charter termination fees to Teekay Corporation of $1.8 million. Immediately following the charter terminations, the Partnership sold its 100% interest in SPT Explorer L.L.C. and Navigator Spirit L.L.C., which own the SPT Explorer and the Navigator Spirit conventional tankers, respectively, to Teekay Tankers Ltd., a company under common control, for net proceeds of $39.0 million, consisting of $80.0 million for the vessels and $8.6 million for working capital less $49.6 million for assumption of long-term debt. The $14.3 million excess of the purchase price over the Partnership’s carrying value of SPT Explorer L.L.C. and Navigator Spirit L.L.C. was accounted for as an equity contribution in the Partnership’s consolidated statement of changes in total equity.
 
The following table summarizes the pretax profit and components thereof for the SPT Explorer, Navigator Spirit, Fuji Spirit and Kilimanjaro Spirit for the periods presented in the consolidated statements of income, while these vessels were owned by the Partnership:
 
Year Ended
December 31, 2016
$
 
Year Ended
December 31, 2015
$
 
Year Ended
December 31, 2014
$
Revenues
8,030

 
30,230

 
33,566

Voyage expenses
(435
)
 
(2,326
)
 
(5,373
)
Vessel operating expenses
(1,340
)
 
(6,234
)
 
(5,906
)
Depreciation and amortization
—

 
(6,583
)
 
(6,680
)
General and administrative
(1
)
 
(11
)
 
(8
)
Income from vessel operations
6,254

 
15,076

 
15,599

Interest expense
(142
)
 
(1,007
)
 
(902
)
Foreign currency exchange loss
(4
)
 
(7
)
 
(6
)
Other expense - net
—

 
—

 
(4
)
Net income before income tax expense
6,108

 
14,062

 
14,687


20.
Investment in Equity Accounted Joint Ventures and Advances to Joint Venture

In October 2014, the Partnership sold a 1995-built shuttle tanker, the Navion Norvegia, to OOG-TK Libra GmbH & Co KG (or Libra Joint Venture), a 50/50 joint venture with OOG. The vessel is committed to a new FPSO unit conversion for the Libra field. The FPSO unit is scheduled to commence operations in mid-2017 (see note 14d). In conjunction with the conversion project, in late-2015, the Libra Joint Venture entered into a ten-year plus construction period loan facility providing total borrowings of up to $804 million, of which $537 million was drawn as of December 31, 2016. The interest payments of the loan facility are based on LIBOR, plus margins which range between 2.50% to 2.65%. The final payment under the loan facility is due October 2027. The Partnership and OOG have severally guaranteed to the banks their 50% shares of the equity contributions scheduled to fund the conversion project, and have jointly guaranteed any unexpected equity requirements. In addition, the Libra Joint Venture entered into ten-year interest rate swap agreements to economically hedge expected interest payments on the loan facility from 2017 to 2027, with an aggregate notional amount of $301 million which amortizes quarterly over the term of the interest rate swap agreements. These interest rate swap agreements exchange the receipt of LIBOR-based interest for the payment of a fixed rate of 2.49%. These interest rate swap agreements have been designated as qualifying cash flow hedging instruments for accounting purposes. During 2016, as a result of certain defaults on interest payments by an OOG affiliate which OOG had guaranteed, the Libra Joint Venture was required to obtain cross default waivers from the lenders of the construction period loan facility. The current waiver is due to expire on June 16, 2017. Although the Libra Joint Venture expects to obtain further cross default waivers from the facility lenders, a failure to do so could adversely affect its ability to fund and complete the Libra FPSO conversion (see note 14d).

In June 2013, the Partnership acquired Teekay Corporation’s 50% interest in OOG-TKP FPSO GmbH & Co KG, a joint venture with OOG, which owns the Itajai FPSO unit. Included in the joint venture is an eight-year loan facility, which as at December 31, 2016 had an outstanding balance of $198 million. The interest payments of the loan facility are based on LIBOR, plus margins which range between 2.15% and 2.45%. The final payment under the loan facility is due October 2021. The Partnership has guaranteed its 50% share of the loan facility. In addition, the joint venture entered into ten-year interest rate swap agreements with an aggregate notional amount of $88 million as at December 31, 2016, which amortizes semi-annually over the term of the interest rate swap agreements. These interest rate swap agreements exchange the receipt of LIBOR-based interest for the payment of a fixed rate of 2.63%. These interest rate swap agreements are not designated as qualifying cash flow hedging instruments for accounting purposes. As at December 31, 2014, the Partnership advanced $5.2 million to the joint venture, which was repaid during 2015.

As at December 31, 2016 and 2015, the Partnership had total investments of $141.8 million and $77.6 million, respectively, in joint ventures. No indicators of impairment existed at December 31, 2016 and 2015.

The following table presents aggregated summarized financial information assuming a 100% ownership interest in the Partnership’s equity method investments. The results included are for the Itajai FPSO joint venture from June 2013 and the Libra Joint Venture from October 2014.

F- 38

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,
 
2016
$
 
2015
$
Cash and cash equivalents
48,561

 
17,212

Other assets - current
17,172

 
18,846

Vessels and equipment and conversion costs
1,001,337

 
589,731

Other assets - non-current
10,128

 
5,385

Current portion of long-term debt
105,736

 
28,889

Other liabilities - current
40,015

 
18,514

Long-term debt
607,588

 
390,219

Other liabilities - non-current
29,795

 
34,978


 
Year ended December 31,
 
2016
$
 
2015
$
 
2014
$
Revenues
80,999

 
82,831

 
82,845

Income from vessel operations
42,380

 
37,351

 
35,273

Realized and unrealized (losses) gains on derivative instruments
1,608

 
(13,214
)
 
(6,656
)
Net income
35,866

 
15,344

 
20,682


F- 39