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, 2018
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, 2018, ("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," "Shell", "BP", "Tullow", "Petronas", and "Hibernia" refer to subsidiaries of ExxonMobil Corporation, Chevron Corporation, Royal Dutch Shell Plc, BP Plc, Tullow Plc, Petroliam Nasional Berhad (PETRONAS), and Hibernia Management and Development Ltd. 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.

i

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;
•
fluctuations in the price of oil;
•
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 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" of the Consolidated Financial Statements included within this report.
 
 
Year Ended December 31,
 
 
2018

2017

2016
 
2015

2014
 
 
(in millions, except per unit data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Total operating revenues (1)
 
$
1,038.2

 
$
1,128.4

 
$
1,600.3

 
$
1,741.6

 
$
1,342.6

Total other operating items (2)
 
(3.2
)
 
90.7

 
—

 
—

 
—

Total operating expenses
 
(678.0
)
 
(755.6
)
 
(782.2
)
 
(897.9
)
 
(727.8
)
Net operating income
 
357.0

 
463.5

 
818.1

 
843.7

 
614.8

Total financial items
 
(196.3
)
 
(187.9
)
 
(185.9
)
 
(254.7
)
 
(265.4
)
Income before income taxes
 
160.7

 
275.6

 
632.2

 
589.0

 
349.4

Income tax expense
 
(86.7
)
 
(40.3
)
 
(86.5
)
 
(100.6
)
 
(34.8
)
Net income
 
$
74.0

 
$
235.3

 
$
545.7

 
$
488.4

 
$
314.6

Earnings per unit (common and subordinated)
 
 
 
 
 
 
 
 
 
 
Common unitholders
 
$
0.75

 
$
1.88

 
$
3.20

 
$
2.45

 
$
1.75

Subordinated unitholders
 
$
—

 
$
—

 
$
2.28

 
$
2.45

 
$
1.75

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 items in 2018 are a result of a loss on impairment of goodwill. The gain in 2017 was primarily related to a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015. Refer to Note 8 - "Other operating items" for further information.
 
 
As of December 31,
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
(in millions)
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
841.6

 
$
848.6

 
$
767.6

 
$
319.0

 
$
242.7

Drilling units
 
5,005.6

 
5,170.9

 
5,340.9

 
5,547.3

 
5,141.1

Total assets
 
6,185.4

 
6,530.8

 
6,780.7

 
6,841.1

 
6,268.1

Total interest bearing debt
 
3,059.1

 
3,367.8

 
3,600.6

 
3,840.2

 
3,572.0

Total equity
 
2,714.2

 
2,701.8

 
2,535.8

 
2,097.4

 
2,044.3

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

1

 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
(in millions, except fleet and unit data)
Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
434.1

 
$
476.2

 
$
873.8

 
$
859.8

 
$
608.7

Net cash (used in)/provided by investing activities
 
(23.4
)
 
(11.1
)
 
97.6

 
(376.3
)
 
(1,542.8
)
Net cash (used in)/provided by financing activities
 
(416.7
)
 
(384.9
)
 
(522.1
)
 
(407.6
)
 
1,087.1

Net (decrease)/increase in cash and cash equivalents
 
(7.0
)
 
81.0

 
448.6

 
76.3

 
153.0

Fleet Data:
 
 
 
 
 
 
 
 
 
 
Number of drilling units at end of period
 
11

 
11

 
11

 
11

 
10

Average age of drilling units at end of period (years)
 
7.7

 
6.7

 
5.7

 
4.7

 
3.6

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
Capital expenditures (1)
 
$
115.0

 
$
121.6

 
$
61.1

 
$
68.4

 
$
70.7

Distributions declared per unit (2)
 
0.4000

 
0.4000

 
0.5500

 
1.9525

 
2.1700

Members Capital (at end of period):
 
 
 
 
 
 
 
 
 
 
Total members capital (excluding non-controlling interest)
 
1,329.7

 
1,303.7

 
1,192.6

 
964.3

 
928.2

Common Unitholders—units
 
75,278,250

 
75,278,250

 
75,278,250

 
75,278,250

 
75,278,250

Subordinated Unitholders—units
 
16,543,350

 
16,543,350

 
16,543,350

 
16,543,350

 
16,543,350

1. 
Capital expenditures include long-term maintenance
2. 
Distributions attributable to the year. Distributions were declared only with respect to the common units in 2018 and 2017.

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, 2018. 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. For a description of the advisory, technical and administrative services agreements and the management and administrative services agreement, please read Note 14 - "Related party transactions" of the Consolidated Financial Statements included within this report.
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 July 2, 2018, Seadrill, along with certain of its Consolidated subsidiaries, emerged from Chapter 11 Proceedings. Substantially all the material claims against the Debtors that arose prior to the date of the bankruptcy filing were addressed during the Chapter 11 proceedings or were resolved in connection with the plan of reorganization and the order of the Bankruptcy Court confirming the plan.
Seadrill may be subject to claims that were not discharged in the bankruptcy proceedings, for example, claims relating to certain actions by governmental units under policy power authority, or instances where a claimant had inadequate notice of the bankruptcy filing. In addition, except in limited circumstances, claims against non-debtor subsidiaries, are generally not subject to discharge under the Bankruptcy Code. To the extent any pre-filing liability remains, the ultimate resolution of such claims and other obligations may have a material adverse effect on Seadrill's results of operations, profitability and financial condition.
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, 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. 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. 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 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. Refer to 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 that 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 numerous factors beyond our control, including, but not limited to, the following:
•
worldwide production of, 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 regarding future energy prices and production;
•
advances in exploration, development and production technology;
•
the ability of the Organization of Petroleum Exporting Countries or OPEC, to set and maintain levels of production 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 problems and the corresponding decline in 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 and military 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.

Decreases in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have negatively affected and could continue to negatively affect our future performance.

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 oil and gas company 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:
•
the availability and quality of competing offshore drilling units;
•
the availability of debt financing on reasonable terms;
•
the level of costs for associated offshore oilfield and construction services;
•
oil and gas transportation costs;
•
the level of rig operating costs, including crew and maintenance;
•
the discovery of new oil and gas reserves;
•
the political and military environment of oil and gas reserve jurisdictions; and
•
regulatory restrictions on offshore drilling.

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 on a local basis. 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, the rig's and/or the drilling contractor's 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.

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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 is currently in a prolonged downcycle. The price of Brent crude has fallen from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. As at December 31, 2018, the price of Brent crude was approximately $55 per barrel. During the downturn our customers have reduced their expenditures on offshore drilling which, coupled with additional newbuild supply, has led to increased price competition and has 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, we may idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As of December 31, 2018, we had four idle units, either "warm stacked," which means the rig is kept operational and ready for redeployment, and maintains most 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. Without new drilling contracts or additional financing being available when needed or available only on unfavorable terms, we will be unable to meet our obligations as they come due or we may be unable to enhance our existing business, complete additional drilling unit acquisitions or otherwise take advantage of business opportunities as they arise.

In the current environment, our customers may also seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, 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.

From time to time, we are approached by potential buyers for the outright purchase of some of our drilling units, businesses, or other fixed assets. We may determine that such a sale would be in our best interests and agree to sell certain drilling units or other assets. Such a sale could have an impact on short-term liquidity and net income. We may recognize a gain or loss on disposal depending on whether the fair value of the consideration received is higher or lower than the carrying value of the asset.

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 interrupted
In the current market conditions, some of our customers may seek to terminate their agreements with us.

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 events beyond our control. In addition, national oil company customers may have special termination rights by law. 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.

Our customers may seek to renegotiate their contracts with us using various techniques, including threatening breaches of contract and applying commercial pressure, resulting in lower dayrates or the cancellation of contracts with or without any applicable early termination payments.
Reduced dayrates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) may adversely affect our performance and lead to reduced revenues from operations.
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, 2018, we had $3,084.7 million in principal amount of external interest-bearing debt 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 5 - "Operating and Financial Review and Prospects - Liquidity and Capital Resources".
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.

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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 certain specified financial ratios and to satisfy covenants, including ratios and covenants that pertain to, among other things, our liquidity and a net leverage ratio under our secured rig financing 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, or a liquidity requirement, 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, liquidity requirement 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 February 28, 2019, our contract backlog was approximately $0.9 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. In some instances, there is an option for a customer to terminate a drilling contract prematurely for convenience on payment of an early termination fee. However, this fee may not adequately compensate us for the loss of this drilling contract.
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 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 February 28, 2019, we have seven drilling units either on contract or mobilizing for operations. Five of these contracts 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.

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If we are unable to secure contracts for our drilling units we may continue to idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As at December 31, 2018 we had four units either "warm stacked," which means the rig is kept operational and ready for redeployment, and maintains most 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.

If we are not able to obtain new contracts in direct continuation of existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and we may be unable to push this risk down to other contractors or be unable or unwilling at competitive prices to insure against this risk, which will mean the risk will have to be managed by applying other controls. 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 contract 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-throughs, 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. Customers may seek to cap indemnities or narrow the scope of their coverage, reducing our level of contractual protection.

In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 decision in a 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 performance.


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The amount recoverable under insurance may also be less than the related impact on enterprise value after a loss or 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.

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. Specifically, we have at times in the past elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the US Gulf of Mexico due to the substantial costs associated with such coverage. Beginning on April 1, 2014, we have insured a limited part of this windstorm risk in a combined single limit annual aggregate policy. We 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. If we elect to self-insure such risks again in the future and such windstorms cause significant damage to any rig and equipment we have in the US Gulf of Mexico, it could have a material adverse effect on our financial position, results of operations or cash flows.

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, 2018, BP accounted for 68.0% and Chevron accounted for 8.5% 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 risk 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 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.

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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.
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.

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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, including arctic 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 United Nation's International Maritime Organization, or the IMO, the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended, or MARPOL, including the designation of Emission Control Areas, or ECAs thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended, or the CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, as from time to time amended, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, the IMO 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 or the BWM Convention, the U.S. Oil Pollution Act of 1990, or the OPA, requirements of the U.S. Coast Guard, or the USCG, the U.S. Environmental Protection Agency, or the EPA, the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, the U.S. Outer Continental Shelf Lands Act, certain regulations of the European Union, and the laws and regulations of other countries in which we operate. 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 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, resulted in the substantial revision of safety regulations applicable to our industry, and 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.


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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.

If 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.

The insurance coverage we currently hold may not be available in the future, or we may not obtain certain insurance coverage. Even if insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities, or our insurance underwriters may be unable to pay compensation if a significant claim should occur. Any of these scenarios could have a material adverse effect on our business, results of operations and financial condition.
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 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. 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.
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.

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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 were permitted under the JCPOA were not actually repealed or permanently terminated the time. Rather, the U.S. government had 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.

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 sanction 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.

On May 8, 2018, the U.S. announced it was ending its participation in the JCPOA, and began to take steps to re-impose economic sanctions broadly targeting the Iranian economy. OFAC announced that sanctions that had been lifted under the JCPOA would be re-instated after a wind-down period, some on August 6, 2018, and others on November 4, 2018. The announcement largely did not establish new sanctions on Iran, but re-imposed in concrete fashion sanctions that had been revoked previously. Notably, at the end of the wind down period, hundreds of Iranian counterparties whose sanctioned status had been lifted pursuant to the JCPOA were once again formally designated by the U.S. government as restricted parties. Also, at the end of the wind-down period, OFAC revoked the general authorization (“General License H”) which allowed non-U.S. companies owned or controlled by U.S. companies to engage in certain business with Iran.

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 common units.


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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.

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 common units. Additionally, some investors may decide to divest their interest, or not to invest, in our common 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 common 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.

An economic downturn 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 European countries and their ability to meet future financial obligations and the overall stability of the euro. A renewed period of adverse development in the outlook for the financial stability of European countries, or market perceptions concerning these and related issues, could reduce the overall demand for oil and natural gas and for our services and thereby could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in the Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.

Negative developments in worldwide financial and economic conditions could further 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, lenders willingness to provide credit facilities to 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 U.K. voted to exit from the European Union (commonly referred to as Brexit). The impact of Brexit and the resulting U.K. and European relationship are uncertain for companies doing business both in the U.K. and the overall global economy.

An extended period of adverse development in the outlook for the world economy could also reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices.

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 when required.






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Our ability to operate our drilling units in the U.S. Gulf of Mexico could be impaired by governmental regulation, particularly in the aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout.
In the aftermath of the Deepwater Horizon Incident (in which we were not involved), various governmental agencies, including the U.S Department of the Interior, U.S. Bureau of Safety and Environmental Enforcement, or the BSEE and its predecessor, the U.S Bureau of Ocean Energy Management or BOEM, and the U.S. Occupational Safety and Health Administration, issued new and revised regulations and guidelines governing safety and environmental management, occupational injuries and illnesses, financial assurance requirements, inspection programs and other well control measure relating to our drilling rigs
In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. Operators have previously had, and may in the future have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico.
In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53 relating to the design, maintenance, installation and testing of well control equipment. Current and pending regulations, guidelines and standards for safety, environmental and financial assurance such as the above and any other new guidelines or standards the U.S. government or industry may issue (including relating to the Deepwater Horizon Incident or the other catastrophic events involving pollution from oil exploration and development activities) or any other steps the U.S. government or industry may take relating to our business activities, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. and non-U.S. offshore areas.
As new standards and procedures are being integrated into the existing framework of offshore regulatory programs, there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as re-completions, workovers and abandonment activities.
We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling units in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for our services. In addition, insurance costs across the industry have increased as a result of the Deepwater Horizon Incident and, in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all. We cannot predict the potential impact of new regulations that may be forthcoming, nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, our cash flow and financial position could be adversely affected if our ultra-deepwater semi-submersible drilling rigs and ultra-deepwater drillships operating in the U.S. Gulf of Mexico were subject to the risks mentioned above.
In addition, hurricanes have from time to time caused damage to a number of drilling units and production facilities unaffiliated to us in the Gulf of Mexico. The BOEM and the BSEE, have in recent years issued more stringent guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, moored drilling unit fitness, as well as other guidelines and regulations in an attempt to increase the likelihood of the survival of offshore drilling units during a hurricane. Implementation of new guidelines or regulations that may apply to our drilling units may subject us to increased costs and limit the operational capabilities of our drilling units.
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 technical services and 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.
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.

