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, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
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                     
Commission file number 001- 35704
 
 
 
SEADRILL PARTNERS LLC
(Exact Name of Registrant as Specified in Its Charter)
 
 
 
Republic of The Marshall Islands
(Jurisdiction of Incorporation or Organization)
2nd floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London,
W4 5YS, United Kingdom
Telephone: +44 20 8811 4700
(Address of Principal Executive Offices)

John Roche
2nd floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London,
W4 5YS, United Kingdom
Telephone: +44 20 8811 4700
E-mail: post@seadrill.com
(Name, Telephone, E-mail and/or Facsimile Number and Address of 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 representing limited liability company interests
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.
75,278,250 Common Units representing limited liability company interests
16,543,350 Subordinated Units representing limited liability company interests
Indicate by check mark if 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 whether 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 whether the registrant 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, a non-accelerated filer, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  o
       Accelerated filer   ý   
       Non-accelerated filer o
Emerging growth company o
                   

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
 
U.S. GAAP  ý
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



SEADRILL PARTNERS LLC
INDEX TO REPORT ON FORM 20-F
PART I
 
 
Item 1.
Item 2.
Item 3.
A.
B.
C.
D.
Item 4.
A.
B.
C.
D.
Item 4A.
Item 5.
A.
B.
C.
D.
E.
F.
G.
Item 6.
A.
B.
C.
D.
E.
Item 7.
A.
B.
C.
Item 8.
A.
B.
Item 9.
A.
B.
C.
D.
E.
F.
Item 10.
A.
B.
C.
D.


E.
F.
G.
H.
I.
Item 11.
Item 12.
 
 
 
PART II
 
 
Item 13.
Item 14.
Item 15.
Item 16A.
Item 16B.
Item 16C.
Item 16D.
Item 16E.
Item 16F.
Item 16G.
Item 16H.
 
 
 
PART III
 
 
Item 17.
Item 18.
Item 19.






Presentation of Information in this Annual Report
This annual report on Form 20-F for the year ended December 31, 2017, ("the annual report"), should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in this report. Unless the context otherwise requires, references in this annual report to "Seadrill Partners LLC," "Seadrill Partners," the "Company," "we," "our," "us" or similar terms refer to Seadrill Partners LLC, a Marshall Islands limited liability company, or any one or more of its subsidiaries (including OPCO, as defined below), or to all of such entities, and, for periods prior to the Company's initial public offering ("IPO") on October 24, 2012, the Company's combined entity. References to the Company's "combined entity" refer to the subsidiaries of Seadrill Limited that had interests in the drilling units in the Company's initial fleet prior to the Company's initial public offering, or in the case of drilling units subsequently acquired from Seadrill Limited in transactions between parties under common control, the subsidiaries of Seadrill Limited that had interests in the drilling units prior to the date of acquisition. References in this annual report to "Seadrill" refer, depending on the context, to Seadrill Limited (NYSE: SDRL) and to any one or more of its direct and indirect subsidiaries. References to "Seadrill Management" refer to Seadrill Management Ltd, the entity that provides the Company with personnel and management, administrative, financial and other support services.
The Company owns (i) a 58% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC and (iii) a 100% interest in Seadrill Partners Operating LLC. Seadrill Operating LP owns: (i) a 100% interest in the entities that own and operate the West Aquarius, the West Vencedor, West Leo and the West Polaris (ii) an approximate 56% interest in the entity that owns and operates the West Capella and (iii) a 100% limited liability company interest in Seadrill Partners Finco LLC. Seadrill Capricorn Holdings LLC owns 100% of the entities that own and operate the West Capricorn, the West Sirius, the West Auriga, and the West Vela. Seadrill Partners Operating LLC owns 100% of the entities that own and operate the T-15 and T-16. Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as "OPCO."
All references in this annual report to "OPCO" when used in a historical context refer to OPCO’s predecessor companies and their subsidiaries, and when used in the present tense or prospectively refer to OPCO and its subsidiaries, collectively, or to OPCO individually, as the context may require.
References in this annual report to "Seadrill Member" refer to the owner of the Seadrill Member interest, which is a non-economic limited liability company interest in Seadrill Partners and is currently held by Seadrill Member LLC, a wholly owned subsidiary of Seadrill. Certain references to the "Seadrill Member" refer to Seadrill Member LLC, as the context requires.
References in this annual report to "ExxonMobil," "Chevron," "Total", "BP", "Tullow", "ConocoPhillips", "Petronas", "Statoil", "Hibernia" and "Medco Energi" refer to subsidiaries of ExxonMobil Corporation, Chevron Corporation, Total S.A., BP Plc, Tullow Plc, ConocoPhillips Company, Petroliam Nasional Berhad (PETRONAS), Statoil ASA, Hibernia Management and Development Ltd. and PT Medco Energi Internasional Tbk respectively, that are or were the Company’s customers.
Important Information Regarding Forward Looking Statements
Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements, which are other than statements of historical or present facts or conditions.
This annual report and any other written or oral statements made by us or on our behalf may include forward-looking statements which reflect our current views with respect to future events and financial performance. The words "believe," "anticipate," "intend," "estimate," "forecast," "project," "plan," "potential," "may," "should," "expect" and similar expressions identify forward-looking statements.
The forward-looking statements in this annual report are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.
In addition to these important factors and matters discussed elsewhere in this annual report, and in the documents incorporated by reference in this annual report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:
•
offshore drilling market conditions, including supply and demand;
•
the Company's distribution policy and the Company's ability to make cash distributions on the Company's units or any increases or decreases in distributions and the amount of such increases or decreases;
•
the future financial condition, liquidity or results of operations of the Company or Seadrill;
•
the repayment of debt;
•
the ability of the Company and OPCO to comply with financing agreements and the effect of restrictive covenants in such agreements;
•
the ability of the Company's drilling units to perform satisfactorily or to the Company's expectations;
•
the financial condition of Seadrill, its comprehensive restructuring efforts and its ability to provide services to the Company under certain management, administrative and technical support agreements. This dependence on Seadrill has given rise to substantial doubt over the Company’s ability to continue as a going concern;
•
fluctuations in the price of oil;

i

•
discoveries of new sources of oil that do not require deepwater drilling units;
•
the development of alternative sources of fuel and energy;
•
technological advances, including in production, refining and energy efficiency;
•
weather events and natural disasters;
•
the Company's ability to meet any future capital expenditure requirements;
•
the Company's ability to maintain operating expenses at adequate and profitable levels;
•
expected costs of maintenance or other work performed on the Company's drilling units and any estimates of downtime;
•
the Company's ability to leverage Seadrill’s relationship and reputation in the offshore drilling industry;
•
the Company's ability to purchase drilling units in the future, including from Seadrill;
•
increasing the Company's ownership interest in OPCO;
•
customer contracts, including contract backlog, contract terminations and contract revenues;
•
delay in payments by, or disputes with the Company’s customers under its drilling contracts;
•
termination of the Company's drilling contracts due to force majeure or other events;
•
the financial condition of the Company’s customers and their ability and willingness to fund oil exploration, development and production activity;
•
the Company’s ability to comply with, maintain, renew or extend its existing drilling contracts;
•
the Company’s ability to re-deploy its drilling units upon termination of its existing drilling contracts at profitable dayrates;
•
the Company's ability to respond to new technological requirements in the areas in which the Company operates;
•
the occurrence of any accident involving the Company’s drilling units or other drilling units in the industry;
•
changes in governmental regulations that affect the Company and the interpretations of those regulations, particularly those that relate to environmental matters, export or import and economic sanctions or trade embargo matters, regulations applicable to the oil industry and tax and royalty legislation;
•
competition in the offshore drilling industry and other actions of competitors, including decisions to deploy or scrap drilling units in the areas in which the Company currently operates;
•
the availability on a timely basis of drilling units, supplies, personnel and oil field services in the areas in which the Company operates;
•
general economic, political and business conditions globally;
•
military operations, terrorist acts, wars or embargoes;
•
potential disruption of operations due to accidents, political events, piracy or acts by terrorists;
•
the Company's ability to obtain financing in sufficient amounts and on adequate terms;
•
workplace safety regulation and employee claims;
•
the cost and availability of adequate insurance coverage;
•
the Company's fees and expenses payable under the advisory, technical and administrative services agreements and the management and administrative services agreements;
•
the taxation of the Company and distributions to the Company's unitholders;
•
future sales of the Company's common units in the public market;
•
acquisitions and divestitures of assets and businesses by Seadrill; and
•
the Company's business strategy and other plans and objectives for future operations.
We caution readers of this annual report not to place undue reliance on these forward-looking statements, which speak only as of their dates.  We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward looking statement.


ii

PART I

Item 1.         Identity of Directors, Senior Management and Advisers
Not applicable.

Item 2.         Offer Statistics and Expected Timetable
Not applicable.
 
Item 3.        Key Information

A.     Selected Financial Data
The following table presents, in each case for the periods and as of the dates indicated, the Company's selected Consolidated and Combined Carve-Out financial and operating data. The following financial data should be read in conjunction with Item 5 "Operating and Financial Review and Prospects" and the Company's historical Consolidated Financial Statements and the notes thereto included elsewhere in this annual report. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding going concern as described in Note 1 "General information".
 
 
Year Ended December 31,
 
 
2017

2016

2015
 
2014

2013
 
 
(in millions, except per unit data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Total operating revenues (1)
 
$
1,128.4

 
$
1,600.3

 
$
1,741.6

 
$
1,342.6

 
$
1,064.3

Total other operating income
 
90.7

 
—

 
—

 
—

 
—

Total operating expenses
 
(755.6
)
 
(782.2
)
 
(897.9
)
 
(727.8
)
 
(576.6
)
Net operating income
 
463.5

 
818.1

 
843.7

 
614.8

 
487.7

Total financial items
 
(187.9
)
 
(185.9
)
 
(254.7
)
 
(265.4
)
 
(39.1
)
Income before income taxes
 
275.6

 
632.2

 
589.0

 
349.4

 
448.6

Income tax expense
 
(40.3
)
 
(86.5
)
 
(100.6
)
 
(34.8
)
 
(33.2
)
Net income
 
$
235.3

 
$
545.7

 
$
488.4

 
$
314.6

 
$
415.4

Earnings per unit (basic and diluted)
 
 
 
 
 
 
 
 
 
 
Common unitholders
 
$
1.88

 
$
3.20

 
$
2.45

 
$
1.75

 
$
2.15

Subordinated unitholders
 
$
—

 
$
2.28

 
$
2.45

 
$
1.75

 
$
1.83

(1) Total operating revenues include amounts recognized as early termination fees under the offshore drilling contracts which have been terminated prior to the contract end date.
(2) Total other operating income include gains resulting from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015 and gains on sale of assets. Please refer to Note 7 - "Other Operating Income" for further information.
 
 
As of December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(in millions)
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
848.6

 
$
767.6

 
$
319.0

 
$
242.7

 
$
89.7

Drilling units
 
5,170.9

 
5,340.9

 
5,547.3

 
5,141.1

 
3,448.3

Total assets
 
6,530.8

 
6,780.7

 
6,841.1

 
6,268.1

 
4,062.6

Total interest bearing debt
 
3,367.8

 
3,600.6

 
3,840.2

 
3,572.0

 
2,350.5

Total equity
 
2,701.8

 
2,535.8

 
2,097.4

 
2,044.3

 
1,254.6

Please also refer to Note 2 "Accounting policies" to the Consolidated Financial Statements included in this annual report.

1

 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(in millions, except fleet and unit data)
Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
476.2

 
$
873.8

 
$
859.8

 
$
608.7

 
$
564.0

Net cash (used in)/provided by investing activities
 
(11.1
)
 
97.6

 
(376.3
)
 
(1,542.8
)
 
(159.3
)
Net cash (used in)/provided by financing activities
 
(384.9
)
 
(522.1
)
 
(407.6
)
 
1,087.1

 
(336.2
)
Net increase in cash and cash equivalents
 
81.0

 
448.6

 
76.3

 
153.0

 
68.5

Fleet Data (1):
 
 
 
 
 
 
 
 
 
 
Number of drilling units at end of period
 
11

 
11

 
11

 
10

 
8

Average age of drilling units at end of period (years)
 
6.7

 
5.7

 
4.7

 
3.6

 
3.1

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
Capital expenditures (2)
 
$
121.6

 
$
61.1

 
$
68.4

 
$
70.7

 
$
185.8

Distributions declared per unit (3)
 
0.4000

 
0.5500

 
1.9525

 
2.1700

 
1.6775

Members Capital (at end of period):
 
 
 
 
 
 
 
 
 
 
Total members capital (excluding non-controlling interest)
 
1,303.7

 
1,192.6

 
964.3

 
928.2

 
299.0

Common Unitholders—units
 
75,278,250

 
75,278,250

 
75,278,250

 
75,278,250

 
44,400,563

Subordinated Unitholders—units
 
16,543,350

 
16,543,350

 
16,543,350

 
16,543,350

 
16,543,350

(1)
During the year ended December 31, 2013, the Company acquired from Seadrill two tender rigs, the T-15 and the T-16, which the Company holds through a 100% limited liability company interest in Seadrill Partners Operating LLC, the semi-submersible drilling rig, the West Sirius, which the Company holds through its 51% interest in Seadrill Capricorn Holdings LLC, and the semi-submersible drilling rig, the West Leo, which the Company currently holds through its 58% interest in Seadrill Operating LP. These transactions were deemed to be a reorganization of entities under common control and therefore the fleet data has been retroactively adjusted as if the Company had acquired the interests in these units when they began operations under the ownership of Seadrill. As of January 2, 2014, the date of the Company’s first annual general meeting, Seadrill ceased to control the Company as defined by generally accepted accounting principles in the United States ("GAAP") and, therefore, Seadrill Partners and Seadrill are no longer deemed to be entities under common control. As such, acquisitions by the Company from Seadrill subsequent to this date are no longer accounted for under this method.
(2)
Capital expenditures include long term maintenance.
(3)
Distributions attributable to the year. Distributions were declared only with respect to the common units in 2017 and 2016.

B.     Capitalization and Indebtedness
Not applicable.

C.     Reasons for the Offer and Use of Proceeds
Not applicable.

D.     Risk Factors
Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following summarizes risks that may materially affect our business, financial condition, results of operations, cash available for distributions or the trading price of our common units. The occurrence of any of the events described in this section could materially and negatively affect our business, financial condition, results of operations, cash available for the payment of distributions or the trading price of our common units. Unless otherwise indicated, all information concerning our business and our assets is as of December 31, 2017. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.
Risks Relating to Our Reliance on Seadrill
We have close business ties to Seadrill, its affiliates and related companies. In the event that these companies are unable to meet their obligations and liabilities, it could have a material adverse effect on our business.

2
Table of Contents

We depend on certain subsidiaries of Seadrill, including Seadrill Management, to assist us in operating and expanding the business.
Our ability to enter into new drilling contracts and expand our customer and supplier relationships will depend largely on our ability to leverage our relationship with Seadrill and its reputation and relationships in the offshore drilling industry. If Seadrill suffers material damage to its reputation or relationships, it may harm our ability to:
•
renew existing drilling contracts upon their expiration;
•
obtain new drilling contracts;
•
efficiently and productively carry out our drilling activities;
•
successfully interact with shipyards;
•
obtain financing and maintain insurance on commercially acceptable terms; or
•
maintain satisfactory relationships with suppliers and other third parties.
In addition, pursuant to the management and administrative services agreement, Seadrill Management provides us with significant management, administrative, financial and other support services and/or personnel. Subsidiaries of Seadrill also provide advisory, technical and administrative services to our fleet pursuant to advisory, technical and administrative services agreements. Our operational success and ability to execute our growth strategy depends significantly upon the satisfactory performance of these services. Our business may be harmed if Seadrill and its subsidiaries fail to perform these services satisfactorily, if they cancel their agreements with us or if they stop providing these services to us. Please read Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions".
For a description of the advisory, technical and administrative services agreements and the management and administrative services agreement, please read Item 7 “Major Unitholders and Related Party Transactions-Related Party Transactions.” The fees and expenses payable pursuant to the advisory, technical and administrative services agreements and the management and administrative services agreement will be payable without regard to our financial condition or results of operations. The payment of fees to and the reimbursement of expenses of Seadrill Management, and certain other subsidiaries of Seadrill could adversely affect our financial condition, our operational performance and our ability to pay cash distributions to unitholders.
The Company is currently dependent on obtaining management and technical support services from Seadrill .
On September 12, 2017, Seadrill, along with certain of its consolidated subsidiaries (the "Company Parties") entered into a restructuring support and lock-up agreement (RSA) with a group of their senior secured bank lenders, unsecured bondholders, certain other stakeholders and new-money providers. In connection with the RSA, the Company Parties entered into an investment agreement (the “Investment Agreement”) under which Hemen Investments Limited, an affiliate of Seadrill’s largest shareholder Hemen Holding Ltd. and a consortium of investors, including the bondholder parties to the RSA, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions.
On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, Seadrill and the other Company Parties commenced prearranged reorganization proceedings under Chapter 11 of title XI of the United States Code in the Southern District of Texas [case number 17-60079]. During the course of the bankruptcy proceedings, the Debtors continue to operate their business as a debtor in possession.
Whilst we believe we have insulated the Company from events of default related to the Seadrill Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by Seadrill to Seadrill Partners. In the event Seadrill is unable to provide these services as a result of its restructuring or otherwise, Seadrill Partners has the right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace the current manager. This may have an adverse effect on our operations and may negatively impact our cash flows and liquidity.
In addition, several of our credit facilities have clauses that require the current management, administrative and technical support agreements with Seadrill to remain in place. Our facilities also include certain change of control terms and other covenants. Whilst we are currently in compliance with all terms of our credit facilities, there is risk associated with remaining in compliance.
If Seadrill defaults on its indemnity obligations due to its financial condition, it could have a material adverse effect on us. 
Seadrill has agreed to indemnify us for certain liabilities under certain sale and purchase agreements relating to acquisitions from Seadrill subsequent to the IPO and certain of our financing agreements. Under the sale and purchase agreements, Seadrill has agreed to indemnify us against certain tax and toxic tort liabilities with respect to the assets that Seadrill contributed or sold to us to the extent arising prior to the time they were contributed or sold. Under certain of our financing agreements, Seadrill has agreed to indemnify us for any payments or obligations under these agreements that are related to drilling units owned by Seadrill.  If Seadrill is unable to indemnify us against claims under these agreements, it may adversely affect our business, financial position, results of operations or available cash.
We depend on officers and directors who are associated with affiliated companies, which may create conflicts of interest.
Certain of our officers and directors perform services for other companies, including Seadrill. For example, Mark Morris, who is our Chief Executive Officer, also acts as the Chief Financial Officer for Seadrill. In addition, John Roche, who is our Chief Financial Officer, also acts as Vice President of Investor Relations for Seadrill. These other companies conduct substantial businesses and activities of their own in which we have economic interest. As a result, there could be material competition for the time and effort of our officers and directors who also provide services to other companies, which could have a material adverse effect on our business, results of operations and financial condition. Please see Item 6 "Directors, Senior Management and Employees-Directors and Senior Management-Executive Officers".

3
Table of Contents


Risks Relating to Our Company
The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition.
Our business depends on the level of oil and gas exploration, development and production in offshore areas worldwide which is influenced by oil and gas prices and market expectations of potential changes in these prices.
Oil and gas prices are extremely volatile and are affected by several factors beyond our control, including, but not limited to, the following:
•
worldwide production and demand for oil and gas and geographical dislocations in supply and demand;
•
the cost of exploring for, developing, producing and delivering oil and gas;
•
expectations of future energy prices and production;
•
advances in exploration, development and production technology;
•
the ability of the Organization of Petroleum Exporting Countries ("OPEC"), to set and maintain levels and pricing;
•
the level of production in non-OPEC countries;
•
international sanctions on oil-producing countries, or the lifting of such sanctions;
•
government regulations, including restrictions on offshore transportation of oil and natural gas;
•
local and international political, economic and weather conditions;
•
domestic and foreign tax policies;
•
the development and exploitation of alternative fuels and unconventional hydrocarbon production, including shale;
•
worldwide economic and financial conditions and the corresponding impact on the demand for oil and gas and, consequently, our services;
•
the policies of various governments regarding exploration and development of their oil and gas reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and
•
the worldwide political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, eastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.
Declines in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have and could continue to negatively affect our future performance.
Sustained periods of low oil and gas prices have resulted in reduced exploration and drilling activities because oil and gas companies’ capital expenditure budgets are subject to cash flow from such activities and consequently have a dramatic effect on rig demand. In addition, mergers among oil and gas exploration and production companies have reduced, and may further reduce the number of available customers, which would increase the ability of potential customers to achieve favorable pricing terms.
Continued periods of low demand can cause excess rig supply and intensify competition in our industry which often results in drilling rigs, particularly older and less technologically-advanced drilling rigs, being idle for long periods of time. We cannot predict the future level of demand for drilling rigs or future conditions of the oil and gas industry with any degree of certainty. In response to the decrease in the prices of oil and gas, a number of our customers have announced significant decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could further reduce our revenues and materially harm our business.
In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, which could reduce demand for our services and adversely affect our business, including:
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the availability and quality of competing offshore drilling units;
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the availability of financing on reasonable terms;
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the level of costs for associated offshore oilfield and construction services;
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oil and gas transportation costs;
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the level of rig operating costs, including crew and maintenance;
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the discovery of new oil and gas reserves;
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the political environment of oil and gas reserve jurisdictions; and
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regulatory restrictions on offshore drilling.

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The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us locally. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, the condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics compared to our drilling rigs, or expand into service areas where we operate.
Competitive pressures and other factors may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition.
The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.
The oil and gas drilling industry is cyclical, and the industry is currently in a downcycle. The price of Brent crude fell from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. Although there has been some recovery in crude oil prices in recent months, this might not be sustainable and in any event remains significantly below 2014 highs. As of March 31, 2018, the price of Brent crude was approximately $70 per barrel. The significant decrease in oil and natural gas prices may continue to reduce many customers’ demand for our services in 2018 due to significant decreases in budgeted expenditures for offshore drilling.
Declines in capital spending levels, coupled with additional newbuild supply, are likely to continue to intensify price competition and put significant pressure on dayrates and utilization of our rigs.
If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, our units will become idle. When idle, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. Idle units are either "warm" stacked, which means the rig is kept operational and ready for redeployment, and maintains some of its crew, or "cold" stacked, which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed.
We currently have four idle units, the West Sirius, West Leo, West Polaris and West Vencedor. The West Sirius drilling contract was terminated early in April 2015 and the unit is currently stacked. The West Leo was contracted with Tullow until its contract was terminated in December 2016. We have disputed the grounds for termination and commenced litigation proceedings. Subsequently the unit has been stacked. The West Polaris drilling contract completed in December 2017. The West Vencedor drilling contract completed in January 2018 . We have not yet secured new contracts for any of these drilling units.
Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
We do not know when the market for offshore drilling units may recover, or the nature or extent of any future recovery. There can be no assurance that the current demand for drilling rigs will not further decline in future periods. The continued or future decline in demand for drilling rigs would adversely affect our financial position, operating results and cash flows.
Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or intaerrupted
Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period. However, in some cases, such payments may not fully compensate us for the loss of the drilling contract.
Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of non-performance, periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance.
In the current environment our customers may seek to renegotiate our contracts. This may result in lower dayrates or the cancellation of contracts with or without any applicable early termination payments.
Reduced day rates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) would lead to reduced revenues and adversely affect our financial condition, results of our operations and ability to make distributions to unitholders.
We may not be able to refinance existing facilities or raise additional capital on acceptable terms, which may hinder or prevent us from meeting existing obligations and expanding our business.
As of December 31, 2017, we had $3,381.1 million in principal amount of external interest-bearing debt and $24.7 million of related party debt, all of which was secured by, among other things, liens on our drilling units.
In order to continue to repay our indebtedness as it becomes due or at maturity, we will need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings.
Our ability to meet our debt service obligations and repayment obligations will be dependent upon our future performance. Our future cash flows may be insufficient to meet all our debt service obligations. Additional debt or equity financing may also not be available to us in the future for refinancing or repayment of existing indebtedness. Refer to Item 5B "Operating and Financial Review - Liquidity and Capital Resources".

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Our current indebtedness and potential future indebtedness could affect our performance, since a significant portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes.
The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate the repayment of funds that we have borrowed.
Our debt agreements impose operating and financial restrictions on us. These restrictions may prohibit or otherwise limit our ability to undertake certain business activities without consent of the lending banks. These restrictions include:
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executing other financing arrangements;
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incurring additional indebtedness;
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creating or permitting liens on our assets;
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selling our drilling units or the shares of our subsidiaries;
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making investments;
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changing the general nature of our business;
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paying distributions to our unitholders;
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changing the management and/or ownership of the drilling units; and
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making capital expenditures.
Our lenders’ interests may be different from ours and we may not be able to obtain our lenders’ consent for requests that may be beneficial to our business. This may impact our performance.
In addition, several of our debt agreements require us to maintain specified financial ratios and to satisfy covenants, including ratios and covenants that pertain to, among other things, our liquidity and net leverage ratios under our secured credit facilities.
In the future, to the extent our operating results indicate that we may not meet the net leverage ratio of our secured credit facilities, there are a number of actions available which are under management’s control. We cannot provide any assurances that management’s actions will resolve compliance with the leverage ratio or any other financial covenant. In the event that we fail to comply with the covenants in our credit facilities, we would be considered in default, after any applicable notice from our lenders, which would enable applicable lenders to accelerate the repayment of amounts outstanding and exercise remedies, subject to applicable cure or grace periods, and we would need to seek an amendment or waiver from the applicable lender groups. 
Such amendments or waivers from our lenders may be subject to competing interests of the lending institutions. We cannot provide any assurances that we will be able to obtain such an amendment or waiver. If we are not able to obtain waivers or amendments, or if such waivers or amendments have onerous conditions attached, this may limit our ability to make decisions in the best interests of our business.
If we are unable to comply with any of the restrictions and covenants in our current or future debt financing agreements, and we are unable to obtain a waiver or amendment from our lenders for such noncompliance, a default could occur under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable. Our drilling units and equity interests in our subsidiaries serve as security for our secured indebtedness. If our lenders were to foreclose their liens on our drilling units or the equity interests in our subsidiaries in the event of a default, this would impair our ability to continue our operations.
Certain of our loan agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, our other loan agreements also may be in default, which could result in amounts outstanding under those loan agreements to be accelerated and become due and payable. If any of these events occur, we cannot guarantee that our assets will be sufficient to repay in full all of our outstanding indebtedness, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that are favorable or acceptable. Any of these events would adversely affect our ability to make distributions to unitholders and cause a decline in the market price of our common units. For more information, please read Item 5 "Operating and Financial Review and Prospects-Liquidity and Capital Resources."
Our contract backlog for our fleet of drilling units may not be realized.
As of March 31, 2018, our contract backlog was approximately $1.4 billion. The contract backlog presented in this Annual Report and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned will be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, such as the current environment, resulting in lower dayrates.
Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

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We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts have expired or been terminated.
During the most recent period of high utilization and high dayrates, which we believe ended in early 2014, industry participants ordered the construction of new drilling units, which resulted in an over-supply and caused, in conjunction with deteriorating industry conditions, a decline in utilization and dayrates when the new drilling units entered the market. A relatively large number of the drilling units currently under construction have not been contracted for future work, and a number of units in the existing worldwide fleet are currently off-contract.
As of March 31, 2018, we have seven drilling units either on contract or mobilizing for operations. Two of these contracts expire in 2018, three expire in 2019 and two expire in 2020.Our ability to renew these contracts or obtain new contracts will depend on our customers and prevailing market conditions, which may vary among different geographic regions and types of drilling units. Customers may also choose not to award drilling contracts to us due to our links with Seadrill and its current Chapter 11 proceedings.
We estimate that approximately 52% of the global fleet of drillships and semi-submersible drilling rigs are off-contract and that the global order book for floaters is 42 rigs. We estimate the equivalent figures for tender rigs are 60% and 6 units.
If we are not able to obtain new contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable than existing contract terms, our revenues and profitability would be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and not be able to pass such additional risks onto our subcontractors, or be unable or unwilling to insure ourselves against any additional risk at competitive prices. This could lead to us being unable to meet our liabilities in the event of a catastrophic event on one of our rigs.
The market value of our drilling units may further decrease.
The market values of drilling units have declined as a result of the recent continued decline in the price of oil, which has been impacted by the spending plans of our customers. If the offshore contract drilling industry suffers further adverse developments in the future, the fair market value of our drilling units may decline further. The fair market value of the drilling units that we currently own, or may acquire in the future, may increase or decrease depending on a number of factors, including:
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the general economic and market conditions affecting the offshore drilling industry, including competition from other offshore contract drilling companies;
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the types, sizes and ages of drilling units;
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the supply and demand for drilling units;
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the costs of newbuild drilling units;
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the prevailing level of drilling services contract dayrates;
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governmental or other regulations; and
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technological advances.
If drilling unit values fall significantly, we may have to record an impairment adjustment in our Consolidated Financial Statements, which could adversely affect our financial results and condition. Additionally, if we sell one or more of our drilling units at a time when drilling unit prices have fallen, the sale price may be less than the drilling unit’s carrying value in our Consolidated Financial Statements, resulting in a reduction in earnings.
Our business and operations involve numerous operating hazards, and in the current market we are increasingly required to take additional contractual risk in our customer contracts and we may not be able to procure insurance to adequately cover potential losses.
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-through, cratering, fires, explosions and pollution. Contract drilling and well servicing requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations.
Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.
Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies.
Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these customers will be willing or financially able to indemnify us against all these risks.

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In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. Further, pollution and environmental risks generally are not totally insurable.
If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our financial condition, results of our operations, cash flows and ability to make distributions to unitholders.
The amount recoverable under insurance may also be less than the related impact on enterprise value after a loss. Our insurance policies may not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs.
Our insurance provides for deductibles for damage to its offshore drilling equipment and third-party liabilities. With respect to hull and machinery, our insurance provides for a deductible per occurrence of $5 million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss is fully covered by its insurance with no deductible. For general and marine third-party liabilities our insurance provides for up to a $0.5 million deductible per occurrence on personal injury liability for crew claims as well as non-crew claims and per occurrence on third-party property damage.
We could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts.
No assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or that we will be able to obtain insurance against certain risks.
We derive the majority of our revenue from a small number of customers, and the loss of any of these customers could result in a material loss of revenues and cash flow.
We are subject to the risks associated with having a limited number of customers for our services. We currently derive the majority of our revenues and cash flow from a small number of customers. For the year ended December 31, 2017, BP accounted for 56.8%, ExxonMobil accounted for 22.2% and Chevron accounted for 7.9% of our total revenues, respectively. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services, or cancel or re-negotiate our contracts.
We are subject to risks of loss resulting from non-payment or non-performance by our customers and certain other third parties. Some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Any material non-payment or non-performance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.
Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs.
Our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. A significant portion of our operating costs may be fixed over the short term.
The majority of our contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, most of our long-term contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semiannually, and therefore may be outdated at the time of adjustment. The adjustments are typically performed on a semi-annual or annual basis. For these reasons, the timing and amount received as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance. In such contracts, the dayrate could be adjusted lower during a period when costs of operation rise, which could adversely affect our financial performance. Shorter-term contracts normally do not contain escalation provisions. In addition, our contracts typically contain provisions for either fixed or dayrate compensation during mobilization. These rates may not fully cover our costs of mobilization, and mobilization may be delayed, increasing our costs, without additional compensation from the customer, for reasons beyond our control.
In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. Expenses may vary based on the scope and length of such required preparations and the duration of the contractual period over which such expenditures are amortized.
Equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment. Our operating expenses and maintenance costs depend on a variety of factors, including crew costs, provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control.
In situations where our drilling units incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling units is limited, as the crews will be engaged in preparing the unit for its next contract. When a unit faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to redeploy crew members, who are not required to maintain the drilling unit, to active rigs, to the extent possible. However, there can be no assurance that we will be successful in reducing our costs in such cases.
Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services. Please see "The success and growth of

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our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition", "Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted" and "We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts which have expired or been terminated". This could adversely affect our revenue from operations.
Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies
We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including, but not limited to, drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. With respect to certain items, such as blow-out preventers ("BOPs"), we are dependent on the original equipment manufacturer for repair and replacement of the item or its spare parts. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. These cost increases or delays could have a material adverse effect on our results of operations and result in rig downtime, and delays in the repair and maintenance of our drilling rigs.
We may be unable to obtain, maintain, and/or renew permits necessary for our operations or experience delays in obtaining such permits including the class certifications of rigs
The operation of our drilling units is subject to certain governmental approvals, the number and prerequisites of which cannot be determined until we identify the jurisdictions in which we will operate on securing contracts for the drilling units. Depending on the jurisdiction, these governmental approvals may involve public hearings and costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to timely secure the necessary approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.
Every offshore drilling unit is a registered marine vessel and must be "classed" by a classification society to fly a flag. The classification society certifies that the drilling unit is "in-class," signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our drilling units are certified as being "in class" by the American Bureau of Shipping, or ABS, Det Norske Veritas and Germanisher Lloyd, or DNV GL, and the relevant national authorities in the countries in which our drilling units operate. If any drilling unit loses its flag, does not maintain its class and/or fails any periodical survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable. Any such inability to carry on operations or be employed could have a material adverse impact on the results of operations.
The international nature of our operations involves additional risks including foreign government intervention in relevant markets.
We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, particular in less developed jurisdictions, including risks of:
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terrorist acts, armed hostilities, war and civil disturbances;
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acts of piracy, which have historically affected ocean-going vessels;
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significant governmental influence over many aspects of local economies;
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the seizure, nationalization or expropriation of property or equipment;
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uncertainty of outcome in foreign court proceedings;
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the repudiation, nullification, modification or renegotiation of contracts;
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limitations on insurance coverage, such as war risk coverage, in certain areas;
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political unrest;
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foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
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the inability to repatriate income or capital;
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complications associated with repairing and replacing equipment in remote locations;
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import-export quotas, wage and price controls, and the imposition of trade barriers;
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U.S. and foreign sanctions or trade embargoes;
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compliance with various jurisdictional regulatory or financial requirements;
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compliance with and changes in taxation;
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other forms of government regulation and economic conditions that are beyond our control; and
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governmental corruption.

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In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:
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the equipping and operation of drilling units;
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exchange rates or exchange controls;
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the repatriation of foreign earnings;
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oil and gas exploration and development;
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the taxation of offshore earnings and the earnings of expatriate personnel; and
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the use and compensation of local employees and suppliers by foreign contractors.
Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, the denial of export privileges, injunctions or seizures of assets.
Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations.
Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.
Accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures or operational changes to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity.
Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from the failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, the seizure of shipments, and the loss of import and export privileges.
Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment.
New laws or other governmental actions that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or to the offshore drilling industry, in particular, could adversely affect our performance.
The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.
We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to the requirements of United Nation’s International Maritime Organization (the "IMO"), the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended ("MARPOL"), including the designation of Emission Control Areas ("ECAs") thereunder, the International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended (the "CLC"), the International Convention on Civil Liability for Bunker Oil Pollution Damage (the "Bunker Convention"), the International Convention for the Safety of Life at Sea of 1974, as from time to time amended ("SOLAS"), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the "ISM Code"), the International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 (the "BWM Convention"), the U.S. Oil Pollution Act of 1990 (the "OPA"), the rules and regulations of the U.S. Environmental Protection Agency (the "EPA"), the U.S. Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the U.S Clean Water Act, the U.S Clean Air Act, the U.S. Maritime Transportation Security Act of 2002, the U.S. Outer Continental Shelf Lands Act and certain regulations of the European Union, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or implementation of operational changes and may affect the resale value or useful lifetime of our drilling units. These costs could have a material

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adverse effect on our business, results of operations, cash flows and financial condition. A 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. Because such conventions, laws, and regulations are often revised, we cannot predict the ultimate cost of complying with them or the impact thereof on the resale prices or useful lives of our rigs. Additional conventions, laws and regulations may be adopted which could limit our ability to do business or increase the cost of our doing business and which may materially adversely affect our operations.
Environmental laws often impose strict liability for the remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the 200-mile exclusive economic zone around the United States. An oil or chemical spill, for which we are deemed a responsible party, could result in us incurring significant liability, including fines, penalties, criminal liability and remediation costs for natural resource damages under other federal, state and local laws, as well as third-party damages, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, the 2010 explosion of the Deepwater Horizon well and the subsequent release of oil into the Gulf of Mexico, or other similar events, may result in further regulation of the shipping industry, and modifications to statutory liability schemes, thus exposing us to further potential financial risk in the event of any such oil or chemical spill.
We are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to our operations, and satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. Although we have arranged insurance to cover certain environmental risks, there can be no assurance that such insurance will be sufficient to cover all such risks or that any claims will not have a material adverse effect on our business, results of operations, cash flows and financial condition.
Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Our drilling units could cause the release of oil or hazardous substances. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling rigs, clean up the releases and comply with more stringent requirements in our discharge permits. Moreover, these releases may result in our customers or governmental authorities suspending or terminating our operations in the affected area, which could have a material adverse effect on our business, results of operations and financial condition.
We are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 case related to the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy.
Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act 1977 or the UK Bribery Act 2010, could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.
We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. We interact with government regulators, licensor's, port authorities and other government entities and officials. Also, our business interaction with national oil companies as well as state or government-owned shipbuilding enterprises and financing agencies puts us in contact with persons who may be considered to be "foreign officials" under the U.S. Foreign Corrupt Practices Act of 1977 (the "FCPA") and the Bribery Act 2010 of the United Kingdom (the "UK Bribery Act"). We are subject to the risk that we or our affiliated companies or our or their respective officers, directors, employees and agents may take actions determined to be in violation of anti-corruption laws, including the FCPA and the U.K. Bribery Act. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
In order to effectively compete in some foreign jurisdictions, we utilize local agents and/or establish entities with local operators or strategic partners. For example, in Nigeria, Nigerian investors had invested in a subsidiary of Seadrill Operating LP that is fully controlled and approximately 56% owned by Seadrill Operating LP, and resulted in a Nigerian joint venture partner owning an effective 1% interest in the West Capella. Seadrill owns the remaining ownership interest in the joint venture. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violations of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business and results of operation.

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If our drilling units are located in countries that are subject to or targeted by economic sanctions, export restrictions, or other operating restrictions imposed by the United States or other governments, our reputation and the market for our debt and common units could be adversely affected.
The U.S. and other governments impose economic sanctions against certain countries, persons and other entities that restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran, and others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. U.S. and other economic sanctions change frequently and enforcement of economic sanctions worldwide is increasing.
In 2010, the United States enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours, and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose in their annual and quarterly reports filed with the Commission after February 6, 2013 if the issuer or “any affiliate” has “knowingly” engaged in certain sanctioned activities involving Iran during the timeframe covered by the report. At this time, we are not aware of any violation conducted by us or by any affiliate, which is likely to trigger such a disclosure requirement.
On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the “Joint Plan of Action,” or the JPOA. Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is only used for peaceful purposes, the United States and the European Union would voluntarily suspend certain sanctions for a period of six months. On January 20, 2014, the United States and the European Union began implementing the temporary relief measures provided for under the JPOA.
The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the European Union announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA, to significantly restrict Iran’s ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and not involving U.S. persons. On January 16, 2016, or the Implementation Day, the United States joined the European Union and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the IAEA, that Iran had satisfied its respective obligations under the JCPOA.
U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time. Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders. These sanctions will not be permanently "lifted" until the earlier of “Transition Day,” set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities.
On October 13, 2017, the current U.S administration announced it would not certify Iran's compliance with the JCPOA. This did not withdraw the U.S. from the JCPOA or re-instate any sanctions. However, they have criticized the JCPOA and threatened to withdraw the U.S. from the JCPOA. Further, the administration must periodically renew sanctions waivers and his refusal to do so could result in the reinstatement of certain sanctions currently suspended under the JCPOA.
OFAC acted several times in 2017 to add Iranian individuals and entities to its list of Specially Designated Nationals whose assets are blocked and with whom U.S. persons are generally prohibited from dealing. Moreover, in August 2017, the U.S. passed the “Countering America’s Adversaries Through Sanctions Act” (Public Law 115-44) (CAATSA), which authorizes imposition of new sanctions on Iran, Russia, and North Korea. The CAATSA sanctions with respect to Russia create heightened sanctions risks for companies operating in the oil and gas sector, including companies that are based outside of the United States. OFAC sanctions targeting Venezuela have likewise increased in the past year, and any new sanctions targeting Venezuela could further restrict our ability to do business in such country. In addition to the sanctions against Iran, subject to certain limited exceptions, U.S. law continues to restrict U.S. owned or controlled entities from doing business with Cuba and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing and enforcing sanctions regimes.
From time to time, we may enter into drilling contracts with countries or government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism where entering into such contracts would not violate U.S. law, or may enter into drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism. However, this could negatively affect our ability to obtain investors. In some cases, U.S. investors would be prohibited from investing in an arrangement in which the proceeds could directly or indirectly be transferred to or may benefit a sanctioned entity. Moreover, even in cases where the investment would not violate U.S. law, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our units. We do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism.

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Certain parties with whom we have entered into contracts may be the subject of sanctions imposed by the United States, the European Union or other international bodies as a result of the annexation of Crimea by Russia in March 2014 and the subsequent conflict in eastern Ukraine, or may be affiliated with persons or entities that are the subject of such sanctions. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected or we may suffer reputational harm. We may also lose business opportunities to companies that are not required to comply with these sanctions.
As stated above, we believe that we are in compliance with all applicable economic sanctions and embargo laws and regulations, and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Rapid changes in the scope of global sanctions may also make it more difficult for us to remain in compliance. Any violation of applicable economic sanctions could result in civil or criminal penalties, fines, enforcement actions, legal costs, reputational damage, or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our units. Additionally, some investors may decide to divest their interest, or not to invest, in our units simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our drilling rigs, and those violations could in turn negatively affect our reputation. Investor perception of the value of our units may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.
Continuing challenges in the world economy could have a material adverse effect on our revenue, profitability and financial position.
We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain eurozone countries and their ability to meet future financial obligations and the overall stability of the euro. An extended period of adverse development in the outlook for European countries could reduce the overall demand for oil and natural gas and for our services. These potential developments, or market perceptions concerning these and related issues, could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.
In addition, worldwide financial and economic conditions could cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us.
A portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.
In June 2016, the UK voted to exit from the E.U. (commonly referred to as "Brexit"). The impact of Brexit and the resulting UK/ EU relationship are uncertain for companies doing business both in the UK and the overall global economy.
An extended period of adverse development in the outlook for the world economy could reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our financial condition, results of operations, cash flows and our ability to make distributions to our unitholders.
Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund our capital expenditures. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations or interpretations thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.
Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic or deepwater locations, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, concentrating drilling units in regions with relatively fewer reductions in activity leading to greater competition.
If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us or at all for the remaining installment payments we are obligated to make before the delivery of our remaining newbuildings and our other capital requirements, including principal repayments.
Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.
We require highly skilled personnel in the right locations to operate and provide support for our business.
Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased, and this may continue to rise. Notwithstanding the general downturn in the drilling industry, in some regions, such as Western Africa, the limited availability of qualified personnel in combination with local regulations focusing on crew composition, are expected to further increase the demand for qualified offshore drilling crews, which may increase our costs. These factors could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.

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Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. Any such downtime or cancellation could adversely affect our financial condition, results of operations and ability to make distributions to our unitholders.
Labor costs and operating restrictions that apply could increase following collective bargaining negotiations and changes in labor laws and regulations.
Some of our employees are represented by collective bargaining agreements. The majority of these employees work in Nigeria and Angola. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and is restricted in its ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.
Interest rate fluctuations could affect our earnings and cash flow.
In order to finance our growth, we have incurred significant amounts of debt. The majority of our debt arrangements have floating interest rates. As such, significant movements in interest rates could have an adverse effect on our earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we use interest rate swaps to effectively fix a part of our floating rate debt obligations. The principal amount covered by interest rate swaps is evaluated continuously and determined based on our debt level, our expectations regarding future interest rates and our overall financial risk exposure. Although we enter into various interest rate swap transactions to manage exposure to movements in interest rates, there can be no assurance that we will be able to continue to do so at a reasonable cost or at all.
If we are unable to effectively manage our interest rate exposure through interest rate swaps in the future, any increase in market interest rates would increase our interest rate exposure and debt service obligations, which would exacerbate the risks associated with our leveraged capital structure.
Fluctuations in exchange rates and the non-convertibility of currencies could result in losses to us.
As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. dollars. Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available in the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.
We use the U.S. dollar as our functional currency because the majority of our revenues and expenses are denominated in U.S. dollars. Accordingly, our reporting currency is also U.S. dollars. We do, however, earn revenues and incur expenses in other currencies, and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.
Brexit, or similar events in other jurisdictions, could impact global markets, which may have an adverse impact on our business and operations as a result of changes in currency, exchange rates, tariffs, treaties and other regulatory matters.
A change in tax laws in any country in which we operate could result in higher tax expense.
We conduct our operations through various subsidiaries in countries throughout the world. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between the countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, which is beyond our control, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings. For example, Nigeria announced in 2015 that the tax regime was to change from a deemed profit percentage of revenue to an actual profit regime, the calculation of which is broadly based on 30% of income before tax. Other such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development. In addition, the United States in December 2017 enacted major tax reform legislation.  This could lead to a material increase in the amount of overall U.S. tax liabilities of the group if it reduces the tax deductions for certain payments our U.S. operating companies make to non-U.S. rig owners. The extent of the impact is still being analyzed especially given a number of subsequent regulations which may be issued and will need to be interpreted with advisers as necessary.
A loss of a major tax dispute or a successful tax challenge to our tax positions, including our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.
Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions that we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any of our tax positions, including our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.

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Climate change and the regulation of greenhouse gases could have a negative impact on our business.
Due to concern over the risk of climate change, a number of countries and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions. The 2015 United Nations Climate Change Conference in Paris did not result in an agreement that directly limits greenhouse gas emissions from ships. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee (the "MEPC") in July 2011, relating to greenhouse gas emissions. The European Union has indicated that it intends to propose an expansion of the existing EU Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels.
Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our assets, and might also 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. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level, which restricts emissions of greenhouse gases, could require us to make significant financial expenditures which we cannot predict with certainty at this time.
Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for the use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business, including capital expenditures to upgrade our drilling rigs, which we cannot predict with certainty at this time.
In addition, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climate events. If any such effects were to occur, they could adversely affect or delay demand for oil or gas, and thereby adversely affect demand for our services, or cause us to incur significant costs in preparing for or responding to those effects.
Acts of terrorism, piracy, cyber-attack, political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism, piracy, and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. Our drilling operations could also be targeted by acts of sabotage carried out by environmental activist groups.
We rely on information technology systems and networks in our operations and administration of our business. Our drilling operations or other business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to an unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.
In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.
We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.
We are currently involved in various litigation matters, and we anticipate that we will be involved in litigation matters from time to time in the future. For example, we are currently involved in litigation regarding the West Leo in which the customer is withholding payment for our services. This has adversely affected and may continue to adversely affect our revenues. Also, the operating hazards inherent in our business expose us to litigation, including personal injury litigation, environmental litigation, contractual litigation with customers, intellectual property litigation, tax or securities litigation and maritime lawsuits, including the possible arrest of our drilling units. We may be subject to significant legal costs in defending any legal actions, which we may or may not be able to recoup depending on the results of such claim. We cannot predict with certainty the outcome or effect of any claim or other litigation matter, or a combination of these. If we are involved in any future litigation, or if our positions concerning current disputes are found to be incorrect, there may be an adverse effect on our business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits, and the diversion of management’s attention to these matters.
For additional information regarding litigation matters that we are currently involved in, please see "Item 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings".

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We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.
The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over an infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services or replacement parts, or could be required to cease using some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of these technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have indemnity provisions in some of our supply contracts to give us some protection from the supplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will have sufficient financial standing to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes. For information on certain intellectual property litigation that we are currently involved in, please see “Item 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings".
The failure to consummate or integrate acquisitions in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.
We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Under the Omnibus Agreement, subject to certain exceptions, Seadrill is obligated to offer to us any of its drilling units acquired or placed under drilling contracts of five or more years. Although we are not obligated to purchase any of these drilling units offered by Seadrill, any acquisition could involve the payment of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain acquisition and investment opportunities may not result in the consummation of a transaction. In addition, we may not be able to obtain acceptable terms for the required financing for any such acquisition or investment that arises. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of its common units. Our future acquisitions could present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management’s attention from existing operations or other priorities. We may also be subject to additional costs related to compliance with various international laws in connection with such acquisition. If we fail to consummate and integrate its acquisitions in a timely and cost-effective manner, its financial condition, results of operations and cash available for distribution could be adversely affected.
Public health threats could have an adverse effect on our operations and financial results.
Public health threats, such as Ebola, influenza, SARS, the Zika virus, and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world in which we operate, could adversely impact our operations, and the operations of our customers. In addition, public health threats in any area, including areas where we do not operate, could disrupt international transportation. Our crews generally work on a rotation basis, with a substantial portion relying on international air transport for rotation. Any such disruptions could impact the cost of rotating our crews, and possibly impact our ability to maintain a full crew on all rigs at a given time. Any of these public health threats and related consequences could adversely affect our financial results.
Data protection and regulations related to privacy, data protection and information security could increase our costs, and our failure to comply could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations, as well as have an impact on our reputation.
We are subject to regulations related to privacy, data protection and information security in the jurisdictions in which we do business. As privacy, data protection and information security laws are interpreted and applied, compliance costs may increase, particularly in the context of ensuring that adequate data protection and data transfer mechanisms are in place.

In recent years, there has been increasing regulatory enforcement and litigation activity in the areas of privacy, data protection and information security in the U.S. and in various countries in which we operate. In addition, legislators and/or regulators in the U.S., the European Union and other jurisdictions in which we operate are increasingly adopting or revising privacy, data protection and information security laws that could create compliance uncertainty and could increase our costs or require us to change our business practices in a manner adverse to our business. For example, the European Union and U.S. Privacy Shield framework was designed to allow for legal certainty regarding transfers of data. However, the agreement itself faces a number of legal challenges and is subject to annual review. This has resulted in some uncertainty and compliance obligations with regards to cross-border data transfers. Moreover, compliance with current or future privacy, data protection and information security laws could significantly impact our current and planned privacy, data protection and information security related practices, our collection, use, sharing, retention and safeguarding of consumer and/or employee information, and some of our current or planned business activities. Our failure to comply with privacy, data protection and information security laws could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations and overall business, as well as have an impact on our reputation. For example, the General Data Protection Regulations of the European Union is enforceable in all 28 EU member states as of May 25, 2018 and will require us to undertake enhanced data protection safeguards, with fines for non-compliance up to 4% of global total annual worldwide turnover or €20 million (whichever is higher), depending on the type and severity of the breach.

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Risks Relating to an Investment in our Units
The market price of our common units has fluctuated widely and may fluctuate widely in the future
The market price of our common units has fluctuated widely and may continue to do so as a result of many factors, such as actual or anticipated fluctuations in our operating results, changes in our distributions. changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Further, there may be no continuing active or liquid public market for our common units. If an active trading market for our common units does not continue, the price of our common units may be more volatile and it may be more difficult and time consuming to complete a transaction in the common units, which could have an adverse effect on the realized price of the common units. In addition, an adverse development in the market price for our common units could negatively affect our ability to issue new equity to fund our activities. For our common unit price history, refer Item 9A "Offer and Listing Details".
Increases in interest rates may cause the market price of our common units to decline.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.
Because our ownership interest in OPCO currently represents our only cash-generating asset, our cash flow depends completely on OPCO’s ability to make distributions to its owners, including us.
Our cash flow depends completely on OPCO’s distributions to us. The amount of cash OPCO distributes may fluctuate from quarter to quarter based on our operational and financial performance which is subject to the risk factors set out above, "Risks Relating to our Company".
The actual amount of cash OPCO has available for distribution also depends on our cash flow which is subject to the risk factors set out above, "Risks Relating to our Company".
OPCO’s operating agreements provide that it will distribute its available cash to its owners on a quarterly basis. OPCO’s available cash includes cash on hand less any reserves that may be appropriate for operating its business. The amount of OPCO’s quarterly distributions, including the amount of cash reserves not distributed, is determined by our board of directors (the "Board").
The amount of cash OPCO generates from operations may differ materially from its profit or loss for the period, which is affected by non-cash items. As a result of this and the other factors mentioned above, OPCO may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.
We may not pay distributions in the future including the minimum quarterly distribution on common units and subordinated units.
The source of our earnings and cash flow consists exclusively of cash distributions from OPCO. Therefore, the amount of cash distributions we are able to make to our unitholders fluctuates, based on the level of distributions made by OPCO to its owners, including us, and the level of cash distributions made by OPCO's operating subsidiaries to OPCO. OPCO or any such operating subsidiaries may make quarterly distributions at levels that will not permit us to make distributions to our common unitholders at the minimum quarterly distribution level or to increase our quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if OPCO increases or decreases 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 OPCO to us.
Our ability to distribute to unitholders any cash we may receive from OPCO or any future operating subsidiaries is or may be limited by a number of factors, including, among others:
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interest expense and principal payments on any indebtedness we may incur;
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restrictions on distributions contained in any of our current or future debt agreements;
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fees and expenses of us, the Seadrill Member, its affiliates or third parties we are required to reimburse or pay; and
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reserves the Board believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.
Many of these factors will reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we make may not be at or above the minimum quarterly distribution. For example, beginning in February 2016, we ceased paying distributions on the subordinated units and reduced our quarterly distribution to common units below the minimum quarterly distribution. The actual amount of cash that is available for distribution to our unitholders depends on several factors, many of which are beyond our control.
Our level of debt and restrictions in our debt agreements may prevent us from paying distributions.
The payment of principal and interest on our debt will reduce cash available for distribution to us and our unitholders. Our and OPCO’s financing agreements contain restrictions on our or OPCO's ability to pay distributions to our unitholders or to us, respectively, under certain circumstances. In addition, our financing agreements contain provisions that, upon the occurrence of certain events, permit lenders to terminate their commitments and/or accelerate the outstanding loans and declare all amounts due and payable, which may prevent us from paying distributions to our unitholders.
Any adverse change in the level of risk to us of exogenous factors influencing our performance could prevent us from paying distributions including, but not limited to, economic conditions in both the industry and the world, legislation in different jurisdictions, interest rates and levels of taxation. Please see "Risks Relating to our Company".

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Restrictions under Marshall Islands law may prevent us from paying distributions.
We or OPCO may be unable to pay distributions due to restrictions under Marshall Islands law. Under the Marshall Islands Limited Liability Company Act of 1996 (the "Marshall Islands Act"), we may not make a distribution to our unitholders if, after giving effect to the distribution, all our liabilities, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to our specified property, 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 our property exceeds that liability. Identical restrictions exist on the payment of distributions by OPCO to its equityholders. Moreover, our subsidiaries that are not organized in the Marshall Islands and are subject to certain restrictions on payment of distributions pursuant to the law of their jurisdictions of organization.
Our common unitholders have limited voting rights compared to the Seadrill Member, who may favor its own interests to the detriment of the common unitholders.
As of March 31, 2018, Seadrill owned 34.9% of our common units and 100% of our subordinated units, and owned and controlled the Seadrill Member. Certain of our officers and directors are directors and/or officers of Seadrill and its subsidiaries and, as such, they have fiduciary duties to Seadrill that may cause them to pursue business strategies that disproportionately benefit Seadrill or which otherwise are not in the best interests of us or our unitholders. Conflicts of interest may arise between Seadrill and its subsidiaries on the one hand, and us and our unitholders, on the other hand. Although a majority of our Board is elected by common unitholders, the Seadrill Member will likely have substantial influence on decisions made by the Board. Refer to Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions".
These conflicts include, among others, the following situations:
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neither our operating agreement nor any other agreement requires the Seadrill Member or Seadrill or its affiliates to pursue a business strategy that favors us or utilizes our assets, and Seadrill’s officers and directors have a fiduciary duty to make decisions in the best interests of the shareholders of Seadrill, which may be contrary to our interests;
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our operating agreement provides that the Seadrill Member may make determinations to take or decline to take actions without regard to the interests of us or our unitholders. Specifically, the Seadrill Member may exercise its call right, pre-emptive rights, registration rights or right to make a determination to receive common units in exchange for resetting the target distribution levels related to the incentive distribution rights, consent or withhold consent to any merger or consolidation of us, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our operating agreement that require a vote of the outstanding units, voluntarily withdraw from us, transfer (to the extent permitted under our operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon our dissolution;
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the Seadrill Member and our directors and officers have limited their liabilities and any fiduciary duties they may have under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders, and, as a result of purchasing common units, unitholders are treated as having agreed to the modified standard of fiduciary duties and to certain actions that may be taken by the Seadrill Member and our directors and officers, all as set forth in the operating agreement;
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the Seadrill Member is entitled to reimbursement of all costs incurred by it and its affiliates for our benefit;
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our operating agreement does not restrict us from paying the Seadrill Member 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;
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the Seadrill Member may exercise its right to call and purchase our common units if it and its affiliates own more than 80% of our common units; and
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the Seadrill Member is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of its limited call right.
The resolution of these conflicts may conflict with our interests and the interests of our unitholders.
Although we control OPCO, we owe duties to OPCO and its other owner, Seadrill, which may conflict with our interests and the interests of our unitholders.
Conflicts of interest may arise because of the relationships between us and our unitholders, on the one hand, and OPCO, and its other owner, Seadrill, on the other hand. Seadrill owns a 42% limited partner interest in Seadrill Operating LP, a 49% limited liability company interest in Seadrill Capricorn Holdings LLC and a 100% limited liability company interest in the Seadrill Member. Our directors have duties to manage OPCO in a manner beneficial to us. At the same time, our directors have a duty to manage OPCO in a manner beneficial to OPCO’s owners, including Seadrill. For example, conflicts of interest may arise in the following situations:
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the allocation of shared overhead expenses between us and OPCO;
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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and OPCO or its subsidiaries, on the other hand;
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the determination and timing of the amount of cash to be distributed to OPCO’s owners and the amount of cash to be reserved for the future conduct of OPCO’s business;
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the decision as to whether OPCO should make asset or business acquisitions or dispositions, and on what terms;
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the determination of the amount and timing of OPCO’s capital expenditures;

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the determination of whether OPCO should use cash on hand, borrow or issue equity to raise cash to finance maintenance or expansion capital projects, repay indebtedness, meet working capital needs or otherwise; and
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any decision we make to engage in business activities independent of, or in competition with, OPCO.
The resolution of these conflicts may conflict with our interests and the interests of our unitholders.
Our operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Seadrill Member, and even if public unitholders are dissatisfied, they will be unable to remove the Seadrill Member without Seadrill’s consent, unless Seadrill’s ownership interest in us is decreased; all of which could diminish the trading price of our common units.
Our operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Seadrill Member.
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The unitholders are unable to remove the Seadrill Member without its consent because the Seadrill Member and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove the Seadrill Member. As of March 31, 2018, Seadrill owned 46.6% of the outstanding common and subordinated units.
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If the Seadrill Member is removed without “cause” during the subordination period and units held by the Seadrill Member and Seadrill are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units, any existing arrearages on the common units will be extinguished, and the Seadrill Member will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. A removal of the Seadrill Member under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we have met certain distribution and performance tests. Any conversion of the Seadrill Member interest or incentive distribution rights would be dilutive to existing unitholders. Furthermore, any cash payment in lieu of such conversion could be prohibitively expensive. “Cause” is narrowly defined to mean that with respect to a director or officer, a court of competent jurisdiction has entered a final, non-appealable judgment finding such director or officer liable for actual fraud or willful misconduct, and with respect to the Seadrill Member, the Seadrill Member is in breach of the operating agreement or a court of competent jurisdiction has entered a final, non-appealable judgment finding the Seadrill Member liable for actual fraud or willful misconduct against us or our members, in their capacity as such. Cause does not include most cases of charges of poor business decisions, such as charges of poor management of our business by the directors appointed by the Seadrill Member, so the removal of the Seadrill Member because of the unitholders’ dissatisfaction with the Seadrill Member’s decisions in this regard would most likely result in the termination of the subordination period.
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Common unitholders are entitled to elect up to four of the members of the Board. The Seadrill Member in its sole discretion appoints the remaining three directors.
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Election of the four directors elected by unitholders is staggered, meaning that the members of only one of three classes of our elected directors are selected each year. In addition, the directors appointed by the Seadrill Member serve for terms determined by the Seadrill Member.
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Our operating agreement contains provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about our operations as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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Unitholders’ voting rights are further restricted by the operating agreement provision providing that if any person or group owns beneficially more than 5% of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board are not subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
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There are no restrictions in our operating agreement on our ability to issue additional equity securities.
The effect of these provisions may be to diminish the price at which the common units trade.

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In establishing cash reserves, the Board may reduce the amount of cash available for distribution to the unitholders.
OPCO’s operating agreements provide that we approve the amount of reserves from OPCO’s cash flow that will be retained by OPCO to fund its future operating and capital expenditures. Our operating agreement requires the Board to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating and capital expenditures. These reserves also affect the amount of cash available for distribution by OPCO to us, and by us to unitholders. In addition, the Board may establish reserves for distributions on the subordinated units, but only if those reserves do not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. Our operating agreement requires the Board each quarter to deduct from operating surplus estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, which could reduce the amount of available cash for distribution. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by the Board at least once a year, provided that any change must be approved by the conflicts committee of the Board.
Unitholders have limited voting rights, and our operating agreement restricts the voting rights of the unitholders owning more than 5% of our common units.
Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. We hold a meeting of the members every year to elect one or more members of the Board and to vote on any other matters that are properly brought before the meeting. Common unitholders are entitled to elect only four of the seven members of the Board. The elected directors are elected on a staggered basis and serve for three year terms. The Seadrill Member in its sole discretion appoints the remaining three directors and sets the terms for which those directors will serve. The operating agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unitholders have no right to elect the Seadrill Member, and the Seadrill Member may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding common and subordinated units, including any units owned by the Seadrill Member and its affiliates, voting together as a single class.
Our operating agreement further restricts unitholders’ voting rights by providing that if any person or group owns beneficially more than 5% of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board are not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
Our operating agreement may limit the duties of the Seadrill Member and our directors and officers to our unitholders and restricts the remedies available to our unitholders for actions taken by the Seadrill Member or our directors and officers.
Our operating agreement provides that the Board has the authority to oversee and direct our operations, management and policies on an exclusive basis. The Marshall Islands Act states that a member's or manager’s "duties and liabilities may be expanded or restricted by provisions in a limited liability company agreement." As permitted by the Marshall Islands Act, our operating agreement contains provisions that reduce the standards to which the Seadrill Member and our directors and officers may otherwise be held by Marshall Islands law. For example, our operating agreement:
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provides that the Seadrill Member may make determinations or take or decline to take actions without regard to the interests of us or our unitholders. The Seadrill Member may consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or our unitholders. Decisions made by the Seadrill Member are made by its sole owner, Seadrill. Specifically, the Seadrill Member may decide to exercise its right to make a determination to receive common units in exchange for resetting the target distribution levels related to the incentive distribution rights, call right, pre-emptive rights or registration rights, consent or withhold consent to any merger or consolidation, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our operating agreement that require a vote of the outstanding units, voluntarily withdraw from us, transfer (to the extent permitted under our operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon our dissolution;
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provides that the Board and officers are entitled to make other decisions in "good faith," meaning they believe that the decision is in our best interests;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," the Board may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
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provides that neither the Seadrill Member nor our officers or directors will be liable for monetary damages to us, our members or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Seadrill Member, our directors or officers or those other persons engaged in actual fraud or willful misconduct.

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The standard of care applicable to an officer or director of Seadrill when that individual is acting in such capacity is, in a number of circumstances, stricter than the standard of care the same individual may have when acting as our officer or director. The fact that our officers or directors may have a fiduciary duty to Seadrill does not, however, diminish the duty that such individual owes to us. Compliance by such officer or director with such individual’s duty to us should not result in a violation of such individual’s duties to Seadrill.
In order to become a member of us, a common unitholder is required to agree to be bound by the provisions in the operating agreement, including the provisions discussed above.
Seadrill’s ownership interest in us could decrease, and substantial future sales of our common units, could lead to a reduction in the trading price of our common units.
The Seadrill Member may transfer its Seadrill Member interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. In addition, our operating agreement does not restrict the ability of the members of the Seadrill Member from transferring their respective limited liability company interests in the Seadrill Member to a third party.
We have granted registration rights to Seadrill and certain of its affiliates. These unitholders have the right, subject to some conditions, to require us to file registration statements covering any of our common, subordinated or other equity securities owned by them or to include those securities in registration statements that we may file. As of March 31, 2018, Seadrill owned 26,275,750 common units and 16,543,350 subordinated units and all of the incentive distribution rights (through its ownership of the Seadrill Member). Following their registration and sale under an applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of our common units to decline.
If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940 which could force us to restructure and restrict our future activities.
If we cease to manage and control OPCO and are deemed to be an investment company under the Investment Company Act of 1940 because of our ownership of OPCO interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional independent directors.
The Seadrill Member, as the initial holder of all of the incentive distribution rights, may elect to cause us to issue additional common units to it in connection with a resetting of the target distribution levels related to the Seadrill Member’s incentive distribution rights without the approval of the conflicts committee of the Board or holders of our common units and subordinated units. This may result in lower distributions to holders of the common units in certain situations.
The Seadrill Member, as the initial holder of all of the incentive distribution rights, has the right, at a time when there are no subordinated units outstanding and the Seadrill Member has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by the Seadrill Member, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount.
In connection with resetting these target distribution levels, the Seadrill Member will be entitled to receive a number of common units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to the Seadrill Member on the incentive distribution rights in the prior two quarters. We anticipate that the Seadrill Member would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that the Seadrill Member could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued the common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause the common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued additional common units to the Seadrill Member in connection with resetting the target distribution levels related to the Seadrill Member’s incentive distribution rights.
We may issue additional equity securities, including securities senior to the common units, without the approval of our unitholders, which could dilute the ownership interests of our existing unitholders.
We may, without the approval of our unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. Our issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest will decrease;
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the amount of cash available for distribution on each unit may decrease;
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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of the common units may decline.
Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.
During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash. For a description of the subordination period, refer Item 8A "Consolidated Statements and Other Financial Information-The Company's Cash Distribution Policy-Subordination Period".
The Seadrill Member has a limited call right that may require our common unitholders to sell their common units at an undesirable time or price.
If at any time the Seadrill Member and its affiliates own more than 80% of the common units, the Seadrill Member will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price of our common units. The Seadrill Member is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right. As a result, the holders of our common units may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such common unitholders may also incur a tax liability upon a sale of their common units.
As of March 31, 2018, Seadrill, which owns and controls the Seadrill Member, owned 34.9% of our common units. At the end of the subordination period, assuming no additional issuances of common units and the conversion of our subordinated units into common units, Seadrill would own 46.6% of our common units.
Unitholders may have liability to repay distributions.
Under some circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the Marshall Islands Act, we may not make a distribution to our unitholders if at the time of the distribution, after giving effect to the distribution, all our liabilities, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to our specified property, 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. The Marshall Islands Act provides that for a period of three years from the date of the impermissible distribution (or longer if an action to recover the distribution is commenced during such period), members who received the distribution and who knew at the time of the distribution that it violated the Marshall Islands Act will be liable to the limited liability company for the distribution amount. Assignees who become substituted members are liable for the obligations of the assignor to make contributions to us that are known to the assignee at the time it became members and for unknown obligations if the liabilities could be determined from the operating agreement.
Because we are a foreign limited liability company, you may not have the same rights that a unitholder in a U.S. limited liability company may have.
We are organized under the laws of Marshall Islands, and substantially all of our assets are located outside of the United States. In addition, our directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to bring an action against us or against these individuals in the United States if you believe that your rights have been infringed under securities laws or otherwise. Even if you are successful in bringing an action of this kind, the laws of Marshall Islands and of other jurisdictions may prevent or restrict you from enforcing a judgment against our assets or the assets of our directors or officers.
The provisions of the Marshall Islands Act resemble provisions of the limited liability company laws of a number of states in the United States, most notably Delaware. The Marshall Islands Act also provides that for non-resident limited liability companies it is to be applied and construed to make the laws of the Marshall Islands, with respect to the subject matter of the Marshall Islands Act, uniform with the laws of the State of Delaware and, so long as it does not conflict with the Marshall Islands Act or decisions of the High or Supreme Courts of the Marshall Islands the non-statutory law (or case law) of the State of Delaware is adopted as the law of the Marshall Islands. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited liability company statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of our unitholders and the duties of the Seadrill Member and our directors and officers under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. As a result, unitholders may have more difficulty in protecting their interests in the face of actions by the Seadrill Member and our officers and directors than would unitholders of a similarly organized limited liability company in the United States.

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If the average closing price of our common units declines to less than $1.00 over 30 consecutive trading days, our common units could be delisted from the NYSE or trading could be suspended.
Our common units are currently listed on the NYSE. In order for our common units to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per unit during a consecutive 30 trading-day period. A renewed or continued decline in the closing price of our common units on the NYSE could result in a breach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common units. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing would be greatly impaired. Furthermore, with respect to any suspended or delisted common units, we would expect decreases in institutional and other investor demand, analyst coverage, market making-activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such common units. A suspension or delisting would likely decrease the attractiveness of our common units to investors and cause the trading volume of our common units to decline, which could result in a further decline in the market price of our common units.
The delisting of our common units from the NYSE could lead to a material increase in the amount of our U.S. federal income tax liability.
Our common units are currently listed on the NYSE. In order for our common units to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per unit during a consecutive 30 trading-day period. A renewed or continued decline in the closing price of our common units on the NYSE could result in a breach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common units. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. Under certain circumstances, a delisting could result in a material increase in the amount of our U.S. federal income tax liability, which would adversely affect our financial position, results of operations and cash flows.
U.S. tax authorities may treat us as a "passive foreign investment company" for U.S. federal income tax purposes, which may have adverse tax consequences for U.S. unitholders.
A foreign corporation will be treated as a "passive foreign investment company" ("PFIC"), for U.S. federal income tax purposes if for any taxable year either (1) at least 75% of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50% of the average value of the corporation’s assets produce or are held for the production of those types of "passive income." For purposes of these tests, "passive income" includes dividends, interest, 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. For purposes of these tests, income derived from the performance of services does not constitute "passive income". U.S. unitholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their units in the PFIC.
Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we believe that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the U.S. Internal Revenue Service (the "IRS"), on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.
If the IRS were to find that we are or have been a PFIC for any taxable year (and regardless of whether we remain a PFIC for any subsequent taxable year), our U.S. unitholders may face adverse U.S. federal income tax consequences.  Under the PFIC rules, unless those unitholders make an election available under the U.S. Internal Revenue Code of 1986, as amended (the "Code") (which election could itself have adverse consequences for such unitholders, as discussed below under Item 10E "Taxation"), such unitholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of the common units, as if the excess distribution or gain had been recognized ratably over the unitholder’s holding period of the common units. In the event that our unitholders face adverse U.S. federal income tax consequences as a result of investing in common units, this could adversely affect our ability to raise additional capital through the equity markets. See Item 10E "Taxation" for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. unitholders if we are treated as a PFIC.
Investors are encouraged to consult their own tax advisers concerning the overall tax consequences of the ownership of the common units arising in an investor’s particular situation under U.S. federal, state, local or foreign law.

Item 4.         Information on the Company


23

A.     History and Development of the Company
Overview
Seadrill Partners, LLC was formed in the Marshall Islands on June 28, 2012 as limited liability company and a wholly owned subsidiary of Seadrill, to own, operate and acquire offshore drilling units. The Company completed its IPO and listed its common units on the New York Stock Exchange in October 2012 under the ticker symbol "SDLP". The company's principal executive headquarters are maintained at 2nd Floor, Building 11, Chiswick Businesses Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom. The Company's telephone number at that address is +44 20 8811 4700. The Company's agent for service of process in the United States is Watson Farley & Williams LLP and its address is 250 West 55th Street New York, New York 10019.
In connection with the IPO, the Company acquired (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Immediately following the IPO, Seadrill Operating LP owned (i) a 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) an approximate 56% interest in the entity that owns and operates the West Capella. In addition, immediately following the Company's IPO, Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn. Subsequent to the IPO (i) the Company’s wholly-owned subsidiary, Seadrill Partners Operating LLC, acquired from Seadrill the entities that own the T-15 and T-16, (ii) Seadrill Capricorn Holdings LLC acquired from Seadrill the entities that own the West Auriga and West Vela, (iii) Seadrill Operating LP acquired from Seadrill the entity that owns the West Polaris and (iv) the Company acquired from Seadrill an additional 28% limited partner interest in Seadrill Operating LP.
Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as "OPCO".
As of January 2, 2014, the date of the Company’s first annual general meeting, Seadrill ceased to control the Company in accordance with GAAP and, therefore, the Company and Seadrill are no longer deemed to be entities under common control.
Seadrill owns the remaining interests in OPCO. As of March 31, 2018, Seadrill owned 34.9% of our common units and all of our subordinated units as well as Seadrill Member LLC, which owns the Seadrill Member interest, a non-economic interest in the Company, and all of our incentive distribution rights.
Management of the Company
Overall responsibility for the management of the Company and its subsidiaries rests with the Board. We are managed on a day to day basis by our executive officers, Mark Morris and John Roche, who are employees of Seadrill and provide services to us under the terms of a management and administrative services agreement. Seadrill also provides operational support and technical supervision services for our fleet and certain other management and administrative services.
Significant developments for the period from January 1, 2015 through December 31, 2017
Acquisition of West Polaris
On June 19, 2015, we completed the purchase of 100% of the ownership interests in Seadrill Polaris Ltd. ("Seadrill Polaris"), the entity that owns and operates the drillship, the West Polaris (the "Polaris Acquisition"). The consideration for the acquisition included both upfront and contingent elements. The upfront consideration was comprised of $204.0 million of cash and $336.0 million of debt outstanding under the existing credit facility financing the West Polaris.
The contingent consideration included a note payable to Seadrill of $50 million ("Seller's Credit"), payment of which is contingent on the future re-contracted dayrate for the West Polaris, and a share of the dayrate earned by the West Polaris over its contract with ExxonMobil ("Initial Earn-Out") and on subsequent contracts until March 2025 ("Subsequent Earn-Out").
Refer to Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report for more information on the Polaris Acquisition.
Drilling Contracts
The below table shows the status of our drilling contracts at March 31, 2018.

24

Rig
Built
Status at December 31, 2017
Customer
Contractual operating rate per day ($'000)
Contracted until
Semi-submersible
 
 
 
West Sirius
2008
Stacked
-
-
-
West Aquarius
2009
Future contract
BP
$260.0
Jul 2018
West Capricorn
2011
Contracted
BP
$525.0
Jul 2019
West Leo
2012
Stacked
-
-
-
 
 
 
 
 
 
Drillship
 
 
 
 
 
West Capella
2008
Future contract
Repsol
Not disclosed
Jul 2018
West Polaris
2008
Stacked
-
-
-
West Auriga
2013
Contracted
BP
$562.0
Oct 2020
West Vela
2013
Contracted
BP
$564.0
Nov 2020
 
 
 
 
 
 
Tender Rig
 
 
 
 
 
West Vencedor
2009
Stacked
-
-
-
T-15
2013
Contracted
Chevron
$110.0
Jul 2019
T-16
2013
Contracted
Chevron
$110.0
Aug 2019
The West Sirius operated under a contract with BP in the Gulf of Mexico until 2015, when it received a notice of termination. In accordance with the cancellation provisions in the contract, we received termination payments over the remaining contract term, which expired in July 2017.
The West Aquarius was on contract with Hibernia in Canada until April 2017. After a short period of idle time the rig then operated under a one-well contract with Statoil in Canada from May 2017 to July 2017. The rig has been warm stacked since July 2017 but has secured a one-well contract with BP Canada which commenced in April 2018.
The West Capricorn has been on contract with BP in the Gulf of Mexico since July 2012. The unit was placed on an extended standby rate of $315k per day from May 2016 to June 2017. In April 2017, we received a notification from BP for the unit to start preparing for a return to operations. The unit returned to normal contractual day rates in July 2017.
The West Leo operated under a contract with Tullow in Ghana until October 2016, when it received a notice of termination for force majeure. We have disputed the grounds for termination and litigation proceedings are ongoing.
The West Capella was on contract with ExxonMobil in Nigeria until May 2016, when it received a notice of termination. In accordance with the cancellation provisions in the contract, we received a termination fee of approximately $125 million, which was paid in two equal installments, plus other direct costs incurred as a result of the termination. In March 2017, we secured a one-well contract for the West Capella with Total in Cyprus, which operated from July 2017 to September 2017. In May 2017, we secured a one-well contract plus the option for a further three optional wells with Petronas in Gabon. This contract started in October 2017 and completed in March 2018. In March 2018 we secured a one well contract with Repsol in Aruba which is expected to commence in June 2018.
The West Polaris was on contact with ExxonMobil in Angola until December 2017, when the rig completed its operations and demobilized. The rig is now stacked.
The West Auriga and West Vela have been on contract with BP in the Gulf of Mexico since October 2013 and November 2013 respectively.
The West Vencedor started work on a contract with ConocoPhillips in Indonesia in March 2017. In May 2017 Medco Energi acquired ConocoPhillips ownership interests in the operating area and assumed the drilling contract. Medco Energi exercised 2 of a potential 7 optional wells under the contract. The contract ended in January 2018.
The T-15 and T-16 have been on contract with Chevron in Thailand since July 2013 and August 2013 respectively.
Litigation with Tullow for the West Leo
As set out above, we received a notice of force majeure in October 2016 for the West Leo 's contract with Tullow in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience.
We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract has been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination.

25

The total amount that we are seeking to recover is $278 million plus interest. The case is scheduled to be heard on May 8, 2018.
Seadrill restructuring
In September 2017, our largest unitholder, Seadrill, entered into a restructuring agreement with its secured lenders, bondholders and a consortium of investors. The agreement defers the maturity of Seadrill's secured bank debt by five years, delays amortization payments until 2020, converts bonds to equity and delivers new capital to Seadrill. To implement the restructuring agreement, Seadrill and certain of its subsidiaries (the "Debtors") have filed prearranged Chapter 11 cases in the Southern District of Texas together with a restructuring plan.  As part of the Chapter 11 cases, "first day" motions were granted that enabled Seadrill's day-to-day operations to continue as usual, including the provision of management services to the Company.
On February 26, 2018, the Debtors filed a proposed second amended plan of reorganization with the bankruptcy court. On April 9, 2018, Seadrill announced that the plan had received approval from each class of creditor and holder of interests that were entitled to vote on the plan. To become effective, the plan will now have to be approved by the bankruptcy court on a confirmation hearing scheduled for April 17, 2018. If the plan is confirmed at this hearing then it would become effective once all conditions precedent have been satisfied or waived. The Debtors would then emerge from Chapter 11 proceedings.
Insulation from events of default related to Seadrill's Chapter 11 filing
In August 2017, we completed amendments to our West Polaris, West Vela and Tender Rig facilities which insulated us from events of default related to Seadrill's use of Chapter 11 proceedings. We did not file any Chapter 11 cases. Our business operations have been largely unaffected by Seadrill's Chapter 11 filings.
Term Loan B covenant waiver
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, the Company has agreed to certain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Capital Expenditures
Capital expenditures were approximately $121.6 million, $61.1 million and $68.4 million in the years ended 2017, 2016 and 2015 respectively. Our capital expenditures relate primarily to additional equipment for our existing drilling units and maintenance. We financed these capital expenditures through cash generated from operations and secured and unsecured debt arrangements.

    B.     Business Overview
The Company
We are a limited liability company formed by Seadrill to own, operate and acquire offshore drilling units. Our fleet consists of drillships, semi-submersible rigs and tender rigs operating in benign and harsh environments. We contract our drilling units primarily on a dayrate basis to oil companies such as BP and Chevron.
As of March 31, 2018, we owned and operated a fleet of four semi-submersible drilling rigs, four drillships and three tender rigs. We have one of the youngest rig fleets in the industry with an average fleet age of approximately 6.7 years.
Our Fleet
We believe that we have one of the most modern fleets in the offshore drilling industry. Details regarding the types of rigs we own and the contracts under which they operate are set forth below.
Semi-submersible drilling rigs
Semi-submersibles are self-propelled drilling rigs consisting of an upper working and living quarters deck connected to a lower hull consisting of columns and pontoons. Such rigs operate in a "semi-submerged" floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The rig is situated over a wellhead location and remains stable for drilling in the semi-submerged floating position, due in part to its wave transparency characteristics at the water line.
Semi-submersible rigs can be either moored or dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors and typically operate in water depths ranging up to 1,500 feet. Dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system and typically operate in water depths ranging from 1,000 to 12,000 feet. Depending on country of operation, semi-submersible rigs generally operate with crews of 65 to 100 people.
Drillships
Drillships are self-propelled ships equipped for drilling offshore in water depths ranging from 1,000 to 12,000 feet, and are positioned over the well through a computer-controlled thruster system similar to that used on semi-submersible rigs. Drillships are suitable for drilling in remote locations because of their mobility and large load-carrying capacity. Depending on country of operation, drillships operate with crews of 65 to 100 people.