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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 US 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 US 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.
In addition, the United States in December 2017 enacted major tax reform legislation. This is likely to continue to have a material impact on the amount of overall U.S. tax expense of the Group due to reduced effective tax deductions for certain payments our U.S. operating companies make to non-U.S. rig owners and other Group and affiliated companies.
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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A change in laws and regulations in any country in which we operate could have a negative impact on our business
During 2017, the European Union Economic and Financial Affairs Council released a list of non-cooperative jurisdictions for tax purposes. The stated aim of the list, and accompanying report, was to promote good governance worldwide in order to maximize efforts to prevent tax fraud and tax evasion. Bermuda was not on the list of non-cooperative jurisdictions, but did feature in the report as having committed to address concerns relating to economic substance by December 31, 2018. In accordance with that commitment, Bermuda enacted the Economic Substance Act 2018 (the “ESA”) in December 2018. The ESA requires each registered entity to maintain a substantial economic presence in Bermuda and provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (i) it is directed and managed in Bermuda, (ii) its core income-generating activities (as may be further prescribed) are undertaken in Bermuda with respect to the relevant activity, (iii) it maintains adequate physical presence in Bermuda, (iv) it has adequate full time employees in Bermuda with suitable qualifications and (v) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity. A registered entity that carries on a relevant activity is obliged under the ESA to file a declaration with the Bermuda Registrar of Companies on an annual basis containing certain information. At present, the impact of the ESA is unclear and it is impossible to predict the nature and effect of these requirements on the Bermuda incorporated subsidiaries of the Company. We are currently evaluating the potential effect ESA will have on the Company's Bermuda subsidiaries.
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, or GHGs. 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 or the Paris Agreement, which resulted from the 2015 United Nations Framework Convention on Climate Change conference in Paris and entered into force on November 4, 2016. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted in July 2011 by the IMO’s Maritime Environment Protection Committee, or the MEPC, relating to greenhouse gas emissions. A roadmap for developing a "comprehensive IMO strategy on reduction of GHG emissions from ships" was also approved by MEPC at its 70th session in October 2016. In April 2018, as the first milestone in the roadmap, the MEPC adopted an "initial IMO strategy on reduction of GHG emissions from ships" which aims to reduce the total annual GHG emissions by at least 50% by 2050 compared to 2008, among other goals. The next milestone of the roadmap is adoption in 2023 of a revised strategy to reduce GHG emissions from ships. These and any future requirements could cause us to incur additional compliance costs.

In addition, the European Union has indicated that it may propose in the future an expansion of the existing European Union Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels. In April 2015, a regulation was adopted requiring that large ships (over 5,000 gross tons) calling at European Union ports from January 2018 collect and publish data on carbon dioxide emissions and other information. In the United States, the Environmental Protection Agency, or the EPA, has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from drilling units, the EPA has received petitions from the California Attorney General and various environmental groups seeking such regulation. In the United States, individual states can also enact environmental regulations. For example, California has introduced caps for greenhouse gas emissions and may take additional actions regarding climate change.

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 to succeed the Kyoto Protocol, or Paris agreement, 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. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and gas activities. 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.

Finally, most 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, hurricanes, and other climatic events, including in the Gulf of Mexico. If any such effects were to occur, they could have a significant financial and operational adverse impact on our business or cause us to incur significant costs in preparing or responding to those effects.

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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 and arbitration matters, and we anticipate that we will be involved in dispute matters from time to time in the future. The operating and other hazards inherent in our business expose us to disputes, including personal injury disputes, environmental and climate change litigation, contractual disputes with customers, intellectual property and patent disputes, tax or securities disputes, regulatory investigations and maritime lawsuits, including the possible arrest of our drilling units. We cannot predict, with certainty, the outcome or effect of any claim or other dispute matters, or a combination of these. If we are involved in any future disputes, 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.
We may also be subject to significant legal costs in defending these actions, which we may or may not be able to recoup depending on the results of such claim. For additional information on litigation matters that we are currently involved in, please see "Item 8 - "Financial Information - Consolidated Statements and Other Financial Information - Legal Proceedings."
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 - 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 our acquisitions in a timely and cost-effective manner, its financial condition, results of operations and cash available for distribution could be adversely affected.

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If we fail to comply with requirements relating to internal control over financial reporting our business could be harmed and our common unit price could decline.

Rules adopted by the Securities and Exchange Commission pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 require that we assess our internal control over financial reporting annually. The rules governing the standards that must be met for management to assess its internal control over financial reporting are complex. They require significant documentation, testing, and possible remediation of any significant deficiencies in and/or material weaknesses of internal controls in order to meet the detailed standards under these rules. Although we have evaluated our internal control over financial reporting as effective as of December 31, 2018, in future fiscal years, we may encounter unanticipated delays or problems in assessing our internal control over financial reporting as effective or in completing our assessments by the required dates. In addition, we cannot assure you that our independent registered public accountants will attest that internal control over financial reporting is effective in future fiscal years.

If we are unable to maintain effective internal controls over financial reporting and disclosure controls, investors may lose confidence in our reported financial information, which could lead to a decline in the price of common units, limit our ability to access the capital markets in the future, and require us to incur additional costs to improve our internal control over financial reporting and disclosure control systems and procedures. Further, if lenders lose confidence in the reliability of our financial statements, it could have a material adverse effect on our ability to fund our operations.
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.

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 9 - "The Offer and Listing - 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.

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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, and in February 2019, we reduced the quarterly distribution on our common units to one cent per common unit. 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".
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 February 28, 2019, 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".

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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;
•
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.

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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 February 28, 2019, Seadrill owned 46.6% of the outstanding common and subordinated units.
•
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.
In establishing cash reserves, the Board may reduce the amount of cash available for distribution to the unitholders.
OPCO's operating agreement provides 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.

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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:
•
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;
•
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
•
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.
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.

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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 February 28, 2019, 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.

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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 unpaid minimum quarterly distributions 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 to Item 8 - "Financial Information - 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 February 28, 2019, 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 and a breach of covenants contained in certain loan agreements.
Our common units are currently listed on the NYSE and are trading below $1.00 per unit. 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 continued decline in the closing price of our common units on the NYSE could result in a breach of additional requirements. Although we have an opportunity to take action to cure this 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 and breach of covenants contained in certain loan agreements, 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 10 - "Additional Information - 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 10 - "Additional Information - 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.









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Item 4.         Information on the Company

A.     History and Development of the Company
Company Details
Seadrill Partners LLC was formed under the Laws of the Republic of Marshall Islands on June 28, 2012 with registration number 962166. Seadrill Partners LLC is the parent company of the group of companies collectively known as Seadrill Partners.
Seadrill Partners LLC is a limited liability company and is listed under the Symbol "SDLP" on the New York Stock Exchange ("NYSE"). Its principal executive headquarters are maintained at 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom and its telephone number at that address is +44 20 8811 4700. Its 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.
Our website address is www.seadrillpartners.com. Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 20-F and should not be considered a part of this report or any other filing that we make with the U.S. Securities and Exchange Commission (“SEC”). We make available on this website free of charge, our annual reports on Form 20-F, quarterly reports on Form 6-K, and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. You may also find on our website information related to our corporate governance, board committees and company code of business conduct and ethics. The SEC also maintains a website, www.sec.gov, which contains reports, proxy statements and other information regarding SEC registrants, including us.
Significant developments for the period from January 1, 2017 through December 31, 2018
In this section we have set out important events in the development of our business. This includes information concerning the nature and results of any material reclassification, merger or consolidation of the company or any of its significant subsidiaries; acquisitions or dispositions of material assets other than in the ordinary course of business; any material changes in the mode of conducting the business; material changes in the types of products produced or services rendered; name changes; or the nature and results of any bankruptcy, receivership or similar proceedings with respect to the company or significant subsidiaries. This section covers the period from the beginning of our last full financial year.
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 (see below). We did not file any Chapter 11 cases.
Seadrill restructuring
In September 2017, our largest unitholder, Seadrill, entered into a restructuring agreement with its secured lenders, bondholders and a consortium of investors. To implement the restructuring agreement, Seadrill and certain of its subsidiaries (the "Debtors") filed prearranged Chapter 11 cases in the Southern District of Texas ("Bankruptcy Court") together with a restructuring plan. After a period of negotiation with their creditors the Debtors filed an amended plan of reorganization (the "Plan") which was confirmed by the Bankruptcy Court on April 17, 2018. The Plan became effective and the Debtors emerged from Chapter 11 Proceedings on July 2, 2018.
The Plan extinguished approximately $2.4 billion of Seadrill's unsecured bond obligations, more than $1.0 billion in contingent newbuild obligations, substantial guarantee obligations, and approximately $250 million in unsecured interest rate and currency swap claims. The Plan also extended near term debt maturities, provided Seadrill with over $1.0 billion in new capital and left employee, customer and ordinary trade claims largely unimpaired.
Term Loan B covenant waiver
In February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). Under this amendment our lenders agreed to waive a leverage covenant until maturity. In return we agreed to certain amendments including, but not limited to, a 3% increase in applicable margin, a par prepayment contingent on the successful outcome of certain ongoing litigation (see below), addition of the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 12 - "Debt" to the Consolidated Financial Statements included in this annual report for further details.
Litigation with Tullow for the West Leo
In October 2016, we received a notice of force majeure for the West Leo 's contract with Tullow in Ghana. We disputed that there had been an occurrence of force majeure and filed a claim in the English High Court ("High Court"). Tullow subsequently terminated the contract on December 31, 2018. We disputed Tullow's grounds for early termination and amended our claim.
The case was heard during May 2018 and on July 3, 2018 the English High Court ruled the case in our favor. We recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "Other revenues" per our Consolidated Statements of Operations. See Note 7 - "Other revenues" for further details. We received the recovered amounts on July 17, 2018, following which we made a prepayment of $121 million against our TLB under the terms of the amendment of that facility in February 2018 (see above).






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Drilling contracts
The below table shows the status of our drilling contracts at February 28, 2019.
Rig
Built
Status at December 31, 2018
Customer
Contractual operating rate per day ($'000)
Contracted until
Semi-submersible
 
 
 
West Sirius
2008
Stacked
-
-
-
West Aquarius
2009
Future Contracted
Exxon Mobil
$270.0
Dec 2019
West Capricorn
2011
Contracted
BP
$543.0
Jul 2019
West Leo
2012
Stacked
-
-
-
 
 
 
 
 
 
Drillship
 
 
 
 
 
West Capella
2008
Contracted
Future Contracted
Shell
Petronas
Not disclosed

Jun 2019
Nov 2019
West Polaris
2008
Stacked
-
-
-
West Auriga
2013
Contracted
BP
$575.0
Oct 2020
West Vela
2013
Contracted
BP
$574.7
Nov 2020
 
 
 
 
 
 
Tender Rig
 
 
 
 
 
West Vencedor
2009
Contracted
Future Contracted
Petronas
Not disclosed
Not disclosed
$110.0
May 2019
Feb 2020
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. We received termination payments over the remaining contract term, which expired in July 2017. The rig is currently cold stacked.
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 had a further period of idle time but subsequently worked from April to December 2018 with BP in Canada. The rig is currently warm stacked and has secured work with Exxon Mobil which we expect to start in May 2019.
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. The unit has been on normal contractual day rates since 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 disputed the grounds for termination and were successful in litigation proceedings (see below). The unit is currently cold stacked.
The West Capella was on contract with ExxonMobil in Nigeria until May 2016, when it received a notice of termination. We received a termination fee of approximately $125 million plus other direct costs incurred because of the termination. The rig was idle until March 2017 when it began work on a series of short term contracts. The rig is currently under contract with Shell in Malaysia and has future work in December 2019 with Petronas, also in Malaysia.
The West Polaris was on contact with ExxonMobil in Angola until December 2017, when the rig completed its operations and demobilized. The rig is currently warm 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 was stacked for most of 2018 since it finished its most recent contract in Indonesia in January 2018. The rig started a new contract with Petronas in Myanmar in January 2019 and has secured further work with CNR in Ivory Coast.
The T-15 and T-16 have been on contract with Chevron in Thailand since July 2013 and August 2013 respectively.
Capital Expenditures
Capital expenditures were approximately $115.0 million, $121.6 million and $61.1 million in the years ended 2018, 2017 and 2016 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.


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    B.     Business Overview
Introduction
We are an offshore drilling contractor providing offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships, semi-submersible rigs and tender rigs for operations in shallow to ultra-deepwater areas in both benign and harsh environments.
We contract our drilling units primarily on a dayrate basis to drill wells for our customers, typically oil super-majors and major integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies. We are recognized for providing high quality operations, in some of the most challenging sectors of offshore drilling.
Our Fleet
Our fleet is one of the youngest, most modern of all the major offshore drilling contractors with an average fleet age of approximately 7.7 years. We currently own and operate a fleet of 11 drilling units, including 4 drillships, 4 semi-submersible rigs and 3 tender rigs. You may find additional information on our drilling units and newbuildings in Item 4 - "Information on the Company - Property, Plant and Equipment".
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.
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.
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.

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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
In 2017 and 2018, we 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 Flows. 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 have 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.
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 under take 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 2018, our largest customer was BP which accounted for 68.0% of our revenues. Revenue recognized following the favorable outcome of our litigation with Tullow accounted for 19.8% of our revenues.
Contract Backlog
Our contract backlog as of February 28, 2019 totals $0.9 billion.
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.