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Table of Contents

Tender rigs
Tender rigs are self-erecting rigs which conduct production drilling from fixed or floating platforms. During drilling operations, the tender rig is moored next to the platform. The modularized drilling package, stored on the deck during transit, is lifted prior to commencement of operations onto the platform by the rig's integral crane. To support the operations, the tender rig contains living quarters, helicopter deck, storage for drilling supplies, power machinery for running the drilling equipment and well completion equipment. There are two types of self-erecting tender rigs, barge type and semi-submersible (semi-tender) type. Tender barges and semi-tenders are equipped with similar equipment but the semi-tenders' hull structure allows the unit to operate in rougher weather conditions. Tender rigs allow for drilling operations to be performed from platforms without the need for permanently installed drilling packages. Self-erecting tender rigs generally operate with crews of 60 to 85 people.
The following table provides additional information about our fleet as of March 31, 2018:
Rig
Seadrill Partners Ownership Interest (2)
Year Built
Water
Depth
(feet)
Drilling
Depth
(feet)
Semi-submersible
 
 
 
 
West Sirius
51%
2008
10,000

35,000

West Aquarius
58%
2009
10,000

35,000

West Capricorn
51%
2011
10,000

35,000

West Leo
58%
2012
10,000

35,000

 
 
 
 
 
Drillship
 
 
 
 
West Capella (1)
33%
2008
10,000

35,000

West Polaris
58%
2008
10,000

35,000

West Auriga
51%
2013
12,000

40,000

West Vela
51%
2013
12,000

40,000

 
 
 
 
 
Tender Rig
 
 
 
 
West Vencedor
58%
2009
6,500

30,000

T-15
100%
2013
6,500

30,000

T-16
100%
2013
6,500

30,000

(1) We own 58% of Seadrill Operating LP, which controls and owns 56% of the entity that owns the West Capella.
(2) Seadrill owns the remaining interest in each of our rigs.
Our Competitive Strengths
We believe that our competitive strengths include:
Technologically advanced and young fleet
Our drilling units are among the most technologically advanced in the world. The majority of our rigs were built after 2008, and we have among the lowest average fleet age in the industry. Although current offshore drilling demand is weak, new and modern units that offer superior technical capabilities, operational flexibility and reliability are preferred by customers and winning the majority of available opportunities. We believe, based on our operational track record, that we will be better placed to secure new drilling contracts than some of our competitors with older, less advanced rig fleets.
Commitment to safety and the environment
We believe that the combination of quality drilling units and experienced and skilled employees allows us to provide our customers with safe and effective operations. Quality assets and operational expertise allow us to establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers.
Relationship with Seadrill
We believe our relationship with Seadrill provides us with operational expertise, stronger relationships with customers and suppliers, and economies of scale from services provided centrally. We also have an omnibus agreement with Seadrill whereby we have the opportunity to acquire floaters with contracts that are five years or more in duration.

27
Table of Contents

Business Strategy
Our immediate objectives during the current industry downturn include the following:
Protect our revenue and contract backlog by continuing to provide excellent service to our customers
We are a leading offshore deepwater drilling company and our mission is to continue to be a preferred offshore drilling contractor and to deliver excellent performance to our clients by consistently exceeding their expectations for performance and safety standards. We believe that we have one of the most modern fleets in the industry and believe that by combining quality assets and experienced and skilled employees we will be able to provide our customers with safe and effective operations, and maintain our position as a preferred provider of offshore drilling services for our customers. We believe that a combination of quality drilling rigs, highly skilled employees and strong operations will facilitate the procurement of term contracts at premium dayrates. By doing this we intend to maximize opportunities for new drilling contracts, while minimizing chances of contract terminations.
Optimize cost of funding and capital structure
Over the past year, we have insulated ourselves from potential events of default related to Seadrill's use of Chapter 11 proceedings, extended the maturities of three credit facilities and achieved a leverage covenant waiver on our $2.8 billion Term Loan B. We believe these agreements leave us well positioned to optimize our cost of funding and capital structure.
Longer term, we have the following objectives:
• Grow Through Strategic and Accretive Acquisitions. We intend to capitalize on opportunities to grow our fleet through further acquisitions of offshore drilling units. This may include further purchases from Seadrill and purchases from third parties.
• Pursue Long-term Contracts and Maintain Stable Cash Flow. We will continue to pursue long-term contracts to maintain stable and predictable operating cash flows. We believe that this focus will enable us to access equity and debt capital markets on attractive terms and, therefore, facilitate our growth strategy.
• Provide Excellent Customer Service and Continue to Prioritize Safety as a Key Element of The Company's Operations. We believe that Seadrill has developed a reputation as a preferred offshore drilling contractor and that we can capitalize on this reputation by continuing to provide excellent customer service. We seek to deliver exceptional performance for our customers by consistently meeting or exceeding their expectations for operational performance, including by maintaining high safety standards and minimizing downtime.
• Maintain a Modern and Reliable Fleet. We have one of the youngest and most technologically advanced fleets in the industry, and plans to maintain a modern and reliable fleet.
We can provide no assurance, however, that we will be able to implement our business objectives described above, particularly in the current challenging low oil price market environment.
Market Overview
We provide operations in oil and gas exploration and development in regions throughout the world and our customers have included major oil and gas companies, state-owned national oil companies and independent oil and gas companies. Due to a significant decline in oil prices many of our customers are focused on conserving cash and have reduced capital expenditures for exploration and development projects. As a result, there has been a significant reduction in demand in the offshore drilling market.
The Global Fleet of Drilling Units
Seadrill Partners currently operates drillships, semi-submersible rigs and tender rigs. The existing worldwide fleet of these units as of March 31, 2018, totals 289 units including 116 drillships, 143 semi-submersible rigs, and 30 tender rigs. In addition, there are 28 drillships, 14 semi-submersible rigs and 6 tender rigs under construction. The water depth capacities for the various drilling rig types depend on rig specifications, capabilities and equipment outfitting. Semi-submersible rigs and drillships can work in water depths up to 12,000 feet and tender rigs work in water depths up to 410 feet for tender barges and up to 6,000 feet for semi-tenders. All offshore rigs can work in benign environment but there are certain additional requirements for rigs to operate in harsh environments due to extreme marine and climatic conditions. The number of units outfitted for such operations are limited and the present number of rigs capable of operating in harsh environments total 146 units. This includes 7 drillships, 62 semi-submersible rigs and 77 jack-up rigs.
Semi-submersible rigs and drillships
The worldwide fleet of semi-submersible rigs and drillships currently totals 259 units. Of the total delivered fleet, 166 units are capable of operations in ultra-deepwater, 31 classed for deepwater operations up to 7500 feet and 62 classed for operations 4500 feet and below. Overall, the average global floater fleet is 15 years old. The average age of ultra-deepwater units is 8 years, 25 years for units classed for deepwater operations and 29 years for units classed for operations below 4500 feet.
Included in the global floater fleet are units classed for operations in harsh environments. The global harsh environment floater fleet is comprised of 69 units and is 19 years old on average.
Whilst oil companies continue to prefer newer and more capable equipment, we are currently seeing a higher utilization for mid-water drilling units. Ultra-deepwater units are currently experiencing 46% capacity utilization versus 42% for deepwater and 56% for mid water floaters. Utilization for harsh environment floaters is 51%. Older units are believed to be at a competitive disadvantage due to the customer preferences and the availability of more modern and efficient equipment.

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Table of Contents

Based on the level of current activity and the aging floater fleet, accelerated stacking and scrapping activity is expected to continue. A total of 103 floaters have been scrapped or retired since the beginning of 2014, equivalent to 32% of the total fleet, and currently there are 28 cold or warm stacked units with no follow-on work identified that are 30 years old or older, which are prime scrapping candidates. In the next 18 months, a further 22 units that are 30 years old or older will be coming off contract with no follow-on work identified which represents additional scrapping candidates. A key rational for scrapping is the 35-year classing expenditures that can cost upwards of $100 million. Many rig owners will choose to retire the unit rather than incur this cost without a visible recovery in demand on the horizon.
Currently the order book stands at approximately 42 units, comprised of 28 drillships and 14 semi-submersible rigs. 12 are scheduled for delivery in 2018, 17 in 2019 and 13 in 2020 and beyond. Due to the subdued level of contracting activity, it is likely that a significant number of newbuild orders will be delayed or canceled until an improved market justifies taking delivery.
Tender rigs
The worldwide fleet of tender rigs currently totals 30 units, of which 12 are contracted representing 40% capacity utilization. Overall, the global fleet is 12 years old on average. Currently the order book stands at approximately 6 units. 2 are scheduled for delivery in 2018 and 4 in 2020.
Activity in the tender rig market is focused primarily in South-east Asia and West Africa. Tendering activity is typically more stable in this market due to these types of units being employed on development projects, however capacity utilization and dayrates have remained under pressure.
The above overview of the various offshore drilling sectors is based on previous market developments and current market conditions. Future markets conditions and developments cannot be predicted and may well differ from our current expectations.
Seasonality
In general, seasonal factors do not have a significant direct effect on our business. We have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operation of our rigs, but generally such operational interruptions do not have a significant impact on our revenues. Such adverse weather could include the hurricane season in the Gulf of Mexico and the monsoon season in Southeast Asia.
Customers
Offshore exploration and production is a capital intensive, high-risk industry. Operating and pursuing opportunities in deepwater basins significantly increases the amount of capital required to effectively conduct such operations. A significant number of operators in this segment of the offshore exploration and production industry are either national oil companies, major oil and gas companies or well-capitalized large independent oil and gas companies.
In 2017, our largest customers were BP and ExxonMobil. For the year ended December 31, 2017, BP accounted for 56.8% and ExxonMobil accounted for 22.2%, of total revenues, respectively.
Contract Backlog
Our contract backlog as of March 31, 2018 totals $1.4 billion. The backlog figure does not include any termination payments in relation to the termination of the West Leo.
Backlog is calculated as the full operating dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization and demobilization, contract preparation, and customer reimbursables.
The actual amounts of revenues earned and the actual periods during which revenues are earned may differ from the backlog amounts and periods shown in the table below due to various factors, including shipyard and maintenance projects, downtime and other factors. Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable dayrates than the full contractual operating dayrate.
In addition, our contracts often provide for termination at the election of the customer with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling unit, the Company’s bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damages periods, no early termination payment would be paid. Accordingly, if one of these events were to occur, the actual amount of revenues earned may be substantially lower than the backlog reported.
Our contract backlog as of March 31, 2018 is as follows:

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Table of Contents

Rig
Contracted
Location
Customer
Contractual
Dayrate
(US $)
Contract
Backlog(1)
(US $ 
millions)
Contract
Start
Contract End
Semi-submersible
 
 
 
 
 
 
West Sirius
Stacked
-
-
-
-
-
West Aquarius
Canada
BP
$260,000
$31.2
Apr 2018
Jul 2018
West Capricorn
USA
BP
$525,000
$251.5
Jul 2017
Jul 2019
West Leo (2)
Stacked
-
-
-
-
-
 
 
 
 
 
 
 
Drillship
 
 
 
 
 
 
West Capella
Aruba
Repsol
Not disclosed
Not disclosed
Jun 2018
Jul 2018
West Polaris
Stacked
-
-
-
-
-
West Auriga
USA
BP
$562,000
$529.4
Oct 2013
Oct 2020
West Vela
USA
BP
$564,000
$510.4
Nov 2013
Nov 2020
 
 
 
 
 
 
 
Tender Rig
 
 
 
 
 
 
West Vencedor
Stacked
-
-
-
-
-
T-15
Thailand
Chevron
$110,000
$50.9
Jul 2013
Jul 2019
T-16
Thailand
Chevron
$110,000
$54.8
Aug 2013
Aug 2019
(1) Expressed in millions. Based on executed drilling contracts.
(2) Tullow terminated the drilling contract for the West Leo in December 2016. We have disputed the grounds for termination and have commenced litigation proceedings.
Competition
The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to smaller companies with fewer than five drilling units.
The demand for offshore drilling services is driven by oil and gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and gas companies’ expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect customers’ drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by customers for drilling services. We are affected by variations in market conditions in different ways, depending primarily on the length of drilling contracts in different markets. Short-term changes in these markets may have a minimal short-term impact on revenues and cash flows, unless the timing of contract renewals coincides with short-term movements in the market.
Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, condition and integrity of equipment, their record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations.
Furthermore, competition for offshore drilling units, particularly submersible semi-tenders and drillships, is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate modifications of the drilling unit and its equipment to specific regional requirements.
We believe that whilst the market for drilling contracts will continue to be highly competitive, our modern fleet of technologically advanced drilling units provides us with a competitive advantage over competitors with older fleets. Our drilling units are generally better suited to meet the requirements of customers for drilling in deepwater. However, some of our competitors may have greater financial resources than us, which may enable them to better withstand periods of low utilization, and compete more effectively on the basis of price.
For further information on current market conditions and global offshore drilling fleet, please see "Market Overview" and Item 5 "Operating and Financial Review and Prospects-Trend Information".

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Principal Suppliers
We source the equipment used on our drilling units from well-established suppliers, including: Cameron International Corp. and National Oilwell Varco, Inc. ("NOV"), each of which supply blowout preventers, and, with respect to NOV, top drives (the device used to turn the drillstring, which is a combination of devices that turn the drill bit), drawworks (the hoisting mechanism on a drilling unit) and other significant drilling equipment; Kongsberg Gruppen, which supplies dynamic positioning systems; Aker-MH AS, which supplies drilling software as well as top drives and drawworks; Rolls Royce, which supplies thrusters; and Caterpillar Inc., which supplies cranes.
In addition, our customers are responsible for providing the fuel to be used by a drilling unit when it is under contract to them, at their own cost. We are not dependent on any one supplier.
Risk of Loss and Insurance
Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, destroy the equipment involved or cause serious environmental damage. We are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our energy insurance package policy provides insurance coverage for physical damage to our drilling units, loss of hire for some of our rigs and third-party liability.
Our insurance claims are subject to a deductible, or non-recoverable, amount. We currently maintain a deductible per occurrence of up to $5 million related to physical damage to its rigs. However, a total loss of, or a constructive total loss of, a drilling unit is recoverable without being subject to a deductible. For general and marine third-party liabilities, we generally maintain a deductible of up to $0.5 million per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units. Furthermore, we buy insurance for certain drilling units to cover loss due to the drilling unit being wholly or partially deprived of income as a consequence of damage to the unit. This loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies are limited to 290 days. If the repair period for any physical damage exceeds the number of days permitted under our loss of hire policy, we will be responsible for the costs in such period. We do not have loss of hire insurance for our tender rigs with the exception of the semi-tender rig the West Vencedor, while the rig is in operation.
We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a combined single limit of $100 million in the annual aggregate, which includes loss of hire. We intend to renew our policy to insure a limited part of this windstorm risk for a further period starting May 1, 2018 through April 30, 2019.

Environmental and Other Regulations in the Offshore Drilling Industry
Our operations are subject to numerous laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permits requirements, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. See Item 3 "Key Information-Risk Factors-Risks Relating to our Company- Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations”.
Flag State Requirements
All of our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. These include engineering, safety and other requirements related to the drilling industry and to maritime vessels in general. In addition, each of our drilling units must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the flag state and the international conventions of which that country is a member. Maintenance of class certification requires expenditure of substantial sums, and can require taking a drilling unit out of service from time to time for repairs or modifications to meet class requirements. Our drilling units must generally undergo a class survey once every five years.
International Maritime Regimes
Requirements of international maritime regimes, such as the United Nation's International Maritime Organization ("the IMO"), include, but are not limited to, the International Convention for the Prevention of Pollution from Ships (“MARPOL”), the International Convention on Civil Liability for Oil Pollution Damage of 1969 (the “CLC”), the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974 (“SOLAS”), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, the International Convention of Load Line in 1966, as from time to time amended, and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 (the “BWM Convention”). These various conventions regulate air emissions and other discharges to the environment from our drilling units worldwide, and we may incur costs to comply with these regimes and continue to comply with these regimes as they may be amended in the future. In addition, these conventions impose liability for certain discharges, including strict liability in some cases. See Item 3 "Key Information-Risk Factors-Risks Relating to Our Company-We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business."

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Annex VI to MARPOL sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. Annex VI applies to all ships and, among other things, imposes a global cap on the sulfur content of fuel oil and allows for specialized areas to be established internationally with even more stringent controls on sulfur emissions. For vessels 400 gross tons and greater, platforms and drilling rigs, Annex VI imposes various survey and certification requirements. Moreover, recent amendments to Annex VI require the imposition of progressively stricter limitations on sulfur emissions from ships. Since January 1, 2015, these limitations have required that fuels of vessels in covered Emission Control Areas (“ECAs”) contain no more than 0.1% sulfur, including the Baltic Sea, North Sea, North America and United States Sea ECAs. For non- ECA areas, the sulfur limit in marine fuel is currently capped at 3.5%, which will then decrease to 0.5% on January 1, 2020 subject to feasibility review. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation.
The BWM Convention calls for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention entered into force on September 8, 2017. Under its requirements, for units with ballast water capacity more than 5,000 cubic meters that were constructed in 2011 or before, only ballast water treatment will be accepted by the BWM Convention.
Environmental Laws and Regulations
Applicable environment laws and regulations include the U.S. Oil Pollution Act of 1990 (“OPA”), the rules and regulations of the U.S Environmental Protection Agency (the "EPA"), the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002 (the “MTSA"), and European Union regulations, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering the Company liable for environmental and natural resource damages without regard to negligence or fault on the Company's part. Implementation of new environmental laws or regulations that may apply to ultra deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition. See Item 3 “Key Information - Risk Factors - Risks Relating to Our Company-We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business".
Safety Requirements
Our operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where we operate. The United States undertook substantial revision of the safety regulations applicable to the Company's industry following the 2010 Deepwater Horizon incident, in which the Company was not involved, that led to the Macondo well blow out situation. Other countries are also undertaking a review of their safety regulations related to the Company's industry. These safety regulations may impact our operations and financial results by adding to the costs of exploring for, developing and producing oil and gas in offshore settings. For instance, in April 2016, the U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement (“BSEE”) published a final rule that sets more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas drilling. The rule adds new requirements and amends existing ones to, among other things, set new baseline standards for the design, manufacture, inspection, repair and maintenance of blow-out preventers and the use of double shear rams. The rule contains a number of other requirements, including third-party verification and certifications, real-time monitoring of deepwater and certain other activities, and sets criteria for safe drilling margins. In December 2017, BSEE proposed to revise or eliminate certain of the requirements under the rule. To the extent these requirements remain in effect, they are likely to increase the costs of our operations and may lead our customers to not pursue certain offshore opportunities because of the increased costs, delays and regulatory risks. In July 2016, U.S. Department of the Interior’s Bureau of Ocean Energy Management (“BOEM”) issued a final Notice to Lessees and Operators substantially revising and making more stringent supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines, and other facilities. In June 2017, BOEM announced that the implementation timeline would be extended, except in circumstances where there is a substantial risk of non-performance of such obligations. In addition, in December 2015, BSEE announced that it is launching a pilot risk-based inspection program for offshore facilities. New requirements resulting from the program may cause us to incur costs and may result in additional downtime for our drilling units in the U.S. Gulf of Mexico. Also, if material spill events similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue additional safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The EU has also undertaken a significant revision of its safety requirements for offshore oil and gas activity through the issuance of the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations.
Navigation and Operating Permit Requirements
Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.
Local Content Requirements
Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in our operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in our local operating subsidiaries in countries such as Angola and Nigeria. Although these requirements have not had material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

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Other Laws and Regulations
In addition to the requirements described above, our international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development. There is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.
Taxation of the Company
Seadrill Partners LLC is organized as a limited liability company under the laws of the Republic of the Marshall Islands and is resident in the United Kingdom for taxation purposes by virtue of being centrally managed and controlled in the United Kingdom. Certain of our controlled affiliates are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. We intend that our business will be conducted and operated in a tax efficient manner. However, we cannot assure this result as tax laws in these or other jurisdictions may change or we may enter into new business transactions, which could affect our tax liabilities.
Marshall Islands
Because Seadrill Partners LLC and its controlled affiliates do not carry on business or conduct transactions or operations in the Republic of the Marshall Islands, neither it nor its controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, and we do not expect this to change in the future, 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 OPCO receives from the controlled affiliates of Seadrill Partners LLC, and distributions Seadrill Partners LLC receives from OPCO, are not expected to be subject to Marshall Islands taxation.
United Kingdom
Seadrill Partners LLC is a resident of the United Kingdom for taxation purposes. Nonetheless, we expect that the distributions it receives from OPCO, generally will be exempt from taxation in the United Kingdom under applicable exemptions for distributions from subsidiaries. As a result, we do not expect to be subject to a material amount of taxation in the United Kingdom as a consequence of Seadrill Partners LLC being resident in the United Kingdom for taxation purposes.
United States
We have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to U.S. federal income tax to the extent that we earn income from U.S. sources or income that is treated as effectively connected with the conduct of a trade or business in the United States. We do not expect to earn a material amount of such taxable net income; however, we have controlled affiliates that conduct drilling operations in the U.S. Gulf of Mexico that are subject to taxation by the United States on their net income and may be required to withhold U.S. federal tax from distributions made to their owner.
US Tax Reform
In December 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “2017 Tax Act”), which includes a number of changes to existing U.S. tax laws that may have an impact on our income tax provision in future years but with some one-off adjustments in 2017. The most notable immediate impact on the group is a reduction of the U.S. corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017.  The 2017 Tax Act also makes prospective changes beginning in 2018, including a base erosion and anti‑abuse tax (“BEAT”), limitations on the deductibility of interest and repeal of the domestic manufacturing deduction.  We are still evaluating the impact and its prospective effect on future periods.
Reduction of the U.S. corporate income tax rate-At December 31, 2017, we recalculated our deferred tax assets and liabilities to reflect the reduction in the U.S. corporate income tax rate from 35 percent to 21 percent. This has resulted in a $3 million increase in income tax expense for the year ended December 31, 2017 and a corresponding $3 million decrease in net deferred tax assets as of December 31, 2017.  
Taxation of rig owning entities
A number of our drilling rigs are owned in tax-free jurisdictions such as Bermuda or the Cayman Islands. There is no taxation of the rig owners’ income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income taxation of the rig owners’ income, being Hungary and Luxembourg. There may also be income tax in certain other jurisdictions where rigs are owned by or allocated to local branches.
Please also see the section below entitled "Taxation in country of drilling operations".

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Taxation in country of drilling operations
Income derived from drilling operations is generally taxed in the country where these operations take place. The taxation of income derived from drilling operations could be based on net income, deemed income, withholding taxes and or other bases, depending upon the applicable tax legislation in each country of operation. Some countries levy withholding taxes on bareboat charter payments (internal rig rent), branch profits, crew, dividends, interest and management fees.
Drilling operations can be carried out by locally incorporated companies, foreign branches of operating companies or foreign branches of the rig owning entities. We select the appropriate structure with due regard to the applicable legislation of each country where the drilling operation occur.
Taxation may also extend to the rig owning entity in some of the countries where the drilling operations are performed. Some countries have introduced new laws and rules since the commencement of certain drilling contracts, which may affect or have affected the position of the group, potentially leading to additional tax on rig owners. The group considers the applicability of these to individual companies and contracts based on the relevant facts and circumstances.
Net income
Net income corresponds to gross income derived from the drilling operations less tax-deductible costs (i.e. operating costs, crew, insurance, management fees and capital costs (internal bareboat fee; tax depreciation; interest costs) incurred in relation to those operations). In addition to net income tax, withholding tax on branch profits, dividends, internal bareboat fees, among other items, may also be levied.
Net income taxation for an international drilling contractor is complex, and pricing of internal transactions (e.g., rig sales; bareboat fees; services) will allocate overall taxable income between the relevant countries. We apply Organization for Economic Cooperation and Development, or "OECD", Transfer Pricing Guidelines as a basis to arrive at pricing for internal transactions. OECD Transfer Pricing Guidelines describe various methods to price internal services on terms believed by us to be no less favorable than are available from unaffiliated third parties. However, some tax authorities could disagree with our transfer pricing methods and disputes may arise in regards to correct pricing.
Deemed income
Deemed income tax is normally calculated based on gross turnover, which can include or exclude reimbursables and often reflects an assumed profit ratio, multiplied by the applicable corporate tax rate. Some countries will also levy withholding taxes on the distribution of dividend and/or branch profits at the deemed tax rate.
Withholding and other taxes
Some countries base their taxation solely on withholding tax on gross turnover. In addition, some countries levy stamp duties, training taxes or similar taxes on the gross turnover.
Customs duties
Customs duties are generally payable on the importation of drilling rigs, equipment and spare parts into the country of operation, although several countries provide exemption from such duties for the temporary importation of drilling rigs. Such exemption may also apply to the temporary importation of equipment.
Taxation of other income
Other income related to crewing, management fees and technical services will generally be taxed in the country where the service provider is resident, although withholding tax and/or income tax may also be imposed in the country where the drilling operations take place.
Dividends and other investment income will be taxable in accordance with the legislation of the country where the company holding the investment is resident. For companies resident in Bermuda, there is currently no tax on these types of income. Some countries levy withholding taxes on outbound dividends and interest payments.
Capital gains taxation
In respect of drilling rigs owned by companies in Bermuda, the Cayman Islands and Hungary, no capital gains tax is payable in these countries upon the sale or disposition of a rig. However, some countries may impose a capital gains tax or a claw-back of tax depreciation (on a full or partial basis) upon the sale of a rig during or attributable to such time as the rig is operating within such country, or within a certain time after completion of such drilling operations, or when the rig is exported after completion of such drilling operations.
Other taxes
Our operations may be subject to sales taxes, value added taxes, or other similar taxes in various countries.


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C.     Organizational Structure
A simplified organizational structure as of March 31, 2018 is shown below.
sdlpgroupstructure2017a02.jpg
Seadrill owned 34.9% of the common units of Seadrill Partners LLC and 100% of the subordinated units of Seadrill Partners LLC, and owned and controlled the Seadrill Member.
A full list of the Company's significant operating and rig-owning subsidiaries is included in Exhibit 8.1.

D.     Property, Plant and Equipment
Other than our fleet of drilling units, we do not have any material property. Information regarding our fleet of drilling units is set out in Item 4 "Information on the Company - Business Overview".
 

Item 4A.     Unresolved Staff Comments

None.


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Item 5.         Operating and Financial Review and Prospects

Overview
The following presentation of management’s discussion and analysis of results of operations and financial condition should be read in conjunction with the Company's Consolidated Financial Statements and notes thereto included elsewhere in this annual report. You should also carefully read the following discussion with the sections of this annual report entitled "Cautionary Statement Regarding Forward-Looking Statements," Item 3 "Key Information— Selected Financial Data", Item 3 "Key Information— Risk Factors" and Item 4 "Information on the Company." Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information. The Company's Consolidated Financial Statements have been prepared in accordance with GAAP and are presented in U.S. Dollars. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding going concern as described in Note 1 "General information".
Our Drilling Contracts
Please read Item 4 "History and Development of the Company - Significant Developments for the Period from January 1, 2015 through December 31, 2017 - Drilling Contracts" for a summary of the terms of our drilling contracts and a summary of the status of each of our drilling contracts.
Factors Affecting our Results of Operations
We believe the principal factors that will affect our future results of operations include the following.
•
Our ability to successfully employ our drilling units at economically attractive dayrates as contracts expire or are otherwise terminated.
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Our ability to maintain good relationships with our existing customers and to increase the number of customer relationships.
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The number and availability of drilling units in our fleet, including our ability to exercise any options to purchase additional drilling units that may arise under the Omnibus Agreement or otherwise.
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Changes in Seadrill Partners LLC's ownership of OPCO.
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Fluctuations in the price of oil and gas, which influence the demand for offshore drilling services.
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The effective and efficient technical management of our drilling units.
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Our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards.
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Economic, regulatory, political and governmental conditions that affect the offshore drilling industry.
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Accidents, natural disasters, adverse weather, equipment failure or other events outside of our control that may result in downtime.
•
The financial condition of Seadrill, its restructuring and its ability to provide services to the Company under certain management, administrative and technical support agreements;
•
Our ability to comply with financing agreements and the effect of the restrictive covenants in such agreements.
•
Changes in the fair value of our interest rate swaps.
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Foreign currency exchange gains and losses.
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Our access to capital required to acquire additional drilling units or equity interests in OPCO and/or to implement our business strategy.
•
Increases in crewing and insurance costs and other operating costs.
•
The level of debt and interest expense and amortization of deferred loan fees.
•
The level of any distribution on Seadrill Partners LLC's common units.
Please read Item 3 "Key Information—Risk Factors" for a discussion of certain risks inherent in the Company's business.
Important Financial and Operational Terms and Concepts
We use a variety of financial and operational terms and concepts when analyzing our performance. These include the following:
Contract Revenues
In general, we contract our drilling units to oil and gas companies to provide offshore drilling services at an agreed dayrate for a specified contact term. Dayrates can vary, depending on the type of drilling unit and its capabilities, contract length, geographical location, operating expenses, taxes and other factors such as prevailing economic conditions. We do not provide "turnkey" or other risk-based drilling services to the customer. Instead, we provide a drilling unit and rig crews and charge the customer a fixed amount per day regardless of the number of days needed to drill the well. The customer bears substantially all the ancillary costs of constructing the well and supporting drilling operations, as well as most of the economic risk relative to the success of the well.
Where operations are interrupted or restricted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption in excess of contractual allowances. Furthermore, the dayrate we receive can be reduced in

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instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or requested suspension of services by the customer and other operating factors.
However, contracts normally allow for compensation when factors beyond our control, including weather conditions, influence the drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In some of our contracts, we are entitled to cost escalation to compensate for industry specific cost increases as reflected in publicly available cost indexes.
We may receive lump sum or dayrate based fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to the start of drilling services. In some cases, we may also receive lump sum or dayrate based fees for demobilization upon completion of a drilling contract. We recognize revenue for mobilization, capital upgrades and non-contingent demobilization fees on a straight-line basis over the expected contract term. We recognize revenue for contingent demobilization fees as earned upon completion of the contract.
Our contracts may generally be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period because of a breakdown of major rig equipment, "force majeure" or upon the occurrence of other specified conditions. Some contracts include provisions that allow the customer to terminate the contract without cause for a specified early termination fee.
A drilling unit may be "stacked" if it has no contract in place. Drilling units may be either warm stacked or cold stacked. When a rig is warm stacked, the rig is idle but can deploy quickly if an operator requires its services. Cold stacking a rig involves reducing the crew to either zero or just a few key individuals and storing the rig in a harbor, shipyard or designated area offshore.
In certain countries, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We record tax-assessed revenue transactions on a net basis in the consolidated statement of income.
Other Revenues
Other revenues include amounts recognized as early termination fees under the drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized on a daily basis as and when any contingencies or uncertainties are resolved. Other revenues also include operation support fees charged to Seadrill for onshore support services provided in Nigeria.
Economic Utilization
Economic utilization is calculated as the total revenue, excluding bonuses, received divided by the full operating dayrate multiplied by the number of days on contract in the period.
If a drilling unit earns its full operating dayrate throughout a reporting period its economic utilization would be 100%. However, there are many situations that give rise to a dayrate being earned that is less than the contractual operating rate. In such instances economic utilization reduces below 100%.
Examples of situations where the drilling unit would operate at reduced operating dayrates, include, among others, a standby rate, where the rig is prevented from commencing operations for reasons such as bad weather, waiting for customer orders, waiting on other contractors; a moving rate, where the drilling unit is in transit between locations; a reduced performance rate in the event of major equipment failure; or a force majeure rate in the event of a force majeure that causes the suspension of operations. In addition, the drilling unit could operate at a zero rate in the event of a shutdown of operations for repairs where the general repair allowance has been exhausted or for any period of force majeure in excess of a specific number of days allowed under a drilling contract.
Reimbursable Revenues and Expenses
Reimbursable revenues are revenues that constitute reimbursements from our customers for reimbursable expenses. Reimbursable expenses are expenses we incur on behalf, and at the request, of customers, and include provision of supplies, personnel and other services that are not covered under the drilling contract.
Other Operating Income
Other operating income primarily relates to revaluation of contingent consideration and gains on sale of assets.
•
Revaluation of contingent consideration relates to changes in the estimated fair value of deferred consideration liabilities. These estimates may increase or decrease as new market information becomes available.
•
Gains on sale of assets occur where proceeds received from the transaction are in excess of the carrying value of the asset.
Operating Expenses
Operating expenses consist primarily of vessel and rig operating expenses, amortization of favorable contracts, reimbursable expenses, depreciation and amortization and general and administrative expenses.
•
Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked. This includes the personnel costs of offshore crews, running costs of the rigs, expenditures for repairs and maintenance activities and costs for onshore personnel that provide operational support to the rigs.
•
Amortization of favorable contracts is amortization expense for acquired drilling contracts with above market rates. Where we acquire an in-progress drilling contract at above market rates through a business combination we record an intangible asset equal to its fair value on the date of acquisition. The asset is then amortized on a straight-line basis over its estimated remaining contract term.
•
General and administrative expenses include management charges from Seadrill, legal and professional fees and other general administration expenses.

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•
Depreciation and amortization costs are based on the historical cost of our drilling units. Drilling units are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our rigs, when new, is 30 years. Costs related to periodic surveys and other major maintenance projects are capitalized as part of drilling units and amortized over the anticipated period covered by the survey or maintenance project, which is up to five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys and other major maintenance projects are included in depreciation and amortization expense.
Financial Items
Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments, foreign exchange gain/loss and gain/loss on bargain purchase.
•
Interest income relates to the amortization of mobilization revenue, interest on cash deposits and interest on insurance receivables.
•
Interest expense depends on the overall level of debt, and may significantly increase if we incur additional debt, for instance to acquire additional drilling units or additional equity interests in the Company. Interest expense may also change with prevailing interest rates, although interest rate swaps or other derivative instruments may reduce the effect of these changes.
•
Gains and losses recognized on derivative financial instruments reflect various mark-to-market and counter party credit risk adjustments to the value of our interest rate swap agreements, and the net settlement amount paid or received on swap agreements.
•
Foreign exchange gains/loss recognized generally relate to transactions and revaluation of balances carried in currencies other than the U.S. dollar.
Income Taxes
Income tax expense consists of taxes currently payable and changes in deferred taxes assets and liabilities related to our ownership and operation of drilling units and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of taxes is based on net income or deemed income, the latter generally being a function of gross revenue.
Cost Inflation
The majority of our contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of cost inflation on revenues from long-term contracts, most of our long term contracts include escalation provisions. These provisions adjust the contractual dayrates each year based on stipulated cost increases, including wages, insurance and maintenance cost.
Critical Accounting Estimates
The preparation of the Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable.
Critical accounting estimates are important to the portrayal of both the Company's financial condition and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain. Basis of preparation and significant accounting policies are discussed in Note 1 "General information", and Note 2 "Accounting policies" to the Consolidated Financial Statements included in this annual report.
We believe that the following are the critical accounting estimates used in the preparation of the Consolidated Financial Statements. In addition, there are other items within the Consolidated Financial Statements that require estimation.
Drilling Units
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our semi-submersible drilling rigs, drillships and tender rigs, when new, is 30 years.
Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset.
We determine the carrying value of our assets based on policies that incorporate estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. These assumptions and judgments reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in establishing estimated useful lives and residual values could result in significantly different carrying values for our drilling units which could materially affect our results of operations.
The useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We re-evaluate the remaining useful lives of our drilling units as and when events occur which may directly impact our assessment of their remaining useful lives. This includes changes the operating condition or functional capability of our rigs as well as market and economic factors.
The carrying values of our long-lived assets are reviewed for impairment when certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. We assess recoverability of the carrying value of an asset by estimating the

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undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value. In general, impairment analysis is based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable.
During the years ended December 31, 2017, 2016, and 2015, we identified indicators that the carrying value of our drilling units may not be recoverable. Such indicators included the reduction in new contract opportunities, fall in market dayrates and contract terminations. We assessed recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the units. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our drilling units, with sufficient headroom. As a result, we did not need to proceed to assess the fair values of our drilling units, and no impairment charges were recorded for the years ended December 31, 2017, 2016, and 2015.
Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets which could materially affect our results of operations.
Income Taxes
Income tax expense is based on reported income or loss before income taxes.
Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. We do not conduct business or operate in the Republic of the Marshall Islands, and we are not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom, we are subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Significant judgment is involved in determining the provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence.
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.
Recently Adopted and Issued Accounting Standards
For a discussion of recently adopted and recently issued accounting standards, please see Note 2 "Accounting policies" to the Consolidated Financial Statements included in this annual report.


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A.     Operating Results
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
The following table summarizes our operating results for the years ended December 31, 2017 and 2016:
 
Year Ended December 31,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 (US$ in millions)
 
 
 
 
 
Operating revenues:
 
 
 
 
 
 
 
Contract revenues
$
1,007.7

 
$
1,356.4

 
$
(348.7
)
 
(25.7
)%
Reimbursable revenues
17.7

 
32.8

 
(15.1
)
 
(46.0
)%
Other revenues
103.0

 
211.1

 
(108.1
)
 
(51.2
)%
Total operating revenues
1,128.4

 
1,600.3

 
(471.9
)
 
(29.5
)%
 
 
 
 
 
 
 
 
Other operating income:
 
 
 
 
 
 
 
Revaluation of contingent consideration
89.9

 
—

 
89.9

 
—
 %
Gain on sale of assets
0.8

 
—

 
0.8

 
—
 %
Total other operating income
90.7

 
—

 
90.7

 
—
 %
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Vessel and rig operating expenses
(345.4
)
 
(373.9
)
 
28.5

 
7.6
 %
Amortization of favorable contracts
(74.4
)
 
(70.6
)
 
(3.8
)
 
(5.4
)%
Reimbursable expenses
(16.1
)
 
(30.2
)
 
14.1

 
46.7
 %
Depreciation and amortization
(274.9
)
 
(266.3
)
 
(8.6
)
 
(3.2
)%
General and administrative expenses
(44.8
)
 
(41.2
)
 
(3.6
)
 
(8.7
)%
Total operating expenses
(755.6
)
 
(782.2
)
 
26.6

 
3.4
 %
Operating income
$
463.5

 
$
818.1

 
$
(354.6
)
 
(43.3
)%
 
 
 
 
 
 
 
 
Financial items:
 
 
 
 
 
 
 
Interest income
15.7

 
11.5

 
4.2

 
36.5
 %
Interest expense
(179.1
)
 
(180.0
)
 
0.9

 
0.5
 %
Loss on derivative financial instruments
(13.9
)
 
(18.0
)
 
4.1

 
22.8
 %
Currency exchange gain
0.9

 
0.6

 
0.3

 
50.0
 %
Other financial items
(11.5
)
 
—

 
(11.5
)
 
—
 %
Total financial items
(187.9
)
 
(185.9
)
 
(2.0
)
 
(1.1
)%
Income before income taxes
275.6

 
632.2

 
(356.6
)
 
(56.4
)%
Income taxes
(40.3
)
 
(86.5
)
 
46.2

 
53.4
 %
Net Income
$
235.3

 
$
545.7

 
$
(310.4
)
 
(56.9
)%
Net income attributable to the non-controlling interest
$
(94.1
)
 
$
(264.7
)
 
$
(170.6
)
 
(64.5
)%
Net income attributable to Seadrill Partners LLC
$
141.2

 
$
281.0

 
$
(139.8
)
 
(49.8
)%
Contract revenues
Contract revenues were $1,007.7 million for the year ended December 31, 2017 (December 31, 2016: $1,356.4 million).
The $348.7 million or 25.7% decrease, was primarily due to the West Leo being idle throughout the year ($204 million), the West Aquarius earning a lower dayrate on its contract with Statoil in Canada and then being idle over the second half of the year ($149 million) and the West Capella earning lower dayrates on its contracts with Total and Petronas ($63 million).
These decreases were partially offset by higher revenues on the West Polaris due to early demobilization fees and a higher dayrate following a rig move from Angola to Equatorial Guinea ($35 million), lower idle time on the West Vencedor ($11 million) and the West Capricorn returning to full contractual rates during the year ($5 million). The residual increase was due to improved economic utilization on the West Vela, West Auriga, T-15 and T-16 ($16 million).
Contract revenues do not include early termination payments, these are classified within "other revenues" (see below).

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The following table summarizes our fleet's average daily revenues and economic utilization percentage by drilling unit type for the periods presented:
 
Year Ended December 31,
 
2017
 
2016
 
Number of rigs/ships
 
Average
Daily Revenues (1)
 
Economic
Utilization (2)
 
Number of rigs/ships
 
Average
Daily Revenues (1)
 
Economic
Utilization (2)
Semi-submersible rigs (3)
2
 
$
459,164

 
97.3
%
 
3
 
$
555,193

 
99.3
%
Drillship
4
 
$
521,487

 
98.6
%
 
4
 
$
531,620

 
94.5
%
Tender rigs
3
 
$
122,054

 
98.2
%
 
3
 
$
116,634

 
98.6
%
(1)
Average daily revenues are the average revenues for each type of unit, based on the actual days available, while on contract.
(2)
Economic utilization is calculated as the total revenue, excluding bonuses received, divided by the full operating dayrate multiplied by the number of days in the period for rigs on contract.
(3)
Average daily revenue excludes the termination payments received as part of the termination of the drilling contract by BP for the West Sirius and ExxonMobil for the West Capella.
Reimbursable revenues
Reimbursable revenues were $17.7 million for the year ended December 31, 2017 (December 31, 2016: $32.8 million). The decrease of $15.1 million or 46.0%, was due to less equipment purchased on behalf of customers, for which we have been reimbursed.
Other revenues
Other revenues were $103.0 million for the year ended December 31, 2017 (December 31, 2016: $211.1 million).
The $108.1 million or 51.2% decrease was primarily due to the conclusion of early termination payments for the West Sirius in July 2017 ($48 million) and for the West Capella in April 2017 ($55 million). The residual decrease was due to lower revenues for services provided to Seadrill within our Nigerian service company, as Seadrill had fewer rigs operating in Nigeria ($5 million).
The West Sirius previously had a contract in Gulf of Mexico which was terminated by BP in July 2015 and the termination period was from July 2015 to July 2017. We therefore received a full year of early termination revenue in the year ended December 31, 2016 but only six months in the year ended December 31, 2017.
The West Capella previously had a contract in Nigeria which was terminated by ExxonMobil in April 2016 and the termination period was from April 2016 to April 2017. We therefore recognized eight months of early termination revenue in the year ended December 31, 2016 but only four months in the year ended December 31, 2017.
Revaluation of contingent consideration
There was gain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 2017 (December 31, 2016: $nil).
The gain is the result of a reduction in contingent liabilities related to the purchase of the West Polaris in 2015. Future dayrate estimates and re-contracting assumptions have been used to determine the fair value of these liabilities. These estimates have decreased during the year, resulting in a decrease in the fair value of the liabilities.
Vessel and rig operating expenses
Vessel and rig operating expenses were $345.4 million in the year ended December 31, 2017 (December 31, 2016: $373.9 million).
The $28.5 million or 7.6% decrease was primarily due to idle time on the West Leo ($28 million) and the West Aquarius ($4 million).
These decreases were offset by higher costs on the West Capricorn as it returned to operations in the second half of the year ($6 million) and on the West Polaris as a result of the rig move from Angola to Equatorial Guinea and early demobilization ($6 million).
The remaining decrease is related to a reduction in costs across other operating rigs as a result of cost saving initiatives ($9 million).
Amortization of favorable contracts
Amortization of favorable contracts was $74.4 million for the year ended December 31, 2017 (December 31, 2016: $70.6 million).
The $3.8 million or 5.4% increase was related to the West Polaris completing its contract sooner than expected.
Reimbursable expenses
Reimbursable expenses were $16.1 million for the year ended December 31, 2017 (December 31, 2016: $30.2 million). The $14.1 million or 46.7% decrease is in line with the reduction in reimbursable revenue.

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Depreciation and amortization
Depreciation and amortization expenses were $274.9 million for the year ended December 31, 2017 (December 31, 2016: $266.3 million). The $8.6 million or 3.2% increase was primarily due to drilling unit upgrades and maintenance projects capitalized and depreciated during the year.
General and administrative expenses
General and administrative expenses were $44.8 million for the year ended December 31, 2017 (December 31, 2016: $41.2 million). The $3.6 million or 8.7% increase was primarily due to higher legal and professional costs not related to the credit facility amendments.
Interest income
Interest income was $15.7 million for the year ended December 31, 2017 (December 31, 2016: $11.5 million). The $4.2 million or 36.5% increase is due to higher cash balances and increased interest rates.
Interest expense
Interest expense was $179.1 million for the year ended December 31, 2017 (December 31, 2016: $180.0 million). The impact of a reduction in average amount of debt outstanding during 2017 was was offset by higher LIBOR rates and increased margins on our bank facilities following the insulation transaction in August 2017.
Derivative financial instruments
Derivative financial items resulted in an expense of $13.9 million for the year ended December 31, 2017 (December 31, 2016: expense of $18.0 million). The $4.1 million or 22.8% decrease in the expense was due to a smaller increase in the forward interest rate curve in 2017 than in 2016.
Currency exchange gain
Gain on foreign currency exchange was $0.9 million for the year ended December 31, 2017 (December 31, 2016: $0.6 million). The gain is broadly in line with the prior year and predominantly occurred from foreign currency denominated transactions in Africa.
Other financial items
Other financial items were an expense of $11.5 million for the year ended December 31, 2017 (December 31, 2016: nil). The increase was due to debt issue costs related to the amendments on our bank facilities in August 2017.
Income taxes
Income tax expense was $40.3 million for the year ended December 31, 2017 (December 31, 2016: $86.5 million) and our effective income tax rate was 14.6% and 13.7% for the years ended December 31, 2017 and 2016 respectively. The decrease is primarily due to lower operating income in the year ended December 31, 2017 compared to the year ended December 31, 2016. Please refer to Note 5 "Taxation" to the Consolidated Financial Statements included in this annual report.


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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
The following table summarizes our operating results for the years ended December 31, 2016 and 2015:
($US in millions)
Year Ended December 31,
 
Increase/(Decrease)
 
2016
 
2015
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
Contract revenues
$
1,356.4

 
$
1,603.6

 
$
(247.2
)
 
(15.4
)%
Reimbursable revenues
32.8

 
49.9

 
(17.1
)
 
(34.3
)%
Other revenues
211.1

 
88.1

 
123.0

 
139.6
 %
Total operating revenues
1,600.3

 
1,741.6

 
(141.3
)
 
(8.1
)%
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Vessel and rig operating expenses
(373.9
)
 
(495.5
)
 
121.6

 
24.5
 %
Amortization of favorable contracts
(70.6
)
 
(66.9
)
 
(3.7
)
 
(5.5
)%
Reimbursable expenses
(30.2
)
 
(45.7
)
 
15.5

 
33.9
 %
Depreciation and amortization
(266.3
)
 
(237.5
)
 
(28.8
)
 
(12.1
)%
General and administrative expenses
(41.2
)
 
(52.3
)
 
11.1

 
21.2
 %
Total operating expenses
(782.2
)
 
(897.9
)
 
115.7

 
12.9
 %
Net operating income
$
818.1

 
$
843.7

 
$
(25.6
)
 
(3.0
)%
 
 
 
 
 
 
 
 
Financial items:
 
 
 
 
 
 
 
Interest income
11.5

 
9.8

 
1.7

 
17.3
 %
Interest expense
(180.0
)
 
(192.5
)
 
12.5

 
6.5
 %
Loss on derivative financial instruments
(18.0
)
 
(82.9
)
 
64.9

 
78.3
 %
Currency exchange gain
0.6

 
1.6

 
(1.0
)
 
62.5
 %
Gain on bargain purchase
—

 
9.3

 
(9.3
)
 
100.0
 %
Total financial items
(185.9
)
 
(254.7
)
 
68.8

 
27.0
 %
Income before income taxes
632.2

 
589.0

 
43.2

 
7.3
 %
Income taxes
(86.5
)
 
(100.6
)
 
14.1

 
14.0
 %
Net Income
$
545.7

 
$
488.4

 
$
57.3

 
11.7
 %
Net income attributable to the non-controlling interest
$
(264.7
)
 
$
(231.2
)
 
$
33.5

 
14.5
 %
Net income attributable to Seadrill Partners LLC
$
281.0

 
$
257.2

 
$
23.8

 
9.3
 %
Contract revenues
Contract revenues were $1,356.4 million, for the year ended December 31, 2016 (December 31, 2015: $1,603.6 million). The $247.2 million or 15.4% decrease was primarily due to additional idle units ($300.3 million) and lower dayrates ($13.3 million). The decrease was partially offset by contract revenues from the West Polaris which was acquired on June 19, 2015 ($49.5 million) and higher economic utilization for rigs in operation ($17.0 million). Contract revenues do not include early termination payments, these are recognized as "other revenues".

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The following table summarizes average daily revenues and economic utilization percentage by drilling unit type of the Company’s fleet for the periods presented:
 
Year Ended December 31,
 
2016
 
2015
 
Number of rigs/ships
 
Average
Daily Revenues (1)
 
Economic
Utilization (2)
 
Number of rigs/ships
 
Average
Daily Revenues (1)
 
Economic
Utilization (2)
Semi-submersible rigs (3)
3
 
$
555,193

 
99.3
%
 
4
 
$
551,590

 
93.0
%
Drillship
4
 
$
531,620

 
94.5
%
 
4
 
$
608,444

 
98.7
%
Tender rigs
3
 
$
116,634

 
98.6
%
 
3
 
$
148,634

 
98.5
%
(1)
Average daily revenues are the average revenues for each type of unit, based on the actual days available, while on contract.
(2)
Economic utilization is calculated as the total revenue, excluding bonuses, received divided by the full operating dayrate multiplied by the number of days in the period for rigs on contract.
(3)
Average daily revenue excludes the termination payments received as part of the termination of the drilling contract by BP for the West Sirius.
Reimbursable revenues
Reimbursable revenues were $32.8 million, for the year ended December 31, 2016 (December 31, 2015: $49.9 million). The $17.1 million or 34.3% decrease was due to less equipment purchased on behalf of customers, for which we have been reimbursed.
Other revenues
Other revenues were $211.1 million for the year ended December 31, 2016 (December 31, 2015: $88.1 million). The $123.0 million or 139.6% increase was primarily due to early termination payments received for the West Sirius which was terminated in April 2015 ($34.0 million) and the West Capella contract which was terminated in May 2016 ($90.1 million). This increase was partially offset by lower revenues for services provided to Seadrill within our Nigerian service company ($0.9 million).
Vessel and rig operating expenses
Vessel and rig operating expenses were $373.9 million, for the year ended December 31, 2016 (December 31, 2015: $495.5 million). The $121.6 million or 24.5% decrease was primarily due to additional idle units ($69.5 million), reduced costs on West Capricorn while on standby rate ($23.9 million) and lower operating costs for vessels in operation ($36.3 million). The decrease was partially offset by the inclusion of a full year of operating expenses for the West Polaris ($8.5 million) which was acquired on June 19, 2015.
Amortization of favorable contracts
Amortization of favorable contracts was $70.6 million for the year ended December 31, 2016 (December 31, 2015: $66.9 million). The $3.7 million or 5.5% increase relates to a full year of amortization of the West Polaris favorable contract. Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition. These intangibles are amortized on a straight-line basis over the remaining contract period.
Reimbursable expenses
Reimbursable expenses were $30.2 million for the year ended December 31, 2016 (December 31, 2015: $45.7 million). The $15.5 million or 33.9% decrease was due to a reduction in equipment purchased on behalf of customers, for which we have been reimbursed.
Depreciation and amortization
Depreciation and amortization was $266.3 million for the year ended December 31, 2016 (December 31, 2015: $237.5 million). The $28.8 million or 12.1% increase was primarily due to the acquisition of the West Polaris on June 19, 2015.
General and administrative expenses
General and administrative expenses were $41.2 million for the year ended December 31, 2016 (December 31, 2015: $52.3 million. The $11.1 million or 21.2% decrease was due to a reduction in management fees and overhead costs as part of our cost efficiency program. The decrease was partially offset by the acquisition of the West Polaris on June 19, 2015 ($1.2 million).
Interest income
Interest income was $11.5 million for the year ended December 31, 2016 (December 31, 2015: $9.8 million). The 1.7 million or 17.3% increase is related to the interest earned on insurance receivables relating to the West Aquarius.
Interest expense
Interest expense was $180.0 million for the year ended December 31, 2016 (December 31, 2015: $192.5 million). The $12.5 million or 6.5% decrease was primarily due to lower debt balances following the repayments in the year ($17.0 million) offset by a full year of interest on the debt associated with the acquisition of the West Polaris ($4.3 million).

44
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Loss on derivative financial instruments
The loss on derivative financial instruments was $18.0 million for the year ended December 31, 2016 (December 31, 2015: $82.9 million). The $64.9 million or 78.3% decrease relates to movements in the mark to market valuation of the Company's interest rate swaps on variable rate debt. Included in the $18.0 million loss for the year ended December 31, 2016 is an out of period gain of $21.4 million recognized in relation to the inclusion of counterparty credit risk in the determination of the fair value of these interest rate swap agreements. Please refer to Item 11 "Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risks," for further information.
Currency exchange gain
Gain on foreign currency exchange was $0.6 million for the year ended December 31, 2016 (December 31, 2015: gains of $1.6 million). The $1.0 million or 62.5% decrease is due to the devaluation of the U.S. Dollar relative to foreign currencies.
Gain on bargain purchase
A $9.3 million gain on bargain purchase was recognized in the year ended December 31, 2015 as a result of the acquisition of the West Polaris in June 2015. Please refer to Note 2 "Accounting policies" and Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report.
Income taxes
Income tax expense was $86.5 million for the year ended December 31, 2016 (December 31, 2015: $100.6 million) and the Company's effective income tax rate was 13.7% and 17.1% for the years ended December 31, 2016 and 2015, respectively. The decrease in the Company's income tax expense was primarily due to a deferred tax benefit arising from the reversal of deferred tax liability related to the West Capella. The decrease is partially offset by the additional uncertain tax position recorded during the year ended December 31, 2016. Please refer to Note 5 "Taxation" to the Consolidated Financial Statements included in this annual report.

B.     Liquidity and Capital Resources
Overview
We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional drilling units, maintenance and ongoing capital expenditure on drilling units, service our debt, fund investments (including the equity portion of investments in drilling units), fund working capital, maintain cash reserves against fluctuations in operating cash flows and pay distributions.
Most of our contract and other revenues are received monthly in arrears, and most of our operating costs are paid on a monthly basis. Our funding and treasury activities are conducted within corporate policies to maximize returns while maintaining appropriate liquidity for our operating requirements.
This section discusses the most important factors affecting our liquidity and capital resources, including:
•
Liquidity requirements
•
Estimated maintenance and replacement capital expenditures
•
Analysis of cash flows for the years ending December 31, 2017, 2016 and 2015
•
Borrowing activities
•
Restrictive covenants
•
Derivative instruments and hedging activities.
Liquidity Requirements
Our primary short-term liquidity requirements relate to servicing our debt, funding working capital requirements, paying for capital expenditures on drilling unit upgrades and major maintenance and making distributions. Our main sources of liquidity include bank balances, undrawn amounts under our revolving credit facility, contract and other revenues. As of December 31, 2017, we had cash and cash equivalents of $848.6 million, compared to $767.6 million as of December 31, 2016.
Short-term outlook and going concern assessment
The financial information in this report has been prepared on the basis that we will continue as a going concern, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Therefore, financial information in this report does not reflect the adjustments to the carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.
Our financial projections indicate that the cash flows we will generate from our current contract backlog, together with our available cash and other resources will allow us to meet our obligations as they fall due for at least the next twelve months after the date that the financial statements are issued. This includes servicing our debt, maintaining working capital, paying for capital expenditure for drilling unit upgrades and major maintenance, making distributions and meeting other obligations as they fall due.

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However, whilst we have taken steps to insulate the Company from events of default related to Seadrill's Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by Seadrill to Seadrill Partners. In the event Seadrill is unable to provide these services, as a result of its restructuring or otherwise, Seadrill Partners has the right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace Seadrill. This may have an adverse effect on operations and may negatively impact our cash flows and liquidity.
Until Seadrill emerges from Chapter 11, uncertainty remains and the condition gives rise to substantial doubt over our ability to continue as a going concern. To the extent Seadrill emerges from Chapter 11,we expect this substantial doubt to be mitigated.
Long-term outlook
Our long-term liquidity requirements include the repayment of long-term debt balances, and funding any potential purchases of drilling units. Generally, our long-term sources of funds will be a combination of borrowings from commercial banks, cash generated from operations and debt and equity financing. We expect that we will rely upon financing from external financing sources, including bank borrowings and the issuance of debt and equity securities, to fund acquisitions and other expansion capital expenditures.
Restrictions on distributions
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, we agreed not to grow our quarterly distributions from the current 10 cents per common unit unless the consolidated net leverage ratio is below 4x during 2018 and below 5x thereafter. Please read Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Estimated Maintenance and Replacement Capital Reserves
Our operating agreement requires us to distribute our available cash each quarter. In determining the amount of cash available for distribution, the Board determines the amount of cash reserves to set aside, including reserves for future maintenance capital expenditures, working capital and other matters. Because of the substantial capital expenditures, we are required to make to maintain our fleet, our current annual estimated maintenance and replacement capital reserves are $207 million per year, which is comprised of $75 million for long term maintenance and society classification surveys and $132 million, including financing costs, for replacing our existing drilling units at the end of their useful lives.
The estimate for future rig replacement is based on assumptions regarding the remaining useful life of our drilling units, a net investment rate applied on reserves, replacement values of our existing rigs based on current market conditions, and the residual value of the rigs. The actual cost of replacing the drilling units in our fleet will depend on a number of factors, including prevailing market conditions, drilling contract operating dayrates and the availability and cost of financing at the time of replacement. Our operating agreement requires the Board to deduct from the Company's operating surplus each quarter estimated maintenance and replacement capital reserves, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as society classification surveys and rig replacement. The Board, with the approval of the conflicts committee, may determine that one or more of the assumptions should be revised, which could cause the Board to increase the amount of estimated maintenance and replacement capital reserves. We may elect to finance some or all of our actual maintenance and replacement capital expenditures through the issuance of additional common units which could be dilutive to existing unitholders. As our fleet matures and expands, estimated long-term maintenance reserves will likely increase.
Analysis of Cash Flows for the years ending December 31, 2017, 2016 and 2015
The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the periods presented:
($ in millions)
Year Ended December 31,
 
2017
 
2016
 
2015
Net cash provided by operating activities
$
476.2

 
$
873.8

 
$
859.8

Net cash (used in) provided by investing activities
(11.1
)
 
97.6

 
(376.3
)
Net cash used in financing activities
(384.9
)
 
(522.1
)
 
(407.6
)
Effect of exchange rate changes on cash
0.8

 
(0.7
)
 
0.4

Net increase in cash and cash equivalents
81.0

 
448.6

 
76.3

Cash and cash equivalents at beginning of period
767.6

 
319.0

 
242.7

Cash and cash equivalents at end of period
848.6

 
767.6

 
319.0

Net Cash Provided by Operating Activities
Net cash provided by operating activities was $476.2 million and $873.8 million for the year ended December 31, 2017 and December 31, 2016 respectively.
The decrease of $397.6 million was primarily due to lower net income, which decreased by $394 million after adding back non-cash items. The residual decrease was due to increased long term maintenance expenditures, partly offset by a favorable change in working capital.
Net cash provided by operating activities was $873.8 million and $859.8 million for the years ended December 31, 2016 and December 31, 2015 respectively. The increase of $14.0 million was primarily due to a favorable change in working capital offset by a decrease in operating income.

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Net Cash (Used in) Provided by Investing Activities
Net cash used in investing activities was $11.1 million for the year ended December 31, 2017. This was due to capital expenditure on drilling unit upgrades of $67 million, offset by a cash inflow from the repayment of a related party loan from Seadrill of $39 million and proceeds from the sale of an under construction managed pressure drilling system to Seadrill of $16 million. Capital expenditures for drilling unit upgrades in 2017 were primarily for managed pressure drilling systems for the West Capella, West Capricorn and West Auriga. We sold the under-construction managed pressure drilling system for the West Auriga to Seadrill in September 2017.
Net cash provided by investing activities was $97.6 million for the year ended December 31, 2016. This was due to proceeds of $104 million from related party long term debt and an insurance refund of $7 million related to claims for the West Aquarius. These cash proceeds were partially offset by $13 million of capital expenditures.
Net cash used in investing activities was $376.3 million for the year ended December 31, 2015. This was primarily due to the acquisition of the entity that owns and operates the West Polaris from Seadrill. The cash consideration paid, net of cash acquired, was $215 million. We also made a loan to related parties of $143 million and capital expenditures were $19 million.
Net Cash Used in Financing Activities
Net cash used in financing activities was $384.9 million for the year ended December 31, 2017. This was due to external debt repayments of $219 million (including associated fees), related party debt repayments of $66 million, payments of deferred and contingent consideration of $40 million and cash distributions of $60 million.
Net cash used in financing activities was $522.1 million for the year ended December 31, 2016. This was due to payments to related parties for long term debt and contingent consideration payable of $309 million, cash distributions of $107 million and $106 million in relation to external long term debt and associated fees.
Net cash used in financing activities was $407.6 million in December 31, 2015. This was primarily due to cash distributions of $435 million, $98 million in relation to long term debt and associated fees and $27 million paid to related parties for contingent consideration payable. There were net cash proceeds from related parties of $103 million in respect of long term debt and $50 million in proceeds from the revolving credit facility.
Net Increase in Cash and Cash Equivalents
As a result of the above, cash and cash equivalents increased in 2017 by $81 million, increased in 2016 by $448.6 million, and increased in 2015 by $76.3 million.

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Borrowing Activities
The below table summarizes the status of our borrowing facilities at December 31, 2017 and December 31, 2016.
Facility
Collateral Vessels
Maturity
Principal outstanding at Dec 31, 2017 ($millions)

Principal outstanding at Dec 31, 2016 ($millions)

Debt repayments in 2017 ($millions)

Debt repayments in 2016             ($millions)

External facilities
 
 
 
 
Term loan B
See below (1)
Feb-2021
2,786.9

2,815.9

29.0

29.1

$100m RCF
See below (1)
Feb-2019
50.0

50.0

—

—

West Vela facility (2)
West Vela
Oct-2020
255.3

342.2

86.9

40.2

West Polaris (2)
West Polaris
Jul-2020
205.6

279.0

73.4

36.0

Tender Rig facility (2)
T-15 & T-16
Jun-2020
83.3

—

25.7

—

 
 
 
3,381.1

3,487.1

215.0

105.3

Related party debt
 
 
 
 
 
 
Tender Rig facility (2)
T-15 & T-16
Jun-2020
—

119.1

10.1

19.9

West Vencedor facility
West Vencedor
Jun-2018
24.7

41.2

16.5

16.5

West Sirius loan (3)
None
Apr-2017
—

39.4

39.4

103.6

Vendor financing loan
None
May-2016
—

—

—

109.5

 
 
 
24.7

199.7

66.0

249.5

 
 
 
 
 
 
 
Total
 
 
3,405.8

3,686.8

281.0

354.8

(1) The collateral vessels for the Term Loan B and linked revolving credit facility are the West Sirius, West Aquarius, West Capricorn, West Leo, West Capella and West Auriga.
(2) The Tender Rig facility was classified as a related party debt facility until the facility was amended in August 2017.
(3) The West Sirius loan has been classified within related party payable on the consolidated balance sheet as at December 31, 2016.
Key changes to borrowing facilities from January 1, 2015 to December 31, 2017
On April 14, 2015, we amended the terms and extended the maturity of the West Vencedor facility with Seadrill. Following this amendment, the maturity date was extended to June 25, 2018 with a balloon payment of $20.6 million due at maturity.
On June 19, 2015, we completed the purchase of the entities that owned and operated the drillship West Polaris (from Seadrill). As part of the purchase price, we acquired the liability for $336 million of debt outstanding under the facility used by Seadrill to finance the West Polaris (the "West Polaris facility"). We also drew down $50 million of the $100 million revolving credit facility available under our Term Loan B to finance a proportion the upfront cash consideration we paid for the West Polaris.
Effective as of December 17, 2015, we borrowed $143.0 million from Seadrill to provide sufficient immediate liquidity to meet the terms of a bareboat charter termination payment we were required to make for the West Sirius contract termination (the "West Sirius loan). Concurrently, Seadrill borrowed $143.0 million (the “Seadrill loan”) from one of our rig owning subsidiaries to restore its liquidity with respect to the West Sirius loan. Each of the loan parties understood and agreed that the loan agreements act in parallel with each other. Each loan bore an interest rate of one-month LIBOR plus 0.56% and matured in August 2017.
On August 11, 2017, we agreed to an amendment and an extension to the maturities of the West Vela, West Polaris and Tender Rig facilities. These amendments insulated us from events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements.
The facilities were amended as follows:
1.
The secured credit facility relating to both the West Vela drillship (owned by Seadrill Partners) and the West Tellus drillship (owned by Seadrill), was split into two separate facilities, the “West Vela facility” and the “West Tellus facility”. Recourse of the West Vela facility is now only to Seadrill Partners consolidated entities and recourse of the West Tellus facility is now only to Seadrill consolidated entities. The maturity date of the West Vela facility was extended until October 2020.

2.
Seadrill resigned as a guarantor to the West Polaris facility. Recourse of the West Polaris facility is now only to Seadrill Partners consolidated entities. The maturity date of the West Polaris facility was extended until July 2020.

3.
The secured credit facility relating to the T-15 & T-16 tender rigs (owned by Seadrill Partners) and the West Telesto jack-up (owned by Seadrill) was split into two separate facilities, the “Tender Rig facility” and the “West Telesto facility”. Recourse of the Tender rig facility is now only to Seadrill Partners consolidated entities and recourse of the West Telesto facility is now only to Seadrill consolidated entities. The maturity date of the Tender Rig facility was extended until June 2020.

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As part of this transaction we agreed to make a prepayment of $100 million on closing and two subsequent prepayments of $25 million in February 2018 and August 2018, in each case distributed pro rata across the West Vela, West Polaris and Tender Rig facilities. We also agreed to a 1% increase in margin, certain covenant and security amendments and to cancel a $100 million revolver provided by Seadrill.
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, the Company has agreed to certain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Debt repayments by year
The outstanding debt as of December 31, 2017 is repayable as follows: 
(In US$ millions)
December 31, 2017

2018
$
199.8

2019
175.1

2020
331.1

2021
2,699.8

Total external and related party debt
$
3,405.8

Debt issuance costs
In our Consolidated Balance Sheet we present debt balances net of debt issuance costs. This is set out in the below table:
 
 
Outstanding debt as of December 31, 2017
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
175.1

$
(12.2
)
$
162.9

Long-term external debt
 
3,206.0

(25.8
)
3,180.2

Total external debt
 
$
3,381.1

$
(38.0
)
$
3,343.1

Current portion of long term related party debt
 
$
24.7

$
—

$
24.7

Total interest bearing debt
 
$
3,405.8

$
(38.0
)
$
3,367.8

 
 
Outstanding debt as of December 31, 2016
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
105.3

$
(11.5
)
$
93.8

Long-term external debt
 
3,381.8

(35.3
)
3,346.5

Total external debt
 
$
3,487.1

$
(46.8
)
$
3,440.3

Current portion of long term related party debt
 
$
135.6

$
—

$
135.6

Long term related party debt
 
$
24.7

$
—

$
24.7

West Sirius loan - included within line item "related party payable"
 
$
39.4

$
—

$
39.4

Total interest bearing debt
 
$
3,686.8

$
(46.8
)
$
3,640.0

Further information
Please refer to Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for detailed information on our borrowings and credit facilities.
Restrictive Covenants
Details of covenants, terms of default and restrictions may be found in the debt agreement and subsequent amendments which have been filed as exhibits to this 20-F report. Please refer to Item 19 - "Exhibits".
We were not in breach of applicable covenants as of December 31, 2017. Please read Note 11 "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Derivative Instruments and Hedging Activities
We may use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. Our use of these instruments is described below.

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Interest rate risk
We use interest rate swaps to reduce the risk associated with fluctuations in interest rates. None of our interest rate swaps have been designated as hedging instruments. Therefore, changes in their fair value are taken to income each period. We classify the gain or loss on interest rate swaps within the line item "Loss on derivative financial instruments" in the consolidated statement of operations.
Total realized and unrealized losses on interest-rate swap agreements amounted to $13.9 million for the year ended December 31, 2017 (December 31, 2016: loss of $18.0 million).
As of December 31, 2017, our interest rate swap contracts had a combined outstanding principal amount of $2,793.9 million (December 31, 2016: $2,822.9 million), swapping LIBOR for an average fixed rate of 2.49% per annum.
As of December 31, 2017, our net exposure to short term fluctuations in interest rates on our outstanding debt was $611.9 million (December 31, 2016: $204.2 million), based on total net interest bearing debt of $3,405.8 million (December 31, 2016: $3,647.4 million), including related party debt agreements, less the $2,793.9 million (December 31, 2016: $3,443.2 million) outstanding balance of fixed interest rate swaps.
We previously held related party interest rate swaps with Seadrill which were canceled on September 12, 2017 as a result of Seadrill entering a Chapter 11 restructuring. The settlement value of these interest rate swaps at the point they were canceled was $1.9 million. This amount was classified as a related party receivable in our Consolidated Balance Sheet. We expect this receivable to be recovered in full.
Foreign currency risk
Our cash and cash equivalents are held primarily in U.S. Dollars with minor balances held in other currencies. Our revenue and costs are primarily denominated in U.S Dollars although a proportion of our vessel and rig operating expenses and a small amount of revenue are denominated in other currencies. The main currencies in which we have foreign currency exposures are Angolan Kwanza, Canadian Dollars, Thai Baht, and Nigerian Naira.
We do not currently use derivative instruments to manage currency risk. However, depending on the level of our currency exposure, we may do so in the future.

C.     Research and Development, Patents and Licenses
We do not undertake any significant expenditures on research and development, and have no significant interests in patents or licenses.


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D.     Trend Information
The offshore drilling market is currently entering the fifth year of a downturn and the timing of recovery remains uncertain. The below table show the average oil price over the period 2013 to 2017.
 
2013
2014
2015
2016
2017
Average Brent oil price
$108.70
$99.49
$53.60
$45.13
$54.74
Brent oil prices have been in the range of $45-$55 throughout most of 2017 before increasing in the last quarter of 2017 and in early 2018. The Brent oil price on March 31, 2018 was $70.
Oil and gas companies have responded to the decrease in oil price over the downturn by decreasing their upstream expenditures. During 2017, oil and gas companies have continued to focus on preserving cash, in some cases consciously allowing the production decline rate on producing fields to accelerate as a result of reduced infill drilling and well intervention. Based on the decreased level of investment since 2014, we expect that production decline rates will increase. Further, the longer the period that lower investment persists, the greater the number of new projects and infill drilling that will be required to replace the lost production.
The below table shows the global number of rigs on contract at March 31, 2018 and for each of the four preceding years.
 
Mar-2014

Mar-2015

Mar-2016
Mar-2017

Mar-2018

Contracted floating rigs
260

237

170
135

125

Contracted tender rigs
25

24

21
15

12

During 2017, we have seen an increase in the activity level in the floater market, albeit primarily for short term work at extremely competitive dayrates. This improvement was from a low base and we still expect utilization in the floater market to get worse before it improves. Whether the recent increase in oil prices will lead to a recovery in offshore exploration and development expenditure in 2018 remains uncertain. It is important to recognize that the resetting of costs across the value chain may facilitate increased activity with only a marginal increase in oil prices.
The offshore drilling market remains oversupplied. Offshore drilling contractors have continued to aggressively market their rigs, often focusing on utilization over returns. The below table shows the utilization of the global fleet at March 31, 2018 and for each of the four proceeding years.
 
Mar-2014
Mar-2015
Mar-2016

Mar-2017

Mar-2018

Global fleet - floaters
320
313
303

282

259

Global fleet - tenders
39
38
34

33

30

Utilization - floaters
81%
76%
56
%
48
%
48
%
Utilization - tenders
64%
63%
62
%
45
%
40
%
Older units that roll off contract may require significant capital expenditure to return to the working fleet and so are more likely to be cold stacked and ultimately scrapped. We expect the combination of increased production decline rates and accelerated scrapping activity to lead to a balanced market at some point. Based on the expected level of scrapping activity and the number of units that are anticipated to be cold stacked, a relatively small increase in spending could meaningfully tighten the floater and tender markets.
Floaters - outlook
Based on the level of current activity and the aging floater fleet, we expect scrapping activity to continue. A total of 103 floaters have been scrapped or retired since the beginning of 2014, equivalent to 32% of the total fleet, and currently there are 28 cold or warm stacked units with no follow-on work identified that are 30 years old or older, which are prime scrapping candidates. In the next 18 months, a further 22 units that are 30 years old or older will be coming off contract with no follow-on work identified which represents additional scrapping candidates. A key rational for scrapping is the 35-year classing expenditures that can cost upwards of $100 million. Many rig owners will choose to retire the unit rather than incur this cost without a visible recovery in demand on the horizon.
Larger drilling companies with diversified fleets will find it easier to make economic decisions and cold stack idle rigs as each individual unit represents a smaller percentage of the overall fleet. Cold stacked units will generally require an improvement in dayrates sufficient to overcome reactivation costs before they are reintroduced into marketed supply. Significant cold stacking activity would represent a positive development in the market, effectively reducing marketed supply and helping to stabilize utilization and pricing until a more fundamental recovery is in place.
Currently 125 floaters out of 259 floaters are under contract, representing 48% marketed utilization. It is estimated that 180-200 rigs are needed in the floater fleet to maintain long-term average production decline curves.
Currently the global floater order book stands at approximately 42 units, comprised of 28 drillships and 14 semi-submersible rigs. 12 are scheduled for delivery in 2018, 17 in 2019 and 13 in 2020 and beyond. Due to the subdued level of contracting activity, it is likely that a significant number of newbuild orders will be delayed or canceled until an improved market justifies taking delivery.

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Tender rigs - outlook
The worldwide fleet of tender rigs currently totals 30 units, of which 12 are contracted representing 40% capacity utilization. Overall, the global fleet is 12 years old on average. Currently the order book stands at approximately 6 units. 2 are scheduled for delivery in 2018 and 4 in 2020.
Activity in the tender rig market is focused primarily in South-east Asia and West Africa. Capacity utilization and dayrates have remained under pressure, similar to the worldwide floater market.
E.     Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2017 or 2016, other than operating lease obligations and other commitments in the ordinary course of business that it is contractually obligated to fulfill with cash under certain circumstances. These commitments include guarantees in favor of banks as well as guarantees towards third parties such as surety performance guarantees towards customers as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these guarantees are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2017, we had not been required to make collateral deposits with respect to these agreements.
The maximum potential future payments are summarized in Note 15 "Commitments and contingencies" to the Consolidated Financial Statements included in this annual report.

F.     Tabular Disclosure of Contractual Obligations
The following table summarizes our long-term contractual obligations as of December 31, 2017:
 
Payments Due by Period
 ($ in millions)
Total
 
Less than
1 Year
 
1-3 Years
 
4-5 Years
 
More than
5 Years
Long-term debt obligations
$
3,381.1

 
$
175.1

 
$
506.2

 
$
2,699.8

 
$
—

Related Party debt obligations
24.7

 
24.7

 
—

 
—

 
—

Interest expense commitments on long-term debt obligations (1)
785.9

 
243.4

 
484.3

 
58.2

 
—

Deferred consideration payable (2)
84.7

 
29.8

 
54.9

 
—

 
—

Total
$
4,276.4

 
$
473.0

 
$
1,045.4

 
$
2,758.0

 
$
—

(1)
Our interest commitment on long-term debt is calculated based on the applicable interest rates contained in our loan agreements as of December 31, 2017, the associated interest rate swap rates and the 3% increase in margin due on the TLB following the amendment in February 2018.
(2)
We recognized deferred consideration payable as a result of the purchase from Seadrill of the entities that own and operate the West Vela on November 4, 2014. The payment of these amounts is contingent on the amount of contract revenues and mobilization revenues received from the customer. For further information on the nature of these payments please see Note 13 "Related Party Transactions" to the Consolidated Financial Statements included in this annual report.
(3)
In addition to the above, we have recognized liabilities for uncertain tax positions at December 31, 2017 of $43.7 million.

G.     Safe Harbor
See the section entitled "Important Information Regarding Forward-Looking Statements" in this annual report.

Item 6.         Directors, Senior Management and Employees


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A.     Directors and Senior Management
Directors
The following provides information about each of the Company's directors. The business address through which the Board can be contacted is 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.
Name
Age
Position
Graham Robjohns
53
Director
Bert Bekker
79
Director and Audit Committee Member
Kate Blankenship
53
Director and Audit Committee Member
Harald Thorstein
38
Director and Chairman
Andrew Cumming
63
Director and Conflicts Committee Member
Keith MacDonald
60
Director, Audit Committee Member and Conflicts Committee Member
Certain biographical information about each of our directors and executive officers is set forth below.
Graham Robjohns was appointed to the Board by Seadrill Member and has served as a director since July 2012. Mr. Robjohns currently serves as a director of Seadrill UK Ltd., a wholly owned subsidiary of Seadrill, and has served in such position since June 2010. Mr. Robojohns has served as the deputy Chief Executive Officer and Chief Financial Officer of Golar LNG Limited since March 2018. Mr. Robjohns was also the Chief Executive Officer of the Company from June 2012 to August 2015. Mr. Robjohns also served as Principal Executive Officer of Golar LNG Partners LP from July 2011 until March 2018 and, prior to that, served as its Chief Executive Officer and Chief Financial Officer from April 2011 to July 2011. Mr. Robjohns served as the Chief Financial Officer of Golar Management Limited ("Golar Management") from November 2005 until June 2011. Mr. Robjohns also served as Chief Executive Officer of Golar Management from November 2009 until July 2011. Mr. Robjohns served as Group Financial Controller of Golar Management from May 2001 to November 2005 and as Chief Accounting Officer of Golar Management from June 2003 until November 2005. He was the Financial Controller of Osprey Maritime (Europe) Ltd from March 2000 to May 2001. From 1992 to March 2000 he worked for Associated British Foods Plc. and then Case Technology Ltd (Case), both manufacturing businesses, in various financial management positions and as a director of Case. Prior to 1992, Mr. Robjohns worked for PricewaterhouseCoopers in their corporation tax department. He is a member of the Institute of Chartered Accountants in England and Wales.
Bert Bekker has served as a director of the Company since September 2012, and serves on the Company's audit committee. Mr. Bekker has been in the heavy marine transport industry since 1978 when he co-founded Dock Express Shipping Rotterdam (the predecessor of Dockwise Transport). Mr. Bekker retired from his position as Chief Executive Officer of Dockwise Transport B.V. in May 2003. Mr. Bekker served as Chief Executive Officer of Cableship Contractors N.V. Curacao from March 2001 until June 2006. In May 2006, Mr. Bekker was appointed Executive Advisor Heavy Lift of Frontline Management AS, an affiliate of Frontline Ltd. ("Frontline"), and in January 2007, he was appointed CEO of Sealift Management B.V. Mr. Bekker held that position until its merger with Dockwise Ltd in May 2007. Mr. Bekker served as a director of Dockwise Ltd. from June 2007 until December 2009. Mr. Bekker served as a director of Wilh. Wilhelmsen Netherlands B.V., part of the Wilh. Wilhelmsen ASA Group, from July 2003 until December 2015. Mr. Bekker served as a director of Seadrill from April 2013 until October 2016. Mr. Bekker has served as a director of Ship Finance International since May 2015.
Kate Blankenship was appointed to the Board by the Seadrill Member and has served as a director of the Company since June 2012, and serves on the Company's audit committee. Mrs. Blankenship has served as a director of Seadrill since its inception in May 2005. Mrs. Blankenship has also served as a director of Frontline since 2003. Mrs. Blankenship joined Frontline in 1994 and served as its Chief Accounting Officer and Company Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003, North Atlantic Drilling Limited since February 2011, Independent Tankers Corporation Limited since February 2008, Golden Ocean Group Limited since November 2004, Archer since its incorporation in 2007 and Avance Gas Holding Limited since October 2013. Mrs. Blankenship served as a director of Golar LNG Limited from July 2003 until September 2015 and Golar LNG Partners LP from September 2007 until September 2015. She is a member of the Institute of Chartered Accountants in England and Wales.
Harald Thorstein has served as a director of the Company since September 2012. Mr. Thorstein is currently employed by Seatankers Consultancy Services (UK) Limited (previously Frontline Corporate Services) in London, prior to which he was employed in the Corporate Finance division of DnB NOR Markets, specializing in the offshore and shipping sectors. Mr. Thorstein has also served as a director of Ship Finance International Limited since 2011. He served as a director of Golden Ocean Shipping Limited’s predecessor from 2014 until its merger with “Knightsbridge Shipping Limited” in 2015. Mr. Thorstein has also served on the Boards of North Atlantic Drilling Ltd., from 2013 until 2015, Archer Limited from 2015 until 2016 and Frontline 2012 Ltd., from 2014 until 2015. Mr. Thorstein is Chairman of the Board of Directors of Deep Sea Supply Plc and has served as a Director of that company since 2013. Mr. Thorstein has an MSc in Industrial Economics and Technology Management from the Norwegian University of Science and Technology.
Andrew Cumming was originally appointed by the remaining elected directors to replace Bart Veldhuizen as a Class III elected director in June 2015 and was elected by the unitholders in September 2016. Mr. Cumming also serves on the Company’s conflicts committee. Mr. Cumming has almost 40 years of experience in banking and risk management. Prior to his retirement in 2014, Mr. Cumming spent 17 years of his career in a variety of positions at Lloyds Bank, including 7 years as Chief Credit Officer, Commercial Banking Division and membership of Group Risk and Commercial Banking Executive Committees.  He is a graduate of the University of London and a Fellow of the Chartered Institute of Bankers Scotland.  Mr. Cumming also currently acts as a director a mortgage company, Bluestone Holdings Group, and a private equity company, Lloyds Development Capital.