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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 February 28, 2019 is as follows:
Rig
Contracted
Location
Customer
Contractual
Dayrate
(US $)
Contract
Backlog(1)
(US $ 
millions)
Contract
Start
Contract End
Semi-submersible
 
 
 
 
 
 
West Sirius
Stacked
-
-
-
-
-
West Aquarius
Canada
Exxon Mobil
$270,000
$61.3
May 2019
Dec 2019
West Capricorn
USA
BP
$543,000
$80.4
Jul 2017
Jul 2019
West Leo
Stacked
-
-
-
-
-
 
 
 
 
 
 
 
Drillship
 
 
 
 
 
 
West Capella
Malaysia
Shell
Petronas
Undisclosed
$23.4
Nov 2018
Sep 2019
Jun 2019
Nov 2019
West Polaris
Stacked
-
-
-
-
-
West Auriga
USA
BP
$575,000
$351.3
Oct 2013
Oct 2020
West Vela
USA
BP
$534,000
$343.4
Nov 2013
Nov 2020
 
 
 
 
 
 
 
Tender Rig
 
 
 
 
 
 
West Vencedor
Myanmar
Ivory Coast
Petronas Undisclosed
Undisclosed $110,000
$26.4
Jan 2019
Sep 2019
May 2019
Feb 2020
T-15
Thailand
Chevron
$110,000
$14.5
Jul 2013
Jul 2019
T-16
Thailand
Chevron
$110,000
$18.4
Aug 2013
Aug 2019
(1) Expressed in millions. Based on executed drilling contracts.
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.

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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".
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, or seriously damage or destroy the equipment involved. Offshore drilling contractors are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our rig insurance package policy provides insurance coverage for physical damage to our rigs, loss of hire for our working rigs and third-party liability.
i. 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.
ii. 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 (floaters and semi-tenders), 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 up to 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.
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 loss of revenue in such period. We do not purchase loss of hire insurance on the T-15 and T-16.
iii. Protection and Indemnity Insurance
Seadrill purchases Protection and Indemnity insurance (P&I) 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 $500 million per event and in the aggregate and up to $900 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 $0 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 $900 million to $500 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.
iv. 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 our policy to insure a limited part of this windstorm risk for a further period starting May 1, 2019 through April 30, 2020.

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".

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Flag State Requirements
All our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. The flag state requirements are international maritime requirements and, in some cases, further interpolated by the flag state itself. These include engineering, safety and other requirements related to the maritime industry. 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. In addition, for some of the internationally-required class certifications, such as the Code for the Construction and Equipment of Mobile Offshore Drilling Units (the "MODU Code") certificate, the classification society will act on a flag state's behalf.
International Maritime Regimes
Applicable international maritime regime requirements 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), (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 (the "ISM Code,") MODU Code, 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."
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, 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, but this was subject to a feasibility review.
At MEPC 73 in October 2018, it was confirmed that there will be no change to the 1 January 2020 0.50% SOx limit and a ban was adopted on the carriage of fuel with sulphur content above the limit for ships without an approved alternative means, such as a scrubber. This will enter into force on 1 Mar 2020, because this is the earliest possible date for a MARPOL amendment to enter into force - it does not change the underlying 1 Jan 2020 limit change. There are related IMO regulations concerning the discharge of scrubber washwater, but some coastal states and ports have implemented local regulations with more stringent requirements that restrict, or completely prohibit, the discharge of washwater from open loop scrubbers or prohibit the use of scrubbers. This is an issue in several European countries, California, Hawaii & Connecticut in USA, UAE, India, Singapore and China.  Annex VI also requires tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation. All our rigs are in compliance with these requirements. Other amendments to Annex VI contain mandatory recordkeeping and reporting requirements that require ships of 5,000 gross tonnage and above to collect fuel consumption data beginning January 1, 2019. Tier III engines are already required in the North American and US Caribbean ECAs, and vessels built after 1 January 2021 will require such engines to enter the North Sea and Baltic ECA. As part of IMO data gathering related to Green House Gas (GHG) emissions, Annex VI also requires data collection for fuel oil consumption and reporting of this to the flag state. 
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. All Seadrill units considered in operational status are in full compliance with the staged implementation of the BWM Convention by International Maritime Organization guidelines.
Environmental Laws and Regulations
Applicable environmental laws and regulations include the U.S. Oil Pollution Act of 1990, ("OPA"), the Comprehensive Environmental Response, Compensation and Liability Act, ("CERCLA"), the U.S. Clean Water Act, ("CWA"), the U.S. Clean Air Act, ("CAA"), the U.S. Outer Continental Shelf Lands Act ("OCSLA"), the U.S. Maritime Transportation Security Act of 2002, ("MTSA"), European Union regulations, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations, and the laws and regulations of other countries in which we operate. 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 us liable for environmental and natural resource damages without regard to negligence or fault on our 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".

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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 our industry following the 2010 Deepwater Horizon incident, in which we were not involved, that led to the Macondo well blow out situation. Other countries are also undertaking a review of their safety regulations related to our 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 May 2018, BSEE issued a proposal 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 nonperformance of such obligations. In addition, in March 2018, BSEE announced the implementation of a new 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.



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C.     Organizational Structure
A simplified organizational structure as of February 28, 2019 is shown below.
untitled3.gif
Seadrill owns 34.9% of the common units of Seadrill Partners LLC and 100% of the subordinated units of Seadrill Partners LLC, and owns and controls the Seadrill Member.
A full list of the Company's significant operating and rig-owning subsidiaries is included in Exhibit 8.1.


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D.     Property, Plant and Equipment
Other than our fleet of drilling units, we do not have any material property. The following table provides additional information about our fleet as of February 28, 2019:
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.

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 US 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" to the Consolidated Financial Statements included in this annual report.
Our Drilling Contracts
Please read Item 4 - "Information on the Company - History and Development of the Company" for a summary of the current status of our rigs and 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.
•
Our ability to maintain good relationships with our existing customers and to increase the number of customer relationships.
•
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.
•
Changes in Seadrill Partners LLC's ownership of OPCO.
•
Fluctuations in the price of oil and gas, which influence the demand for offshore drilling services.
•
The effective and efficient technical management of our drilling units.
•
Our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards.
•
Economic, regulatory, political and governmental conditions that affect the offshore drilling industry.
•
Accidents, natural disasters, adverse weather, equipment failure or other events outside of our control that may result in downtime.
•
The financial condition of Seadrill 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.
•
Foreign currency exchange gains and losses.
•
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.

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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 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.
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.
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.
Other Operating Items
Other operating items include impairments of goodwill, revaluation of contingent consideration and gains or losses on sale of assets.
•
Impairments of goodwill arise where the fair value of a reporting unit that has goodwill recognized against it decreases below its carrying value.
•
Revaluation of contingent consideration occurs where there are changes in the estimated fair value of deferred consideration liabilities. These estimates may increase or decrease as new market information becomes available.
•
Gains or losses on sale of assets occur where proceeds received from an asset sale are higher or lower than the carrying value of the asset.
Financial Items
Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments, and foreign exchange gain/loss.
•
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 tax 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.

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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 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.
In the year ended December 31, 2018, 2017 and 2016, impairment indicators were identified due to the reduction in 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, 2018, 2017 and 2016.
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 losses carried forward. 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 3 - "Recent accounting standards" to the Consolidated Financial Statements included in this annual report.


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A.     Operating Results
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
The following table summarizes our operating results for the years ended December 31, 2018 and 2017:
 
Year Ended December 31,
 
Increase/(Decrease)
 
2018
 
2017
 
$
 
%
 (US$ in millions)
 
 
 
 
 
Operating revenues:
 
 
 
 
 
 
 
Contract revenues
$
797.5

 
$
1,007.7

 
$
(210.2
)
 
(20.9
)%
Reimbursable revenues
31.2

 
17.7

 
13.5

 
76.3
 %
Other revenues
209.5

 
103.0

 
106.5

 
103.4
 %
Total operating revenues
1,038.2

 
1,128.4

 
(90.2
)
 
(8.0
)%
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Vessel and rig operating expenses
(278.2
)
 
(345.4
)
 
67.2

 
19.5
 %
Amortization of favorable contracts
(45.1
)
 
(74.4
)
 
29.3

 
39.4
 %
Reimbursable expenses
(28.6
)
 
(16.1
)
 
(12.5
)
 
(77.6
)%
Depreciation and amortization
(280.3
)
 
(274.9
)
 
(5.4
)
 
(2.0
)%
General and administrative expenses
(45.8
)
 
(44.8
)
 
(1.0
)
 
(2.2
)%
Total operating expenses
(678.0
)
 
(755.6
)
 
77.6

 
10.3
 %
 
 
 
 
 
 
 
 
Other operating items:
 
 
 
 
 
 
 
Revaluation of contingent consideration
—

 
89.9

 
(89.9
)
 
(100.0
)%
Loss on impairment of goodwill
(3.2
)
 
—

 
(3.2
)
 
—
 %
Gain on sale of assets
—

 
0.8

 
(0.8
)
 
(100.0
)%
Total other operating (loss)/income
(3.2
)
 
90.7

 
(93.9
)
 
(103.5
)%
 
 
 
 
 
 
 
 
Operating income
$
357.0

 
$
463.5

 
$
(106.5
)
 
(23.0
)%
 
 
 
 
 
 
 
 
Financial items:
 
 
 
 
 
 
 
Interest income
47.1

 
15.7

 
31.4

 
200.0
 %
Interest expense
(263.7
)
 
(179.1
)
 
(84.6
)
 
(47.2
)%
Gain/(Loss) on derivative financial instruments
24.9

 
(13.9
)
 
38.8

 
279.1
 %
Currency exchange gain
0.2

 
0.9

 
(0.7
)
 
(77.8
)%
Other financial items
(4.8
)
 
(11.5
)
 
6.7

 
58.3
 %
Total financial items
(196.3
)
 
(187.9
)
 
(8.4
)
 
(4.5
)%
 
 
 
 
 
 
 
 
Income before income taxes
160.7

 
275.6

 
(114.9
)
 
(41.7
)%
 
 
 
 
 
 
 
 
Income tax expense
(86.7
)
 
(40.3
)
 
(46.4
)
 
(115.1
)%
 
 
 
 
 
 
 
 
Net Income
$
74.0

 
$
235.3

 
$
(161.3
)
 
(68.6
)%
 
 
 
 
 
 
 
 
Net income attributable to the non-controlling interest
$
17.9

 
$
94.1

 
$
(76.2
)
 
(81.0
)%
Net income attributable to Seadrill Partners LLC
$
56.1

 
$
141.2

 
$
(85.1
)
 
(60.3
)%
Contract revenues
Contract revenues were $797.5 million for the year ended December 31, 2018 (December 31, 2017: $1,007.7 million).
The $210.2 million or 20.9% decrease, was primarily due to idle time on the West Polaris ($207 million) and the West Vencedor ($31 million), new contacts at lower dayrates for the West Aquarius ($12 million), and downtime on the West Auriga and West Vela related to five year classing surveys ($12 million).
These were partially offset by the West Capricorn returning to full operating rate for a full year in 2018 after being on extended standby rate for part of the year in 2017 ($51 million) and additional days in operation for the West Capella ($3 million).

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Table of Contents

The following table summarizes our fleet's average daily contract revenues and economic utilization percentage by drilling unit type for the periods presented:
 
Year Ended December 31,
 
2018
 
2017
 
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
2
 
$
462,658

 
99.8
%
 
2
 
$
459,164

 
97.3
%
Drillship
3
 
$
472,076

 
92.7
%
 
4
 
$
521,487

 
98.6
%
Tender rigs
2
 
$
119,943

 
98.6
%
 
3
 
$
122,054

 
98.2
%
(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.
Reimbursable revenues
Reimbursable revenues were $31.2 million for the year ended December 31, 2018 (December 31, 2017: $17.7 million). The increase of $13.5 million or 76.3%, was due to more equipment purchased on behalf of customers, for which we have been reimbursed.
Other revenues
Other revenues were $209.5 million for the year ended December 31, 2018 (December 31, 2017: $103.0 million).
The $106.5 million or 103.4% increase was primarily due to the West Leo litigation judgment in our favor ($205 million). Please refer to Note 17 - "Commitments and contingencies" for further information.
This was partially offset by the reduction in early termination revenue for the West Capella ($35 million) and West Sirius ($61 million) which concluded in April 2017 and July 2017, respectively.
Vessel and rig operating expenses
Vessel and rig operating expenses were $278.2 million in the year ended December 31, 2018 (December 31, 2017: $345.4 million).
The $67.2 million or 19.5% decrease was primarily due to idle time on the West Polaris ($41 million) and the West Vencedor ($6 million), lower costs on the West Aquarius due to mobilization costs in 2017 not being repeated in 2018($10 million) and lower costs on the West Leo ($10 million) as it moved from warm stack to cold stack during the year.
Amortization of favorable contracts
Amortization of favorable contracts was $45.1 million for the year ended December 31, 2018 (December 31, 2017: $74.4 million). The $29.3 million or 39.4% decrease was related to the West Polaris completing its contract with ExxonMobil in 2017.
Reimbursable expenses
Reimbursable expenses were $28.6 million for the year ended December 31, 2018 (December 31, 2017: $16.1 million). The $12.5 million or 77.6% increase is in line with the reduction in reimbursable revenue.
Depreciation and amortization
Depreciation and amortization expenses were $280.3 million for the year ended December 31, 2018 (December 31, 2017: $274.9 million). The $5.4 million or 2.0% increase was primarily due to a full year of depreciation for costs capitalized on the West Capella related to reactivation and installation of a managed pressure drilling ("MPD") system in 2017.
General and administrative expenses
General and administrative expenses were $45.8 million for the year ended December 31, 2018 (December 31, 2017: $44.8 million).
Revaluation of contingent consideration
The $89.9 million gain in the year ended December 31, 2017 was the result of a reduction in contingent liabilities related to the purchase of the West Polaris in 2015. This gain was due to reductions in future dayrate estimates and re-contracting assumptions, resulting in a decrease in the fair value of the liabilities. No gain was recorded in the year ended December 31, 2018.
Loss on impairment of goodwill
During the year ended December 31, 2018, we recognized a loss on impairment of goodwill of $3.2 million following early adoption of ASU 2017-04, Intangibles. For further information refer to Note 3 - "Recent Accounting Standards".