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Keith MacDonald was appointed to the Company’s board of directors in October 2014. Mr. MacDonald also serves on the Company’s audit and conflicts committees. Mr. MacDonald has over 30 years of experience in asset finance as an adviser, banker and independent board director. From 2009 to 2013 he was Global Head of Structured Corporate Finance for Lloyds Banking Group which included the Shipping and other asset finance operations of the Bank. Prior to Lloyds he held senior roles for Citibank from 1990 to 2006 culminating in being Asia-Pacific Head of Structured Corporate Finance based in Hong Kong and was extensively involved in the Bank’s ship finance activities for the Asian market. From 2006 to 2009 he was a Founding Partner of Manresa Partners, a London-based Corporate Finance boutique that specialized in cross-border asset financing. Mr. MacDonald currently acts as an adviser to a number of companies and financial institutions. He is also an Independent Director of three aircraft finance entities and is a Non-Executive Director of First Derivatives plc, a FinTech company listed in London and Dublin. He is a graduate of the National University of Ireland, a Fellow of the Institute of Chartered Accountants in Ireland and a Chartered Director.
Executive Officers
The Company currently does not employ any of its executive officers and relies solely on Seadrill Management to provide the Company with personnel who perform executive officer services for the Company's benefit pursuant to the management and administrative services agreement and who are responsible for the Company's day-to-day management subject to the direction of the Board. The following table provides information about each of the personnel of Seadrill Management who perform executive officer services for us. The business address for the Company's executive officers is 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.
Name
Age
Position
Mark Morris
54
Chief Executive Officer
John T. Roche
38
Chief Financial Officer
Mark Morris has served as the Chief Executive Officer of the Company since September 2015. Mr. Morris has served as the Chief Financial Officer of Seadrill since September 2015. Prior to joining Seadrill Partners and Seadrill, Mr. Morris was most recently Chief Financial Officer for Rolls-Royce Group plc. During his 28 year career at Rolls Royce, among other roles, Mark served as Group Treasurer, Managing Director, Rolls-Royce Capital and Treasurer of International Aero Engines, a Rolls-Royce Joint Venture. Mr. Morris is employed by Seadrill Management Ltd.
John T. Roche has served as the Chief Financial Officer of the Company since June 2015. Since 2013, Mr. Roche has served as Vice President of Investor Relations for Seadrill. Prior to joining Seadrill in May 2013, Mr. Roche spent 12 years at Morgan Stanley, most recently as an Executive Director in its Investment Banking Division. Mr. Roche is employed by Seadrill Management Ltd. and is a Chartered Financial Analyst.

B.     Compensation
Executive Compensation
We are managed on a day to day basis by our executive officers, Mark Morris and John Roche, who are employees of Seadrill and provide services to us under the terms of the management and administrative services agreement. Please read Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreement" for further details on this agreement.
For the year-ended December 31, 2017, we were charged $0.3 million by Seadrill for the services of Mark Morris and John Roche under this agreement. We do not pay any additional compensation to either of our executive officers.
Directors Appointed by Seadrill
Two of our Directors, Kate Blankenship and Graham Robjohns were appointed to the Board by Seadrill. We pay these Directors for their service as Directors, and we reimburse them for out-of-pocket expenses incurred attending meetings of the Board or its committees.
For the year-ended December 31, 2017, the two Directors appointed by Seadrill received aggregate compensation for services of $0.1 million. In addition, we reimbursed each of these Directors for out-of-pocket expenses incurred attending meetings of the Board or its committees.

Directors Elected by Common Unit Holders

Four of our Directors, Bert Bekker, Harold Thorstein, Andrew Cumming and Keith MacDonald were elected by our common unit holders. We pay these Directors, and we reimbursed them for out-of-pocket expenses incurred attending meetings of the Board or its committees.

For the year-ended December 31, 2017, the Directors elected by common unitholders received aggregate compensation for services of $0.3 million.

Indemnification
We fully indemnify each Director for actions associated with being a Director to the extent permitted under Marshall Islands law.

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C.     Board Practices
General
Our operating agreement provides that the Board has authority to oversee and direct our operations, management and policies on an exclusive basis. The executive officers manage our day-to-day activities consistent with the policies and procedures adopted by the Board. Certain of the current executive officers and directors are also executive officers or directors of Seadrill.
The Company's current Board consists of six members: Kate Blankenship, Graham Robjohns, Bert Bekker, Harald Thorstein, Andrew Cumming, and Keith MacDonald. The Board has determined that each of Ms. Blankenship, Mr. Bekker, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by NYSE and Rule 10A-3 of the Exchange Act as applicable to the Company. Ms. Blankenship and Mr. Robjohns were appointed by the Seadrill in its sole discretion and will serve as directors for terms determined by Seadrill. Mr. Bekker, Mr. Thorstein, Mr. Cumming and Mr. MacDonald were elected by our common unitholders.
Directors elected by our common unitholders are divided into three classes serving staggered three-year terms. Mr. Thorstein is designated as the Class I elected director and will serve until the annual meeting of unitholders in 2020. Mr. Bekker is designated as the Class II elected director and will serve until the annual meeting of unitholders in 2018. Each of Mr. MacDonald and Mr. Cumming is designated as a Class III elected director and will serve until the annual meeting of unitholders in 2019.
At each annual meeting of unitholders, directors will be elected to succeed the class of directors whose terms have expired by a plurality of the votes of the common unitholders. Directors elected by the common unitholders will be nominated by the Board or by any member or group of members that holds at least 10% of the outstanding common units.
Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, if at any time, any person or group owns beneficially more than 5% or more of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted (except for purposes of nominating a person for election to the Board). The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of such class of units. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of its board of directors is not subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.
Committees
We have an audit committee that, among other things, reviews our external financial reporting, engages external auditors and oversees its internal audit activities and procedures and the adequacy of its internal accounting controls. The audit committee is currently composed of three directors, Mrs. Blankenship, Mr. Bekker and Mr. MacDonald. Mrs. Blankenship and Mr. MacDonald qualify as "audit committee experts" for purposes of SEC rules and regulations.
We also have a conflicts committee composed of two members of the Board. The conflicts committee is available at the Board’s discretion to review specific matters that the Board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to Seadrill Partners. The members of the conflicts committee may not be officers or employees of Seadrill Partners or directors, officers or employees of Seadrill or its affiliates, and must meet the independence standards established by the NYSE to serve on an audit committee of a board of directors and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to Seadrill Partners, approved by all of its members, and not a breach by its directors, Seadrill or its affiliates of any duties any of them may owe the Company or its unitholders. The current members of the conflicts committee are Mr. Cumming and Mr. MacDonald.
Exemption from NYSE Corporate Governance Rules
Because Seadrill Partners qualifies as a foreign private issuer under SEC rules, we are permitted to follow the corporate governance practices of the Marshall Islands (the jurisdiction in which Seadrill Partners is organized) in lieu of certain NYSE corporate governance requirements that would otherwise be applicable to U.S. companies. NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is composed of a majority of independent directors. Under Marshall Islands law, we are not required to have a board of directors composed of a majority of directors meeting the independence standards described in NYSE rules. NYSE rules do not require foreign private issuers like us to establish a compensation committee or a nominating/corporate governance committee. Similarly, under Marshall Islands law, we are not required to have a compensation committee or a nominating/corporate governance committee. Accordingly, we do not have a compensation committee or a nominating/corporate governance committee. For a listing and further discussion of how our corporate governance practices differ from those required of U.S. companies listed on the NYSE, please see Item 16G or visit the corporate governance section of our website at www.seadrillpartners.com.
Management of OPCO
Our wholly owned subsidiary, Seadrill Operating GP LLC, the general partner of Seadrill Operating LP, manages Seadrill Operating LP’s operations and activities. We have the authority to appoint and elect the directors of Seadrill Operating GP LLC, who in turn appoint the officers of Seadrill Operating GP LLC. Certain of the directors and officers of Seadrill Partners also serve as directors or executive officers of Seadrill Operating GP LLC. The partnership agreement of Seadrill Operating LP provides that certain actions relating to Seadrill Operating LP must be approved by its board of directors. These actions include, among other things, establishing maintenance and replacement capital and other cash reserves and the determination of the amount of quarterly distributions by Seadrill Operating LP to its partners, including us. In addition, we own 51% of the limited liability company interests in Seadrill Capricorn Holdings LLC and control its operations and activities. We also own 100% of the limited liability company interests in Seadrill Partners Operating LLC and control its operations and activities. Please read Item 7 “Major Unitholders and Related Party Transactions—Related Party Transactions—Operating Agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC.”

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D.     Employees
Our Chief Executive Officer and Chief Financial Officer provide their services to us pursuant to the management and administrative services agreement.
As of December 31, 2017, approximately 1,153 offshore staff served on our offshore drilling units and approximately 46 staff served onshore in technical, commercial and administrative roles in various countries. Certain subsidiaries of Seadrill provide onshore advisory, operational and administrative support to our operating subsidiaries pursuant to service agreements. Please read Item 7 "Major Unitholders and Related Party Transactions—Related Party Transactions—Advisory, Technical and Administrative Services Agreements", and "Major Unitholders and Related Party Transactions—Related Party Transactions—Management and Administrative Services Agreement".
Some of Seadrill’s employees that provide services to us and some of our own contracted labor are represented by collective bargaining agreements. Some of these agreements require the contribution of certain amounts to retirement funds and pension plans and special procedures for the dismissal of employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. We consider our and Seadrill's relationships with the various unions as stable, productive and professional.
E.     Unit Ownership
See Item 7 "Major Unitholders and Related Party Transactions—Major Unitholders".


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Item 7.         Major Unitholders and Related Party Transactions

A.     Major Unitholders
The following table sets forth the beneficial ownership of units of Seadrill Partners LLC owned by beneficial owners of 5% or more of the units, and its directors and executive officers as of March 31, 2018:
 
Name of Beneficial Owner
Common Units
Beneficially Owned
 
Subordinated Units
Beneficially Owned
 
Percentage of Total Common and Subordinated Units Beneficially Owned
 
Number
 
Percent
 
Number
 
Percent
 
 
Seadrill Limited (1)
26,275,750

 
34.9
%
 
16,543,350

 
100.0
%
 
46.6
%
Mark Morris (Chief Executive Officer)
—

 
—
%
 
—

 
—
%
 
—

John Roche (Chief Financial Officer)
—

 
—
%
 
—

 
—
%
 
—

Graham Robjohns (Director)
*

 
*

 
—

 
—
%
 
*

Bert Bekker (Director)
—

 
—
%
 
—

 
—
%
 
—
%
Kate Blankenship (Director)
*

 
*

 
—

 
—
%
 
*

Harald Thorstein (Director)
—

 
—
%
 
—

 
—
%
 
—
%
Andrew Cumming (Director)
—

 
—
%
 
—

 
—
%
 
—
%
Keith MacDonald (Director)
*

 
*

 
—

 
—
%
 
*

All directors and executive officers as a group (8 persons)
*

 
*

 
—

 
—
%
 
*

 * Less than 1%.
(1)
Seadrill’s principal shareholder is Hemen Holdings Limited. Hemen Holding Limited, a Cyprus Holding Company, and other related companies which are collectively referred to herein as Hemen, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 119,097,583 shares, or 23.6%, of the common stock of Seadrill, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen.
Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, if at any time any person or group owns beneficially more than 5% of any class of units then outstanding, any units beneficially owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes under the Company's operating agreement, unless otherwise required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board will not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.

B.     Related Party Transactions
From time to time, we have entered into agreements and consummated transactions with certain related parties. We may enter into related party transactions from time to time in the future. In connection with our IPO, we established a conflicts committee, comprised entirely of independent directors, which must approve all proposed material related party transactions.

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Additional disclosure of related party transactions for the years ended December 31, 2017, 2016, and 2015 are presented in Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
The following is a summary of the significant related party agreements with Seadrill:
i.
Omnibus agreement
ii.
Acquisitions
iii.
Management and administrative services agreements
iv.
Advisory, technical and administrative services agreements
v.
Operating agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC
vi.
Loans and financing agreements
vii.
Derivative interest rate swap agreements
viii.
Bareboat charter agreements
i. Omnibus Agreement
At the closing of the Company's IPO, the Company and OPCO entered into the Omnibus Agreement with Seadrill, the Seadrill Member and certain of the Company's other subsidiaries. The following discussion describes certain provisions of the Omnibus Agreement.
Non-competition
Under the Omnibus Agreement, Seadrill agreed, and caused its controlled affiliates (other than the Company and the Seadrill Member) to agree, not to acquire, own, operate or contract for any drilling rig operating under a contract for five or more years. For purposes of the Omnibus Agreement, the term drilling rigs refers only to semi-submersibles, drillships and tender rigs. The Company refers to these drilling rigs, together with any related contracts, as "Five-Year Drilling Rigs" and to all other drilling rigs, together with any related contracts, as "Non-Five-Year Drilling Rigs". The restrictions in this paragraph do not prevent Seadrill or any of its controlled affiliates (including us and its subsidiaries) from:
(1)
acquiring, owning, operating or contracting for Non-Five-Year Drilling Rigs;
(2)
acquiring one or more Five-Year Drilling Rigs if Seadrill promptly offers to sell the drilling rig to us for the acquisition price plus any administrative costs (including reasonable legal costs) associated with the transfer to us at the time of the acquisition;
(3)
putting a Non-Five-Year Drilling Rig under contract for five or more years if Seadrill offers to sell the drilling rig to us for fair market value (x) promptly after the time it becomes a Five-Year Drilling Rig and (y) at each renewal or extension of that contract for five or more years;
(4)
acquiring one or more Five-Year Drilling Rigs as part of the acquisition of a controlling interest in a business or package of assets and owning, operating or contracting for those drilling rigs; provided, however, that:
a.
if less than a majority of the value of the business or assets acquired is attributable to Five-Year Drilling Rigs, as determined in good faith by Seadrill’s board of directors, Seadrill must offer to sell such drilling rigs to us for their fair market value plus any additional tax or other similar costs that Seadrill incurs in connection with the acquisition and the transfer of such drilling rigs to us separate from the acquired business; and
b.
if a majority or more of the value of the business or assets acquired is attributable to Five-Year Drilling Rigs, as determined in good faith by Seadrill’s board of directors, Seadrill must notify us of the proposed acquisition in advance. Not later than 10 days following receipt of such notice, the Company will notify Seadrill if the Company wishes to acquire such drilling rigs in cooperation and simultaneously with Seadrill acquiring the Non-Five-Year Drilling Rigs. If the Company does not notify Seadrill of its intent to pursue the acquisition within 10 days, Seadrill may proceed with the acquisition and then offer to sell such drilling rigs to us as provided in (a) above;
(5)
acquiring a non-controlling interest in any company, business or pool of assets;
(6)
acquiring, owning, operating or contracting for any Five-Year Drilling Rig if the Company does not fulfill its obligation to purchase such drilling rig in accordance with the terms of any existing or future agreement;
(7)
acquiring, owning, operating or contracting for a Five-Year Drilling Rig subject to the offers to us described in paragraphs (2), (3) and (4) above pending the Company's determination whether to accept such offers and pending the closing of any offers the Company accepts;
(8)
providing drilling rig management services relating to any drilling rig;
(9)
owning or operating a Five-Year Drilling Rig that Seadrill owned and operated as of October 24, 2012, and that was not included in the Company’s initial fleet; or
(10)
acquiring, owning, operating or contracting for a Five-Year Drilling Rig if the Company has previously advised Seadrill that the Company consents to such acquisition, operation or contract.

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If Seadrill or any of its controlled affiliates (other than us or its subsidiaries) acquires, owns, operates or contracts for Five-Year Drilling Rigs pursuant to any of the exceptions described above, it may not subsequently expand that portion of its business other than pursuant to those exceptions.
Under the Omnibus Agreement the Company is not restricted from acquiring, operating or contracting for Non-Five-Year Drilling Rigs.
Upon a change of control of us or the Seadrill Member, the noncompetition provisions of the Omnibus Agreement will terminate immediately. Upon a change of control of Seadrill, the noncompetition provisions of the Omnibus Agreement applicable to Seadrill will terminate at the time that is the later of the date of the change of control and the date on which all of our outstanding subordinated units have converted to common units.
Rights of First Offer on Drilling Rigs
Under the Omnibus Agreement, the Company and its subsidiaries granted to Seadrill a right of first offer on any proposed sale, transfer or other disposition of any Five-Year Drilling Rigs or Non-Five-Year Drilling Rigs owned by us. Under the Omnibus Agreement, Seadrill agreed (and will cause its subsidiaries to agree) to grant a similar right of first offer to us for any Five-Year Drilling Rigs they might own. These rights of first offer do not apply to a (a) sale, transfer or other disposition of drilling rigs between any affiliated subsidiaries, or pursuant to the terms of any current or future contract or other agreement with a contractual counterparty or (b) merger with or into, or sale of substantially all of the assets to, an unaffiliated third-party.
Prior to engaging in any negotiation regarding any drilling rig’s disposition with respect to a Five-Year Drilling Rig with a non-affiliated third-party or any Non-Five-Year Drilling Rig, the Company or Seadrill, as the case may be, will deliver a written notice to the other relevant party setting forth the material terms and conditions of the proposed transaction. During the 30 day period after the delivery of such notice, the Company and Seadrill will negotiate in good faith to reach an agreement on the transaction. If the Company does not reach an agreement within such 30 day period, the Company or Seadrill, as the case may be, will be able within the next 180 calendar days to sell, transfer, dispose or re-contract the drilling rig to a third party (or to agree in writing to undertake such transaction with a third party) on terms generally no less favorable to us or Seadrill, as the case may be, than those offered pursuant to the written notice.
Upon a change of control of us or the Seadrill Member, the right of first offer provisions of the Omnibus Agreement will terminate immediately. Upon a change of control of Seadrill, the right of first offer provisions applicable to Seadrill under the Omnibus Agreement will terminate at the time that is the later of the date of the change of control and the date on which all of its outstanding subordinated units have converted to common units.
Rights of First Offer on OPCO Equity Interests
Pursuant to the Omnibus Agreement, Seadrill granted (and caused its controlled affiliates other than us to grant) to us a 30 day right of first offer on any proposed transfer, assignment, sale or other disposition of any equity interests in OPCO upon agreement of the purchase price of such equity interests by Seadrill and us. The right of first offer under the Omnibus Agreement does not apply to a transfer, assignment, sale or other disposition of any equity interest in OPCO between any controlled affiliates.
Prior to engaging in any negotiation regarding any disposition of equity interests in OPCO to an unaffiliated third party, Seadrill will deliver a written notice setting forth the material terms and conditions of the proposed transactions. During the 30 day period after the delivery of such notice, the Company and Seadrill will negotiate in good-faith to reach an agreement on the transaction. If the parties do not reach an agreement within such 30 day period, Seadrill will be able within the next 180 days to transfer, assign, sell or otherwise dispose of any equity interest in OPCO to an unaffiliated third party (or agree in writing to undertake such transaction with a third party) on terms generally no less favorable to the third party than those included in the written notice.
If Seadrill or its affiliates no longer control the Seadrill Member or the Company, the provisions of the Omnibus Agreement relating to the right of first offer with respect to the equity interests in OPCO will terminate automatically. Upon a change of control of Seadrill, the provisions of the Omnibus Agreement relating to the right of first offer with respect to the equity interests in OPCO will terminate at the later of (a) the date on which all of the outstanding subordinated units have converted into common units and (b) the date of the change of control of Seadrill.
Indemnification
Under the Omnibus Agreement, Seadrill agreed to indemnify us until October 24, 2017 against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us. Liabilities resulting from a change in law after October 24, 2012 are excluded from the environmental indemnity. There is an aggregate cap of $10 million on the amount of indemnity coverage provided by Seadrill for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Seadrill is liable for claims only to the extent such aggregate amount exceeds $500,000.
Seadrill also agreed to indemnify us for liabilities related to:
•
certain defects in title to Seadrill’s assets contributed or sold to OPCO and any failure to obtain, prior to the time they were contributed, certain consents and permits necessary to conduct, own and operate such assets, which liabilities arise on or before October 24, 2015 (or, in the case of the T-15 or the T-16, within three years after its purchase of the T-15 or the T-16); and
•
tax liabilities attributable to the operation of the assets contributed or sold to OPCO prior to the time they were contributed or sold.
Amendments
The Omnibus Agreement may not be amended without the prior approval of the conflicts committee of the Board if the proposed amendment will, in the reasonable discretion of the Board, adversely affect holders of the Company's common units.

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ii. Acquisitions
The Company made the following acquisitions for the period from January 1, 2015 through December 31, 2017:
Polaris Acquisition
On June 19, 2015, Seadrill Operating LP completed the purchase of 100% of the ownership interests in Seadrill Polaris, the entity that owns and operates the drillship the West Polaris. Refer to Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report for more information on the Polaris Acquisition.
iii. Management and Administrative Services Agreements
In connection with the IPO, subsidiaries of Seadrill Partners, entered into a management and administrative services agreement with Seadrill Management, a wholly owned subsidiary of Seadrill, pursuant to which Seadrill Management provides Seadrill Partners certain management and administrative services. In April 2016, the agreement was amended and extended for an indefinite term. It can be terminated by providing 90 days written notice. In September 2017, the agreement was updated to clarify the compensation charges for these services. The services provided by Seadrill Management are charged at cost plus a management fee, weighted according to the type and stacking status of the rig. During the year ended December 31, 2017 the management fee has ranged from 4.85% to 8% of costs and expenses incurred in connection with providing these services.
Under the management and administrative services agreement, the Company is obligated to reimburse Seadrill Management for its reasonable costs and expenses incurred in connection with the provision of executive officer and other administrative services to us. Please refer to Item 6- "Directors, Senior Management and Employees B- Compensation" for further details.
iv. Advisory, Technical and Administrative Services Agreements
Each of the Company’s operating subsidiaries have entered into certain advisory, technical and administrative services agreements with subsidiaries of Seadrill, pursuant to which such subsidiaries provide advisory, technical and administrative services. The services provided by Seadrill's subsidiaries are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services. Amounts payable under the advisory, technical and administrative services agreements must be paid within 30 days after such Seadrill subsidiary submits to the applicable subsidiary an invoice for such fees, costs and expenses, together with any supporting detail that may be reasonably required. Such services include:
•
Operations Services: assistance and support for the development of technical standards, supervision of third-party contractors, development of maintenance practices and strategies, development of operating policies, improvement of efficiency, minimizing environmental and safety incidents, periodic auditing of operations and purchasing and logistics;
•
Technical Supervision Services: assistance and advice on maintaining vessel classification and compliance with local regulatory requirements, compliance with contractual technical requirements for the drilling units, ensuring that technical operations are professional and satisfactory in every respect;
•
Accidents-Contingency Plans: assistance in handling all accidents in the course of operations, and development of a crisis management procedure, and other advice and assistance in connection with crisis response, including crisis communications assistance; and
•
General Administrative Services: any general administrative services as needed.
Under the advisory, technical and administrative services agreements, the Company’s operating subsidiaries have agreed to indemnify certain affiliates of Seadrill and their officers, employees, agents and sub-contractors against all actions which may be brought against them under the advisory, technical and administrative services agreements; provided, however that such indemnity excludes losses which may be caused by or due to the fraud, gross negligence or willful misconduct of Seadrill Management or its officers, employees, agents and sub-contractors. Except for losses that are caused by or due to the fraud of Seadrill Management or its officers, employees, agents and sub-contractors, in no event shall such affiliates of Seadrill’s liability to us exceed ten times the annual services fee.
v. Operating Agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC
The Company's wholly-owned subsidiary, Seadrill Operating GP LLC, and Seadrill have entered into an agreement of limited partnership of Seadrill Operating LP. This agreement governs the ownership and management of Seadrill Operating LP, designates Seadrill Operating GP LLC as the general partner of Seadrill Operating LP, and provides for quarterly distributions of available cash to its partners, as determined by us as the sole member of the general partner of Seadrill Operating LP. Seadrill owns 42% of the limited partner interests in Seadrill Operating LP and the Company owns 58% of such interests.
The Company owns 51% of the limited liability company interests in Seadrill Capricorn Holdings LLC and controls its operations and activities. Seadrill owns 49% of the limited liability company interests. The limited liability company agreement that governs the ownership and management of Seadrill Capricorn Holdings LLC provides for quarterly distributions of available cash to its members, as determined by its board of directors.
These operating agreements provide that the amount of cash reserves for future maintenance and replacement capital expenditures, working capital and other matters and the amount of quarterly cash distributions to owners will be determined by the Company as the sole member of Seadrill Operating GP LLC and by the board of directors of Seadrill Capricorn Holdings LLC. In addition, the Company's approval as the sole member of Seadrill Operating GP LLC and as the controlling member of Seadrill Capricorn Holdings LLC is required for the following actions relating to Seadrill Operating LP or Seadrill Capricorn Holdings LLC:
•
effecting any merger or consolidation involving Seadrill Operating LP or Seadrill Capricorn Holdings LLC;
•
effecting any sale or exchange of all or substantially all of Seadrill Operating LP or Seadrill Capricorn Holdings LLC's assets;

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•
dissolving or liquidating Seadrill Operating LP or Seadrill Capricorn Holdings LLC;
•
creating or causing to exist any consensual restriction on the ability of Seadrill Operating LP or Seadrill Capricorn Holdings LLC to make distributions, pay any indebtedness, make loans or advances or transfer assets to us or its subsidiaries;
•
settling or compromising any claim, dispute or litigation directly against, or otherwise relating to indemnification by Seadrill Operating LP or Seadrill Capricorn Holdings LLC of, any of the directors or officers of Seadrill Operating GP LLC or Seadrill Capricorn Holdings LLC; or
•
issuing additional interests in Seadrill Operating LP or Seadrill Capricorn Holdings LLC.
Approval of the conflicts committee of the Board is required to amend these operating agreements.
vi. Loans and Financing Agreements
Seadrill has provided the Company and its subsidiaries with various loans and financing agreements. Below is information regarding the loans outstanding during the years ended December 31, 2017 and 2016. For additional disclosure regarding these agreements, please read Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
Tender Rig Facility (previously referred to as $440 million Rig Financing Agreement).
Seadrill financed the construction of certain drilling units in the Company’s fleet with borrowings under third party credit facilities. In connection with the Company's IPO and certain subsequent acquisitions from Seadrill, Seadrill amended and restated the various third party credit facilities (“Rig Financing Agreements”) to allow for the transfer of the respective drilling units to OPCO and to provide for OPCO and its subsidiaries that, directly or indirectly, own the drilling units to guarantee the obligations under the facilities. In connection therewith, such subsidiaries entered into intercompany loan agreements with Seadrill corresponding to the aggregate principal amount outstanding under the third party credit facilities allocable to the applicable drilling units.
The Facility was originally secured by the T-15 and T-16 and one other rig owned by Seadrill. In May 2013, Seadrill entered into an amendment to the agreement to allow for the transfer of the T-15 to Seadrill Partners Operating LLC and to add Seadrill Partners Operating LLC as a guarantor under the financing agreement.  In October 2013, Seadrill entered into an amendment to the agreement to allow for the transfer of the T-16 to Seadrill Partners Operating LLC. Effective from the respective dates of transfer of the T-15 and the T-16 from Seadrill to Seadrill Partners Operating LLC, the entities that own the T-15 and T-16 entered into intercompany loan agreements with Seadrill in the amount of approximately $100.5 million and $93.1 million, respectively. These loans bore interest at a rate of LIBOR plus 3.25% and were due to mature in December 2017. The entities which own the T-15 and T-16 made payments of principal and interest directly to the lenders under the Rig Financing Agreement, at Seadrill’s direction and on its behalf.  Such payments corresponded to payments of principal and interest due under the Agreement that are allocable to the T-15 and the T-16. 
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements. The facility has been split into two separate facilities, the “Tender rig facility” and the “West Telesto facility”. Recourse of the Tender rig facility is now only to us and recourse of the West Telesto facility is now only to Seadrill. Since the amendment, the facility is no longer a related party agreement and is classified as "Long term debt" on the Consolidated Balance Sheet. The outstanding balance of this facility as of December 31, 2017 was $83.3 million.
West Vencedor Loan Agreement
The senior secured credit facility relating to the West Vencedor was repaid in full by Seadrill in June 2014, and subsequently the related party agreement between the Company's subsidiary, Seadrill Vencedor Ltd., and Seadrill was amended to carry on this facility on the same terms (the "West Vencedor Loan Agreement"). The West Vencedor Loan Agreement was scheduled to mature in June 2015, at which time all outstanding amounts thereunder would have become due and payable, including a balloon payment of $70 million. On April 14, 2015, the West Vencedor Loan Agreement was amended and the maturity date was extended to June 25, 2018. The West Vencedor Loan Agreement bears interest at LIBOR plus a margin of 2.3% and a balloon payment of $21 million due at maturity in June 2018. The total amount owed to Seadrill under the West Vencedor Loan Agreement as of December 31, 2017, was $24.7 million (December 31, 2016: $41.2 million).
West Vela Facility (previously referred to as the $1,450 million Senior Secured Credit Facility).
Under the terms of the West Vela Facility certain subsidiaries of Seadrill and the Company were jointly and severally liable for their own debt and obligations under the facility and the debt and obligations of other borrowers who were party to such agreement.  Seadrill provided an indemnity to us for any payments or obligations related to this facility that are not related to the West Vela. The facility had a final maturity in 2025, with a commercial tranche maturing in 2018, and bore interest at a rate equal to LIBOR plus a margin that varied from 1.2% to 3% depending on which of the four loan tranches to which it is applicable which, in the case of the 3% margin, may be further increased by an additional 0.75% per annum depending on the leverage ratio.
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings and addressed near-term refinancing requirements. This facility has been split into two separate facilities, the “West Vela facility” and the “West Tellus facility”. Recourse of the West Vela facility is now only to us and recourse of the West Tellus facility is now only to Seadrill. Since the amendment, the facility is no longer a related party agreement and is classified as "Long term debt" on the Consolidated Balance Sheet. The outstanding balance under this facility as of December 31, 2017 was $255.3 million.

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West Sirius Loan and Seadrill Loan
Effective as of December 17, 2015, an operating subsidiary of the Company borrowed $143.0 million (the “West Sirius loan”) from Seadrill in order to provide sufficient immediate liquidity to meet the terms of its bareboat charter termination payment in connection with the West Sirius contract termination. Concurrently, Seadrill borrowed $143.0 million (the “Seadrill loan”) from a rig owning subsidiary of the Company in order to restore its liquidity with respect to the West Sirius loan. Each of the loan parties understood and agreed that the loan agreements acted in parallel with each other.
Each loan bore an interest rate of one-month LIBOR plus 0.56% and matured in August 2017. As of December 31, 2017, the loan had been fully repaid by both parties. At December 31, 2016, $39.4 million was outstanding under each loan.
$100 Million Sponsor Revolving Credit Facility
On October 24, 2012, in connection with the closing of the Company's IPO, OPCO entered into a $300 million revolving credit facility with Seadrill, as the lender, to be used to fund working capital requirements, acquisitions and other general company purposes. On March 1, 2014, the Sponsor Revolving Credit Facility was amended to reduce its capacity to $100 million. The Sponsor Revolving Credit Facility was for a term of 5 years, maturing on October 24, 2017 and bore interest at a rate of LIBOR plus 5% per annum, with an annual 2% commitment fee on the undrawn balance.
In August 2017, amendments were made to insulate Seadrill Partners from the events of default related to Seadrill's use of Chapter 11 proceedings. As part of this arrangement, the Sponsor Revolving Credit Facility was canceled. The facility had remained undrawn for the year ended December 31, 2017 and December 31, 2016.
vii. Derivative Interest Rate Swap Agreements
The filing of Seadrill's Chapter 11 petitions triggered an event of default under each of Seadrill's ISDA agreements. The related party swap agreements held with Seadrill were therefore canceled September 12, 2017. Refer to Note 14 "Risk management and financial instruments" to the Consolidated Financial Statements included in this annual report for further information.
viii. Bareboat Charter Agreements
Between October 2012 and April 2017, Seadrill China Operations Limited S.A.R.L, a subsidiary of Seadrill Operating LP, provided Seadrill Offshore AS, a subsidiary of Seadrill, with the right to use the West Aquarius under a bareboat charter arrangement. During the same period, Seadrill Offshore AS provided Seadrill Canada Ltd, a subsidiary of Seadrill Operating LP, with the right to use the West Aquarius under a further bareboat charter arrangement. The net effect to the Company of these two arrangements was a cost of $25,500 per day, for the period that the arrangement was in place.

Until December 31, 2016 Seadrill T-15 Ltd. and Seadrill International Ltd. were each party to a bareboat charter agreement with Seadrill UK Limited, a wholly owned subsidiary of Seadrill. Under this arrangement, the difference in the charter hire rate between the two charters was retained by Seadrill UK Ltd., in the amount of approximately $820 per day. Similarly, until December 31, 2016 Seadrill T-16 Ltd. and Seadrill International Ltd. were each party to a bareboat charter agreement with Seadrill UK Limited. Under this arrangement, the difference in the charter hire rate between the two charters was retained by Seadrill UK Ltd., in the amount of approximately $770 per day. All of these agreements were terminated effective December 31, 2016.
For the year ended December 31, 2017 the net effect to the Company of the above bareboat charters was net expenditure of $2.8 million (December 31, 2016: $9.5 million).
ix. Equity Distribution
During the year-ended December 31, 2017, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions. A total balance of $15.3 million has been distributed to Seadrill, comprised of a $6.1 million cash distribution and a $9.2 million non-cash distribution that was offset against certain trading balances owed to us by Seadrill.

These transactions have been presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2017.

C.     Interests of Experts and Counsel
Not applicable.

Item 8.         Financial Information

A.     Consolidated Statements and Other Financial Information
Please see Item 18 "Financial Statements" below for additional information required to be disclosed under this item.

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Legal Proceedings
From time to time the Company has been, and expects that in the future it will be, subject to legal proceedings and claims in the ordinary course of 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. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2017.
West Leo
We received a notice of force majeure in October 2016 for the West Leo 's contract with Tullow in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience.
We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract has been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination.
The total amount that we are seeking to recover is $278 million plus interest. The case is scheduled to be heard on May 8, 2018.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit against certain of our subsidiaries for patent infringement. The suit alleges that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity drilling. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office which ultimately stayed the litigation. The IPR board held in March 2017 that the patents were valid. Despite this finding, we do not believe that our rigs infringe the Transocean patents, which have now expired, and we continue to defend ourselves vigorously against this suit. We do not believe that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. We have not recognized any related loss contingency in our Consolidated Financial Statements as of December 31, 2017 as we do not believe the loss to be probable. We are also not able to make a reasonable estimate of the possible loss.
We are not aware of any other legal proceedings or claims that will have, individually or in the aggregate, a material adverse effect on the Company.
Please also see Note 15 "Commitments and contingencies" to the Consolidated Financial Statements in this annual report.
The Company's Cash Distribution Policy
Rationale for the Company's Cash Distribution Policy
Our cash distribution policy reflects a judgment that our unitholders will be better served by distributing our available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves) rather than retaining it. We will generally finance any expansion capital expenditures from external financing sources, including borrowings from commercial banks and the issuance of equity and debt securities. Our cash distribution policy is consistent with the terms of our operating agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves).
Limitations on Cash Distributions and the Company's Ability to Change the Company's 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:
•
The Company's unitholders have no contractual or other legal right to receive distributions other than the obligation under the Company's operating agreement to distribute available cash on a quarterly basis, which is subject to the broad discretion of the Board to establish reserves and other limitations.
•
The board of directors of Seadrill Operating LP’s general partner, Seadrill Operating GP LLC (subject to approval by the Company's Board), has authority to establish reserves for the prudent conduct of its business. In addition, the Company's Board controls Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, and has the authority to establish reserves for the prudent conduct of their respective businesses. The establishment of these reserves could result in a reduction in cash distributions to the Company's unitholders from levels the Company currently anticipates pursuant to the Company's stated cash distribution policy.
•
The Company's ability to make cash distributions will be limited by restrictions on distributions under its financing agreements. The Company’s financing agreements contain material financial tests and covenants that must be satisfied in order to pay distributions. If the Company is unable to satisfy the restrictions included in any of its financing agreements or is otherwise in default under any of those agreements, it could have a material adverse effect on the Company's ability to make cash distributions to its unitholders, notwithstanding the Company's stated cash distribution policy. These financial tests and covenants are described in this annual report in Item 5 "Operating and Financial Review and Prospects—Liquidity and Capital Resources—Borrowing Activities".
•
The Company will be required to make substantial capital expenditures to maintain and replace its fleet. These expenditures may fluctuate significantly over time, particularly as drilling units near the end of their useful lives. In order to minimize these

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fluctuations, the Company is required to deduct estimated, as opposed to actual, maintenance and replacement capital expenditures from the amount of cash that the Company would otherwise have available for distribution to the Company's unitholders. In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance and replacement capital expenditures were deducted.
•
Although the Company's operating agreement requires the Company to distribute all of the Company's available cash, the Company's operating agreement, including provisions requiring the Company to make cash distributions, may be amended. During the subordination period, with certain exceptions, the Company's operating agreement may not be amended without the approval of a majority of the units held by non-affiliated common unitholders. After the subordination period has ended, the Company's operating agreement can be amended with the approval of a majority of the outstanding common units, including those held by Seadrill. As of March 31, 2018, Seadrill owns approximately 34.9% of the Company's common units and all of the Company's subordinated units.
•
Even if the Company's cash distribution policy is not modified or revoked, the amount of distributions the Company pays under the Company's cash distribution policy and the decision to make any distribution is determined by the Board, taking into consideration the terms of the Company's operating agreement.
•
Under Section 40 of the Marshall Islands Act, the Company may not make a distribution to the Company's unitholders if, after giving effect to the distribution, all liabilities of the Company, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specified property of the Company, exceed the fair value of the assets of the Company, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in the assets of the Company only to the extent that the fair value of that property exceeds that liability. Identical restrictions exist on the payment of distributions by OPCO to its equity holders.
•
The Company may lack sufficient cash to pay distributions to the Company's unitholders due to, among other things, changes in the Company's business, including decreases in total operating revenues, decreases in dayrates, the loss of a drilling unit, increases in operating or general and administrative expenses, principal and interest payments on outstanding debt, taxes, working capital requirements, maintenance and replacement capital expenditures or anticipated cash needs. Please read Item 3 “Key Information—Risk Factors” for a discussion of these factors.
Our ability to make distributions to the Company's unitholders depends on the performance of our controlled affiliates, including OPCO, and their ability to distribute cash to us. Our interests in OPCO represent the Company's only cash-generating assets. The ability of our controlled affiliates, including OPCO, to make distributions to the Company may be restricted by, among other things, the provisions of existing and future indebtedness, applicable limited partnership and limited liability company laws and other laws and regulations.
Minimum Quarterly Distribution
Common unitholders are entitled under the Company's operating agreement to receive a quarterly distribution of $0.3875 per unit prior to any distribution on the subordinated units and to the extent the Company has sufficient cash on hand to pay the distribution, after establishment of cash reserves and payment of fees and expenses. There is no guarantee that the Company will pay the minimum quarterly distribution on the common units and subordinated units in any quarter. Even if the Company's cash distribution policy is not modified or revoked, the amount of distributions paid under the Company's policy and the decision to make any distribution is determined by the Board, taking into consideration the terms of the Company's operating agreement. The Company will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default then exists under the Company's financing agreements. Please read Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources” for a discussion of the restrictions contained in the Company's credit facilities and lease arrangements that may restrict the Company's ability to make distributions.
Subordination Period
During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.
The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:
•
distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•
the "adjusted operating surplus" (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and
•
there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.

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In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by our conflicts committee, the holder or holders of a majority of our subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.
Because the Company did not make payment of the minimum quarterly distribution in 2017, the subordinated units will not convert prior to 2021.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The Seadrill Member currently holds the incentive distribution rights, which may be transferred separately from the Seadrill Member interest, subject to restrictions in the operating agreement. Except for transfers of incentive distribution rights to an affiliate or another entity as part of the Seadrill Member’s merger or consolidation with or into, or sale of substantially all of its assets to such entity, the approval of a majority of the Company's common units (excluding common units held by the Seadrill Member and its affiliates) generally is required for a transfer of the incentive distribution rights to a third party prior to September 30, 2017. Any transfer by the Seadrill Member of the incentive distribution rights would not change the percentage allocations of quarterly distributions with respect to such rights.
The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of the unitholders and the holders of the incentive distribution rights in any available cash from operating surplus the Company distributes up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount", until available cash from operating surplus the Company distributes reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of the incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
 
 
 
Marginal Percentage Interest in 
Distributions
 
Total Quarterly Distribution 
Target Amount
 
Unitholders
 
Holders of IDRs
Minimum Quarterly Distribution
$0.3875
 
100
%
 
—
%
First Target Distribution
up to $0.4456
 
100
%
 
—
%
Second Target Distribution
above $0.4456 up to $0.4844
 
85
%
 
15
%
Third Target Distribution
above $0.4844 up to $0.5813
 
75
%
 
25
%
Thereafter
above $0.5813
 
50
%
 
50
%

B.     Significant Changes
There have been no significant changes since the date of our Consolidated Financial Statements included in this report, other than as described in Note 18 "Subsequent Events" thereto.

Item 9.         The Offer and Listing

A.     Offer and Listing Details
The high and low sales prices of the Company's common units as reported by the New York Stock Exchange, for the five most recent fiscal years:
Year Ended
High
 
Low
December 31, 2017
$
5.33

 
$
2.61

December 31, 2016
6.45

 
1.70

December 31, 2015
17.33

 
2.92

December 31, 2014
35.10

 
14.57

December 31, 2013
33.68

 
25.65

The following table sets forth the high and low prices of our common units trading on the NYSE for each full financial quarter for the two most recent fiscal years:

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Quarter Ended
High
 
Low
March 31, 2018
$
4.08

 
$
2.70

December 31, 2017
4.20

 
3.21

September 30, 2017
3.95

 
2.61

June 30, 2017
3.73

 
2.70

March 31, 2017
5.33

 
2.85

December 31, 2016
5.07

 
3.00

September 30, 2016
6.45

 
3.00

June 30, 2016
6.24

 
3.02

March 31, 2016
4.74

 
1.70

The following table sets forth the high and low prices for our common units on the NYSE for the six most recent months.
Month Ended
High
 
Low
April 11, 2018 (1)
$
2.89

 
$
2.60

March 31, 2018
3.42

 
2.74

February 28, 2018
3.60

 
2.97

January 31, 2018
4.08

 
3.38

December 31, 2017
3.80

 
3.21

November 30, 2017
4.20

 
3.50

October 31, 2017
3.94

 
3.43

(1) Includes the period from April 1, 2018 to April 11, 2018  


B.     Plan of distribution
Not applicable.

C.     Markets
The Company's common units currently trade on the New York Stock Exchange under the symbol “SDLP”.

D.    Selling Shareholders
Not applicable.

E.    Dilution
Not applicable.

F.    Expenses of the issue
Not applicable.

Item 10.         Additional Information

A.     Share Capital
Not applicable.

B.     Memorandum and Articles of Association
The information required to be disclosed under Item 10B is incorporated by reference to the Company's Registration Statement on Form 8-A filed with the SEC on October 17, 2012.