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Table of Contents

Interest income
Interest income was $47.1 million for the year ended December 31, 2018 (December 31, 2017: $15.7 million). The $31.4 million or 200.0% increase was primarily due to interest related to the West Leo litigation judgment ($24 million). Please refer to Note 17 - "Commitments and contingencies" for further information. The residual increase was due to higher interest rates.
Interest expense
Interest expense was $263.7 million for the year ended December 31, 2018 (December 31, 2017: $179.1 million). The $84.6 million or 47.2% increase was due to an increase in margin on the Term Loan B related to the amendments completed in February 2018 ($99 million) and an increase in LIBOR. Please see Note 12 - "Debt" for further information on the covenant waiver. This was partially offset by a decrease in the unwind of discount recorded against contingent liabilities for the West Polaris following the settlement of these liabilities in 2018 ($9 million) and lower interest on the West Vencedor facility as the loan matured in 2018 ($4 million).
Gain / (Loss) on derivative financial instruments
Derivative financial items resulted in a gain of $24.9 million for the year ended December 31, 2018 (December 31, 2017: loss of $13.9 million). The $38.8 million change was due to an increase in forward interest rates since 2017.
Currency exchange gain
Gain on foreign currency exchange was $0.2 million for the year ended December 31, 2018 (December 31, 2017: gains of $0.9 million). The gain is broadly in line with the prior year and predominantly related to foreign currency denominated transactions in Asia.
Other financial items
Other financial items were an expense of $4.8 million for the year ended December 31, 2018 (December 31, 2017: $11.5 million expense). The decrease was due to debt issue costs relating to the amendments on our bank facilities in August 2017 not repeating in 2018. This was partially offset by fees incurred related to the amendments to the Term Loan B in the year ended December 31, 2018.
Income taxes
Income tax expense was $86.7 million for the year ended December 31, 2018 (December 31, 2017: $40.3 million) and our effective income tax rate was 54.0% and 14.6% for the years ended December 31, 2018 and 2017 respectively. The increase primarily relates to an uncertain tax position recorded in the year ended December 31, 2018 in respect of recent changes in US tax legislation. Please refer to Note 6 - "Taxation" for further information.


42
Table of Contents

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:
(US$ in millions)
Year Ended December 31,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
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
)%
 
 
 
 
 
 
 
 
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
 %
 
 
 
 
 
 
 
 
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 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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Table of Contents

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,
 
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, for 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.
Depreciation and amortization
Depreciation and amortization was $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.

44
Table of Contents

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 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 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: $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: gains of $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 6 - "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, 2018, 2017 and 2016
•
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 and contract and other revenues. As of December 31, 2018, we had cash and cash equivalents of $841.6 million, compared to $848.6 million as of December 31, 2017.

45
Table of Contents

Short-term outlook and going concern assessment
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.
In our form 20-F covering our annual report for the fiscal year ended December 31, 2017, issued on April 12, 2018, we reported that the combination of (i) our operational dependence on Seadrill because of the management, administrative and technical support services provided to us by Seadrill and (ii) uncertainties over Seadrill's ability to continue as a going concern linked to its Chapter 11 Re-organization, gave rise to a substantial doubt over our ability to continue as a going concern for a period of at least twelve months after the date the financial statements were issued.
Seadrill completed its plan of reorganization and emerged from bankruptcy proceedings on July 2, 2018. Therefore, the above uncertainty has been mitigated and there is no longer a substantial doubt over our ability to continue as a going concern for at least the twelve months after the date the financial statements are issued.
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 that our quarterly distributions would not exceed 10 cents per common unit unless the Consolidated net leverage ratio is below 4x during 2018 and below 5x thereafter. Please read Note 12 - "Debt" to the Consolidated Financial Statements 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 $217 million per year, which is comprised of $75 million for long term maintenance and society classification surveys and $142 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, 2018, 2017 and 2016
The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the periods presented:
(US$ in millions)
Year Ended December 31,
 
2018
 
2017
 
2016
Net cash provided by operating activities
$
434.1

 
$
476.2

 
$
873.8

Net cash (used in) / provided by investing activities
(23.4
)
 
(11.1
)
 
97.6

Net cash used in financing activities
(416.7
)
 
(384.9
)
 
(522.1
)
Effect of exchange rate changes on cash
(1.0
)
 
0.8

 
(0.7
)
Net (decrease) / increase in cash and cash equivalents
(7.0
)
 
81.0

 
448.6

Cash and cash equivalents at beginning of period
848.6

 
767.6

 
319.0

Cash and cash equivalents at end of period
841.6

 
848.6

 
767.6

Net Cash Provided by Operating Activities
Net cash provided by operating activities was $434.1 million and $476.2 million for the year ended December 31, 2018 and December 31, 2017 respectively. The decrease of $42.1 million was primarily due to lower net income, which decreased by $112 million after adding back non-cash items. The residual decrease was due to increased long term maintenance expenditures primarily incurred on five-year surveys for the West Vela, West Auriga and West Polaris ($37 million), offset by a favorable change in working capital ($107 million) primarily driven by collections on receivables for the West Polaris and West Leo.
Net cash provided by operating activities was $476.2 million and $873.8 million for the years 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 (Used in) / Provided by Investing Activities
Net cash used in investing activities was $23.4 million for the year ended December 31, 2018. This was due to capital expenditure on drilling unit upgrades of $23 million. Capital expenditures for drilling unit upgrades in 2018 were primarily for managed pressure drilling system for the West Capricorn and upgrades to the blow out preventer for the West Auriga and West Aquarius.
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 Financing Activities
Net cash used in financing activities was $416.7 million for the year ended December 31, 2018. This was due to external debt repayments of $296 million, related party debt repayments of $25 million, payments of deferred and contingent consideration of $34 million, repayment of shareholder loan of $6 million and cash distributions of $55 million.
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 in 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 Increase in Cash and Cash Equivalents
As a result of the above, cash and cash equivalents decreased in 2018 by $7 million, increased in 2017 by $81 million, and increased in 2016 by $448.6 million.

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Borrowing Activities
The below table summarizes the status of our borrowing facilities at December 31, 2018 and December 31, 2017.
Facility
Collateral Vessels
Maturity
Principal outstanding at Dec 31, 2018 ($millions)

Principal outstanding at Dec 31, 2017 ($millions)

Debt repayments in 2018 ($millions)

Debt repayments in 2017             ($millions)

External facilities
 
 
 
 
Term loan B
See below (1)
Feb-2021
2,636.4

2,786.9

150.5

29.0

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

50.0

—

—

West Vela facility
West Vela
Oct-2020
191.3

255.3

64.0

86.9

West Polaris
West Polaris
Jul-2020
150.8

205.6

54.8

73.4

Tender Rig facility (2)
T-15 & T-16
Jun-2020
56.2

83.3

27.1

25.7

 
 
 
3,084.7

3,381.1

296.4

215.0

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

—

—

10.1

West Vencedor facility
West Vencedor
Jun-2018
—

24.7

24.7

16.5

West Sirius loan
None
Apr-2017
—

—

—

39.4

 
 
 
—

24.7

24.7

66.0

 
 
 
 
 
 
 
Total
 
 
3,084.7

3,405.8

321.1

281.0

(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, West Auriga and West Vencedor.
(2) The Tender Rig facility was classified as a related party debt facility until the facility was amended in August 2017.
Key changes to borrowing facilities from January 1, 2017 to December 31, 2018
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.
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"). Under this amendment our lenders agreed to waive a leverage covenant until maturity. In return we agreed to certain amendments including, but not limited to, a 3% increase in applicable margin, a par prepayment contingent on the successful outcome of certain ongoing litigation (see below), addition of the West Vencedor as collateral and certain amendments relating to cash movements outside the TLB collateral group. Please read Note 12 - "Debt" to the Consolidated Financial Statements included in this annual report for further details.

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Debt repayments by year
The outstanding debt as of December 31, 2018 is repayable as follows: 
(In US$ millions)
December 31, 2018

2019
$
175.1

2020
331.1

2021
2,578.5

2022
—

Total external and related party debt
$
3,084.7

Debt issuance costs
In our Consolidated Balance Sheets we present debt balances net of debt issuance costs. This is set out in the below table:
 
 
Outstanding debt as of December 31, 2018
(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
 
2,909.6

(13.4
)
2,896.2

Total external debt
 
$
3,084.7

$
(25.6
)
$
3,059.1

Current portion of long term related party debt
 
$
—

$
—

$
—

Total interest bearing debt
 
$
3,084.7

$
(25.6
)
$
3,059.1

 
 
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

Further information
Please refer to Note 12 - "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 report on Form 20-F. Please refer to Item 19 - "Exhibits".
We were not in breach of applicable covenants as of December 31, 2018. Please read Note 12 - "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.
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 "Gain/(loss) on derivative financial instruments" in the Consolidated Statement of Operations.
Total realized and unrealized gains on interest-rate swap agreements amounted to $24.9 million for the year ended December 31, 2018 (December 31, 2017: losses of $13.9 million).
As of December 31, 2018, our interest rate swap contracts had a combined outstanding principal amount of $2,764.9 million (December 31, 2017: $2,793.9 million), swapping LIBOR for an average fixed rate of 2.49% per annum.
As of December 31, 2018, our net exposure to short term fluctuations in interest rates on our outstanding debt was $319.8 million (December 31, 2017: $611.9 million), based on total net interest bearing debt of $3,084.7 million (December 31, 2017: $3,405.8 million), including related party debt agreements, less the $2,764.9 million (December 31, 2017: $2,793.9 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.
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.

D.     Trend Information
The below table show the average oil price over the period 2014 to 2018. The Brent oil price at February 28, 2019 was $66.
 
2014
2015
2016
2017
2018
Average Brent oil price
$99
$54
$45
$55
$71
We have seen an improvement in the oil and gas market over 2018 with Brent oil prices remaining above $60 per barrel for most of the year. This favorable development in oil prices, combined with efficiencies across the industry, has led to improved economics for our customers. This has in turn led to increased tendering activity and a positive trend in dayrates. We expect these trends to continue in 2019 as our customers continue to increase their levels of investment.

The below table shows the global number of rigs on contract and marketed utilization at December 31, 2018 and for each of the four preceding years.

 
 
2014

 
2015

 
2016

 
2017

 
2018

 
Contracted rigs
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
48

 
45

 
35

 
30

 
31

 
Benign environment floater
 
232

 
196

 
139

 
120

 
116

 
Tender
 
24

 
22

 
20

 
16

 
14

 
Marketed utilization
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
99
%
 
93
%
 
81
%
 
83
%
 
85
%
 
Benign environment floater
 
93
%
 
83
%
 
71
%
 
71
%
 
73
%
 
Tender
 
73
%
 
66
%
 
66
%
 
60
%
 
62
%
 

Activity has remained subdued over 2018 in the floater market. The harsh environment has higher marketed utilization, continuing to trend ahead of benign environment. There is high demand for high specification harsh environment units relative to their supply, which has led to increased dayrates and higher utilization within this segment. There is still an excess supply of benign environment units which has delayed the recovery in this market. The tender market remains relatively subdued.

Floaters - outlook

Based on the current level of activity, age of the floater fleet and level of consolidation in the industry, we expect scrapping activity to continue. A total of 119 floaters have been scrapped or retired since the beginning of 2014, equivalent to 38% of the total fleet, and currently there are 22 cold or warm stacked units that are 30 years old or older, with no follow-on work identified which are prime scrapping candidates. In the next 18 months, a further 17 units that are 30 years old or older will become available unless they win new work. These units represent 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.

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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.

Marketed utilization is 75% across benign and harsh environment floaters. The global floater order includes approximately 42 units, comprised of 28 drillships and 14 semi-submersible rigs. 22 units are scheduled for delivery in 2019, 11 in 2020 and 9 in 2021 and beyond.

Tender rigs - outlook
As of December 31, 2018, marketed utilization is 62%. Overall, the global fleet is 10 years old on average. The order book includes approximately 6 units. 2 are scheduled for delivery in 2019 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, 2018 or 2017, 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, 2018, we had not been required to make collateral deposits with respect to these agreements.
The maximum potential future payments are summarized in Note 17 - "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, 2018:
 
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 (1)
$
3,084.7

 
$
175.1

 
$
2,909.6

 
$
—

 
$
—

Deferred consideration payable (2)
59.0

 
37.5

 
21.5

 
—

 
—

Total
$
3,143.7

 
$
212.6

 
$
2,931.1

 
$
—

 
$
—

(1) 
Debt principal repayments, excluding interest on debt.
(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 14 - "Related Party Transactions" to the Consolidated Financial Statements included in this annual report.
In addition to the above, we have recognized liabilities for uncertain tax positions including interest and penalties of $118 million at December 31, 2018.
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
Position
Bert Bekker
Director and Audit Committee Member
Andrew Cumming
Director and Conflicts Committee Member
John Darlington
Director and Audit Committee Member
Keith MacDonald
Director, Audit Committee Member and Conflicts Committee Member
Harald Thorstein
Director and Chairman
Certain biographical information about each of our directors and executive officers is set forth below.
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.
Andrew Cumming was originally appointed by the remaining elected directors 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 seven 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 of a mortgage company, Bluestone Holdings Group, and a private equity company, Lloyds Development Capital.
John Darlington was appointed to the Board by the Seadrill Member and has served as a director of the Company since December 2018, and serves on the Company's audit committee. Mr. Darlington's previous experience includes serving as a Partner of KPMG from 2006 to 2013. He was Executive Chairman of Linpac Group Holdings Ltd. (2010-2012), a multinational packaging group, and Executive Chairman of Sunseeker International Ltd. (2009-2010), the luxury yacht manufacturer. He has significance experience of stakeholder management, public relations and acquisitions and disposals.
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.
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.







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Executive Officers
The Company currently does not employ any of its executive officers. It 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. The individuals 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
Position
Mark Morris
Chief Executive Officer
John T. Roche
Chief Financial Officer
Mark Morris serves as the Chief Financial Officer of Seadrill Management and as the Company’s Principal Financial Officer and Principal Accounting Officer. Mr. Morris was appointed Chief Financial Officer of the Group in September 2015. Prior to joining Seadrill, Mr. Morris was the chief financial officer for Rolls-Royce Group plc as well as serving as a director on its main board and held several roles in his 28 years with the company. During his career at Rolls-Royce, amongst other roles, Mr. Morris served as group treasurer, ran Rolls-Royce Capital, its aircraft and engine leasing division and was treasurer of IAE International Aero Engines AG, a Rolls-Royce joint venture based in the USA. Mr. Morris also serves as the Chief Executive Officer of Seadrill Partners, a position he has held since September 2015.  He is a graduate of the University of Manchester where he received a Bachelor’s degree in Aeronautical Engineering, is a member of the Association of Corporate Treasurers (ACT) Advisory Panel and an Honorary Fellow of the ACT.
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, 2018, we were charged $0.4 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
One of our Directors, John Darlington, and two of our former Directors, Graham Robjohns and Kate Blankenship, were appointed to the Board by Seadrill. We pay Seadrill appointed Directors for their service as Directors, and we reimburse out-of-pocket expenses incurred attending meetings of the Board or its committees.
For the year-ended December 31, 2018, Seadrill appointed Directors 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, 2018, the Directors elected by common unitholders received aggregate compensation for services of $0.4 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.
Our current Board consists of five members: Bert Bekker, Andrew Cumming, John Darlington, Keith MacDonald and Harald Thorstein. The Board has determined that each of Mr. Darlington, Mr. Bekker, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by NYSE and Rule 10A-3 of the Exchange Act. Mr. Darlington was appointed by Seadrill in its sole discretion and will serve as a director for a term 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 2021. 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, Mr. Bekker, Mr. Darlington and Mr. MacDonald. Mr. Darlington 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, Mr. Darlington and Mr. MacDonald.
Management of OPCO
Our wholly owned subsidiary, Seadrill Operating GP LLC is the general partner of Seadrill Operating LP. 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 officers of Seadrill Partners also serve as directors 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."

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, 2018, approximately 1,121 offshore staff served on our offshore drilling units and approximately 17 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".

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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 February 28, 2019:
 
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 Partners LLC Holdco Limited (1)
26,275,750

 
34.9
%
 
16,543,350

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

 
—
%
 
—

 
—
%
 
—

John Roche (Chief Financial Officer)
—

 
—
%
 
—

 
—
%
 
—

Bert Bekker (Director)
—

 
—
%
 
—

 
—
%
 
—
%
Andrew Cumming (Director)
—

 
—
%
 
—

 
—
%
 
—
%
John Darlington (Director)
—

 
—
%
 
—

 
—
%
 
—
%
Keith MacDonald (Director)
*

 
*

 
—

 
—
%
 
*

Harald Thorstein (Director)
—

 
—
%
 
—

 
—
%
 
—
%
All directors and executive officers as a group (7 persons)
*

 
*

 
—

 
—
%
 
*

 * Less than 1%.
(1)
Seadrill Partners LLC Holdco Limited is an intermediate holding company which is ultimately owned by Seadrill Limited. 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 27,857,045 shares, or 27.9%, 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, 2018, 2017, and 2016 are presented in Note 14 - "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 non-competition provisions of the Omnibus Agreement will terminate immediately. Upon a change of control of Seadrill, the non-competition 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 counter-party 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.
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.
Please see Note 14 - "Related Party Transactions" of the Consolidated Financial Statements included within this report for other significant related party arrangements with Seadrill.

C.     Interests of Experts and Counsel
Not applicable.


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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.

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, 2018.
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 did not accept that the contract had been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract had been discharged by frustration.  Accordingly, we amended our claim in the English High Court to reflect this.
On July 3, 2018 the English High Court ruled the case in our favor and we recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "Other revenues" per our Consolidated Statements of Operations. See Note 7 - "Other revenues" for further details.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit ("the Suit") against certain of our subsidiaries for patent infringement. The Suit alleged that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity. 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. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.  

In December 2018, we reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean for the dual activity drilling method on our rigs covering alleged past infringements and future use.
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.
Please also see Note 17 - "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.

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•
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 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 February 28, 2019, 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 unpaid common unit minimum quarterly distributions 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.

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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 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.
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 was 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 20 - "Subsequent Events" thereto.

Item 9.         The Offer and Listing

A.     Offer and Listing Details
Seadrill Partners LLC is a limited liability company and is listed under the trading symbol of "SDLP" on the New York Stock Exchange ("NYSE").  
B.     Plan of distribution
Not applicable.


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C.     Markets
The Company's common units currently trade on the New York Stock Exchange under the trading 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.

C.     Material Contracts
Attached as exhibits to this annual report are the contracts we consider to be both material and not in the ordinary course of business. Other than these contracts, we have no material contracts other than those entered in the ordinary course of business. 

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
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.

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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 made in 2017. The most notable immediate impact on the group was a reduction of the U.S. corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017 so we recalculated our deferred tax assets and liabilities to reflect the reduction in the U.S. corporate income tax rate which 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. The 2017 Tax Act made changes effective 2018, including a base erosion and anti‑abuse tax (“BEAT”), limitations on the deductibility of interest and repeal of the domestic manufacturing deduction. We continue to further evaluate the interpretation of the US tax code and its effect on future periods on US subsidiaries of the Company. It appears that there are some unintended consequences of the 2017 Tax Act that affect the US subsidiaries of the Company. We understand that the US Department of Treasury is aware of this issue and that it could potentially be remediated with additional guidance in the future. However, in the meanwhile, the Company is considering its approach for future filings which may result in a mitigation of a portion of the liability that has been recorded.  
See Note 6 - "Taxation" for further details of the impact for 2018.
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".
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.

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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.

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, 2018. 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 2018 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 2018 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 2018 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 March 28, 2019, 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.
 

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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.
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, 2018, we had interest rate swaps for a combined outstanding principal amount of $2,764.9 million, (December 31, 2017: $2,793.9 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, 2018 was an asset of $9.9 million (December 31, 2017: liability of $29 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 asset or liability within other current assets or 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 "Gain/(loss) on derivative financial instruments".
The total realized and unrealized gain recognized under "Gain/(loss) on derivative financial instruments" in the Consolidated Statement of Operations relating to interest rate swap agreements for 2018 was 24.9 million (2017: loss of 13.9 million, 2016: loss of 18.0 million). Included 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, 2018, were as follows:
Maturity date
Outstanding principal as of December 31, 2018
Receive rate
Pay rate
 
 
(In US$ millions)
 
 
 
February 21, 2021
2,764.9

3 month LIBOR
 2.45% to 2.52%
(1) (2)
Total outstanding principal
$
2,764.9

 
 
 
(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, 2018, $319.8 million of our debt was exposed to interest rate fluctuations, compared to $611.9 million as of December 31, 2017. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, our interest expense by approximately $3.2 million on an annual basis as of December 31, 2018, as compared to $6.1 million in 2017.
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.
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.

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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.
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, 2018.
Based upon that evaluation, 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.

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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:
•
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.
Our Management, with the participation of the Chief Executive Officer and the Chief Financial Officer, assessed the effectiveness of the design and operation of our internal control over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2018.

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). Management reviewed the results of its assessment with the Audit Committee of our Board of Directors. Based on this assessment, Management concluded that, as of December 31, 2018, our internal control over financial reporting was effective.
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, 2018, appearing under Item 18 and such report is incorporated herein by reference.
d)    Changes in Internal Control over Financial Reporting
There were no changes in these internal controls during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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

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 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, 2018 and December 31, 2017 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:

69
Table of Contents

 
2018
 
2017
Audit Fees
$
688,285

 
$
1,062,836

Audit-Related Fees
—

 
—

Tax Fees
—

 
—

All other fees
—

 
—

 
$
688,285

 
$
1,062,836

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 2018.

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.


70
Table of Contents

Item 16G.     Corporate Governance
Overview
Pursuant to an exemption under the NYSE listing standards for foreign private issuers, we are 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. We believe that our 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 our 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, we are 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 Mr. Darlington, 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, our non-management directors do not regularly hold executive sessions without management and we do 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, we do 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, we do 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. We are not required to adopt such guidelines under Marshall Islands law and we have 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 believe that our 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-33 together with the related report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, are filed as part of this annual report:

71
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

72
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

73
Table of Contents

Exhibit
Number
Description
4.35
4.36
4.37
4.38
4.39

4.40
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
7.10
7.11
7.12
7.13
7.14
7.15
7.16

74
Table of Contents

Exhibit
Number
Description
7.17
7.18
7.19
8.1*
12.1*
12.2*
13.1*
13.2*
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.


75
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 (the “Company”) as of December 31, 2018 and 2017, 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, 2018 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.




/s/ PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
March 28, 2019

We have served as the Company’s auditor since 2012.  

F- 2
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions, except per unit data)
 
 
Note
 
2018
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
 
Contract revenues
 
 
$
797.5

 
$
1,007.7

 
$
1,356.4

Reimbursable revenues
 
 
31.2

 
17.7

 
32.8

Other revenues
7

*
209.5

 
103.0

 
211.1

Total operating revenues
 
 
1,038.2

 
1,128.4

 
1,600.3

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Vessel and rig operating expenses
 
*
(278.2
)
 
(345.4
)
 
(373.9
)
Depreciation
11

 
(280.3
)
 
(274.9
)
 
(266.3
)
Amortization of favorable contracts
10

 
(45.1
)
 
(74.4
)
 
(70.6
)
Reimbursable expenses
 
 
(28.6
)
 
(16.1
)
 
(30.2
)
General and administrative expenses
 
*
(45.8
)
 
(44.8
)
 
(41.2
)
Total operating expenses
 
 
(678.0
)
 
(755.6
)
 
(782.2
)
 
 
 
 
 
 
 
 
Other operating items
 
 
 
 
 
 
 
Loss on impairment of goodwill
 
 
(3.2
)
 
—

 
—

Revaluation of contingent consideration
 
 
—

 
89.9

 
—

Gain on sale of assets
 
 
—

 
0.8

 
—

Total other operating items
8

 
(3.2
)
 
90.7

 
—

 
 
 
 
 
 
 
 
Operating income
 
 
357.0

 
463.5

 
818.1

 
 
 
 
 
 
 
 
Financial items
 
 
 
 
 
 
 
Interest income
 
 
47.1

 
15.7

 
11.5

Interest expense
 
*
(263.7
)
 
(179.1
)
 
(180.0
)
Gain/(loss) on derivative financial instruments
15

*
24.9

 
(13.9
)
 
(18.0
)
Currency exchange gain
 
 
0.2

 
0.9

 
0.6

Other financial expenses
 
 
(4.8
)
 
(11.5
)

—

Total financial items
 
 
(196.3
)
 
(187.9
)
 
(185.9
)
 
 
 
 
 
 
 
 
Income before income taxes
 
 
160.7

 
275.6

 
632.2

Income tax expense
6

 
(86.7
)
 
(40.3
)
 
(86.5
)
Net income
 
 
74.0

 
235.3

 
545.7

 
 
 
 
 
 
 
 
Net income attributable to the non-controlling interest
 
 
17.9

 
94.1

 
264.7

Net income attributable to Seadrill Partners LLC owners
 
 
56.1

 
141.2

 
281.0

 
 
 
 
 
 
 
 
Earnings per unit (common and subordinated)
 
 
 
 
 
 
 
Common unitholders
 
 
$
0.75

 
$
1.88

 
$
3.20

Subordinated unitholders
 
 
$
—

 
$
—

 
$
2.28

* Includes transactions with related parties. Refer to Note 14 - "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- 3
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED BALANCE SHEETS
As of December 31, 2018 and 2017
(In US$ millions)
 
Note
2018
 
2017
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
841.6

 
$
848.6

Accounts receivables, net
9

150.9

 
254.1

Amount due from related party
14

6.4

 
24.2

Other current assets
10

110.6

 
86.8

Total current assets
 
1,109.5

 
1,213.7

Non-current assets:
 
 
 
 
Drilling units
11

5,005.6

 
5,170.9

Goodwill
3

—

 
3.2

Deferred tax assets
6

7.7

 
9.5

Other non-current assets
10

62.6

 
133.5

Total non-current assets
 
5,075.9

 
5,317.1

Total assets
 
$
6,185.4

 
$
6,530.8

 
 
 
 
 
LIABILITIES AND MEMBERS' CAPITAL
 
 
 
 
Current liabilities:
 
 
 
 
Current portion of long-term debt
12

$
162.9

 
$
162.9

Current portion of long-term related party debt
14

—

 
24.7

Trade accounts payable and accruals
 
25.7

 
37.4

Current portion of deferred and contingent consideration to related party
14

37.5

 
41.7

Related party payable
14

126.3

 
157.0

Other current liabilities
13

80.2

 
121.8

Total current liabilities
 
432.6

 
545.5

Non-current liabilities:
 
 
 
 
Long-term debt
12

2,896.2

 
3,180.2

Deferred and contingent consideration to related party
14

21.5

 
46.0

Deferred tax liability
6

0.4

 
1.5

Other non-current liabilities
13

120.5

 
55.8

Total non-current liabilities
 
3,038.6

 
3,283.5

 
 
 
 
 
Commitments and contingencies (see Note 17)
 


 


Equity
 
 
 
 
Members' Capital:
 


 


Common unitholders (issued 75,278,250 units as at December 31, 2018 and December 31, 2017)
 
1,224.8

 
1,208.9

Subordinated unitholders (issued 16,543,350 units as at December 31, 2018 and December 31, 2017)
 
104.9

 
94.8

Total members' capital
 
1,329.7

 
1,303.7

Non-controlling interest
 
1,384.5

 
1,398.1

Total equity
 
2,714.2

 
2,701.8

Total liabilities and equity
 
$
6,185.4

 
$
6,530.8

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

F- 4
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
 
2018
 
2017
 
2016
Cash Flows from Operating Activities
 
 
 
 
 