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C.     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 the Company or any of the Company's 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:
1.
Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of October 22, 2012, as amended by Amendment No 1, dated June 30, 2013. This agreement effected the transfer of the ownership interests in OPCO to the Company, and the use of the net proceeds of the IPO.
2.
Omnibus Agreement among Seadrill Limited, Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC, and Seadrill Capricorn, dated as of October 24, 2012. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Omnibus Agreement."
3.
Amended and Restated Management and Administrative Services Agreement with Seadrill Management Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
4.
Advisory, Technical and Administrative Services Agreement with Seadrill Americas, Inc. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
5.
Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Vencedor Ltd. dated January 1, 2012. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
6.
Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Deepwater Drillship Ltd. dated January 1, 2012. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
7.
Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
8.
Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
9.
Administrative, Technical and Advisory Agreement, effective as of March 21, 2014, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Auriga LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
10.
Administrative, Technical and Advisory Agreement, effective as of February 15, 2013, between Seadrill Americas Inc. and Seadrill Gulf Operations Vela LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
11.
Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Nigeria Operations Limited. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
12.
Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Offshore Nigeria Limited. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
13.
Advisory, Technical and Administrative Services Agreement, dated June 19, 2015, between Seadrill Management AME Ltd. and Seadrill Polaris Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Advisory, Technical and Administrative Services Agreements."
14.
Amended and Restated Revolving Loan Agreement, dated August 31, 2013 among Seadrill Operating LP, Seadrill Capricorn Holdings LLC, and Seadrill Partners Operating LLC as borrowers, and Seadrill Limited, as lender, as amended by the Second Amendment to Revolving Loan Agreement, dated March 1, 2014. See Note 11"Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
15.
Loan Agreement dated September 28, 2012 between Seadrill Limited and Seadrill Vencedor Ltd, as amended by Amendment No. 1, dated August 28, 2014, and Amendment No. 2, dated April 14, 2015. See Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
16.
US$440,000,000 Secured Credit Facility Agreement dated December 4, 2012 between Seadrill Limited, as borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders, as amended by the letter agreement, dated June 18, 2015, the waiver approval letter, dated April 28, 2016, and the consent request and waiver approval letter dated March 28, 2017. See Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.

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17.
Loan Agreement, dated May 16, 2013, between Seadrill Limited, Seadrill T-15 Ltd., Seadrill Partners Operating LLC and Seadrill International Limited. This is an intercompany loan agreement with Seadrill pursuant to which Seadrill T-15 Ltd. makes payments of principal and interest to the lenders of the $440 Million Rig Financing Agreement on Seadrill’s behalf. See Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
18.
Intercompany Loan Agreement, dated May 16, 2013, between Seadrill Limited, as lender and Seadrill Partners Operating LLC, as borrower. Pursuant to this agreement, Seadrill Partners Operating borrowed $109.5 million to fund the acquisition of the entities that own and operate the T-15. See Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
19.
Loan Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill T-16 Ltd. and Seadrill Partners Operating LLC. Pursuant to this agreement, Seadrill T-16 makes payments of principal and interest directly to the lenders under the $440 Million Rig Financing Agreement on Seadrill's behalf. See Note 11 "Debt" and Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
20.
Amended and Restated Credit Agreement dated as of June 26, 2014, among Seadrill Operating LP, Seadrill Partners Finco LLC, Seadrill Capricorn Holdings LLC, various lenders and Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
21.
Second Amended and Restated $1,450 million Senior Secured Credit Facility Agreement, dated as of November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, as amended by the letter agreement, dated May 28, 2015 and the waiver approval letter dated April 28, 2016, and the consent request and waiver approval letter, dated March 29, 2017. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
22.
On Demand and Guarantee and Indemnity, dated November 4, 2014, between Seadrill Partners LLC and ING Bank N.V. Pursuant to this agreement, Seadrill Partners LLC has guaranteed the obligations of Seadrill Vela Hungary Kft. under the $1,450 million Senior Secured Credit Facility Agreement, dated as of November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, in an amount up to $497.5 million plus interest and costs.
23.
Amendment and Restatement Agreement, dated June 19, 2015, between Seadrill Polaris Ltd. as borrower, Seadrill Limited as parent, Ship Finance International Limited as retiring guarantor and the other companies listed therein as guarantors, the banks and financial institutions listed therein as lenders, DNB Bank ASA and Nordea Bank AB, London Branch as bookrunners, the banks and financial institutions named therein as mandated lead arrangers and DNB Bank ASA, as agent, relating to the US$420,000,000 Term Loan and Revolving Credit Facilities Agreement, originally dated December 28, 2012, as previously amended and as amended by the waiver approval letter dated April 28, 2016, and the consent request and waiver approval letter, dated March 28, 2017. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
24.
Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Hungary Kft and Seadrill Limited. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Loans and Financing Agreements-$143 Million Loan Agreement."
25.
Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Neptune Hungary Kft and Seadrill Gulf Operations Sirius LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Loans and Financing Agreements-$143 Million Loan Agreement."
26.
Bareboat Charter Agreement between Seadrill Offshore AS and Seadrill Canada Ltd. dated October 5, 2012. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
27.
Bareboat Charter Agreements between Seadrill China Operations Ltd. and Seadrill Offshore AS dated October 5, 2012. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
28.
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-15 Ltd. and Seadrill UK Ltd. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
29.
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-16 Ltd. and Seadrill UK Ltd. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
30.
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-15. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
31.
Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-16. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.
32.
Contribution, Purchase and Sale Agreement, dated March 11, 2014. Pursuant to this agreement, Seadrill Capricorn Holdings LLC acquired the entities that own and operate the West Auriga. See Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report.
33.
Limited Partner Interest Purchase Agreement, dated as of July 17, 2014, between Seadrill Limited and Seadrill Partners LLC. Pursuant to this agreement, the Company purchased an additional 28% limited partner interest in Seadrill Operating LP. See Note 13 "Related party transactions" to the Consolidated Financial Statements included in this annual report.

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34.
Contribution, Purchase and Sale Agreement, dated November 4, 2014, by and among Seadrill Limited, Seadrill Partners LLC, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc. Pursuant to this agreement, Seadrill Capricorn Holdings LLC acquired the entities that own and operate the West Vela. See Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report.
35.
Purchase and Sale Agreement, dated as of June 16, 2015, by and among Seadrill Limited, Seadrill Operating LP, Seadrill Polaris Ltd. Pursuant to this agreement, Seadrill Operating LP acquired the entity that owns and operates the West Polaris. See Note 3 "Business Acquisitions" to the Consolidated Financial Statements included in this annual report.
36.
Promissory Note, dated as of June 19, 2015, between Seadrill Operating LP and Seadrill Limited. See Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report.
37.
Guaranty, dated as of June 19, 2015, between Seadrill Partners LLC as the guarantor and Seadrill Limited as the holder. See Note 3 "Business acquisitions" to the Consolidated Financial Statements included in this annual report.
38.
Fifth Amendment and Restated Agreement, dated 16 August 2017, relating to the USD 420,000,000 Term Loan and Revolving Credit Facilities Agreement of Seadrill Polaris Ltd, as borrower. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
39.
Third Amendment and Restated Agreement, dated 16 August 2017, relating to, among other things, the USD 483,333,333.34 Third Amended and Restated Senior Secured Credit Facility Agreement for Seadrill Vela Hungary Kft., as borrower. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
40.
China ECA Facility Framework Agreement, dated 16 August 2017, relating to, among other things, a new USD 119,100,000 Secured Credit Facility Agreement of Seadrill T-15 Ltd. and Seadrill T-16 Ltd., each as borrowers. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
41.
Consent & Amendment No. 1, dated as of February 12, 2018, relating to the Term Loan B Credit Agreement. See Note 11 "Debt" to the Consolidated Financial Statements included in this annual report.
42.
Amended and Restated Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Partners LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
43.
Management and Administrative Services Agreement between Seadrill Management Ltd and Sebras Rig Holdco Kft. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
44.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Auriga Hungary Kft. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
45.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Canada Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
46.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill China Operations Ltd S.à .r.l. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
47.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Deepwater Drillship Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
48.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Far East Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
49.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Ghana Operations Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
50.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Auriga LLC Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
51.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Vela LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
52.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Hungary Kft. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
53.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill International Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."

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54.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Leo Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
55.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Polaris Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
56.
Management and Administrative Services Agreement between Seadrill Management Ltd and T-15 Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
57.
Management and Administrative Services Agreement between Seadrill Management Ltd and T-16 Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
58.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill US Gulf LLC. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
59.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vela Hungary Kft. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."
60.
Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vencedor Ltd. See Item 7 "Major Unitholders and Related Party Transactions-Related Party Transactions-Management and Administrative Services Agreements."

D.     Exchange Controls
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, distributions, interest or other payments to non-resident and non-citizen holders of the Company's securities.
We are not aware of any limitations on the right of non-resident or foreign owners to hold or vote the Company's securities imposed by the laws of the Republic of The Marshall Islands or the Company's operating agreement.

E.     Taxation
Material U.S. Federal Income Tax Considerations
The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders.
This discussion is based upon provisions of the Code, Treasury Regulations, and current administrative rulings and court decisions, all as in effect or existence on the date of this prospectus and all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership 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 Seadrill Partners LLC.
The following discussion applies only to beneficial owners of common units that own the common units as “capital assets” within the meaning of Section 1221 of the Code (i.e., generally, for investment purposes) and is not intended to be applicable to all categories of investors, such as unitholders subject to special tax rules (e.g., financial institutions, insurance companies, broker-dealers, tax-exempt organizations, retirement plans or individual retirement accounts or former citizens or long-term residents of the United States), persons who will hold the units as part of a straddle, hedge, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes, or persons that have a functional currency other than the U.S. Dollar, each of whom may be subject to tax rules that differ significantly from those summarized below. If a partnership or other entity classified as a partnership for U.S. federal income tax purposes holds the Company's common units, the tax treatment of its partners generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding the Company's common units, you should consult your own tax adviser regarding the tax consequences to you of the partnership’s ownership of the Company's common units.
No ruling has been or will be requested from the IRS regarding any matter affecting the Company or prospective unitholders. The statements made herein may be challenged by the IRS and, if so challenged, may not be sustained upon review in a court.
This discussion does not contain information regarding any U.S. state or local, estate, gift or alternative minimum tax considerations concerning the ownership or disposition of common units. This discussion does not comment on all aspects of U.S. federal income taxation that may be important to particular unitholders in light of their individual circumstances, and each prospective unitholder is urged to consult its own tax adviser regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of common units.
Election to be Treated as a Corporation
The Company has elected to be treated as a corporation for U.S. federal income tax purposes. As a result, U.S. Holders (as defined below) will not be directly subject to U.S. federal income tax on the Company's income, but rather will be subject to U.S. federal income tax on distributions received from the Company and dispositions of units as described below.

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U.S. Federal Income Taxation of U.S. Holders
As used herein, the term "U.S. Holder" means a beneficial owner of the Company's common units that owns (actually or constructively) less than 10% of the Company's equity and that is:
•
an individual U.S. citizen or resident (as determined for U.S. federal income tax purposes),
•
a corporation (or other entity that is classified as a corporation for U.S. federal income tax purposes) organized under the laws of the United States or any of its political subdivisions,
•
an estate the income of which is subject to U.S. federal income taxation regardless of its source, or
•
a trust if (i) a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in effect to be treated as a U.S. person for U.S. federal income tax purposes.
Distributions
Subject to the discussion below of the rules applicable to PFICs, any distributions to a U.S. Holder made by the Company with respect to the Company's common units generally will constitute dividends, to the extent of the Company's current and accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of the Company's earnings and profits will be treated first as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in its common units and, thereafter, as capital gain. U.S. Holders that are corporations generally will not be entitled to claim dividends received deductions with respect to distributions they receive from the Company because the Company is not a U.S. corporation. Dividends received with respect to the Company's common units generally will be treated as “passive category income” for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes.
Dividends received with respect to the Company's common units, by a U.S. Holder that is an individual, trust or estate (a "U.S. Individual Holder") generally will be treated as "qualified dividend income", which is taxable to such U.S. Individual Holder at preferential tax rates provided that: (i) the Company's common units are readily tradable on an established securities market in the United States (such as The New York Stock Exchange on which the Company's common units are traded); (ii) the Company is not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (which the Company does not believe it is, has been or will be, as discussed below under "PFIC Status and Significant Tax Consequences"); (iii) the U.S. Individual Holder has owned the common units for more than 60 days during the 121 days period beginning 60 days before the date on which the common units become ex-dividend (and has not entered into certain risk limiting transactions with respect to such common units); and (iv) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property.
The Company has published on its website a copy of its IRS Form 8937 in connection with its distributions paid in the year ended December 31, 2017. There is no assurance that any dividends paid on the Company's common units will be eligible for these preferential rates in the hands of a U.S. Individual Holder, and any dividends paid on the Company's common units that are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.
Special rules may apply to any amounts received in respect of the Company's common units that are treated as "extraordinary dividends". In general, an extraordinary dividend is a dividend with respect to a common unit that is equal to or in excess of 10% of a unitholder’s adjusted tax basis (or fair market value upon the unitholder’s election) in such common unit. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a unitholder’s adjusted tax basis (or fair market value). If the Company pays an “extraordinary dividend” on the Company's common units that is treated as “qualified dividend income,” then any loss recognized by a U.S. Individual Holder from the sale or exchange of such common units will be treated as long-term capital loss to the extent of the amount of such dividend.
Sale, Exchange or Other Disposition of Common Units
Subject to the discussion of PFIC status below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of the Company's 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 adjusted tax basis in such units. The U.S. Holder’s initial tax basis in its units generally will be the U.S. Holder’s purchase price for the units and that tax basis will be reduced (but not below zero) by the amount of any distributions on the units that are treated as non-taxable returns of capital (as discussed above under “Distributions”). Such gain or loss will be treated as 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. Certain U.S. Holders (including individuals) 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 limitations. Such capital gain or loss generally will be treated as U.S. source income or loss, as applicable, for U.S. foreign tax credit purposes.
Medicare Tax on Net Investment Income
Certain U.S. Holders, including individuals, estates and trusts, will be subject to an additional 3.8% Medicare tax on, among other things, dividends and capital gains from the sale or other disposition of equity interests. For individuals, the additional Medicare tax applies to the lesser of (i) "net investment income" or (ii) the excess of "modified adjusted gross income" over $200,000 ($250,000 if married and filing jointly or $125,000 if married and filing separately). "Net investment income" generally equals the taxpayer’s gross investment income reduced by deductions that are allocable to such income. Unitholders should consult their tax advisers regarding the implications of the additional Medicare tax resulting from their ownership and disposition of the Company's common units.

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PFIC Status and Significant Tax Consequences
Adverse U.S. federal income tax rules apply to a U.S. Holder that owns an equity interest in a non-U.S. corporation that is classified as a PFIC for U.S. federal income tax purposes. In general, the Company will be treated as a PFIC with respect to a U.S. Holder if, for any taxable year in which the holder held the Company's units, either:
•
at least 75% of the Company's gross income (including the gross income of the Company's drilling unit owning subsidiaries) for such taxable year consists of passive income (e.g., dividends, interest, capital gains from the sale or exchange of investment property and rents derived other than in the active conduct of a rental business); or
•
at least 50% of the average value of the assets held by the Company (including the assets of the Company's drilling unit owning subsidiaries) during such taxable year produce, or are held for the production of, passive income.
Income earned, or treated as earned (for U.S. federal income tax purposes), by the Company in connection with the performance of services would not constitute passive income. By contrast, rental income generally would constitute “passive income” unless the Company was treated as deriving that rental income in the active conduct of a trade or business under the applicable rules.
Based on the Company's current and projected method of operation, the Company believes that the Company was not a PFIC for its 2017 taxable year, and the Company expects that it will not be treated as a PFIC for the current or any future taxable year. The Company expects that more than 25% of its gross income for its 2017 taxable year arose and for the current and each future year will arise from such drilling contracts or other income that the Company believes should not constitute passive income, and more than 50% of the average value of the Company's assets for each such year will be held for the production of such non-passive income. Assuming the composition of the Company's income and assets is consistent with these expectations, the Company believes that it should not be a PFIC for its 2017 taxable year or its current or any future year.
Distinguishing between arrangements treated as generating rental income and those treated as generating services income involves weighing and balancing competing factual considerations, and there is no legal authority under the PFIC rules addressing the Company's specific method of operation. Conclusions in this area therefore remain matters of interpretation. The Company is not seeking a ruling from the IRS on the treatment of income generated from the Company's drilling contracts or charters. Thus, it is possible that the IRS or a court could disagree with this position. In addition, although the Company intends to conduct its affairs in a manner to avoid being classified as a PFIC with respect to any taxable year, the Company cannot assure unitholders that the nature of its operations will not change in the future and that the Company will not become a PFIC in any future taxable year.
As discussed more fully below, if the Company was to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat the Company as a "Qualified Electing Fund", which the Company refers to as 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 the Company's common units, as discussed below. If the Company is a PFIC, a U.S. Holder will be subject to the PFIC rules described herein with respect to any of the Company's subsidiaries that are PFICs. However, the mark-to-market election discussed below will likely not be available with respect to shares of such PFIC subsidiaries. In addition, if a U.S. Holder owns the Company's common units during any taxable year that the Company is a PFIC, such holder must file an annual report with the IRS.
Taxation of U.S. Holders Making a Timely QEF Election
If a U.S. Holder makes a timely QEF election (an "Electing Holder"), then, for U.S. federal income tax purposes, that holder must report as income for its taxable year its pro rata share of the Company's ordinary earnings and net capital gain, if any, for the Company's taxable years that end with or within the taxable year for which that holder is reporting, regardless of whether or not the Electing Holder received distributions from the Company in that year. The Electing Holder’s adjusted tax basis in the common units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in common units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of the Company's common units. A U.S. Holder makes a QEF election with respect to any year that the Company is a PFIC by filing IRS Form 8621 with its U.S. federal income tax return. If contrary to the Company's expectations, the Company determines that the Company is treated as a PFIC for any taxable year, the Company will provide each U.S. Holder with the information necessary to make the QEF election described above.
Taxation of U.S. Holders Making a “Mark-to-Market” Election
If the Company was to be treated as a PFIC for any taxable year and, as the Company anticipates, the Company's 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 the Company's common units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the U.S. Holder’s common units at the end of the taxable year over the holder’s adjusted tax basis in the common units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common units over the fair market value thereof at the end of the taxable year, 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 its common units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of the Company's common units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units 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 the Company's subsidiaries that were determined to be PFICs.

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Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election
If the Company was to be treated as a PFIC for any taxable year, a U.S. Holder that does not make either a QEF election or a "mark-to-market" election for that year (or a Non-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on the Company's common units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period for the common units), and (2) any gain realized on the sale, exchange or other disposition of the units. Under these special rules:
•
the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for the common units;
•
the amount allocated to the current taxable year and any taxable year prior to the taxable year the Company was first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income; and
•
the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayers 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.
These penalties would not apply to a qualified pension, profit sharing or other retirement trust or other tax-exempt organization that did not borrow money or otherwise utilize leverage in connection with its acquisition of the Company's common units. If the Company was treated as a PFIC for any taxable year and a Non-Electing Holder who is an individual dies while owning the Company's common units, such holder’s successor generally would not receive a step-up in tax basis with respect to such units.
U.S. Federal Income Taxation of Non-U.S. Holders
A beneficial owner of the Company's common units (other than a partnership or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is referred to as a "Non-U.S. Holder". If you are a partner in a partnership (or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holding the Company's common units, you should consult your own tax adviser regarding the tax consequences to you of the partnership’s ownership of the Company's common units.
Distributions
Distributions the Company pays to a Non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax if the Non-U.S. Holder is not engaged in a U.S. trade or business. If the Non-U.S. Holder is engaged in a U.S. trade or business, the Company's distributions will be subject to U.S. federal income tax to the extent they constitute income effectively connected with the Non-U.S. Holder’s U.S. trade or business. However, distributions paid to a Non-U.S. Holder that is engaged in a U.S. trade or business may be exempt from taxation under an income tax treaty if the income arising from the distribution is not attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder.
Disposition of Units
In general, a Non-U.S. Holder is not subject to U.S. federal income tax or withholding tax on any gain resulting from the disposition of the Company's common units provided the Non-U.S. Holder is not engaged in a U.S. trade or business. A Non-U.S. Holder that is engaged in a U.S. trade or business will be subject to U.S. federal income tax in the event the gain from the disposition of units is effectively connected with the conduct of such U.S. trade or business (provided, in the case of a Non-U.S. Holder entitled to the benefits of an income tax treaty with the United States, such gain also is attributable to a U.S. permanent establishment). However, even if not engaged in a U.S. trade or business, individual Non-U.S. Holders may be subject to tax on gain resulting from the disposition of the Company's common units if they are present in the United States for 183 days or more during the taxable year in which those units are disposed and meet certain other requirements.
Backup Withholding and Information Reporting
In general, payments to a non-corporate U.S. Holder of distributions or the proceeds of a disposition of common units is subject to information reporting. 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 provide an accurate taxpayer identification number;
•
is notified by the IRS that it has failed to report all interest or corporate distributions required to be reported 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 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 timely filing a U.S. federal income tax return with the IRS.
In addition, individual citizens or residents of the United States holding certain "foreign financial assets" (which generally includes stock and other securities issued by a foreign person unless held in an account maintained by a financial institution) that exceed certain thresholds (the lowest being holding foreign financial assets with an aggregate value in excess of: (1) $50,000 on the last day of the tax year, or (2) $75,000 at any time during the tax year) are required to report information relating to such assets. Significant penalties may apply for failure to satisfy the reporting obligations described above. Unitholders should consult their tax advisers regarding the reporting obligations, if any, that result from their purchase, ownership or disposition of the Company's units.

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Non-United States Tax Considerations
Unless the context otherwise requires, references in this section to "we", "our" or "us" are references to Seadrill Partners LLC.
Marshall Islands Tax Consequences
The following discussion is based upon the current laws of the Republic of the Marshall Islands applicable to persons who are not citizens of and do not reside in, maintain offices in or carry on business or conduct transactions or operations in the Republic of the Marshall Islands.
Because the Company and the Company's subsidiaries (including those resident there) do not and do not expect to carry on business or conduct transactions or operations in the Republic of the Marshall Islands, under current Marshall Islands law the Company's unitholders will not be subject to Marshall Islands taxation or withholding on distributions, including upon distribution treated as a return of capital, the Company makes to the Company's unitholders. In addition, the Company's unitholders will not be subject to Marshall Islands stamp, capital gains or other taxes on the purchase, ownership or disposition of common units, and will not be required by the Republic of the Marshall Islands to file a tax return relating to their ownership of common units.
United Kingdom Tax Consequences
The following is a discussion of the material U.K. tax consequences that may be relevant to unitholders who are persons not resident for tax purposes in the United Kingdom (and who are persons who have not been resident for tax purposes in the United Kingdom) ("non-U.K. Holders").
Unitholders who are, or have been, resident in the United Kingdom are urged to consult their own tax advisers regarding the potential U.K. tax consequences to them of an investment in the Company's common units. For this purpose, a company incorporated outside of the U.K. will be treated as resident in the United Kingdom in the event its central management and control is carried out in the United Kingdom.
The discussion that follows is based upon existing U.K. legislation and current H.M. Revenue & Customs practice as of April 12, 2018, both of which may change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences of unit ownership described below.
The Company is not required to withhold U.K. tax when paying distributions to unitholders.
Under U.K. taxation legislation, non-U.K. Holders will not be subject to tax in the United Kingdom on income or profits, including chargeable (capital) gains, in respect of the acquisition, holding, disposition or redemption of the common units, provided that:
•
such holders do not use or hold and are not deemed or considered to use or hold their common units in the course of carrying on a trade, profession or vocation in the United Kingdom; and
•
such holders do not have a branch or agency or permanent establishment in the United Kingdom through which such common units are used, held or acquired.
U.K. stamp duty should not be payable in connection with a transfer of units, provided that the instrument of transfer is executed and retained outside the U.K. and no other action is taken in the U.K in relation to the transfer.
No U.K. stamp duty reserve tax will be payable in respect of any agreement to transfer units provided that the units are not registered in a register kept in the U.K. by or on behalf of the Company. The Company currently does not intend that any such register will be maintained in the U.K.
EACH PROSPECTIVE UNITHOLDER IS URGED TO CONSULT THEIR OWN TAX COUNSEL OR OTHER ADVISER WITH REGARD TO THE LEGAL AND TAX CONSEQUENCES OF UNIT OWNERSHIP UNDER THEIR PARTICULAR CIRCUMSTANCES.

F.     Dividends and Paying Agents
Not applicable.

G.    Statements by Experts
Not applicable.

H.     Documents on Display
We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). In accordance with these requirements we file reports and other information with the Commission. These materials, including this annual report and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, NE, Room 1580, Washington, D.C. 20549.  You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C.  The Commission maintains a website (http://www.sec.gov.) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. In addition, documents referred to in this annual report may be inspected at our principal executive offices at Building 11, Chiswick Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.
 

74
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I.    Subsidiary Information
Not applicable.

Item 11.        Quantitative and Qualitative Disclosures About Market Risk
The Company is exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. The Company may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.
Please refer to Note 14 "Risk Management and financial instruments" to the Consolidated Financial Statements included in this annual report for further details.

Item 12.     Description of Securities Other than Equity Securities
Not applicable.

A.     Debt securities
Not applicable.

B.     Warrants and rights
Not applicable.

C.     Other securities
Not applicable.

D.     American Depositary shares
Not applicable.

PART II

Item 13.     Defaults, Dividend Arrearages and Delinquencies
Neither the Company, nor any of its subsidiaries has been subject to a material default in the payment of principal, interest, a sinking fund or purchase fund installment, or any other material delinquency that was not cured within 30 days.

Item 14.         Material Modifications to the Rights of Security Holders and Use of Proceeds
Not applicable.

Item 15.     Controls and Procedures
a)    Disclosure Controls and Procedures
Management assessed the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15 and Rule 15a-15 of the Exchange Act as of December 31, 2017.
Based upon that evaluation and taking into account the remediation of the material weakness in the internal control over financial reporting set forth in Management's Annual Report on Internal Controls over Financial Reporting below, the Principal Executive Officer and the Principal Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the evaluation date.
b)    Management’s Annual Report on Internal Controls over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15 and Rules 15d-15 promulgated under the Exchange Act.
Internal controls over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Board, management and other personnel, 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 and includes those policies and procedures that:

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•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and
•
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company'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 or compliance with the policies or procedures may deteriorate.
The Company's management with the participation of the Company's Principal Executive Officer and the Principal Financial Officer assessed the effectiveness of the design and operation of the Company's internal control over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2017 and concluded that the Company's internal controls over financial reporting were effective as of that date.
Management conducted the evaluation of the effectiveness of internal control over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), published in its report entitled Internal Control- Integrated Framework (2013) and concluded that the material weakness previously reported within the annual report on Form 20-F for the year-ended December 31, 2016 had been remediated.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis.
In our annual report on Form 20-F for the year ended December 31, 2016 we reported that the Company had not maintained effective controls over the accounting for interest rate swaps. Specifically, the design and execution of controls over the application of accounting principles under GAAP were ineffective in relation to the inclusion of counterparty credit risk in fair value measurements related to interest rate swaps, and the completeness of accounting policy guidance in relation to the inclusion of counterparty credit risk in fair value measurements. The errors caused by this control deficiency resulted in a cumulative correction which was not material to the year ended December 31, 2016 or to any of the Company's previously issued Consolidated Financial Statements. The errors did not result in a material misstatement in the Company's prior financial statements and therefore did not require the Company's previously filed reports to be amended.
Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2016. As set out below, management completed remediation activities that remediated the material weakness.
c)     Attestation Report of the Registered Public Accounting Firm
The independent registered public accounting firm that audited the Consolidated Financial Statements, PricewaterhouseCoopers LLP, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2017, appearing under Item 18 and such report is incorporated herein by reference.
d)    Changes in Internal Control over Financial Reporting
We have completed the remediation activities described below to remediate the material weakness reported in our annual report on Form 20-F for the year-ended December 31, 2016.
Remediation of material weakness
Management completed remediation activities to address the material weakness described above. These activities, summarized below, were intended to address the above material weakness and to improve the overall control environment. These activities included:
•
We re-designed the fair value measurement process in respect of derivative financial instruments to include counterparty credit risk;
•
We performed a review of our accounting policy guidance, including a third party review of all accounting policies; and
•
We enhanced the documentation of policies, procedures and responsibilities throughout the financial reporting process.
Management believes the successful completion of these activities has remediated the material weakness. The completion of these activities was subject to senior management review, including Audit Committee oversight. During the period that the remediation activities were in-progress, we performed additional control activities, as required, to ensure that our financial statements were fairly stated in all material respects.

Item 16A.     Audit Committee Financial Expert
The Board has determined that Kate Blankenship and Keith MacDonald qualify as audit committee financial experts and are independent under applicable NYSE and SEC standards.


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Item 16B.     Code of Ethics
We have adopted a Code of Ethics that applies to all entities controlled by the Company and its employees, directors, officers and agents of the Company. We have posted a copy of our Code of Ethics on our website at www.seadrillpartners.com. We will provide any person, free of charge, a copy of the Code of Ethics upon written request to our registered office.

Item 16C.     Principal Accountant Fees and Services
Our principal accountant for the fiscal years ended December 31, 2017 and December 31, 2016 was PricewaterhouseCoopers LLP in the United Kingdom.
Fees Incurred by the Company for PricewaterhouseCoopers LLP’s Services
The following table sets forth the fees related to audit and other services provided by the principal accountants and their affiliates:
 
2017
 
2016
Audit Fees
$
1,062,836

 
$
904,151

Audit-Related Fees
—

 
—

Tax Fees
—

 
—

All other fees
—

 
—

 
$
1,062,836

 
$
904,151

Audit Fees
Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.
Audit-Related Fees
Not applicable.
Tax Fees
Not applicable.
All Other Fees
Not applicable.
Audit committee approvals
The audit committee 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 for all periods in 2017.

Item 16D.     Exemptions from the Listing Standards for Audit Committees
Not applicable.

Item 16E.     Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Not applicable.

Item 16F.     Change in Registrant's Certifying Accountant
Not applicable.


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Item 16G.     Corporate Governance
Overview
Pursuant to an exemption under the NYSE listing standards for foreign private issuers, the Company is not required to comply with the corporate governance practices followed by U.S. companies under the NYSE listing standards. However, pursuant to Section 303.A.11 of the NYSE Listed Company Manual, the Company is required to state any significant differences between our governance practices and the practices required by the NYSE for U.S. companies. The Company believes that the Company's established practices in the area of corporate governance are in line with the spirit of the NYSE standards and provide adequate protection to the Company's unitholders. The significant differences between the Company's corporate governance practices and the NYSE standards applicable to listed U.S. companies are set forth below.
Independence of Directors
The NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is composed of a majority of independent directors. Under Marshall Islands law, the Company is not required to have a board of directors composed of a majority of directors meeting the independence standards described in NYSE rules. However, the Board has determined that each of Mrs. Blankenship, Mr. Bekker, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by the NYSE, as applicable to us.
Executive Sessions
The NYSE requires that non-management directors of a listed U.S. company meet regularly in executive sessions without management. The NYSE also requires that all independent directors of a listed U.S. company meet in an executive session at least once a year. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company's non-management directors do not regularly hold executive sessions without management and the Company does not expect them to do so in the future.
Nominating/Corporate Governance Committee
The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company does not currently have a nominating or corporate governance committee.
Compensation Committee
The NYSE requires that a listed U.S. company have a compensation committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and the Company's limited liability company agreement, the Company does not have a compensation committee.
Corporate Governance Guidelines
The NYSE requires listed U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. The Company is not required to adopt such guidelines under Marshall Islands law and the Company has not adopted such guidelines.
Issuance of Additional Units
The NYSE requires that a listed U.S. company obtain unitholder approval in certain circumstances prior to the issuance of additional units. Consistent with Marshall Islands law and the Company's operating agreement, the Company is authorized to issue an unlimited amount of additional limited liability company interests and options, rights and warrants to buy limited liability company interests for the consideration and on the terms and conditions determined by the Board without the approval of the unitholders.
We make available a statement of significant differences on our website (www.seadrillpartners.com).
The Company believes that the Company's established corporate governance practices satisfy the NYSE listing standards.
Item 16H.     Mine Safety Disclosure
Not applicable.

PART III

Item 17.     Financial Statements
Not applicable.

Item 18.     Financial Statements
The following financial statements listed below and set forth on pages F-1 through F-36 together with the related report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, are filed as part of this annual report:
 


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Table of Contents

Item 19.     Exhibits
The following exhibits are filed as part of this annual report:
Exhibit
Number
Description
1.1
1.2
1.2.1
1.3
1.4
1.5
4.1.
4.1.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.14.1
4.15
4.15.1

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Table of Contents

Exhibit
Number
Description
4.15.2
4.16
4.16.1
4.16.2
4.16.3
4.17
4.18
4.19
4.20
4.20.1
4.20.2
4.20.3
4.21
4.22
4.22.1
4.22.2
4.23

4.24

4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34

80
Table of Contents

Exhibit
Number
Description
4.35
4.36
4.37
4.38
4.39

4.40
8.1*
12.1*
12.2*
13.1*
13.2*
14.1*
14.2*
14.3*
14.4*
14.5*
14.6*
14.7*
14.8*
14.9*
14.10*
14.11*
14.12*
14.13*
14.14*
14.15*
14.16*
14.17*
14.18*
14.19*
101. INS
XBRL Instance Document
101. SCH
XBRL Taxonomy Extension Schema
101. CAL
XBRL Taxonomy Extension Schema Calculation Linkbase
101. DEF
XBRL Taxonomy Extension Schema Definition Linkbase
101. LAB
XBRL Taxonomy Extension Schema Label Linkbase
101. PRE
XBRL Taxonomy Extension Schema Presentation Linkbase
*     Filed herewith.


81
Table of Contents

Index to Consolidated Financial Statements of Seadrill Partners LLC
 


F- 1
Table of Contents



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of Seadrill Partners LLC

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Seadrill Partners LLC and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations, of changes in members’ capital and of cash flows for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.


Substantial Doubt About the Company’s Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the financial statements, Seadrill Partners LLC is operationally dependent on Seadrill Limited and Seadrill Limited filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on September 12, 2017. Uncertainties inherent in Seadrill Limited’s Chapter 11 bankruptcy process raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.


Basis for Opinions

The Company's management is responsible for these consolidated financial statements, 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 Annual Report on Internal Control over Financial Reporting appearing under Item 15. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.


Definition and Limitations of Internal Control over Financial Reporting

A company’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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F- 2
Table of Contents


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.




PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
April 12, 2018

PricewaterhouseCoopers LLP (United Kingdom) has served as the Company’s auditor since 2012.