 
Net income
 
$
74.0

 
$
235.3

 
$
545.7

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation
 
280.3

 
274.9

 
266.3

Amortization of deferred loan charges
 
12.4

 
12.6

 
11.4

Amortization of favorable contracts
 
45.1

 
74.4

 
70.6

Gain on disposal of PPE
 
—

 
(0.8
)
 
—

Loss on impairment of goodwill
 
3.2

 
—

 
—

Unrealized gain related to derivative financial instruments
 
(38.9
)
 
(25.8
)
 
(32.2
)
Unrealized foreign exchange loss/(gain)
 
0.5

 
(3.5
)
 
(9.4
)
Payment for long term maintenance
 
(91.6
)
 
(54.9
)
 
(48.0
)
Gain on revaluation of contingent consideration
 
—

 
(89.9
)
 
—

Deferred tax expense
 
0.7

 
4.6

 
19.2

Accretion of discount on deferred consideration
 
5.3

 
13.2


17.3

 
 
 
 
 
 
 
Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
 
 
Trade accounts receivable
 
103.2

 
(1.6
)
 
38.7

Prepaid expenses and accrued income
 
(3.6
)
 
(4.0
)
 
8.6

Trade accounts payable
 
(11.7
)
 
5.4

 
7.8

Related party balances
 
(12.9
)
 
16.1

 
(64.3
)
Other assets
 
15.5

 
34.4

 
70.0

Other liabilities
 
56.5

 
(4.9
)
 
(12.1
)
Changes in deferred revenue
 
(3.4
)
 
(9.7
)
 
(17.0
)
Other, net
 
(0.5
)
 
0.4

 
1.2

Net cash provided by operating activities
 
$
434.1

 
$
476.2

 
$
873.8

 
 
 
 
 
 
 
Cash Flows from Investing Activities
 
 
 
 
 
 
Additions to drilling units
 
(23.4
)
 
(66.7
)
 
(13.1
)
Proceeds from sale of assets
 
—

 
16.2


—

Payment received from loans granted to related parties
 
—

 
39.4

 
103.6

Insurance refund
 
—

 
—

 
7.1

Net cash (used in) / provided by investing activities
 
$
(23.4
)
 
$
(11.1
)
 
$
97.6




F- 5
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
 
2018
 
2017
 
2016
Cash Flows from Financing Activities
 
 
 
 
 
 
Repayments of long term debt
 
(296.4
)
 
(215.0
)
 
(105.3
)
Debt fees paid
 
—

 
(3.8
)
 
(0.3
)
Repayments of related party debt
 
(24.7
)
 
(66.0
)
 
(249.5
)
Contingent consideration paid
 
(34.0
)
 
(40.0
)
 
(59.7
)
Cash distributions
 
(55.4
)
 
(60.1
)
 
(107.3
)
Repayment of shareholder loan
 
(6.2
)
 
—

 
—

Net cash (used in) / provided by financing activities
 
$
(416.7
)
 
$
(384.9
)
 
$
(522.1
)
 
 
 
 
 
 
 
Effect of exchange rate changes on cash
 
(1.0
)
 
0.8

 
(0.7
)
 
 
 
 
 
 
 
Net (decrease) / increase in cash and cash equivalents
 
(7.0
)
 
81.0

 
448.6

Cash and cash equivalents at beginning of the year
 
848.6

 
767.6

 
319.0

Cash and cash equivalents at the end of year
 
$
841.6

 
$
848.6

 
$
767.6

 
 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
 
Interest and other financial items paid
 
$
261.3

 
$
200.3

 
$
196.4

Taxes paid
 
24.9

 
42.9

 
49.0

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

F- 6
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’
CAPITAL
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
Members’ Capital
 
 
 
 
 
 
 
 
Common
Units
 
Subordinated
Units
 
Total Before
Non-
Controlling
interest
 
Non-
controlling
Interest
 
Total 
Equity
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

Net income
 
46.0


10.1


56.1


17.9


74.0

Cash distributions
 
(30.1
)

—


(30.1
)

(25.3
)

(55.4
)
Repayment of shareholder loan
 
—

 
—

 
—

 
(6.2
)
 
(6.2
)
Consolidated balance at December 31, 2018
 
$
1,224.8

 
$
104.9

 
$
1,329.7

 
$
1,384.5

 
$
2,714.2

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

F- 7
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 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn, and
(ii) 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.
Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn. Seadrill Operating LP owned: (i) 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) approximately 56% interest in the entity that owns and operates the West Capella.
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, (iv) Seadrill Capricorn Holdings LLC acquired the West Sirius and Seadrill Operating LP acquired the West Leo; and (v) we acquired from Seadrill an additional 28% limited partner interest in Seadrill Operating LP.  As a result of the acquisition, the Company's limited partner interest in Seadrill Operating LP increased from 30% to 58% .
As of December 31, 2018 and 2017, 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.
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
In our Form 20-F covering our annual report for the fiscal year ended December 31, 2017, issued on April 12, 2018, we reported that the combination of (i) our operational dependence on Seadrill because of the management, administrative and technical support services provided to us by Seadrill and (ii) uncertainties over Seadrill's ability to continue as a going concern linked to its Chapter 11 Re-organization, gave rise to a substantial doubt over our ability to continue as a going concern for a period of at least twelve months after the date the financial statements were issued.
Seadrill completed its plan of reorganization and emerged from Bankruptcy on July 2, 2018. Therefore, the above uncertainty has been mitigated and there is no longer a substantial doubt over our ability to continue as a going concern for at least the twelve months after the date the financial statements are issued.
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 as well as Seadrill Capricorn Holdings LLC and its majority owned subsidiaries. We separately present within equity on our Consolidated Balance Sheets the ownership interests attributable to parties with non-controlling interests in our Consolidated subsidiaries, and we separately present net income attributable to such parties in our Consolidated Statements of Operations.
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.

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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.
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.
Foreign currencies
The majority of our revenues and expenses are denominated in U.S. dollars and therefore the majority of our subsidiaries use U.S. dollars as their functional currency. Our reporting currency is also U.S. dollars. For subsidiaries that maintain their accounts in currencies other than U.S. dollars, we use the current method of translation whereby the Statement of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders' equity.
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. Refer to Note 14 - ''Related party transactions''.
Revenue from contracts with customers
The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments.
We recognize consideration for activities that correspond to a distinct time increment within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment, ratably over the estimated contract term.
We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required.
Dayrate Drilling Revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.
Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.
Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as "Reimbursable revenues" in our Consolidated Statements of Operations.

F- 9
Table of Contents


Contract Balances - Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Contract asset balances consist primarily of demobilization revenues which have been recognized during the period but are contingent on future demobilization activities. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.
Local Taxes - 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.
Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.
Other revenues
Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 7 - ''Other revenues''.
Related party revenues - Related party revenues relate to onshore support and offshore personnel provided to Seadrill
Early termination fees - Other revenues also 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. Refer to Note 14 - ''Related party transactions''.
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.
Mobilization and demobilization expenses
We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see deferred contract costs above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.
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.
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 expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.
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. We have 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. Refer to Note 6 - ''Taxation''.

F- 10
Table of Contents

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. Refer to Note 18 - ''Earnings per unit and cash distributions''.
Current and non-current classification
Generally, 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. In addition, we classify any derivatives financial instruments whose fair value is a net liability as current.
Generally, assets and liabilities are classified as non-current assets and liabilities respectively, if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivatives financial instruments whose fair value is a net asset as non-current.
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. Interest income on receivables is recognized as earned. Refer to Note 9 - ''Accounts receivable''.
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 residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up 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. Refer to Note 11 - ''Drilling rigs''.
Impairment of long-lived assets
We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first 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 disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, we then compare the carrying value of the intangible asset with the discounted future net cash flows, using relevant WACC to determine an impairment loss to be recognized during the period.
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 Consolidated Statements 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 Statements of Operations in each period. Refer to Note 16 - ''Fair value of financial instruments''.
We classify the gain or loss on derivative financial instruments as a separate line item within financial items in the Consolidated Statements of Operations. We classify the asset or liability for derivative financial instruments as an other current asset or liability in our Consolidated Balance Sheets. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements.
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.

F- 11
Table of Contents

Debt
We have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement, or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid. Refer to Note 12 - ''Debt''.
Loss contingencies
We recognize a loss contingency in the Consolidated Balance Sheets 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. Refer to Note 17- ''Commitments and contingencies''.
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.

Note 3 - Recent accounting standards
We adopted the following accounting standard updates ("ASUs") in the year:
ASU 2014-09 - Revenue from contracts with customers (also 2016-8, 2016-10, 2016-11, 2016-12, 2016-20, 2017-13, 2017-14)
In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.

We adopted ASU 2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues or on our opening retained earnings at January 1, 2018. Refer to Note 5- "Revenue from Contracts with Customers" for further information.
ASU 2017-04 Intangibles (Topic 350)- 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 early adopted ASU 2017-04, effective December 31, 2018. on a prospective basis. Accordingly, we have applied the simplified test for goodwill at December 31, 2018. Prior to adopting ASU 2017-04, we had recorded goodwill of $3.2 million with accumulated impairment losses of nil. As a result of adopting ASU 2017-04, we have recorded a goodwill impairment loss of $3.2 million in 2018.


F- 12
Table of Contents

Other ASUs
We adopted the following ASUs in the year, none of which had any impact on our Consolidated Financial Statements and related disclosures:
•
ASU 2016-01 Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities
•
ASU 2016-15 Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments
•
ASU 2016-16 Income Taxes - Income taxes intra-entity transfers of assets other than inventory
•
ASU 2016-18 Statement of Cash Flows - Restricted Cash
•
ASU 2017-01 Business Combinations (Topic 805)- Clarifying the Definition of a Business
•
ASU 2018-03 Technical Corrections and Improvements to Financial Instruments-Overall (Subtopic 825-10)
•
ASU 2018-04 Investments-Debt Securities (Topic 320) and Regulated Operations (Topic 980)
•
ASU 2018-05 Income Taxes (Topic 740)
•
ASU 2018-06 Codification Improvements to (Topic 942)
•
ASU 2018-09 Codification Improvements
•
ASU 2018-19 Codification Improvements to (Topic 326)

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 2016-02 Leases (Topic 842) (also 2018-01, 2018-10, 2018-11. 2018-20)
•
ASU 2016-13 Financial Instruments - Credit Losses (Topic 326)
•
ASU 2018-07 Compensation-Stock Compensation (Topic 718)
•
ASU 2018-13 Fair Value Measurement (Topic 820)
•
ASU 2018-14 Compensation-Retirement Benefits-Defined Benefit Plans (Subtopic 715-20)
•
ASU 2018-15 Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40)
•
ASU 2018-16 Derivatives and Hedging (Topic 815)
•
ASU 2018-17 Consolidation (Topic 810)
ASU 2016-02 - Leases (also 2018-01, 2018-10, 2018-11. 2018-20)
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update required an entity to recognize right-of-use assets and lease
liabilities on its balance sheet and disclose key information about leasing arrangements. It also offered 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 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal year, using a modified retrospective application.
Effective January 1, 2019, we will adopt Topic 842 using the modified retrospective application through a cumulative-effect adjustment to retained earnings at January 1, 2019. We have elected the following transition practical expedients, which will be applied consistently to all leases that commenced before January 1, 2019:
1.
We will not reassess whether any expired or existing contracts are or contain leases.
2.
We will not reassess the lease classification for any expired or existing leases.
3.
We will not reassess initial direct costs for any existing leases.
4.
We will use hindsight in determining the lease term and in assessing impairment of the right-of-use assets.
We have determined that our drilling contracts contain a lease component, however, we have elected not to separate the drilling contract lease and non-lease components. We have determined that the non-lease component in our drilling contracts is the predominant component. As such, we will continue to account for our drilling contracts under the guidance in Topic 606. We do not expect our pattern of revenue recognition to change significantly compared to current accounting standards.
We have determined that adoption of this standard will result in increased disclosure of our leasing arrangements. We currently expect this guidance to have nil impact our Consolidated Financial Statements and related disclosures when we adopt it.

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ASU 2016-13 - Financial Instruments - Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 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 for annual and interim periods beginning after December 15, 2019, with early adoption permitted only from January 1, 2019. Entities are required to apply the standard's provisions as a cumulative-effect adjustment to retained earnings as at 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 2018-07 Compensation - Stock Compensation
In June 2018, the FASB issued ASU 2018-07, Stock Compensation (Topic 718): Improvements to non-employee share-based payment accounting, which intended to reduce cost and complexity and to improve financial reporting for share-based payments issued to non-employees. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-13 Fair Value Measurement - Changes to the Disclosure Requirements for Fair Value Measurement
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity's financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-14 Compensation - Changes to the Disclosure Requirements for Defined Benefit Plans
In August 2018, the FASB issued ASU 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans- General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity's financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2020, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-15 Intangibles
In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force). The update is intended to provide additional guidance on the accounting for costs of implementation activities performed in a cloud computing arrangement that is a service contract. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-16 Derivatives and Hedging
In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. The update is intended to permit use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815 in addition to the direct Treasury obligations of the U.S. government, the LIBOR swap rate, the OIS rate based on the Fed Funds Effective Rate, and the Securities Industry and Financial Markets Association Municipal Swap Rate. The guidance will be effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted if an entity has already adopted ASU 2017-12. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities
In October 2018, the FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The update is intended to improve general purpose financial reporting by considering indirect interests held through related parties in common control arrangements on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted.
Effective January 1, 2019, we will adopt ASU 2018-17 on a prospective basis and apply the amendments in the update to qualifying new or re-designated hedging relationships entered into on or after January 1, 2019. We do not expect this to have a material impact on our Consolidated Financial Statements and related disclosures.
Other accounting standard updates issued by the FASB
As of February 28, 2019, the FASB have 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.

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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, 2018, 2017 and 2016 is as follows: 
 
2018
 
2017
 
2016
BP
68.0
%
 
56.8
%
 
42.0
%
Tullow
19.8
%
 
—
%
 
13.0
%
Chevron
8.5
%
 
7.9
%
 
5.4
%
ExxonMobil
0.3
%
 
22.2
%
 
22.0
%
Hibernia
—
%
 
6.4
%
 
15.1
%
Other
3.4
%
 
6.7
%
 
2.5
%
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, 2018, 2017 and 2016 and fixed assets as of December 31, 2018 and 2017 by geographic area:
Revenues
(In US$ millions)
2018
 
2017
 
2016
United States
$
618.1

 
$
638.0

 
$
672.2

Ghana
205.5

 
—

 
208.1

Thailand
88.7

 
89.2

 
86.3

Canada
85.3

 
87.1

 
241.5

Indonesia
8.9

 
37.3

 
—

Angola
1.3

 
152.5

 
175.9

Equatorial Guinea
0.9

 
48.1

 
—

Nigeria
—

 
39.5

 
185.2

Other
29.5

 
36.7

 
31.1

Total
$
1,038.2

 
$
1,128.4

 
$
1,600.3

Fixed Assets—Drilling Units (1)  
(In US$ millions)
2018
 
2017
United States
$
2,647.1

 
$
2,729.6

Spain
1,050.1

 
1,075.9

Malaysia
640.0

 
—

Canada
439.7

 
460.9

Thailand
228.7

 
234.6

Gabon
—

 
507.4

Indonesia
—

 
162.5

Total
$
5,005.6

 
$
5,170.9

(1) 
The fixed assets referred to in the table above include the eleven drilling units at December 31, 2018 and December 31, 2017. 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.


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Table of Contents


Note 5 – Revenue from contracts with customers

The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers:
(In US$ millions)
2018
 
2017
Accounts receivable, net
$
150.9

 
$
254.1

Current contract liabilities (deferred revenues) (1)
4.0

 
5.3

Non-current contract liabilities (deferred revenues) (1)
2.4

 
4.1

(1)  Current contract assets and liabilities balances are included in "Other current assets" and "Other current liabilities", respectively in our Consolidated Balance Sheets as of December 31, 2018.

Significant changes in the contract assets and the contract liabilities balances during the year ended December 31, 2018 are as follows:
(In US$ millions)
Net Contract balances
Contract liabilities at December 31, 2017
(9.4
)
Decrease due to amortization of revenue that was included in the beginning contract liability balance
4.6

Increase due to cash received, excluding amounts recognized as revenue
(1.6
)
Contract liabilities at December 31, 2018
(6.4
)

Certain direct and incremental costs that are expected to be recovered, relate directly to a contract, and enhance resources that will be used in satisfying our performance obligations in the future. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Deferred contract revenue during the year ended December 31, 2018 and 2017 are as follows:
(In US$ millions)
Net Deferred Contract costs
Opening deferred contract costs at December 31, 2017
0.3

Decrease due to amortization of costs that were included in the beginning balance
(2.3
)
Increase due to contract costs incurred, excluding amounts recognized as operating expenses
14.6

Closing deferred contract costs at December 31, 2018
12.6


Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling unit additions and depreciated over the estimated useful life of the improvement. Refer to Note 11 - ''Drilling units'' for more information.

Deferred revenue - The deferred revenue balance of $4.0 million reported in "Other current liabilities" at December 31, 2018 is expected to be realized within the next twelve months and $2.4 million reporting in "Other non-current liabilities" is expected to be realized within the following next twelve months. The deferred revenue included above consists primarily of expected mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2018. The actual timing of recognition of such amounts may vary due to factors outside of our control.

Practical expedient - We have applied the disclosure practical expedient in ASC 606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue. The duration of our performance obligations varies by contract.

Impact of Topic 606 on Financial Statement Line Items - Adopting Topic 606 did not have a material effect on the Consolidated Statement of Operations, or Consolidated Statement of Cash Flows in the year ended December 31, 2018 and 2017. Refer to Note 3 - ''Recent accounting standards'' for more information on the recently adopted accounting pronouncements.



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Note 6 – Taxation
Income taxes consist of the following:
(In US$ millions)
2018
 
2017
 
2016
Current tax expense:
 
 
 
 
 
U.K.
$
(0.3
)
 
$
(4.5
)
 
$
(1.6
)
Foreign
86.3

 
40.4

 
110.2

Total current tax expense
86.0

 
35.9

 
108.6

Deferred tax (benefit) / expense:
 
 
 
 
 
U.K.
—

 
—

 
—

Foreign
0.7

 
4.4

 
(22.1
)
Total income tax expense
$
86.7

 
$
40.3

 
$
86.5

Seadrill Partners LLC is tax resident in the U.K. 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 U.K. (none of whom presently own or operate rigs) are resident in the U.K. 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, 2018, 2017 and 2016 differs from the U.K. statutory income tax rate as follows:
 
2018
 
2017
 
2016
U.K. statutory income tax rate
19.0
%
 
19.3
 %
 
20.0
 %
Non-U.K. taxes
35.0
%
 
(4.7
)%
 
(6.3
)%
Effective income tax rate
54.0
%
 
14.6
 %
 
13.7
 %
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.
The net deferred tax assets consist of the following:
(In US$ millions)
2018
 
2017
Provisions
$
11.0

 
$
0.5

Net operating losses carry forward
64.4

 
33.3

Interest carry forward
16.7

 
—

Other
5.7

 
5.0

Gross deferred tax assets
97.8

 
38.8

Valuation allowance
(90.1
)
 
(28.9
)
Deferred tax asset, net of valuation allowance
$
7.7

 
$
9.9

The net deferred tax liabilities consist of the following:
(In US$ millions)
2018
 
2017
Property, plant and equipment
$
0.1

 
$
0.4

Unremitted earnings of subsidiaries
0.3

 
1.5

Gross deferred tax liabilities
0.4

 
1.9

 
 
 
 
Net deferred tax asset
7.3

 
8.0

As of December 31, 2018, deferred tax assets related to net operating loss ("NOL") carryforwards were $64.4 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $61.1 million which will not expire and $3.3 million that will expire between 2022 and 2023 if not utilized. We establish a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change. Our valuation allowance consists of $62.8 million on NOL carryforward, $16.7 million on interest carryforward, and $10.6 million on provisions.
The Company's increase in NOL and corresponding valuation allowance was primarily due to the increase in uncertain tax positions.

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Table of Contents

Uncertain tax positions
As of December 31, 2018, the Company had uncertain tax positions, exclusive of interest and penalties, of $101.6 million (December 31, 2017: $43.7 million) included in "Other non-current liabilities" on the Consolidated Balance Sheets. The changes to the Company's liabilities related to uncertain tax positions were as follows:
(In US$ millions)
2018
 
2017
Balance beginning of year
$
43.7

 
$
40.0

Increases as a result of positions taken in prior years
70.4

 
—

Increases as a result of positions taken during the current year
10.1

 
3.7

Decreases as a result of positions taken in prior years
(22.6
)
 
—

Uncertain tax position
$
101.6

 
$
43.7

Accrued interest and penalties totaling $16.4 million as of December 31, 2018 (December 31, 2017: $8.0 million) was included in "Other non-current liabilities" on the Consolidated Balance Sheets. The associated expense of $8.4 million was recognized in "Income tax expense" in the Consolidated Statements of Operations during the year ended December 31, 2018 (December 31, 2017: $6.2 million and December 31, 2016: $1.8 million).
As of December 31, 2018, we have recognized liabilities for uncertain tax positions including interest and penalties of $118.0 million. In the event that these issues are resolved for amounts less than provided, there would be a favorable impact on the effective tax rate.
The increase in our uncertain tax position was primarily due to US taxes following a recently identified interpretation of the US tax code that appears to be an unintended consequence of the US tax reform. We understand that the US Department of Treasury is aware of this issue and that it could potentially remediated with additional guidance in the future. However, in the meanwhile, the Company is considering its approach for future filings which may result in a mitigation of a portion of the liability that has been recorded.  At this stage, no cash payment is expected as a result of this uncertain tax position.
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
2015
Nigeria
2012
Ghana
2013

Note 7 – Other revenues
Other revenues comprise the following items: 
(In US$ millions)
2018
 
2017
 
2016
Termination payments revenue
$
204.9

 
$
95.9

 
$
198.8

Related party other revenues
4.6

 
7.1

 
12.3

Total
$
209.5

 
$
103.0

 
$
211.1

Termination payments earned during the year ended December 31, 2018 relates to the West Leo litigation judgment of which $204.9 million was recognized as revenue during 2018 .
Termination payments earned during the years ended December 31, 2017 and December 31, 2016 include the termination fees for 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 and Old Seadrill's drilling rigs that were operating in Nigeria during the years ended December 31, 2018, December 31, 2017 and December 31, 2016. Please refer to Note 14 – "Related party transactions" for further detail on related party other revenues.


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Table of Contents

Note 8 – Other operating items
Other operating items comprise the following: 
(In US$ millions)
2018
 
2017
 
2016
Loss on impairment of goodwill

$
(3.2
)
 
$
—

 
$
—

Revaluation of contingent consideration
$
—

 
$
89.9

 
$
—

Gain on sale of assets
—

 
0.8

 
—

Total
$
(3.2
)
 
$
90.7

 
$
—

During the year ended December 31, 2018, we recognized a loss on impairment of goodwill following early adoption of ASU 2017-04, Intangibles. For further information refer to Note 3 - ''Recent accounting standards''.
There was gain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 2017. 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 decreased during 2017 as new market information became available. For further information please see Note 14 - "Related party transactions".
Note 9 – Accounts receivable
Accounts receivable are presented net of allowances for customer disputes and bad debts.
We have recorded provisions for disputes with customers totaling $2.2 million as of December 31, 2018 (December 31, 2017: $247.5 million). The offsetting entry for these provisions is to reduce revenue. These provisions primarily relate to disputed amounts billed to BP on West Vela.
The provisions as of December 31, 2017 primarily related to disputed amounts billed to Tullow on the West Leo, which were settled during 2018 and the provisions were reversed.
We do not hold any provisions for bad debts. We did not recognize any bad debt expense in 2018, 2017 or 2016.

Note 10 – Other assets
Other assets include the following:
(In US$ millions)
2018
 
2017
Reimbursable amounts due from customers
$
2.9

 
$
3.6

Mobilization revenue receivables
47.9

 
73.8

Intangible asset - Favorable contracts to be amortized
85.5

 
130.6

Prepaid expenses
12.1

 
8.5

Deferred mobilization costs
12.6

 
0.3

Interest rate swap agreements
9.9

 
—

Other
2.3

 
3.5

Total other assets
$
173.2

 
$
220.3

Other assets are presented in our Consolidated Balance Sheet as follows:
(In US$ millions)
2018
 
2017
Other current assets
110.6

 
86.8

Other non-current assets
62.6

 
133.5

Total other assets
$
173.2

 
$
220.3

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.

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Table of Contents

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 and the West Auriga from Seadrill as at December 31, 2018. As at December 31, 2017 the balance related to the contract acquired with the West Polaris was fully amortized when the contract was completed. 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:
 
2018
 
2017
(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

 
$
(226.7
)
 
$
130.6

 
$
357.3

 
$
(152.3
)
 
$
205.0

Amortization of favorable contracts
—

 
(45.1
)
 
(45.1
)
 
—

 
(74.4
)
 
(74.4
)
Balance at end of period
$
357.3

 
$
(271.8
)
 
$
85.5

 
$
357.3

 
$
(226.7
)
 
$
130.6

The amortization is recognized in the Consolidated Statements 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:
 
Year ended December 31
(In US$ millions)
2019

 
2020

 
2021

 
2022

 
2023

 
Total

Amortization of favorable contracts
$
45.1

 
$
40.4

 
$
—

 
$
—

 
$
—

 
$
85.5

Note 11 – Drilling units 
The below table shows the gross value and net book value of our drilling units at December 31, 2018 and December 31, 2017.
(In US$ millions)
Cost
 
Accumulated depreciation

 
Net Book Value
Opening balance as at January 1, 2017
$
6,494.1

 
$
(1,153.2
)
 
$
5,340.9

Additions
121.6

 
—

 
121.6

Disposals
(16.7
)
 
—

 
(16.7
)
Depreciation
—

 
(274.9
)
 
(274.9
)
Closing balance as at December 31, 2017
6,599.0

 
(1,428.1
)
 
5,170.9

Additions
115.0

 
—

 
115.0

Disposals
—

 
—

 
—

Depreciation
—

 
(280.3
)
 
(280.3
)
Closing balance as at December 31, 2018
6,714.0

 
(1,708.4
)
 
5,005.6

Depreciation and amortization expense related to the drilling units was $280.3 million, $274.9 million and $266.3 million for the years ended December 31, 2018, 2017 and 2016 respectively.
Each of our drilling units has been pledged as collateral under our debt agreements. Please read Note 12 – "Debt" for further details.


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Table of Contents

Note 12 – Debt
As of December 31, 2018 and December 31, 2017, we had the following debt amounts outstanding:
 (In US$ millions)
2018
 
2017
External debt agreements
 
 
 
Term Loan B
$
2,686.4

 
$
2,836.9

West Vela Facility
191.3

 
255.3

West Polaris Facility
150.8

 
205.6

Tender Rig Facility

56.2

 
83.3

Sub-total external debt
3,084.7

 
3,381.1

 
 
 
 
Related party debt agreements
 
 
 
   West Vencedor Facility
—

 
24.7

Sub-total related party debt
—

 
24.7

 
 
 
 
Total external and related party debt
$
3,084.7

 
$
3,405.8

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 $2,636.4 million outstanding on the term loan at December 31, 2018. 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, 2018. The revolving credit facility matured in February 2019 and was repaid.
During the year to December 31, 2018, we paid interest of LIBOR + 6.0% 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, West Auriga and West Vencedor as collateral vessels under the TLB. The net book value of these drilling units at December 31, 2018 was $3.6 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.
In the year ended December 31, 2017 the TLB included certain covenants and other provisions that could 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 received a 3% increase in margin on the term loan and a conditional prepayment of $120.8 million based on the successful outcome of the litigation with Tullow on the West Leo. Refer to Note 17 - "Commitments and contingencies" for further details. We were required to repay the West Vencedor facility and make the West Vencedor a collateral vessel under the TLB. The amendment also added certain other restrictions on our ability to transfer cash outside of the TLB collateral group. As part of this amendment we also agreed that our quarterly distributions would not exceed 10 cents per common unit unless the Consolidated net leverage ratio is below 4x during 2018 and below 5x thereafter.
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 further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The $120.8 million balloon payment is due in October 2020. We had $191.3 million outstanding on this loan at December 31, 2018.
We pay interest on the term loan at LIBOR plus a margin of between 1.20% 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 $660.8 million at December 31, 2018. 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.