F- 3
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2017, 2016 and 2015
(In US$ millions, except per unit data)
 
 
Note
 
2017
 
2016
 
2015
Operating revenues
 
 
 
 
 
 
 
Contract revenues
 
 
$
1,007.7

 
$
1,356.4

 
$
1,603.6

Reimbursable revenues
 
 
17.7

 
32.8

 
49.9

Other revenues
6
*
103.0

 
211.1

 
88.1

Total operating revenues
 
 
1,128.4

 
1,600.3

 
1,741.6

 
 
 
 
 
 
 
 
Other operating income
 
 
 
 
 
 
 
Revaluation of contingent consideration
 
 
89.9

 
—

 
—

Gain on sale of assets
 
 
0.8

 
—

 
—

Total other operating income
7
 
90.7

 
—

 
—

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Vessel and rig operating expenses
 
*
(345.4
)
 
(373.9
)
 
(495.5
)
Amortization of favorable contracts
9
 
(74.4
)
 
(70.6
)
 
(66.9
)
Reimbursable expenses
 
 
(16.1
)
 
(30.2
)
 
(45.7
)
Depreciation and amortization
10
 
(274.9
)
 
(266.3
)
 
(237.5
)
General and administrative expenses
 
*
(44.8
)
 
(41.2
)
 
(52.3
)
Total operating expenses
 
 
(755.6
)
 
(782.2
)
 
(897.9
)
 
 
 
 
 
 
 
 
Operating income
 
 
463.5

 
818.1

 
843.7

 
 
 
 
 
 
 
 
Financial items
 
 
 
 
 
 
 
Interest income
 
 
15.7

 
11.5

 
9.8

Interest expense
 
*
(179.1
)
 
(180.0
)
 
(192.5
)
Loss on derivative financial instruments
14
*
(13.9
)
 
(18.0
)
 
(82.9
)
Currency exchange gain
 
 
0.9

 
0.6

 
1.6

Gain on bargain purchase
 
*
—

 
—

 
9.3

Other financial expenses
 
 
(11.5
)
 
—


—

Total financial items
 
 
(187.9
)
 
(185.9
)
 
(254.7
)
 
 
 
 
 
 
 
 
Income before income taxes
 
 
275.6

 
632.2

 
589.0

Income tax expense
5
 
(40.3
)
 
(86.5
)
 
(100.6
)
Net income
 
 
235.3

 
545.7

 
488.4

Net income attributable to the non-controlling interest
 
 
(94.1
)
 
(264.7
)
 
(231.2
)
Net income attributable to Seadrill Partners LLC owners
 
 
141.2

 
281.0

 
257.2

 
 
 
 
 
 
 
 
Earnings per unit (basic and diluted)
 
 
 
 
 
 
 
Common unitholders
 
 
$
1.88

 
$
3.20

 
$
2.45

Subordinated unitholders
 
 
$
—

 
$
2.28

 
$
2.45

* Includes transactions with related parties. Refer to Note 13 "Related party transactions".
A Statement of Other Comprehensive Income has not been presented as there are no items recognized in other comprehensive income.
See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 4
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED BALANCE SHEETS
As of December 31, 2017 and 2016
(In US$ millions)
 
Note
2017
 
2016
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
848.6

 
$
767.6

Accounts receivables, net
8

254.1

 
249.0

Amount due from related party
13

24.2

 
80.6

Other current assets
9

86.8

 
117.0

Total current assets
 
1,213.7

 
1,214.2

Non-current assets:
 
 
 
 
Drilling units
10

5,170.9

 
5,340.9

Goodwill
3

3.2

 
3.2

Deferred tax assets
5

9.5

 
14.1

Other non-current assets
9

133.5

 
208.3

Total non-current assets
 
5,317.1

 
5,566.5

Total assets
 
$
6,530.8

 
$
6,780.7

 
 
 
 
 
LIABILITIES AND MEMBERS’ CAPITAL
 
 
 
 
Current liabilities:
 
 
 
 
Current portion of long-term debt
11

$
162.9

 
$
93.8

Current portion of long-term related party debt
13

24.7

 
135.6

Trade accounts payable and accruals
 
37.4

 
31.9

Current portion of deferred and contingent consideration to related party
13

41.7

 
45.6

Related party payable
13

157.0

 
189.6

Other current liabilities
12

121.8

 
168.9

Total current liabilities
 
545.5

 
665.4

Non-current liabilities:
 
 
 
 
Long-term debt
11

3,180.2

 
3,346.5

Long-term related party debt
13

—

 
24.7

Deferred and contingent consideration to related party
13

46.0

 
157.6

Deferred tax liability
5

1.5

 
1.5

Other non-current liabilities
12

55.8

 
49.2

Total non-current liabilities
 
3,283.5

 
3,579.5

 
 
 
 
 
Commitments and contingencies (see Note 15)
 


 


Equity
 
 
 
 
Members’ Capital:
 


 


Common unitholders (issued 75,278,250 units)
 
1,208.9

 
1,123.2

Subordinated unitholders (issued 16,543,350 units)
 
94.8

 
69.4

Seadrill member interest
 
—

 
—

Total members’ capital
 
1,303.7

 
1,192.6

Non-controlling interest
 
1,398.1

 
1,343.2

Total equity
 
2,701.8

 
2,535.8

Total liabilities and equity
 
$
6,530.8

 
$
6,780.7

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 5
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2017, 2016 and 2015
(In US$ millions)
 
 
 
2017
 
2016
 
2015
Cash Flows from Operating Activities
 
 
 
 
 
 
Net income
 
$
235.3

 
$
545.7

 
$
488.4

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
274.9

 
266.3

 
237.5

Amortization of deferred loan charges
 
12.6

 
11.4

 
20.2

Amortization of favorable contracts
 
74.4

 
70.6

 
66.9

Gain on disposal of PPE
 
(0.8
)
 
—

 
—

Gain on bargain purchase
 
—

 
—

 
(9.3
)
Unrealized (gain) / loss related to derivative financial instruments
 
(25.8
)
 
(32.2
)
 
31.8

Unrealized foreign exchange gain
 
(3.5
)
 
(9.4
)
 
(1.7
)
Payment for long term maintenance
 
(54.9
)
 
(48.0
)
 
(49.8
)
Gain on revaluation of contingent consideration
 
(89.9
)
 
—

 
—

Net movement in taxes
 
4.6

 
19.2

 
27.9

Accretion of discount on deferred consideration
 
13.2

 
17.3


13.3

 
 
 
 
 
 
 
Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
 
 
Trade accounts receivable
 
(1.6
)
 
38.7

 
49.8

Prepaid expenses and accrued income
 
(4.0
)
 
8.6

 
(1.9
)
Trade accounts payable
 
5.4

 
7.8

 
15.3

Related party balances
 
16.1

 
(64.3
)
 
(29.0
)
Other assets
 
34.4

 
70.0

 
57.9

Other liabilities
 
(4.9
)
 
(12.1
)
 
(45.0
)
Changes in deferred revenue
 
(9.7
)
 
(17.0
)
 
(12.0
)
Other, net
 
0.4

 
1.2

 
(0.5
)
Net cash provided by operating activities
 
$
476.2

 
$
873.8

 
$
859.8

 
 
 
 
 
 
 
Cash Flows from Investing Activities
 
 
 
 
 
 
Additions to drilling units
 
(66.7
)
 
(13.1
)
 
(18.6
)
Proceeds from sale of assets
 
16.2

 
—

 
—

Acquisition of subsidiaries, net of cash acquired
 
—

 
—

 
(214.7
)
Loan granted to related parties
 
—

 
—

 
(143.0
)
Payment received from loans granted to related parties
 
39.4

 
103.6

 
—

Insurance refund
 
—

 
7.1

 
—

Net cash (used in) / provided by investing activities
 
$
(11.1
)
 
$
97.6

 
$
(376.3
)



F- 6
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2017, 2016 and 2015
(In US$ millions)
 
 
 
2017
 
2016
 
2015
Cash Flows from Financing Activities
 
 
 
 
 
 
Repayments of long term debt
 
(215.0
)
 
(105.3
)
 
(97.6
)
Debt fees paid
 
(3.8
)
 
(0.3
)
 
(0.8
)
Net proceeds from related party debt
 
—

 
—

 
143.0

Repayments of related party debt
 
(66.0
)
 
(249.5
)
 
(40.3
)
Proceeds from revolving credit facility
 
—

 
—

 
50.0

Contingent consideration paid
 
(40.0
)
 
(59.7
)
 
(26.6
)
Cash distributions
 
(60.1
)
 
(107.3
)
 
(435.3
)
Net cash (used in) / provided by financing activities
 
$
(384.9
)
 
$
(522.1
)
 
$
(407.6
)
 
 
 
 
 
 
 
Effect of exchange rate changes on cash
 
0.8

 
(0.7
)
 
0.4

 
 
 
 
 
 
 
Net increase in cash and cash equivalents
 
81.0

 
448.6

 
76.3

Cash and cash equivalents at beginning of the year
 
767.6

 
319.0

 
242.7

Cash and cash equivalents at the end of year
 
$
848.6

 
$
767.6

 
$
319.0

 
 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
 
Interest and other financial items paid
 
$
200.3

 
$
196.4

 
$
228.6

Taxes paid
 
42.9

 
49.0

 
57.0

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 7
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’
CAPITAL
for the years ended December 31, 2017, 2016 and 2015
(In US$ millions)
 
 
Members’ Capital
 
 
 
 
 
 
 
 
Common
Units
 
Subordinated
Units
 
Seadrill
Member
 
Total Before
Non-
Controlling
interest
 
Non-
controlling
Interest
 
Total 
Equity
Consolidated Balance at December 31, 2014
 
$
913.3

 
$
11.7

 
$
3.2

 
$
928.2

 
$
1,116.1

 
$
2,044.3

Net income
 
203.0

 
44.7

 
9.5

 
257.2

 
231.2

 
488.4

Cash Distributions
 
(170.8
)
 
(37.6
)
 
(12.7
)
 
(221.1
)
 
(214.2
)
 
(435.3
)
Consolidated balance at December 31, 2015
 
$
945.5

 
$
18.8

 
$
—

 
$
964.3

 
$
1,133.1

 
$
2,097.4

Net income
 
230.4

 
50.6

 
—

 
281.0

 
264.7

 
545.7

Cash Distributions
 
(52.7
)
 
—

 
—

 
(52.7
)
 
(54.6
)
 
(107.3
)
Consolidated balance at December 31, 2016
 
$
1,123.2

 
$
69.4

 
$
—

 
$
1,192.6

 
$
1,343.2

 
$
2,535.8

Net income
 
115.8

 
25.4

 
—

 
141.2

 
94.1

 
235.3

Cash Distributions
 
(30.1
)
 
—

 
—

 
(30.1
)
 
(30.0
)
 
(60.1
)
Other Distributions
 
—

 
—

 
—

 
—

 
(9.2
)
 
(9.2
)
Consolidated balance at December 31, 2017
 
$
1,208.9

 
$
94.8

 
$
—

 
$
1,303.7

 
$
1,398.1

 
$
2,701.8

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 8
Table of Contents

SEADRILL PARTNERS LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - General information
Background
On June 28, 2012, Seadrill Limited ("Seadrill") formed Seadrill Partners LLC (the "Company" or "we) under the laws of the Republic of the Marshall Islands.
On October 24, 2012, we completed initial public offerings ("IPO") and listed our common units on the New York Stock Exchange under the symbol “SDLP”. In connection with the IPO we acquired (i) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through our 100% ownership of its general partner, Seadrill Operating GP LLC, and (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Operating LP owned: (i) a 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) an approximate 56% interest in the entity that owns and operates the West Capella. Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn. In addition, in connection with the IPO we issued to Seadrill Member LLC, a wholly owned subsidiary of Seadrill, the Seadrill Member interest, which is a non-economic limited liability company interest in the Company, and all of the Company's incentive distribution rights, which entitle the Seadrill Member to increasing percentages of the cash the Company can distribute in excess of $0.4456 per unit, per quarter.
Subsequent to the IPO (i) our wholly-owned subsidiary Seadrill Partners Operating LLC acquired from Seadrill two entities that own the T-15 and T-16, (ii) Seadrill Capricorn Holdings LLC acquired from Seadrill two entities that own the West Auriga and West Vela, (iii) Seadrill Operating LP acquired from Seadrill the entity that owns the West Polaris, and (iv) we acquired from Seadrill an additional 28% limited partner interest in Seadrill Operating LP.
Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as "OPCO".
Seadrill owns the remaining interests in OPCO. As of December 31, 2017 and 2016, Seadrill owned 34.9% of the Company's common units and all of its subordinated units (which together represent 46.6% of the outstanding limited liability company interests) as well as Seadrill Member LLC, which owns a non-economic interest in the Company and all of its incentive distribution rights.
As of January 2, 2014, the date of the Company's first annual general meeting, Seadrill ceased to control the Company as defined under GAAP and, therefore, Seadrill Partners and Seadrill are no longer deemed to be entities under common control.
On June 19, 2015, Seadrill Operating LP completed the acquisition of Seadrill Polaris Ltd ("Seadrill Polaris"), the entity that owns and operates the drillship the West Polaris from Seadrill. The purchase was accounted for as a business combination. Refer to Note 3 "Business acquisitions" for more information.
Basis of presentation
The financial statements are presented in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The amounts are presented in United States dollar (US dollar) rounded to the nearest hundred thousand, unless otherwise stated.
Going concern
The financial statements have been prepared on a going concern basis and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Therefore, financial information in this report does not reflect the adjustments to the carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.
Our financial projections indicate that the cash flows we will generate from our current contract backlog, together with our available cash and other resources will allow us to meet our obligations as they fall due for at least the next twelve months after the date that the financial statements are issued. This includes servicing our debt, maintaining working capital, paying for capital expenditure for drilling unit upgrades and major maintenance, making distributions and meeting other obligations as they fall due.
Whilst we have taken steps to insulate the Company from events of default related to Seadrill's Chapter 11 proceedings, we remain operationally dependent on Seadrill on account of the management, administrative and technical support services provided by Seadrill to Seadrill Partners. In the event Seadrill is unable to provide these services, as a result of its restructuring or otherwise, Seadrill Partners has the right to terminate these agreements and would seek to build these capabilities internally or determine a suitable third party contractor to replace Seadrill. This may have an adverse effect on operations and may negatively impact our cash flows and liquidity.
Until Seadrill emerges from Chapter 11, uncertainty remains and the condition gives rise to substantial doubt over our ability to continue as a going concern. To the extent Seadrill emerges from Chapter 11,we expect this substantial doubt to be mitigated.
Out of period adjustments
The financial statements for the year ended December 31, 2017 include a pre-tax gain of $20.9 million for out of period adjustments relating to 2016. These adjustments relate to the valuation of contingent consideration recognized on acquisition of the West Polaris from Seadrill.
The financial statements for the year ended December 31, 2016 include a pre-tax gain of $24.1 million for out-of-period adjustments relating to 2014 and 2015. These adjustments relate to the valuation of our interest rate swap portfolio.
Refer to Note 14 – "Risk management and financial instruments" for further information.

F- 9
Table of Contents

Management evaluated the impact of these out-of-period adjustments in 2017 and 2016 and concluded that they were not material to the financial statements for the year ended December 31, 2017, December 31, 2016 or to any previously reported quarterly or annual financial statements.
Basis of consolidation
The financial statements include the results and financial position of all companies in which we directly or indirectly hold more than 50% of the voting control. We eliminate all intercompany balances and transactions.
We control Seadrill Operating LP and its majority owned subsidiaries because of our 100% ownership of its non-economic general partner Seadrill Operating GLP LLC and through our 58% limited partner economic interest. We control Seadrill Capricorn Holdings LLC and its majority owned subsidiaries through our 51% limited partner interest.
We separately present within equity on our consolidated balance sheets the ownership interests attributable to parties with noncontrolling interests in our consolidated subsidiaries, and we separately present net income attributable to such parties in our consolidated statements of operations.
Business combinations
We apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred. See Note 3 – "Business acquisitions" for further discussion on business acquisitions.
Note 2- Accounting policies
The accounting policies set out below have been applied consistently to all periods in these consolidated financial statements, unless otherwise noted.
Use of estimates
Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Contract revenue
A substantial majority of our revenues are derived from dayrate based drilling contracts and other service contracts. We recognize dayrate revenues ratably over the contract period when services are rendered. Under some contracts, we are entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any uncertainties regarding achievements of such targets are resolved or upon completion of the drilling program.
We may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the expected contract term. We may also receive fees for making capital upgrades during the contract. We recognize revenue for such fees over the expected remaining contract term.
In some cases, we may receive lump sum fees or dayrate based fees from customers for demobilization upon completion of a drilling contract. We recognize non-contingent demobilization fees as revenue over the expected contract term. We recognize revenue for contingent demobilization fees as earned upon completion of the drilling contract.
In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.
Reimbursable revenue and expenses
Reimbursements received for the purchases of supplies, personnel services and other services provided on behalf of and at the request of our customers in accordance with a contract or agreement are recorded as revenue. The related costs are recorded as reimbursable expenses in the same period.
Other revenues
Other revenues include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved. Other revenues also include fees charged to Seadrill for onshore support and offshore personnel.

F- 10
Table of Contents

Mobilization and demobilization expenses
We incur costs to prepare a drilling unit for a new customer contract and to move the rig to the contract location. We recognize the expense for such mobilization costs over the expected contract term.
We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract.
Vessel and rig operating expenses
Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.
Repairs, maintenance and periodic surveys
Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation and amortization expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.
Foreign currencies
The Company and all its subsidiaries use the U.S. dollar as their functional currencies because most of their revenues and expenses are denominated in U.S. dollars. Accordingly, our reporting currency is also U.S. dollars.
Transactions in foreign currencies during a period are translated into U.S. dollars at the rates of exchange in effect at the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the consolidated statements of operations.
Earnings Per Unit ("EPU")
We compute EPU using the two-class method set out in GAAP. We first allocate undistributed earnings for the period to the holders of common units, subordinated units and incentive distribution rights. This allocation is made in accordance with the cash distribution provisions contained in our Operating Agreement. Unallocated earnings may be negative if amounts distributed are higher than total earnings. We allocate such deficits using the same cash distribution model.
We calculate the EPU for each category of units by taking the sum of the distributions to those units plus the allocation of those units undistributed earnings for the period and dividing this total by the weighted average number of units outstanding for the period.
We don't have any potentially dilutive instruments and therefore don't present a diluted EPU.
Current and non-current classification
Assets and liabilities (excluding deferred taxes) are classified as current assets and liabilities respectively, if their maturity is within one year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.
Cash and cash equivalents
Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.
Receivables
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. We establish reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, we consider the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. Receivable amounts determined as being unrecoverable are written off.
Drilling units
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our semi-submersibles, drillships and tender rigs, when new, is 30 years. Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset.
Drilling units that are acquired in business combinations are recognized at fair value on date of acquisition.
Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the consolidated balance sheet, and resulting gains or losses are included in the consolidated statement of operations.

F- 11
Table of Contents

Impairment of long-lived assets
We review the carrying value of our long-lived assets for impairment whenever certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value.
Favorable drilling contracts - intangible assets
Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the statement of operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.
Derivative Financial Instruments and Hedging Activities
We record derivative financial instruments at fair value. None of our derivative financial instruments have been designated as hedging instruments. Therefore, changes in their fair value are taken to the consolidated statement of operations in each period.
We classify the gain or loss on derivative financial instruments as a separate line item within financial items in the consolidated statement of operations. We classify the asset or liability for derivative financial instruments as an other current asset or liability in our consolidated balance sheet. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements.
Income taxes
Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate.
Significant judgment is involved in determining the provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. The Company recognizes tax liabilities based on its assessment of whether its tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedent.
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.
In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non-current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard effective December 31, 2015 and applied it retrospectively to all periods presented. As a result, the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.
Deferred charges
Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in interest expense.
Loss contingencies
We recognize a loss contingency in the consolidated balance sheet where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.
Related parties
Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence.

F- 12
Table of Contents

Equity allocation
Earnings attributable to unitholders of Seadrill Partners are allocated to all unitholders on a pro rata basis for the purposes of presentation in the consolidated statements of changes in members’ capital. Earnings attributable to unitholders for any period are first reduced for any cash distributions for the period to be paid to the holders of the incentive distribution rights.
At the time of the IPO the equity attributable to unitholders was allocated using the hypothetical amounts which would be distributed to the various unitholders on a liquidation of the Company ("hypothetical liquidation method"). This method has also been used to account for issuances of common units by the Company, and the deemed distributions from equity which resulted from acquisitions of drilling units from Seadrill.
Recently Adopted Accounting Standards
We adopted the following accounting standard updates ("ASUs") during the year ended December 31, 2017, none of which had any impact on our consolidated financial statements and related disclosures:
•
ASU 2016-05 - Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (a consensus of the Emerging Issues Task Force)
•
ASU 2016-06 - Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (a consensus of the Emerging Issues Task Force)
•
ASU 2016-07 - Investments—Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting
•
ASU 2016-09 - Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
•
ASU 2016-17 - Consolidation (Topic 810): Interests Held through Related Parties that are under Common Control
•
ASU 2016-19 - Technical Corrections and Improvements
Recently Issued Accounting Standards
The FASB have issued the following ASUs that we have not yet adopted but which could affect our consolidated financial statements and related disclosures in future periods.
•
ASU 2014-09 - Revenue from Contracts with Customers (also 2016-8, 2016-10, 2016-11, 2016-12, 2016-20, 2017-13, 2017-14)
•
ASU 2016-01 - Financial Instruments — Recognition and Measurement of Financial Assets and Financial Liabilities
•
ASU 2016-02 - Leases
•
ASU 2016-13 - Financial Instruments — Measurement of Credit Losses on Financial Instruments
•
ASU 2016-15 - Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments
•
ASU 2016-16 - Income taxes — Intra-Entity Transfers of Assets other than Inventory
•
ASU 2016-18 - Statement of Cash Flows — Restricted Cash
•
ASU 2017-01 - Business Combinations — Clarifying the Definition of a Business
•
ASU 2017-04 - Intangibles — Simplifying the Test for Goodwill Impairment
•
ASU 2017-05 - Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets
ASU 2014-09 - Revenue from contracts with customers
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which provides new authoritative guidance on the methods of revenue recognition and related disclosure requirements. This new standard supersedes all existing revenue recognition requirements, including most industry-specific guidance. We will be required to apply this standard for the year ended December 31, 2018 and for interim periods within that year.
We have substantially completed our work to implement the new standard and do not expect our pattern of revenue recognition to materially change as a consequence of adopting the new guidance. We plan to use the modified retrospective method to transition to the new standard. This method requires us to apply the new standard to all outstanding contracts as of January 1, 2018. Under this method we record the cumulative effect of applying the new standard as an adjustment to opening retained earnings.
To apply the standard, we were required to assess the core promise made to our customers under a drilling contract. We have assessed that our core promise is to stand ready to provide drilling services, as directed by our customer, over the operating period of a contract. We have concluded that this promise is provided as a series of distinct services that are substantially the same and have the same pattern of transfer to the customer. Therefore, we follow the so-called series guidance and treat the series of distinct services as a single performance obligation.

F- 13
Table of Contents

Under the series guidance we allocate variable contract revenue to either the entire contract or individual periods during the contract, depending on what the variable contract revenue relates to. We have concluded that dayrate and bonus revenue relate to individual periods and allocate them accordingly. Mobilization and demobilization revenues don't relate to specific periods and we have concluded that they will be allocated to the entire contract, subject to the constraint around revenue reversals which is explained below.
To apply the ASC 606 revenue model, we will be required to estimate the value of each component of variable contract revenue each reporting period. We will then recognize revenue equal to the estimated value of contract revenue that has been allocated to the current reporting period plus any change in the estimated value of contract revenue that has been allocated to previous reporting periods.
We will generally use the most likely amount basis to form our estimates of variable contract revenue. However, if there is a range of potential outcomes for a component of variable revenue under a contract it may be appropriate to use an expected value basis instead. We only include estimates of variable contract revenue to the extent that it is probable that there will not be a significant reversal of revenue in a future reporting period.
The application of this revenue model leads to a similar revenue recognition to the approach previously followed under ASC 605. However, we have identified several potential differences as set out below:
•
Under ASC 605 we recognized contingent demobilization fees as the demobilization was performed at the end of the contract. Under ASC 606 we will estimate the amount of contingent demobilization fee each reporting period and recognize the estimated fee over the expected contract term, subject to the constraint that it must be probable that this will not result in a subsequent reversal of revenue in future periods ("reversal constraint").
•
Under ASC 605 we recognized disputed dayrates when the revenue became fixed or determinable. Under ASC 606 we will estimate the amount of disputed dayrate billings and recognize the estimated amount as revenue in the period the disputed dayrates related to, subject to the reversal constraint.
•
Under ASC 605 we recognized contingent early termination fees on daily basis over the termination period. Under ASC 606 we will estimate the amount of early termination fees for any contract that have been early terminated. We will recognize this amount as revenue at the point the contract is early terminated, subject to the reversal constraint.
•
Under ASC 605 we did not allocate revenue to customer options. Under ASC 606 we will assess whether a customer option provides a material right to the customer. Where a contract includes a customer option that provides a material right we will allocate a proportion of contract revenue to the material right and recognize this either at the point the option expires or when the additional services are provided.
•
Under ASC 605 we applied the terms of contract modifications or extensions from the point they became effective. Where a contract was extended we changed the period over which unamortized mobilization revenue was taken to income. Under ASC 606 we will account for contract modifications either as separate contracts, a single combined contract or under the cumulative catch up method, depending on the terms of the modification.
As part of our implementation we have assessed our open contracts at January 1, 2018 (the "transition date"). Based on our implementation work to date we have not identified any material adjustments at the transition date and do not expect material differences between our revenue under ASC 605 and ASC 606 going forward. This assessment may change as we finalize our work to implement the new standard.
ASU 2016-01 - Financial Instruments — Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which made targeted improvements to the recognition and measurement of financial assets and financial liabilities.
The update changes how entities measure equity investments that do not result in consolidation and are not accounted for under the equity method and how they present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. The new guidance also changes certain disclosure requirements and other aspects of current GAAP. The guidance will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years and early adoption is permitted in some cases.
As we do not have any investments accounted for under the equity method we do not expect this standard update to affect our consolidated financial statements and related disclosures.
ASU 2016-02 - Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted, using a modified retrospective application.

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We have started to assess the impact of this standard update on our consolidated financial statements and related disclosures. We have determined that our drilling contracts contain a lease component and therefore adoption of this standard will result in increased disclosure of our leasing arrangements and may affect the way we recognize revenues associated with the lease and revenue components. Based on our work to date, we don't expect our pattern of revenue recognition to change significantly compared to current accounting standards.
We are consulting with other drilling companies to fully determine recognition and disclosure under the new standard. We may change our initial assessment as we complete the implementation process.
ASU 2016-13 - Financial Instruments — Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective January 1, 2020, with early adoption permitted. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted.
We are in the early stage of evaluating the impact of this standard update. Our customers are international oil companies, national oil companies and large independent oil companies. Our financial assets are primarily held with counter parties with high credit standing and we have historically had a low incidence of bad debt expense. Therefore, we do not currently expect this guidance to significantly affect our consolidated financial statements and related disclosures when we adopt it.
ASU 2016-15 - Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments based on a consensus of the Emerging Issues Task Force (EITF), to address the classification of certain cash receipts and cash payments on the statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The guidance will be effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. Entities are generally required to apply the guidance retrospectively.
We are in the process of evaluating the impact of this standard upon our consolidated financial statements and related disclosures.
ASU 2016-16 - Income taxes — Intra-Entity Transfers of Assets other than Inventory
In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Income Taxes Intra-Entity Transfers of Assets other than Inventory, which requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the consolidated statement of operations as income tax expense (or benefit) in the period of sale or transfer occurs. The exception to recognizing the income tax effects of intercompany sales or transfers of assets remains in place for intercompany inventory sales and transfers, i.e. companies will still be required to defer the income tax effects of intercompany inventory transactions. The standard will be effective for annual periods beginning after December 15, 2017, with early adoption permitted. Entities are required to apply the guidance on a modified retrospective basis, with the cumulative effect adjustment to retained earnings at the beginning of the period of adoption.
We have not historically incurred any substantial tax liabilities as a result of making intra-entity transfers of assets. Our balance sheet does not include assets or liabilities recorded for the deferral of income tax expenses or benefits on intra-entity transfers. Therefore, we do not currently expect this guidance to affect our consolidated financial statements and related disclosures when we adopt it.
ASU 2016-18 - Statement of Cash Flows — Restricted Cash
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, to address classification of activity related to restricted cash and restricted cash equivalents in the cash flows. The standard eliminates the presentation of transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents and restricted cash equivalents are presented in more than one line item on the balance sheet, a reconciliation of the totals in the cash flows to the related captions in the balance sheet are required, either on the face of the cash flow or in the notes to the financial statements. Additional disclosures are required for the nature of the restricted cash and restricted cash equivalents. The standard will be effective for fiscal years beginning after December 15, 2017, and interim periods within those years.
We do not currently have any substantial restricted cash balances. Therefore, we do not currently expect this guidance to affect our consolidated financial statements and related disclosures when we adopt it.
ASU 2017-01 - Business Combinations — Clarifying the Definition of a Business
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) or assets or businesses. The guidance will be effective for annual and interim periods beginning after December 15, 2017. Entities apply the guidance prospectively. We will apply this standard when we next undertake a business acquisition or disposal.

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ASU 2017-04 - Intangibles — Simplifying the Test for Goodwill Impairment
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, entities will continue to perform Step 1 of the goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. The entity will now recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
We do not currently have any substantial goodwill balances. Therefore, we do not currently expect this guidance to significantly affect our consolidated financial statements and related disclosures when we adopt it.
ASU 2017-05 - Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets
In February 2017, the FASB issued 2017-05, Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The standard update clarifies that a model consistent with ASC 606 and ASC 810 should be applied to sales of non-financial assets to non-customers. Under this guidance an entity would recognize a gain or loss in full when it transfers control of the asset. The effective date of the guidance will be effective for annual and interim periods beginning after December 15, 2017.
The new guidance is consistent with our current practice and therefore we do not expect this guidance to affect our consolidated financial statements and related disclosures when we adopt it.
Other accounting standard updates issued by the FASB
As of March 31, 2018, the FASB has issued several further updates not included above. We do not currently expect any of these updates to affect our consolidated financial statements and related disclosures either on transition or in future periods.

Note 3 - Business acquisitions
For the year-ended December 31, 2017
There were no business acquisitions undertaken in the year ended December 31, 2017.
For the year-ended December 31, 2016
There were no business acquisitions undertaken in the year ended December 31, 2016
For the year-ended December 31, 2015
West Polaris Acquisition
On June 19, 2015, our 58% owned subsidiary, Seadrill Operating LP, completed the purchase (the "Polaris Acquisition") of 100% of the ownership interests in Seadrill Polaris Ltd. ("Seadrill Polaris") the entity that owns and operates the drillship the West Polaris (the "Polaris Business") from Seadrill. Seadrill Operating LP is 42% owned by Seadrill.
The initial consideration for the Polaris Acquisition was comprised of $204.0 million of cash and $336.0 million of debt outstanding under the existing facility financing the West Polaris.
In addition, Seadrill Operating LP issued a note (the "Seller's Credit") of $50.0 million to Seadrill, payment of which is contingent on the future re-contracted dayrate for the West Polaris. The Seller's Credit is due in 2021 and bears an interest rate of 6.5% per annum. During the three-year period following the completion of the current drilling contract with ExxonMobil, the Seller's Credit may be reduced if the average contracted dayrate (net of commissions) for the period, adjusted for utilization, under any replacement contract is below $450,000 per day until the Seller's Credit's maturity in 2021. Should the average dayrate of the replacement contract be above $450,000 per day, the entire Seller's Credit must be paid to Seadrill upon maturity of the Seller's Credit in 2021.
In addition, Seadrill Polaris may be required to make further contingent payments to Seadrill based upon the West Polaris's operating dayrate until March 2025. At the time of acquisition, the West Polaris was contracted with ExxonMobil on a dayrate of $653,000 per day until March 2018. Under the terms of the acquisition agreement, Seadrill Polaris agreed to pay Seadrill (a) any dayrate it received in excess of $450,000 per day, adjusted for daily utilization, through the remaining term, without extension, of the ExxonMobil contract (the "Initial Earn-Out") and (b) after the expiration of the term of the existing contract until March 2025, 50% of any dayrate above $450,000 per day, adjusted for daily utilization, tax and agency commission (the "Subsequent Earn-Out").
In connection with the completion of the Polaris Acquisition, Seadrill Polaris as borrower, entered into an amendment and restatement of the $420.0 million term loan facility secured by the West Polaris (the "West Polaris Facility"). Please refer further to Note 11 "Debt".
The fair value of the total consideration paid was $374.6 million, was comprised of cash of $204.0 million, the Seller's Credit, which had a fair value of $44.6 million as of the acquisition date, contingent consideration with a fair value of $95.3 million as of the acquisition date, and a working capital adjustment which increased consideration by $30.7 million.

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The following table summarizes the consideration paid, and the amounts of the assets and liabilities recognized at the acquisition date.
(In US$ millions)
June 19, 2015

Consideration
 
Cash
$
204.0

Contingent consideration
95.3

Seller's Credit
44.6

Plus: Working capital adjustment
30.7

Fair value of total consideration transferred
$
374.6

 
 
Recognized amounts of identifiable assets acquired and liabilities assumed at estimated fair value
 
Cash
$
20.0

Current assets
52.1

Intangible asset - favorable drilling contract
124.3

Drilling unit
575.3

Long term interest bearing debt
(336.0
)
Current liabilities
(20.2
)
Non-current liabilities
(1.3
)
Total identifiable net assets at acquisition
$
414.2

 
 
Measurement period adjustment
$
(30.3
)
Gain on bargain purchase
(9.3
)
Total
$
374.6

We estimated the fair value of the West Polaris drilling unit using an income approach with market participant based assumptions, including estimates of future dayrates, drilling unit utilization, operating costs, capital and long term maintenance expenditures and applicable tax rates. The cash flows were estimated over the remaining useful economic life of the drilling unit. At the acquisition date, the cash flows were discounted using an estimated market participant weighted average cost of capital of 8.5%. The estimated fair value of the West Polaris drilling unit was $575.3 million at the acquisition date.
The fair value of the West Polaris drilling contract was determined using an "excess earnings" technique where the terms of the contract were assessed relative to current market conditions. At the acquisition date, the fair value of the favorable contract was recognized as an intangible asset totaling $124.3 million. This intangible asset was amortized over the remaining contract term.
The fair value of trade receivables was $31.9 million at the acquisition date, which was also the gross contractual amount. All amounts have since been collected.
At the time of acquisition, the fair value of contingent consideration consisted of the fair value of the Initial Earn-Out of $61.8 million, the fair value of the Subsequent Earn-Out of $33.5 million and the fair value of the Seller's Credit of $44.6 million. The fair value as of the acquisition date was determined using future estimated contract revenues based upon estimates of re-contracted dayrate, average utilization, less any expected commissions and taxes. The contingent consideration has been discounted to present value using a discount rate of 8.5%.
Acquisition related transaction costs consisted of various advisory, legal, accounting, valuation and other professional fees of $0.7 million, which were expensed as incurred and are presented in the Statement of Operations within general and administrative expenses.
Measurement period adjustment
At the acquisition date, we initially recognized a gain on bargain purchase from the Polaris Acquisition of $39.6 million, which was the excess of the total identifiable net assets acquired over the consideration transferred. In February 2016, customer ongoing negotiations were concluded and the customer contract for the West Polaris was adjusted to $490,000 per day. This provided further information regarding the value of the favorable contract intangible asset and the Initial Earn-Out. The information was further evidence of a condition that existed at the time of the acquisition and therefore was accounted for as a measurement period adjustment. The favorable contract intangible asset and the Initial Earn-out liability were reduced by $47.9 million and $17.6 million, respectively. As a result, we reduced the gain on bargain purchase for the Polaris Acquisition by $30.3 million. The final gain on bargain purchase was therefore $9.3 million. This was classified in a separate line item "Gain on bargain purchase" in the Consolidated Statement of Operations.
Pro-forma information
In the consolidated statement of operations, $131.6 million of revenue and $7.8 million of net income have been included from the acquisition date of the Polaris Business until December 31, 2015.

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The pro forma revenue and pro forma net income of the combined entity for the year ended December 31, 2015 and December 31, 2014, had the acquisition date been January 1, 2014 are as follows:
 
Year ended December 31,
(In US$ millions)
2015
 
2014
 
Seadrill Partners LLC as reported
 
Supplemental pro forma combined entity
 
Seadrill Partners LLC as reported
 
Supplemental pro forma combined entity
Total Revenue
$
1,741.6

 
$
1,851.3

 
$
1,342.6

 
$
1,564.1

Net Income
488.4

 
535.7

 
314.6

 
388.9

Net income attributable to Seadrill Partners LLC members
257.2

 
284.6

 
138.2

 
181.3


Note 4 – Segment information
Operating segment
We regard our fleet as one single operating segment. The Chief Operating Decision Maker, which is the Board of Directors, review performance at this level as an aggregated sum of assets, liabilities and activities generating distributable cash to meet minimum quarterly distributions.
A breakdown of our revenues by customer for the years ended December 31, 2017, 2016 and 2015 is as follows: 
 
2017
 
2016
 
2015
BP
56.8
%
 
42.0
%
 
44.8
%
ExxonMobil
22.2
%
 
22.0
%
 
29.5
%
Chevron
7.9
%
 
5.4
%
 
8.5
%
Hibernia
6.4
%
 
15.1
%
 
2.6
%
Tullow
—
%
 
13.0
%
 
13.5
%
Other
6.7
%
 
2.5
%
 
1.1
%
Total
100.0
%
 
100.0
%
 
100.0
%
Geographic Data
Revenues are attributed to geographical areas based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the revenues for the years ended December 31, 2017, 2016 and 2015 and fixed assets as of December 31, 2017 and 2016 by geographic area:
Revenues
(In US$ millions)
2017
 
2016
 
2015
United States
$
638.0

 
$
672.2

 
$
781.1

Angola
152.5

 
175.9

 
179.4

Thailand
89.2

 
86.3

 
99.8

Canada
87.1

 
241.5

 
190.9

Equatorial Guinea
48.1

 
—

 
—

Nigeria
39.5

 
185.2

 
250.1

Indonesia
37.3

 
—

 
—

Ghana
—

 
208.1

 
234.7

Other
36.7

 
31.1

 
5.6

Total
$
1,128.4

 
$
1,600.3

 
$
1,741.6


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Fixed Assets—Drilling Units (1)  
(In US$ millions)
2017
 
2016
United States
$
2,729.6

 
$
2,815.5

Spain
1,075.9

 
496.2

Canada
460.9

 
488.0

Thailand
234.6

 
241.0

Gabon
507.4

 
—

Indonesia
162.5

 
—

Ghana
—

 
575.0

Angola
—

 
554.0

Singapore
—

 
171.2

Total
$
5,170.9

 
$
5,340.9

(1)
The fixed assets referred to in the table above include the eleven drilling units at December 31, 2017 and December 31, 2016. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

Note 5 – Taxation
Income taxes consist of the following:
 
Year Ended December 31,
(In US$ millions)
2017
 
2016
 
2015
Current tax expense:
 
 
 
 
 
United Kingdom
$
(4.5
)
 
$
(1.6
)
 
$
—

Foreign
40.4

 
110.2

 
72.6

Total current tax expense
35.9

 
108.6

 
72.6

Deferred tax (benefit) expense:
 
 
 
 
 
United Kingdom
—

 
—

 
—

Foreign
4.4

 
(22.1
)
 
28.0

Total income tax expense
$
40.3

 
$
86.5

 
$
100.6

Seadrill Partners LLC is tax resident in the United Kingdom. The Company's controlled affiliates operate and earn income in several countries and are subject to the laws of taxation within those countries. Currently some of the Company's controlled affiliates formed in the Marshall Islands along with all those incorporated in the United Kingdom (none of whom presently own or operate rigs) are resident in the United Kingdom and are subject to U.K. tax. Subject to changes in the jurisdictions in which the Company's drilling units operate and/or are owned, differences in levels of income and changes in tax laws, the Company's effective income tax rate may vary substantially from one reporting period to another. The Company's effective income tax rate for each of the years ended on December 31, 2017, 2016 and 2015 differs from the U.K. statutory income tax rate as follows:
 
2017
 
2016
 
2015
U.K. statutory income tax rate
19.3
 %
 
20.0
 %
 
20.3
 %
Non-U.K. taxes
(4.7
)%
 
(6.3
)%
 
(3.2
)%
Effective income tax rate
14.6
 %
 
13.7
 %
 
17.1
 %
Deferred Income Taxes
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

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The net deferred tax assets consist of the following:
(In US$ millions)
2017
 
2016
Provisions
$
0.5

 
$
7.6

Net operating losses carry forward
33.3

 
23.3

Other
5.0

 
6.4

Gross deferred tax assets
38.8

 
37.3

Valuation allowance related to NOL
(28.9
)
 
(22.6
)
Deferred tax asset, net of valuation allowance
$
9.9

 
$
14.7

The net deferred tax liabilities consist of the following:
(In US$ millions)
2017
 
2016
Property, plant and equipment
$
0.4

 
$
0.6

Unremitted earnings of subsidiaries
1.5

 
1.5

Gross deferred tax liabilities
1.9

 
2.1

 
 
 
 
Net deferred tax asset / (liability)
8.0

 
12.6

As of December 31, 2017, deferred tax assets related to net operating loss ("NOL") carryforwards were $33.3 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $33.3 million which will not expire. A valuation allowance of $28.9 million exists on the NOL carryforwards results where the Company does not expect to generate future taxable income.
At December 31, 2017, we recalculated our deferred tax assets and liabilities to reflect the reduction in the U.S. corporate income tax rate from 35 percent to 21 percent. This has resulted in a $3 million increase in income tax expense for the year ended December 31, 2017 and a corresponding $3 million decrease in net deferred tax assets as of December 31, 2017.  
Uncertain tax positions
As of December 31, 2017, the Company had uncertain tax positions, exclusive of interest, of $43.7 million (December 31, 2016: $40.0 million) included in "Other non-current liabilities" on the consolidated balance sheets and is exclusive of interest. The changes to the Company's liabilities related to uncertain tax positions were as follows:
(In US$ millions)
2017
 
2016
Balance beginning of year
$
40.0

 
$
9.0

Increases as a result of positions taken in prior years
—

 
42.0

Increases as a result of positions taken during the current year
3.7

 
31.9

Decreases as a result of positions taken in prior years
—

 
(34.2
)
Decreases as a result of positions taken in the current year
—

 
(8.7
)
Uncertain tax position
$
43.7

 
$
40.0

Accrued interest and penalties totaling $8.0 million as of December 31, 2017 (December 31, 2016: $1.8 million) was included in "Other non-current liabilities" on the consolidated balance sheets. The associated expense of $6.2 million was recognized in "Income tax expense" in the consolidated statements of operations during the year ended December 31, 2017 (December 31, 2016: $1.8 million and December 31, 2015: nil).
As of December 31, 2017, if recognized, $51.7 million of the Company's unrecognized tax benefits, including interest and penalties, would have a favorable impact on its effective tax rate.
Tax examinations
The Company is subject to taxation in various jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:
Jurisdiction
Earliest Open Year
United States
2014
Angola
2015
Nigeria
2012
Ghana
2013


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Table of Contents

Note 6 – Other revenues
Other revenues comprise the following items: 
 
Year Ended December 31,
(In US$ millions)
2017
 
2016
 
2015
Termination payments revenue
$
95.9

 
$
198.8

 
$
74.7

Related party other revenues
7.1

 
12.3

 
13.4

Total
$
103.0

 
$
211.1

 
$
88.1

Termination payments earned during the years ended December 31, 2017, December 31, 2016 and December 31, 2015 include the termination fees for the West Sirius and West Capella, which were canceled before the end of the contract term.
Related party other revenues primarily relate to the provision of onshore support services and offshore personnel to Seadrill's drilling rigs that were operating in Nigeria during the years ended December 31, 2017, December 31, 2016 and December 31, 2015. Please refer to Note 13 – "Related party transactions" for further detail on related party other revenues.

Note 7 – Other operating income
Other operating income comprises the following items: 
 
Year Ended December 31,
(In US$ millions)
2017
 
2016
 
2015
Revaluation of contingent consideration
$
89.9

 
$
—

 
$
—

Gain on sale of assets
0.8

 
—

 
—

Total
$
90.7

 
$
—

 
$
—

There was gain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 2017 (December 31, 2016 and December 31, 2015: nil).
This gain resulted from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015. We use estimates of long-term dayrates and re-contracting factors to determine the fair value of these liabilities. These estimates have decreased during the year as new market information has become available, resulting in a decrease in the fair value of the liabilities. For further information please see Note 13 "Related party transactions".

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Table of Contents

Note 8 – Accounts receivable
Accounts receivable are presented net of allowances for customer disputes and bad debts.
We have recorded provisions for disputes with customers totaling $247.5 million as of December 31, 2017 (December 31, 2016: $242.3 million). The offsetting entry for these provisions is to reduce revenue. These provisions primarily relate to disputed amounts billed to Tullow on the West Leo, for which litigation proceedings are ongoing. Please refer to Note 15 – "Commitments and contingencies" for further details on this dispute.
We do not hold any provisions for bad debts. We did not recognize any bad debt expense in 2017, 2016 or 2015.