F- 21
Table of Contents

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 further prepayments of $9.4 million in February 2018 and August 2018. The $93.8 million balloon payment is due in July 2020. We had $150.8 million outstanding on this facility at December 31, 2018.
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 $525.8 million at December 31, 2018. 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.
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 paid further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The $31.2 million balloon payment is due in June 2020. We had $56.2 million outstanding on this loan at December 31, 2018.
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 $228.7 million at December 31, 2018. We have also pledged substantially all the assets of our subsidiaries which own and operate the T-15 and T-16, as well as our investments in those companies.
The Tender Rig facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable.
West Vencedor Loan Agreement
The West Vencedor Loan Agreement facility was a term loan due to Seadrill. The outstanding balance of the loan at December 31, 2018 was nil as the facility was repaid during the year. We paid interest on the facility at LIBOR plus a margin of 2.3%.
We previously pledged the West Vencedor as a collateral vessel under this facility. After repaying the facility the West Vencedor was pledged as collateral to the TLB.
Debt repayments by year
The outstanding debt as of December 31, 2018 is repayable as follows: 
(In US$ millions)
2018
2019
$
175.1

2020
331.1

2021
2,578.5

2022
—

2023
—

2024 and thereafter
—

Total external and related party debt
$
3,084.7


F- 22
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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, 2018
(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
 
2,909.6

(13.4
)
2,896.2

Total interest bearing debt
 
$
3,084.7

$
(25.6
)
$
3,059.1

 
 
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


Note 13 – Other liabilities
Other liabilities are comprised of the following: 
(In US$ millions)
2018

2017
Uncertain tax position
$
118.0

 
$
51.7

Accrued expenses
33.3

 
35.4

Taxes payable
31.3

 
36.5

Employee and business withheld taxes, social security and vacation payment
8.1

 
8.7

Deferred mobilization/demobilization revenues
6.4

 
9.4

VAT payable
3.6

 
6.5

Interest rate swap agreements
—

 
29.0

Other liabilities
—

 
0.4

Total other liabilities
$
200.7

 
$
177.6

Other liabilities are classified in our Consolidated Balance Sheets as follows:
(In US$ millions)
2018

2017
Other current liabilities
80.2

 
121.8

Other non-current liabilities
120.5

 
55.8

Total other liabilities
$
200.7

 
$
177.6



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Note 14 – Related party transactions
The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2018, 2017 and 2016.
(In US$ millions)
 
2018
 
2017
 
2016
Related party inventory sales (a)
 
$
3.2

 
$
2.2

 
$
1.4

Rig operating costs (b)
 
1.4

 
4.9

 
10.9

Total related party operating revenues

 
$
4.6

 
$
7.1

 
$
12.3

 
 
 
 
 
 
 
Management and technical support fees (c) (d)
 
$
70.6

 
$
74.5

 
$
62.8

Rig operating costs (e)
 
0.8

 
22.9

 
24.9

Bareboat charter arrangement (f)
 
—

 
2.8

 
9.5

Related party inventory purchases (a)
 
0.7

 
1.0

 
2.0

Total related party operating expenses
 
$
72.1

 
$
101.2

 
$
99.2

 
 
 
 
 
 
 
Interest expense recognized on deferred contingent consideration (k)
 
$
(3.1
)
 
$
(4.2
)
 
$
(5.2
)
Related party interest expense (g)
 
(1.4
)
 
(4.7
)
 
(10.1
)
Losses on related party derivatives (h)
 
—

 
(1.3
)
 
(4.1
)
Related party commitment fee (i)
 
—

 
(1.3
)
 
(2.0
)
Total related party financial items
 
$
(4.5
)
 
$
(11.5
)
 
$
(21.4
)
The below table provides a summary of amounts due to or from Seadrill at December 31, 2018 and December 31, 2017.
(In US$ millions)
 
2018
 
2017
Trading balances due from Seadrill and subsidiaries (j)
 
$
6.4

 
$
24.2

Total related party receivables
 
$
6.4

 
$
24.2

(In US$ millions)
 
2018
 
2017
Trading balances due to Seadrill and subsidiaries (j)
 
$
(126.3
)
 
$
(157.0
)
Deferred and contingent consideration to related party - short term portion (k)
 
(37.5
)
 
(41.7
)
Deferred and contingent consideration to related party - long term portion (k)
 
(21.5
)
 
(46.0
)
West Vencedor Loan Agreement with Seadrill (l)
 
—

 
(24.7
)
Total related party payables
 
$
(185.3
)
 
$
(269.4
)
(a) Related party inventory sales and purchases
Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.
(b) Rig operating costs charged to Seadrill
Seadrill Partners has charged to Seadrill Limited, through its Nigerian service company, certain services including the provision of onshore and offshore personnel, which was provided for the West Jupiter drilling rig operating 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 2018.
Service agreements
(c) 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, 2018, 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.
(d) Operations and technical supervision agreements
In addition, certain subsidiaries of Seadrill Partners are in advisory, technical, and/or administrative services agreements with subsidiaries of Seadrill. The services provided by our subsidiaries are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services.

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Table of Contents

(e) Rig operating costs charged by Seadrill
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, 2017 we also received similar services from Seadrill for the West Vencedor.
(f) Bareboat charter arrangement
Seadrill previously acted as an intermediate charterer for the West Aquarius during its contract with Hibernia. The contract ended on April 19, 2017. Seadrill also acted as an intermediate charterer for the T-15 and T-16 until December 2016.
(g) Interest expense charged by Seadrill
Interest expense charged by Seadrill for our related party loan arrangement. Please read Note 12 – "Debt" for a description of the loan facility.
(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 15 – "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 amendments to our bank financing agreements.
(j) Trading balances
Receivables and payables with Seadrill Partners and its subsidiaries are comprised of management fees, advisory and administrative services, and other items including accrued interest. In addition, certain receivables and payables arise when we pay an invoice on behalf of Seadrill Partners or its subsidiaries and vice versa. Receivables and payables are generally settled quarterly in arrears. Trading balances to Seadrill Partners and its subsidiaries are unsecured and are intended to be settled in the ordinary course of business.
(k) Deferred consideration to related party
We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela and West Polaris.
On the West Vela we are required to pay to Seadrill $42k per day for mobilization and a further $40k per day adjusted for utilization over the remaining contract term with BP, which runs until November 2020.
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 $450k per day.
The below table sets out the fair value of the liabilities at December 31, 2018 and December 31, 2017.
(In US$ millions)
 
2018

2017
West Vela
 
 
 
 
Mobilization due to Seadrill
 
$
31.2

 
$
44.2

Seadrill share of dayrate from BP contract
 
27.0

 
38.6

 
 
58.2

 
82.8

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

 
4.2

Seadrill share of dayrate from subsequent contracts ("Earnout 2")
 
0.8

 
0.7

 
 
0.8

 
4.9

 
 
 
 
 
Total
 
$
59.0

 
$
87.7







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Table of Contents




These liabilities are presented in our Consolidated Balance Sheets as follows:
(In US$ millions)
 
2018

2017
Current portion of deferred and contingent consideration to related party
 
$
37.5

 
$
41.7

Non-current portion of deferred and contingent consideration to related party
 
21.5

 
46.0

Total
 
$
59.0

 
$
87.7

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.
(l) West Vencedor Loan Agreement
Please read Note 12 - "Debt" for details of the loan facilities.
Other agreements and transactions with Seadrill
Equity Distribution
During the year ended December 31, 2018 and 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 cash distribution of $6.2 million has been distributed to Seadrill in the year ended December 31, 2018.
In the year ended December 31, 2017, 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 were presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2018 and December 31, 2017.
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.
Guarantees
Seadrill has provided performance guarantees to certain of our customers on our behalf. These totaled $7 million as at December 31, 2018 (December 31, 2017: $165.4 million).
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 certain liabilities arising from the operation of the assets contributed or sold to the Company prior to the time they were contributed or sold.

Note 15 – 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, 2018, we had interest rate swaps for a combined outstanding principal amount of $2,764.9 million, (December 31, 2017: $2,793.9 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, 2018 was an asset of $9.9 million (December 31, 2017: liability of $29 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.

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Table of Contents

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 asset or liability within other current assets or 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 "Gain/(loss) on derivative financial instruments".
The total realized and unrealized gain recognized under "Gain/(loss) on derivative financial instruments" in the Consolidated Statement of Operations relating to interest rate swap agreements for 2018 was 24.9 million (2017: loss of $13.9 million, 2016: loss of $18.0 million). Included 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, 2018, were as follows:
Maturity date
Outstanding principal as of December 31, 2018
Receive rate
Pay rate
 
 
(In US$ millions)
 
 
 
February 21, 2021
2,764.9

3 month LIBOR
 2.45% to 2.52%
(1) (2)
Total outstanding principal
$
2,764.9

 
 
 
(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, 2018, $319.8 million of our debt was exposed to interest rate fluctuations, compared to $611.9 million as of December 31, 2017. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, our interest expense by approximately $3.2 million on an annual basis as of December 31, 2018, as compared to $6.1 million in 2017.
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.
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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Table of Contents

Note 16 – Fair Value Measurement
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 measured at amortized cost
The carrying value and estimated fair value of our financial instruments that are measured at amortized cost as of December 31, 2018 and December 31, 2017 are as follows:
 
2018
 
2017
(In US$ millions)
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
841.6

 
$
841.6

 
$
848.6

 
$
848.6

 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
Term Loan B
2,115.1

 
2,662.7

 
2,249.8

 
2,802.3

Other external debt facilities
383.4


396.4


514.7


540.8

Long-term debt to related party
—

 
—

 
23.8

 
24.7

Level 1
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, 2018 and December 31, 2017. This has been categorized at level 1 on the fair value measurement hierarchy.
Level 2
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, 2018 and December 31, 2017 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 8.16% (December 31, 2017 8.36%) was used to estimate the present value of the future cash flows. This is categorized at level 2 on the fair value measurement hierarchy.

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Table of Contents

Financial instruments measured at fair value 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, 2018
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
$
9.9

—

9.9

—

Total assets
9.9

—

9.9

—

 
 
 
 
 
Current liabilities:
 
 
 
 
Related party deferred and contingent consideration
(59.0
)
—

(59.0
)
—

Total liabilities
$
(59.0
)
—

(59.0
)
—

 
 
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
)
—

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, 2018 and December 31, 2017. 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 discounted future cash flows. These liabilities are considered to be at estimated market rates. These are categorized at level 2 on the fair value measurement hierarchy.
Fair value considerations on one-time transactions
In the year ended December 31, 2018, a $3.2 million loss on impairment of goodwill is included in operating income resulting from early adoption of the new standard 2017-04 ASC 350, which requires comparing the fair value of the goodwill against its carrying value. Under this assessment the goodwill's carrying amount exceeded its fair value and was written off.


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Table of Contents

Note 17 – 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, 2018.
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 did not accept that the contract had been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract had been discharged by frustration.  Accordingly, we amended our claim in the English High Court to reflect this.
On July 3, 2018 the English High Court ruled the case in our favor and we recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "Other revenues" per our Consolidated Statements of Operations. See Note 7 - "Other revenues" for further details.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit ("the Suit") against certain of our subsidiaries for patent infringement. The Suit alleged that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity. 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. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.  

In December 2018, Seadrill and Seadrill Partners reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean for the dual activity drilling method on our rigs covering alleged past infringements and future use.
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, 2018 and 2017.

Note 18 – Earnings per unit and cash distributions
(in US $ millions, except per unit data)
2018
 
2017
 
2016
Net income attributable to:
 
 
 
 
 
Common unitholders
$
56.1

 
$
141.2

 
$
240.7

Subordinated unitholders
—

 
—

 
37.8

Seadrill member interest
—

 
—

 
2.5

Net income attributable to Seadrill Partners LLC owners
$
56.1

 
$
141.2

 
$
281

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

 
75,278

 
75,278

Subordinated unitholders
16,543

 
16,543

 
16,543

 
 
 
 
 
 
Earnings per unit:
 
 
 
 
 
Common unitholders
$
0.75

 
$
1.88

 
$
3.20

Subordinated unitholders
$
—

 
$
—

 
$
2.28

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

 
$
0.4000

 
$
0.7000

 
 
 
 
 
 
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):
$
0.0100

 
$
0.1000

 
$
0.1000


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Table of Contents

(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 2018.
(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
•
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.

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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 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.
No distributions were paid to the incentive distribution rights holders for the years ending December 31, 2018, 2017 and 2016.

Note 19 - Supplementary cash flow information
The table below summarizes the non-cash investing and financing activities relating to the periods presented:
(In US$ millions)
2018
 
2017
 
2016
Other distributions (1)
—

 
9.2

 
—

(1) Non cash distribution, refer to Note 14 – "Related party transactions" for further information.
Note 20 – Subsequent events
Distribution declared
On January 22, 2019, we declared a distribution for the fourth quarter of 2018 of $0.0100 per common unit, which was paid on February 14, 2019.
On February 21, 2019, we fully repaid $50 million outstanding on the revolving credit facility linked to the Term Loan B.


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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: March 28, 2019
 
 
 
 
 
 
 
 
 
By:
/s/ Mark Morris
 
 
Name:
Mark Morris
 
 
Title:
Chief Executive Officer of Seadrill Partners LLC
(Principal Executive Officer of Seadrill Partners LLC)