Note 9 – Other assets
Other assets include the following:
(In US$ millions)
December 31,
2017
 
December 31,
2016
Reimbursable amounts due from customers
$
3.6

 
$
5.9

Mobilization revenue receivables
73.8

 
108.5

Intangible asset- Favorable contracts to be amortized
130.6

 
205.0

Prepaid expenses
8.5

 
4.5

Other
3.8

 
1.4

Total other assets
$
220.3

 
$
325.3

Other assets are presented in our Consolidated Balance Sheet as follows:
(In US$ millions)
December 31,
2017
 
December 31,
2016
Other current assets
86.8

 
117.0

Other non-current assets
133.5

 
208.3

Total other assets
$
220.3

 
$
325.3

Mobilization revenue receivables
Under our contracts for the West Capricorn, West Auriga and West Vela we are paid for mobilization activities over the contract term. We recorded a financial asset equal to the fair value of this future stream of payments when we acquired these drilling units from Seadrill. We expect to collect these amounts over the remaining term of the drilling contracts. We record the unwind of time value of money discount as interest income.
The mobilization receivable for the West Capricorn was collected in full by July 2017, which was the original firm term of the West Capricorn's contract with BP. The mobilization receivable for the West Auriga and West Vela will be collected by October 2020 and November 2020 respectively.
Favorable contracts
Favorable drilling contracts are recorded as intangible assets at fair value on the date of acquisition less accumulated amortization. The amounts recognized represent the net present value of the existing contracts at the time of acquisition compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. The estimated favorable contract values have been recognized and amortized on a straight line basis over the terms of the contracts, ranging from two to five years.
Favorable contracts to be amortized relate to the favorable contracts acquired with the West Vela, West Auriga and the West Polaris from Seadrill. As at December 31, 2017 the balance related to the contract acquired with the West Polaris was fully amortized. The gross carrying amounts and accumulated amortization included in 'Other current assets' and 'Other non-current assets' in the Consolidated Balance Sheets were as follows:
 
December 31, 2017
 
December 31, 2016
(In US$ millions)
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Intangible assets- Favorable contracts
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of period
$
357.3

 
$
(152.3
)
 
$
205.0

 
$
357.3

 
$
(81.7
)
 
$
275.6

Amortization of favorable contracts
—

 
(74.4
)
 
(74.4
)
 
—

 
(70.6
)
 
(70.6
)
Balance at end of period
$
357.3

 
$
(226.7
)
 
$
130.6

 
$
357.3

 
$
(152.3
)
 
$
205.0

The amortization is recognized in the statement of operations under "amortization of favorable contracts". The table below shows the amounts relating to favorable contracts that is expected to be amortized over the next five years:

F- 22
Table of Contents

 
Year ended December 31
(In US$ millions)
2018

 
2019

 
2020

 
2021

 
2022

 
Total

Amortization of favorable contracts
$
45.2

 
$
45.1

 
$
40.3

 
$
—

 
$
—

 
$
130.6


Note 10 – Drilling units 
The below table shows the gross value and net book value of our drilling units at December 31, 2017 and December 31, 2016.
(In US$ millions)
December 31,
2017
 
December 31,
2016
Cost
$
6,599.0

 
$
6,494.1

Accumulated depreciation
(1,428.1
)
 
(1,153.2
)
Net book value
$
5,170.9

 
$
5,340.9

Depreciation and amortization expense related to the drilling units was $274.9 million, $266.3 million and $237.5 million for the years ended December 31, 2017, 2016 and 2015 respectively.
Each of our drilling units has been pledged as collateral under our debt agreements. Please read Note 11 – "Debt" for further details.

Note 11 – Debt
As of December 31, 2017 and December 31, 2016, we had the following debt amounts outstanding:
 (In US$ millions)
December 31, 2017

 
December 31, 2016

External debt agreements
 
 
 
Term Loan B
$
2,836.9

 
$
2,865.7

West Vela Facility
255.3

 
342.4

West Polaris Facility
205.6

 
279.0

Tender Rig Facility

83.3

 
—

Sub-total external debt
3,381.1

 
3,487.1

 
 
 
 
Related party debt agreements
 
 
 
   West Vencedor Facility
24.7

 
41.2

   Tender Rig Facility
—

 
119.1

Sub-total related party debt
24.7

 
160.3

 
 
 
 
Total external and related party debt
$
3,405.8

 
$
3,647.4

Term Loan B (previously the "Amended Senior Secured Credit Facilities")
Our Term Loan B facilities ("TLB") consists of a term loan and a linked $100.0 million revolving credit facility. We initially borrowed $1.8 billion under the term loan on February 21, 2014 and then a further $1.1 billion on June 26, 2014. This loan is subject to a 1% per year ($29.0 million) amortization payment with the balance of the loan then being repayable in February 2021. We had $2,786.9 million outstanding on the term loan at December 31, 2017. We have drawn $50 million under the $100 million revolving credit facility linked to the TLB. The remaining $50 million was available and undrawn at December 31, 2017. The revolving credit facility matures in February 2019 and does not amortize.
During the year to December 31, 2017, we paid interest of LIBOR + 3.0% on the term loan and LIBOR + 2.25% on the revolving credit facility. LIBOR is subject to a 1% floor. We also pay a commitment fee of 0.5% on any unused portion of the revolving credit facility. As set out below, we have agreed to a 3.0% increase in margin on the term loan as part of an amendment to the TLB agreed in February 2018.
We have pledged the West Capella, West Aquarius, West Sirius, West Leo, West Capricorn and West Auriga as collateral vessels under the TLB. The net book value of these drilling units at December 31, 2017 was $3.7 billion. We have also pledged substantially all the assets of our subsidiaries, which own or charter the collateral vessels as well as our investments in those companies. As set out below, we have agreed to add the West Vencedor to the TLB collateral vessels as part of an amendment to the TLB agreed in February 2018.
We may be required to make mandatory prepayments of the term loan if we generate proceeds from asset sales or loss events. As set out below, we have also agreed to make a partial prepayment of the term loan if there is a successful outcome from our ongoing litigation with Tullow for the West Leo contract in Ghana. Please see Note 15 – "Commitments and contingencies" for further details on this litigation.

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The TLB includes certain covenants and other provisions that can cause amounts borrowed to become immediately due and payable. This included a covenant over the ratio of TLB debt to the EBITDA of the TLB collateral vessels. Based on our results for the year-ended December 31, 2017 this ratio would have been above the level permitted under the covenant. Therefore, unless cured, we would have violated this covenant when financial statements were delivered on April 30, 2018.
To address this, we agreed a modification to the terms of the TLB in February 2018. Under this amendment our lenders agreed to waive the leverage covenant until maturity. In return the TLB lenders receive a 3% increase in margin on the term loan and a prepayment contingent on the successful outcome of our ongoing litigation with Tullow on the West Leo. We will also be required to repay the West Vencedor facility and make the West Vencedor a collateral vessel under the TLB. The amendment also adds certain other restrictions on our ability to transfer cash outside of the TLB collateral group.
Full details of covenants, terms of default and restrictions may be found in the TLB loan agreements and subsequent amendments which have all been filed as exhibits to this 20-F report. Please refer to Item 19- "Exhibits".
West Vela facility (previously the "$1,450 million Senior Secured Credit Facility")
The West Vela facility consists of a term loan with four tranches. We initially incurred the liability to repay $443 million under this term loan when we acquired the West Vela from Seadrill in November 2014. The loan is subject to amortization payments of $40.3 million per year. We made a prepayment of $46.7 million in August 2017 and agreed to further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The residual $120.9 million is repayable in October 2020. We had $255.3 million outstanding on this loan at December 31, 2017.
We pay interest on the term loan at LIBOR plus a margin of between 3.35% and 4%, inclusive of guarantee fees, depending on the tranche.
We have pledged the West Vela as a collateral vessel under this facility. The net book value of the West Vela was $679.5 million at December 31, 2017. We have also pledged substantially all the assets of our subsidiaries which own and operate the West Vela, as well as our investments in those companies.
The West Vela facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the West Vela facility agreements and subsequent amendments which have all been filed as exhibits to this 20-F report.
West Polaris facility (previously the $420 million West Polaris Facility)
The West Polaris facility consists of a term loan and a linked revolving credit facility. We initially incurred the liability to repay $226 million under this term loan and $100 million under the revolving credit facility when we acquired the West Polaris from Seadrill in June 2015. The loan is subject to amortization payments of $36 million per year. We made a prepayment of $37.4 million in August 2017 and agreed to further prepayments of $9.4 million in February 2018 and August 2018. The residual $93.8 million is repayable in July 2020. We had $205.6 million outstanding on this facility at December 31, 2017.
We pay interest on the term loan and revolving credit facility at LIBOR plus a margin of 3.25%. We also pay a commitment fee of 1.3% on any unused portion of the revolving credit facility.
We have pledged the West Polaris as a collateral vessel under this facility. The net book value of the West Polaris was $523.4 million at December 31, 2017. We have also pledged substantially all the assets of our subsidiaries which own and operate the West Polaris, as well as our investments in those companies.
The West Polaris facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the West Polaris facility agreements and subsequent amendments which have all been filed as exhibits to this 20-F report.
Tender rig facility (previously the $440 million Rig Financing Agreement)
The Tender Rig facility consists of two term loans. We initially borrowed $100.5 million and $93.1 million under intercompany loans from Seadrill when we acquired the T-15 and T-16 in May 2013 and October 2013 respectively. These intercompany loans were back to back with an external debt facility Seadrill had used to finance the construction of the T-15 and T-16. In August 2017, we amended the terms of these loans so that we held the facility directly with the external lender.
We are required to make amortization payments of $19.8 million per year against this facility. We made a prepayment of $15.8 million in August 2017 when we amended the facility and agreed to further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The residual $31.2 million is repayable in June 2020. We had $83.3 million outstanding on this loan at December 31, 2017.
We pay interest on these loans at LIBOR plus a margin of 4.25%.
We have pledged the T-15 and T-16 as collateral vessels under this facility. The net book value of the T-15 and T-16 was $234.6 million at December 31, 2017. We have also pledged substantially all the assets of our subsidiaries which own and operate the T-15 and T-16, as well as our investments in those companies.
The Tender Rig facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. Full details of covenants, terms of default and restrictions may be found in the Tender Rig facility agreements and subsequent amendments which have all been filed as exhibits to this 20-F report.

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West Vencedor Loan Agreement
The West Vencedor Loan Agreement facility consists of a term loan due to Seadrill. The outstanding balance of the loan at December 31, 2017 was $24.7 million. The remaining amounts borrowed on the facility are to be repaid in 2018. We pay interest on the facility at LIBOR plus a margin of 2.3%.
We have pledged the West Vencedor as a collateral vessel under this facility. As set out above, we agreed to repay this facility and make the West Vencedor a collateral vessel under the TLB as part of as part of an amendment to the TLB agreed in February 2018. The net book value of the West Vencedor was $162.5 million at December 31, 2017.
Debt repayments by year
The outstanding debt as of December 31, 2017 is repayable as follows: 
(In US$ millions)
As of December 31, 2017
2018
$
199.8

2019
175.1

2020
331.1

2021
2,699.8

2022
—

2023 and thereafter
—

Total external and related party debt
$
3,405.8

Presentation in Consolidated Balance Sheet
We present external debt net of debt issuance costs. The below tables show how the above balances are presented in the Consolidated Balance Sheet:
 
 
Outstanding debt as of December 31, 2017
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
175.1

$
(12.2
)
$
162.9

Long-term external debt
 
3,206.0

(25.8
)
3,180.2

Total external debt
 
$
3,381.1

$
(38.0
)
$
3,343.1

Current portion of long term related party debt
 
$
24.7

$
—

$
24.7

Total interest bearing debt
 
$
3,405.8

$
(38.0
)
$
3,367.8

 
 
Outstanding debt as of December 31, 2016
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
105.3

$
(11.5
)
$
93.8

Long-term external debt
 
3,381.8

(35.3
)
3,346.5

Total external debt
 
$
3,487.1

$
(46.8
)
$
3,440.3

Current portion of long term related party debt
 
$
135.6

$
—

$
135.6

Long term related party debt
 
$
24.7

$
—

$
24.7

Total interest bearing debt
 
$
3,647.4

$
(46.8
)
$
3,600.6


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Table of Contents

Note 12 – Other liabilities
Other liabilities are comprised of the following: 
(In US$ millions)
December 31, 2017

 
December 31, 2016

Uncertain tax position
$
51.7

 
$
41.9

Taxes payable
36.5

 
47.7

Accrued expenses
35.4

 
29.3

Unrealized loss on derivative financial instruments
29.0

 
55.2

Deferred mobilization/demobilization revenues
9.4

 
19.6

Employee and business withheld taxes, social security and vacation payment
8.7

 
12.3

VAT payable
6.5

 
10.9

Other liabilities
0.4

 
1.2

Total other liabilities
$
177.6

 
$
218.1

Other liabilities are classified in our Consolidated Balance sheet as follows:
(In US$ millions)
December 31,
2017
 
December 31,
2016
Other current liabilities
121.8

 
168.9

Other non-current liabilities
55.8

 
49.2

Total other liabilities
$
177.6

 
$
218.1


Note 13 – Related party transactions
The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2017, 2016 and 2015.
(In US$ millions)
 
Year ended December 31,
 
 
2017
 
2016
 
2015
Related party operating expenses
 
 
 
 
 
 
Management and technical support fees (a) and (b)
 
$
74.5

 
$
62.8

 
$
75.3

Rig operating costs (c)
 
22.9

 
24.9

 
29.3

Insurance premiums (d)
 
10.5

 
16.0

 
20.2

Bareboat charters (e)
 
2.8

 
9.5

 
(1.6
)
Related party inventory purchases (f)
 
1.0

 
2.0

 
—

 
 
111.7

 
115.2

 
123.2

Related party financing expenses
 
 
 
 
 
 
Related party interest expense (g)
 
4.7

 
10.1

 
13.7

Losses on related party derivatives (h)
 
1.3

 
4.1

 
10.2

Related party commitment fee (i)
 
1.3

 
2.0

 
2.0

 
 
7.3

 
16.2

 
25.9

Less: related party revenues
 
 
 
 
 
 
Operation support fees (j)
 
(4.9
)
 
(10.9
)
 
(13.4
)
Related party inventory sales (f)
 
(2.2
)
 
(1.4
)
 
—

 
 
(7.1
)
 
(12.3
)
 
(13.4
)
 
 
 
 
 
 
 
Total
 
$
111.9

 
$
119.1

 
$
135.7

(a) Management and administrative services agreement – Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged for these services on a cost plus mark-up basis. During the year ended December 31, 2017, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreement has an indefinite term but we can terminate it for convenience by providing 90 days written notice.

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Table of Contents

(b) Operations and technical supervision agreements – Seadrill provides us with operations support and technical supervision services. The functions covered by these services include logistics, supply chain, warehousing, technical services and QHSE. We also have access to a pool of shared capital equipment maintained by Seadrill. We are charged for these services on a cost plus mark-up basis. During the year ended December 31, 2017, the mark-up we were charged for these services was approximately 5%.
(c) Rig operating costs – Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%. During the year ended December 31, 2016 we also received similar services from Seadrill for the West Vencedor.
(d) Insurance premiums – Our drilling units are insured by a subsidiary of Seadrill. We are recharged for insurance premiums that are arranged by Seadrill for our rigs.
(e) Bareboat charters – Seadrill acted as an intra-charterer for the West Aquarius during its contract with Hibernia in Canada, which ended in April 2017. Seadrill also previously acted as an intra-charterer for the T-15 and T-16 until December 2016. Seadrill earned a margin of $25,500 per day under the West Aquarius arrangement and $1,590 per day under the T-15 and T-16 arrangement. This margin was adjusted for utilization.
We incurred expenses for these arrangements of $2.8 million and $9.5 million in the years ended December 31, 2017 and 2016, respectively. We experienced high downtime on the West Aquarius in the year ended December 31, 2015 which resulted in us earning net income of $1.6 million under these arrangements that year.
(f) Related party inventory sales and purchases - Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.
(g) Related party interest expense – Interest charged by Seadrill on the Tender Rig facility, West Vencedor loan agreement and West Vela deferred consideration liability. Please read Note 11 – "Debt" for a description of the loan facilities and note (n) below for a description of the deferred consideration balance.
(h) Loss on related party derivatives - Losses on related party interest rate swaps previously held to mitigate interest rate exposures on the West Vela facility, West Polaris facility and Tender Rig facility. See Note 14 – "Risk management and financial instruments" for a description of these interest rate swaps. These swaps were canceled in September 2017 when Seadrill filed for Chapter 11.
(i) Related party commitment fee - Seadrill previously provided us with a revolving credit facility of $100 million. We were charged an interest rate of LIBOR of 5% for any amounts drawn under the facility and a commitment fee of 2% for any unused portion. The facility was canceled in August 2017 as part of the insulation transaction.
(j) Other revenues - We provided onshore support services and offshore personnel for two of Seadrill's drilling units, the West Jupiter and West Saturn, whilst the rigs operated in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended during 2017.
The below table provides a summary of amounts due to or from Seadrill at December 31, 2017 and December 31, 2016.
(In US$ millions)
 
December 31, 2017

 
December 31, 2016

Trading balances due from Seadrill and subsidiaries (k)
 
$
24.2

 
$
80.6

Trading balances due to Seadrill and subsidiaries (k)
 
(157.0
)
 
(192.0
)
Tender Rig Facility Seadrill (T-15 and T-16) (l)
 
—

 
(119.1
)
West Vencedor Loan Agreement with Seadrill (l)
 
(24.7
)
 
(41.2
)
Derivatives with Seadrill - interest rate swaps (m)
 
—

 
2.4

Deferred and contingent consideration to related party - short term portion (n)
 
(41.7
)
 
(45.6
)
Deferred and contingent consideration to related party - long term portion (n)
 
(46.0
)
 
(157.6
)
Total
 
(245.2
)
 
(472.5
)
(k) Trading balances – Receivables and payables with Seadrill are comprised primarily of invoices for management fees, operation support fees, rig operating costs, insurance premiums, bareboat charters. We also include accrued interest on financing balances within this category. In addition, certain receivables and payables arise when we pay an invoice on behalf of Seadrill or vice versa.
Related party invoices are generally settled quarterly in arrears. Trading balances with Seadrill are unsecured, interest free, and are intended to be settled in the ordinary course of business.
(l) Tender Rig Facility and West Vencedor Loan Agreement – Please read Note 11 "Debt" for details of these loan facilities.
(m) Derivatives with Seadrill - Interest rate swaps - The interest rate swaps held with Seadrill were canceled on September 12, 2017 when Seadrill entered Chapter 11. Refer to Note 14 "Risk management and financial instruments" for further information.
(n) Deferred consideration to related party - We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela and West Polaris.

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Table of Contents

On the West Vela we are required to pay to Seadrill $42k per day over the life of the contract with BP which runs until November 2020 for mobilization of the rig and a further $40k per day, adjusted for utilization, over the remaining contract term.
On the West Polaris we agreed to pay Seadrill 100% of dayrate earned above $450k per day for the remainder of the contract with ExxonMobil and 50% of the dayrate earned above $450k per day on any subsequent contract until March 2025. We also issued a $50 million note ("Sellers Credit") that is payable in March 2021. Payment in kind interest of 6.5% per year is accreted to the note. If the average dayrate earned by the West Polaris is less than $450k per day during the period March 2018 to March 2021, then the value of the note is reduced by the difference between the actual dayrate earned during the period and the amount that would have been earned if the average dayrate earned had been $450k per day.
In the year ended December 31, 2017, we recorded a gain of $89.9 million due to a reduction in the fair value of these liabilities. Please read Note 7 - "Other operating income" for further detail.
The below table sets out the fair value of the liabilities at December 31, 2017 and December 31, 2016.
(In US$ millions)
 
December 31, 2017

 
December 31, 2016

West Vela
 
 
 
 
Mobilization due to Seadrill
 
44.2

 
56.1

Seadrill share of dayrate from BP contract
 
38.6

 
49.0

 
 
82.8

 
105.1

West Polaris
 
 
 
 
Seadrill share of dayrate from ExxonMobil contract ("Earnout 1")
 
4.2

 
9.2

Seadrill share of dayrate from subsequent contracts ("Earnout 2")
 
0.7

 
38.1

Seller's credit
 
—

 
50.8

 
 
4.9

 
98.1

 
 
 
 
 
Total
 
87.7

 
203.2

These liabilities are presented in our Consolidated Balance Sheet as follows:
(In US$ millions)
 
December 31, 2017

 
December 31, 2016

Current portion of deferred and contingent consideration to related party
 
41.7

 
45.6

Non-current portion of deferred and contingent consideration to related party
 
46.0

 
157.6

Total
 
87.7

 
203.2


Other agreements and transactions with Seadrill
Equity Distribution
During the year-ended December 31, 2017, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions.
A total balance of $15.3 million has been distributed to Seadrill, comprised of a $6.1 million cash distribution and a $9.2 million non-cash distribution that was offset against certain trading balances owed to us by Seadrill.
These transactions have been presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2017.
$143 million Loan Agreement
Effective as of December 17, 2015, one of our operating subsidiaries borrowed $143.0 million from Seadrill (the "West Sirius loan”) to provide liquidity to meet the terms of a bareboat charter termination payment for the West Sirius contract termination. Concurrently, Seadrill borrowed $143.0 million (the "Seadrill loan”) from one of our rig owning subsidiaries to restore its liquidity. Each of the loan parties understood and agreed that the loan agreements acted in parallel with each other.
Each loan had an interest rate of LIBOR plus 0.56% and matured in August 2017. As at December 31, 2017, the loans had been fully repaid (December 31, 2016: outstanding balance $39.4 million)
These transactions were classified within current and long-term portions of "Amount due from related party", "Related party payable" and "Related party payable" in the Consolidated Balance Sheet.

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Table of Contents

Spare parts agreement with Seadrill
During the year ended December 31, 2015, we entered an agreement with Seadrill to store spare parts of the West Sirius rig while it was cold stacked. Seadrill may use the spare parts during the stacking period, but must replace them at its own cost when the West Sirius returns to operations.
Indemnifications and guarantees
Performance guarantees
Seadrill provides performance guarantees in connection with our drilling contracts in favor of our customers, amounting to a total of $165.4 million as of December 31, 2017 (December 31, 2016: $184.5 million).
Customs guarantees
Seadrill provides customs guarantees in connection with the Company’s operations, primarily in Thailand, in favor of banks amounting to a total of $0.6 million as at December 31, 2017 (December 31, 2016: nil).
Tax indemnifications
Under our omnibus agreement with Seadrill at the time of the IPO (the "Omnibus Agreement") and purchase and sale agreements relating to acquisitions from Seadrill subsequent to the IPO, Seadrill has agreed to indemnify the Company against any tax liabilities arising from the operation of the assets contributed or sold to the Company prior to the time they were contributed or sold.
Loan Guarantees
Seadrill was previously a guarantor under the West Polaris Facility and West Vela Facility. In August 2017, we completed amendments to these facilities which released Seadrill as a guarantor. Please refer to Note 11- "Debt" for further discussion.
T-15 and T-16 Acquisitions
In connection with the T-15 and T-16 acquisitions, Seadrill agreed to indemnify Seadrill T-15 Ltd, Seadrill T-16 Ltd, Seadrill International Ltd and Seadrill Partners Operating LLC against any liability incurred by them pursuant to their guarantees and share pledges under the Tender Rig Agreement. Seadrill was entitled to set off any such claims for indemnification against any claim it may have against Seadrill T-15 Ltd, Seadrill T-16 Ltd, Seadrill International Ltd and Seadrill Partners Operating LLC, including for claims under the related party loan agreements for the T-15 and T-16. As at August 17, 2017, indemnifications of this nature from Seadrill have been canceled in connection with the new Tender Rig Facility.
Environmental and other indemnifications
Under the Omnibus Agreement, and sale and purchase agreements relating to acquisitions from Seadrill subsequent to the IPO, Seadrill has agreed to indemnify the Company against certain environmental and toxic tort liabilities with respect to the assets that Seadrill contributed or sold to the Company to the extent arising prior to the time they were contributed or sold. This indemnification expired October 24, 2017.

Note 14 – Risk management and financial instruments
We are exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. We may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.
Interest rate risk management
Our exposure to interest rate risk relates mainly to our floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps. Our objective is to obtain the most favorable interest rate borrowings available without increasing its exposure to fluctuating interest rates. Surplus funds are used to repay revolving credit tranches, or placed in accounts and deposits with reputable financial institutions in order to maximize returns, while providing us with flexibility to meet all requirements for working capital and capital investments. The extent to which we utilize interest rate swaps to manage our interest rate risk is determined by our net debt exposure and our views on future interest rates.
Interest rate swap agreements
As of December 31, 2017, we had interest rate swaps for a combined outstanding principal amount of $2,793.9 million, (December 31, 2016: $2,822.9 million) swapping floating rate for an average fixed rate of 2.49% per annum. The fair value of the interest rate swaps outstanding as of December 31, 2017 amounted to a gross and net liability of $29.0 million, (December 31, 2016: a gross liability of $70.2 million and a net liability of $55.2 million). The collateral vessels under our TLB have been pledged as collateral against our interest rate swap liabilities. The interest rate swaps and TLB debt rank pari passu.
We record interest rate swaps on a net basis where netting is as allowed under International Swaps and Derivatives Association, Inc. ("ISDA") Master Agreements. We classify the liability within other current liabilities. We have not designated any interest swaps as hedges and accordingly any changes in the fair values of the swap agreements are included in the consolidated statement of operations under "loss on derivative financial instruments".
The total realized and unrealized loss recognized under "loss on derivative financial instruments" in the consolidated statement of operations relating to interest rate swap agreements with external parties for 2017 was $12.5 million (2016: $13.9 million, 2015: $72.7 million). Included

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in the $13.9 million net loss for the year ended December 31, 2016 was an out of period gain of $21.8 million recognized in respect of the Company's own creditworthiness.
Our interest rate swap agreements as of December 31, 2017, were as follows:
Maturity date
Outstanding principal as of December 31, 2017
Receive rate
Pay rate
 
 
(In US$ millions)
 
 
 
February 21, 2021
2,793.9

3 month LIBOR
 2.45% to 2.52%
(1) (2)
Total outstanding principal
$
2,793.9

 
 
 
(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.
(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.
As of December 31, 2017, $611.9 million of our debt was exposed to interest rate fluctuations, compared to $204.2 million as of December 31, 2016. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, our interest expense by approximately $6.1 million on an annual basis as of December 31, 2017, as compared to $2.0 million in 2016.
The credit exposure of interest rate swap agreements is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements, adjusted for counterparty non-performance credit risk assumptions. It is our policy to enter into ISDA Master Agreements, with the counterparties to derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes us.

The related party interest rate swaps held by Seadrill were canceled on September 12, 2017 as a result of Seadrill entering a Chapter 11 restructuring. The total fair value of the related party interest rate swaps, with Seadrill as counterparty, was therefore nil at December 31, 2017 (December 31, 2016: a net asset of $2.4 million and gross asset of $2.6 million). The fair value of the related party interest rate swaps is classified within amounts due to related party in the Consolidated Balance Sheets.
The total realized and unrealized loss recognized under "loss on derivative financial instruments" in the Consolidated Statement of Operations relating to interest rate swap agreements with Seadrill for the year ended December 31, 2017 was $1.3 million (2016: $4.1 million, 2015: $10.2 million). Included in the $4.1 million net loss for the year ended December 31, 2016 is an out of period loss of $0.4 million recognized in respect of the Company's' own creditworthiness.
Foreign currency risk
We use the US Dollar as the functional currency of all our subsidiaries because the majority of our revenues and expenses are denominated in US Dollars. Therefore, we also use US Dollars as our reporting currency. We do, however, earn revenue and incur expenses in Canadian Dollars due to the operations of the West Aquarius in Canada and as such, there is a risk that currency fluctuations could have an adverse effect on the value of the Company's cash flows. The impact of a 10% appreciation or depreciation in the exchange rate of the Canadian Dollar against the US Dollar would not have a material impact on our results.
Our foreign currency risk arises from:
•
the measurement of monetary assets and liabilities denominated in foreign currencies converted to US Dollars, with the resulting gain or loss recorded as "Foreign exchange gain/(loss)"; and
•
the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies.
We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.
Credit risk
We have financial assets which expose us to credit risk arising from possible default by a counterparty. Our counterparties primarily include our customers, which are international oil companies, national oil companies or large independent companies or financial institutions. We consider these counterparties to be creditworthy and do not expect any significant loss due to credit risk. We don't demand collateral from our counterparties in the normal course of business.
Concentration of Credit Risk
There is a concentration of credit risk with respect to revenue as two of our customers that each represent more than 10% of total revenues. Refer to Note 4 "Segment Information" for an analysis of our revenue by customer. The market for our services is the offshore oil and gas industry, and our customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral from them. Reserves for potential credit losses are maintained when necessary.
There is a concentration of credit risk with respect to cash and cash equivalents as most of the amounts are deposited with Nordea Bank Finland Plc and Danske Bank A/S. We consider these risks to be remote given the strong credit rating of these banks.

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Fair Values
GAAP emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, GAAP establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).
Level one input utilizes unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.
Fair value of financial assets and liabilities recorded at cost
The carrying value and estimated fair value of our financial assets and liabilities as of December 31, 2017 and December 31, 2016 are as follows:
 
December 31, 2017
 
December 31, 2016
(In US$ millions)
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Cash and cash equivalents
$
848.6

 
$
848.6

 
$
767.6

 
$
767.6

Term Loan B
2,249.8

 
2,802.3

 
1,925.2

 
2,865.7

Other external debt facilities
514.7

 
540.8

 
581.8

 
621.4

Long-term debt to related party
23.8

 
24.7

 
153.3

 
160.3

The carrying value of cash and cash equivalents, which are highly liquid, is a reasonable estimate of fair value and categorized at level 1 on the fair value measurement hierarchy.
The loans under the Term Loan B are freely tradable and their fair value has been set equal to the price at which they were traded on December 31, 2017 and December 31, 2016. This has been categorized at level 1 on the fair value measurement hierarchy.
Loans under other external debt facilities being the West Vela facility (previously the $1,450 million Senior Secured Credit Facility), West Polaris facility, Tender Rig facility (previously the $440 million Rig Financing Agreement) and the West Vencedor facility are not freely tradable. For the years ended December 31, 2017 and December 31, 2016 the fair value of the current and long term portion of these debt facilities was derived using the Discounted Cash Flow (DCF) model. A cost of debt of 8.36% (December 31, 2016 8.34%) was used to estimate the present value of the future cash flows. This is categorized at level 2 on the fair value measurement hierarchy.
Assets and liabilities recorded at cost on a recurring basis
Other financial instruments that are measured at fair value on a recurring basis:
 
 
Fair value measurements
at reporting date using
 
Total fair value as of December 31, 2017
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions)
 
(Level 1)
(Level 2)
(Level 3)
Current liabilities:
 
 
 
 
Derivative instruments - Interest rate swap contracts
(29.0
)
—

(29.0
)
—

Related party deferred and contingent consideration
(87.7
)
—

(87.7
)
—

Total liabilities
$
(116.7
)
—

(116.7
)
—


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Fair value measurements
at reporting date using
 
Total fair value as of December 31, 2016
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions)
 
(Level 1)
(Level 2)
(Level 3)
Current assets:
 
 
 
 
Derivative instruments - Interest rate swap contracts (related party)
$
2.4

—

2.4

—

Total assets
2.4

—

2.4

—

 
 
 
 
 
Current liabilities:
 
 
 
 
Derivative instruments - Interest rate swap contracts (related party)
(55.2
)
—

(55.2
)
—

Related party deferred and contingent consideration
(203.2
)
—

(203.2
)
—

Total liabilities
$
(258.4
)
—

(258.4
)
—

The fair values of interest rate swap contracts are calculated using well-established independent valuation techniques, applied to contracted cash flows and expected future LIBOR interest rates, and counterparty non-performance credit risk assumptions as of December 31, 2017 and December 31, 2016. The calculation of the credit risk in the swap values is subject to a number of assumptions including an assumed Credit Default Swap rate based on the Company's traded debt, plus a curve profile and recovery rate.

The fair value of the related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris are estimated based on future cash outflows discounted back to the present value. The contingent consideration has been discounted to present value using a cost debt of 8.36%. These liabilities are considered to be at estimated market rates. These are categorized at level 2 on the fair value measurement hierarchy.

In the year ended December 31, 2017, a $89.9 million gain is included in operating income resulting from a reduction in contingent liabilities related to the purchase of the West Polaris in 2015. Future dayrate estimates and re-contracting assumptions have been used to determine the fair value of these liabilities. These estimates have decreased during the year, resulting in a decrease in the fair value of the liabilities. Included in the fair value recognized in the year ended December 31, 2017 is an out of period gain of $20.9 million. Management has evaluated the impact of this out of period adjustment in 2017 and concluded that this was not material to the financial statements for the year ended December 31, 2017 or to any previously reported financial statements.

Included in the $13.9 million net "loss on derivative financial instruments" recognized for the year ended December 31, 2016 was an out of period gain of $24.1 million recognized in respect of the Company's own creditworthiness. We had reviewed our fair value accounting principles under ASC 820 - Fair value Measurements relating to our interest rate swap portfolio, and determined we had not appropriately included counterparty credit risk in our fair value measurements relating to our derivative instruments. ASC 820 requires counterparty credit risk to be included in the determination of the fair value of our interest rate swap portfolio, and any related changes in fair value as a result of changes in counterparty credit risk are recognized in the Consolidated Statements of Operations in the line item "Loss on derivative financial instruments".

Management evaluated the impact of this out of period adjustment in 2016 and concluded that this was not material to the financial statements for the year ended December 31, 2016 or to any previously reported financial statements.

Retained risk
a) Physical Damage Insurance
Seadrill has purchased hull and machinery insurance to cover physical damage to its drilling units and those of the Company. We are charged for the cost of insuring our drilling units. We retain the risk for the deductibles relating to physical damage insurance on our fleet. The deductible is currently a maximum of $5 million per occurrence.
b) Loss of Hire Insurance
Seadrill purchases insurance to cover for loss of revenue for their operational rigs in the event of extensive downtime caused by physical damage to its drilling units and those of the Company, where such damage is covered under Seadrill’s physical damage insurance, and charges us for the cost related to our fleet.
The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which we are compensated for loss of revenue are limited to 290 days per event and aggregated per year. The daily indemnity will vary from 75% to 100% of the contracted dayrate.

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We retain the risk related to loss of hire during the initial 60 day period, as well as any loss of hire exceeding the number of days permitted under the insurance policy. If the repair period for any physical damage exceeds the number of days permitted under the loss of hire policy, we will be responsible for the costs in such period. We do not purchase loss of hire insurance on the T-15 and T-16.
c) Protection and Indemnity Insurance
Seadrill purchases protection and indemnity insurance and excess liability insurance for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units to cover claims of up to $250 million per event and in the aggregate for the West Vencedor, T-15 and T-16, up to $300 million per event and in the aggregate for the West Leo and West Aquarius. $400 million per event and in the aggregate for the West Capella and West Polaris, up to $500 million per event and in the aggregate for the West Sirius; and up to $0.5 million per event and in the aggregate for the West Capricorn, West Auriga and West Vela.
In the event of no drilling activities, the excess liability insurance is suspended and therefore the limit is reduced from $500 million to $350 million per events and in the aggregate with the exception of the West Capricorn, West Auriga and West Vela which is reduced from $750 million to $500.0 million per event and in aggregate.
We retain the risk for the deductible of up to $0.5 million per occurrence relating to protection and indemnity insurance.
d) Windstorm Insurance
We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico (West Sirius, West Capricorn, West Vela and West Auriga) with a Combined Single Limit of $100 million in the annual aggregate, which includes loss of hire. We intend to renew this policy to insure this windstorm risk for a further period starting May 1, 2018 through April 30, 2019.

Note 15 – Commitments and contingencies
Legal Proceedings
From time to time the Company is a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with its acquisition or disposal activities. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2017.
West Leo
We received notification of a force majeure occurrence on October 1, 2016 in respect of the West Leo which was operating for Tullow Ghana Limited ("Tullow") in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience. We do not accept that the contract has been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract has been discharged by frustration.  Accordingly, we amended our claim in the English High Court to reflect this. In the event of termination for convenience, we are entitled to an early termination fee of 60% of the remaining contract backlog, subject to an upward or downward adjustment depending on the work secured for the West Leo over the remainder of the contract term, plus other direct costs incurred as a result of the early termination. The total amount we are seeking to recover is $278.0 million plus interest.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit against certain of our subsidiaries for patent infringement. The suit alleges that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity drilling. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office which ultimately stayed the litigation. The IPR board held in March 2017 that the patents were valid. Despite this finding, we do not believe that our rigs infringe the Transocean patents, which have now expired, and we continue to defend ourselves vigorously against this suit. We do not believe that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. We have not previously recognized any related loss contingency in our Consolidated Financial Statements as of December 31, 2017 as we do not believe the loss to be probable. We are also not able to make a reasonable estimate of the possible loss.
Other claims or legal proceedings
We are not aware of any other legal proceedings or claims that we expect to have, individually or in the aggregate, a material adverse effect on the Company.
Commitments
We had no material lease commitments or unconditional purchase obligations at December 31, 2017 and 2016.


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Note 16 – Earnings per unit and cash distributions
 
Year ended December 31,
(in US $ millions, except per unit data)
2017
 
2016
 
2015
Net income attributable to:
 
 
 
 
 
Common unitholders
$
141.2

 
$
240.7

 
$
184.1

Subordinated unitholders
—

 
37.8

 
40.5

Seadrill member interest
—

 
2.5

 
32.6

Net income attributable to Seadrill Partners LLC owners
$
141.2

 
$
281.0

 
$
257.2

 
 
 
 
 
 
Weighted average units outstanding (basic and diluted) (in thousands):
 
 
 
 
 
Common unitholders
75,278

 
75,278

 
75,278

Subordinated unitholders
16,543

 
16,543

 
16,543

 
 
 
 
 
 
Earnings per unit (basic and diluted):
 
 
 
 
 
Common unitholders
$
1.88

 
$
3.20

 
$
2.45

Subordinated unitholders
$
—

 
$
2.28

 
$
2.45

 
 
 
 
 
 
Cash distributions declared and paid in the period per unit (1) (2)
$
0.4000

 
$
0.7000

 
$
1.7025

 
 
 
 
 
 
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):
$
0.1000

 
$
0.1000

 
$
0.2500

(1) Refers to the cash distributions declared and paid during the year.
(2) Distributions were declared and paid only with respect to the common units in 2017.
(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.
Earnings per unit is calculated using the two-class method where undistributed earnings are allocated to the various member interests. The net income attributable to the common and subordinated unitholders and the holders of the incentive distribution rights is calculated as if all net income was distributed according to the terms of the distribution guidelines set forth in the First Amended and Restated Operating Agreement of the Company (the “Operating Agreement”), regardless of whether those earnings could be distributed. The Operating 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 the quarter after establishment of cash reserves determined by the Company’s board of directors to provide for the proper conduct of the Company’s business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Therefore, the earnings per unit is not indicative of potential cash distributions that may be made based on historic or future earnings. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains (losses).
Under the Operating Agreement, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit per quarter, plus any arrearages in the payment of minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
Distributions of available cash from operating surplus are to be made in the following manner for any quarter during the subordination period:
•
First, to the common unitholders, pro-rata, until the Company distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•
Second, to the common unitholders, pro-rata, until the Company distributes for each outstanding common an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters during the subordination period; and
•
Third, to the subordinated units, pro-rata, the Company distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.
In addition, the Seadrill Member currently holds all of the incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of the quarterly distributions of cash available from operating surplus after the minimum quarterly distribution and target distribution levels have been achieved.
If for any quarter during the subordination period:
•
The Company has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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•
The Company has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
then, the Company will distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of the incentive distributions rights in the following manner:
•
first, 100.0% to all unitholders, until each unitholder receives a total of $0.4456 per unit for that quarter (the “first target distribution”);
•
second, 85% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.4844 per unit for that quarter (the “second target distribution”);
•
third, 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.5813 per unit for that quarter (the “third target distribution”); and
•
thereafter, 50.0% to all unitholders, and 50.0% to the holders of the incentive distribution rights, pro rata.
The percentage interests set forth above assumes that the Company does not issue additional classes of equity securities.
The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:
•
distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•
the “adjusted operating surplus” (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and
•
there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.
In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by the conflicts committee, the holder or holders of a majority of the subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.
Commencing with the distributions made in February 2016, in respect of the fourth quarter of 2015, no distributions have been made to the holders of the subordinated units and distributions to the common units have been below the minimum quarterly distribution. Arrearages in the payment of the minimum quarterly distribution on the common units must be settled before any distributions of available cash from operating surplus may be made in the future on the subordinated units.
The following distributions were paid to the incentive distribution rights holders for the years ending December 31, 2017, 2016 and 2015.
 
Year ended December 31,
(in US $ millions)
2017
 
2016
 
2015
Distributions paid to incentive distribution rights holders
—

 
—

 
9.5


Note 17 - Supplementary cash flow information
The table below summarizes the non-cash investing and financing activities relating to the periods presented:
(In US$ millions)
2017
 
2016
 
2015
Purchase of the West Polaris, deferred consideration payable to related party (1)(2)
—

 
—

 
65.0

Purchase of the West Polaris, seller's credit payable to related party (1) (2)
—

 
—

 
44.6

Other distributions (3)
9.2

 
—

 
—

(1) The purchase of the West Polaris was financed in part by a seller's credit and deferred consideration: refer to Note 3 "Business acquisitions".
(2) The contingent consideration payable to Seadrill was reduced by a measurement period adjustment in the year ended December 31, 2017 and December 31, 2015. Refer to Note 14 "Risk management and financial instruments" and Note 3 "Business acquisitions".
(3) Non cash distribution, refer to Note 13 – "Related party transactions" for further information.


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Note 18 – Subsequent events
Distribution declared
On February 22, 2018, we declared a distribution for the fourth quarter of 2017 of $0.1000 per common unit, which was paid on March 12, 2018.
Amendments to the TLB credit agreement
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the amendment, the Company has agreed to certain amendments, including but not limited to, increasing the applicable margin by 3%, a par prepayment contingent on the successful outcome of certain ongoing litigation, adding the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 11 "Debt" for further details.




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SIGNATURES
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.
 
 
 
SEADRILL PARTNERS LLC
(Registrant)
 
 
 
 
Date: April 12, 2018
 
 
 
 
 
 
 
 
 
By:
/s/ Mark Morris
 
 
Name:
Mark Morris
 
 
Title:
Chief Executive Officer of Seadrill Partners LLC
(Principal Executive Officer of Seadrill Partners LLC)